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UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

WASHINGTON, D.C. 20549

FORM 40-F



|            |  |                                                                                        
|----------- |  | ---------------------------------------------------------------------------------------
|[Check one]
|            | 
| ̈           |  | REGISTRATION STATEMENT PURSUANT TO SECTION 12 OF THE SECURITIES EXCHANGE ACT OF 1934   
|            |  | OR                                                                                     
|            | 
|þ           |  | ANNUAL REPORT PURSUANT TO SECTION 13(a) or 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

For the fiscal year ended: December 31, 2015      Commission File Number:
1-34513

CENOVUS ENERGY INC.

(Exact name of Registrant as specified in its charter)

Not applicable

(Translation of Registrants name into English (if applicable))

Canada

(Province or other
jurisdiction of incorporation or organization)

1311

(Primary Standard Industrial

Classification Code Number (if applicable))

Not applicable

(I.R.S.
Employer

Identification Number (if applicable))

2600, 500 Centre Street S.E.

Calgary, Alberta, Canada T2G 1A6

(403) 766-2000

(Address and
telephone number of Registrants principal executive offices)

CT Corporation System

111 8th Avenue

New York, New York 10011

(212) 894-8641

(Name,
address (including zip code) and telephone number (including area code)

of agent for service in the United States)

Securities registered or to be registered pursuant to Section 12(b) of the Act.



|                                                                                    |  |                                          
|----------------------------------------------------------------------------------- |  | -----------------------------------------
|Title of each class                                                                 |  | Name of each exchange on which registered
|                                                                                    | 
|Common shares, no par value (together with associated
common share purchase rights) |  | New York Stock Exchange                  

Securities registered or to be registered pursuant to Section 12(g) of the Act.

None

(Title of Class)



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Securities for which there is a reporting obligation pursuant to Section 15(d) of the Act.

None

(Title of Class)

For annual reports indicate by check mark the information filed with this Form:

þ Annual information form      þ Audited annual financial statements

Indicate the number of outstanding shares of each of
the issuers classes of capital or common stock as of the close of the period covered by the annual report:

833,289,845

Indicate by check mark whether the Registrant (1) has filed all reports to be filed by Section 13 or 15(d) of the Exchange Act during the preceding
12 months (or for such shorter period that the Registrant was required to file such reports) and (2) has been subject to filing requirements for the past 90 days.

Yes þ    No  ̈

Indicate by check mark whether the Registrant has submitted electronically and posted on its corporate Web site, if any, every Interactive Data File
required to be submitted and posted pursuant to Rule 405 of Regulation S-T (§232.405 of this chapter) during the preceding 12 months (or for such shorter period that the Registrant was required to submit and post such files).

Yes  ̈    No  ̈

The annual report on Form 40-F shall be incorporated by reference into or as an exhibit to, as applicable, each of the Registrants Registration
Statements under the Securities Act of 1933, as amended: Form S-8 (File No. 333-163397), Form F-3D (File No. 333-202165) and Form F-10 (File No. 333-196696).









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Principal Documents

The following documents have been filed as part of this annual report on Form 40-F, beginning on the following page:



| | (a) | Annual Information Form of Cenovus Energy Inc. for the fiscal year ended December 31, 2015.
| | --- | -------------------------------------------------------------------------------------------



| | (b) | Managements Discussion and Analysis of Cenovus Energy Inc. for the fiscal year ended December 31, 2015.
| | --- | --------------------------------------------------------------------------------------------------------



| | (c) | Consolidated Financial Statements of Cenovus Energy Inc. for the fiscal year ended December 31, 2015.
| | --- | -----------------------------------------------------------------------------------------------------



| | (d) | Supplementary Information  Oil and Gas Activities (unaudited) for the fiscal year ended December 31, 2015.
| | --- | -----------------------------------------------------------------------------------------------------------









2



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LOGO

Cenovus Energy Inc.

Annual Information Form

For the Year Ended December 31, 2015

February 10, 2016



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|                                                                                           |  |  |    | 
|------------------------------------------------------------------------------------------ |  |  | -- | 
|TABLE OF CONTENTS                                                                          |  |  |    | 
|                                                                                           | 
|FORWARD-LOOKING INFORMATION                                                                |  |  | 1  | 
|CORPORATE STRUCTURE                                                                        |  |  | 3  | 
|GENERAL DEVELOPMENT OF THE BUSINESS                                                        |  |  | 4  | 
|DESCRIPTION OF THE BUSINESS                                                                |  |  | 7  | 
|Oil Sands                                                                                  |  |  | 7  | 
|Conventional                                                                               |  |  | 10 | 
|Refining and Marketing                                                                     |  |  | 13 | 
|RESERVES DATA AND OTHER OIL AND GAS INFORMATION                                            |  |  | 14 | 
|Disclosure of Reserves Data                                                                |  |  | 15 | 
|Development of Proved and Probable Undeveloped Reserves                                    |  |  | 20 | 
|Significant Factors or Uncertainties Affecting Reserves Data                               |  |  | 21 | 
|Other Oil and Gas Information                                                              |  |  | 21 | 
|OTHER INFORMATION                                                                          |  |  | 27 | 
|Competitive Conditions                                                                     |  |  | 27 | 
|Environmental Considerations                                                               |  |  | 27 | 
|Corporate Responsibility                                                                   |  |  | 28 | 
|Employees                                                                                  |  |  | 28 | 
|Foreign Operations                                                                         |  |  | 28 | 
|DIRECTORS AND EXECUTIVE OFFICERS                                                           |  |  | 29 | 
|AUDIT COMMITTEE                                                                            |  |  | 33 | 
|DESCRIPTION OF CAPITAL STRUCTURE                                                           |  |  | 35 | 
|DIVIDENDS                                                                                  |  |  | 37 | 
|MARKET FOR SECURITIES                                                                      |  |  | 37 | 
|RISK FACTORS                                                                               |  |  | 37 | 
|LEGAL PROCEEDINGS AND REGULATORY ACTIONS                                                   |  |  | 48 | 
|INTEREST OF MANAGEMENT AND OTHERS IN MATERIAL TRANSACTIONS                                 |  |  | 48 | 
|MATERIAL CONTRACTS                                                                         |  |  | 48 | 
|INTERESTS OF EXPERTS                                                                       |  |  | 48 | 
|TRANSFER AGENTS AND REGISTRARS                                                             |  |  | 48 | 
|ADDITIONAL INFORMATION                                                                     |  |  | 49 | 
|ABBREVIATIONS AND CONVERSIONS                                                              |  |  | 50 | 
|                                                                                           | 
|APPENDIX A -     Report on Reserves Data by Independent Qualified Reserves Evaluators      |  |  | A1 | 
|APPENDIX B -     Report of Management and Directors on Reserves Data and Other Information |  |  | B1 | 
|APPENDIX C -     Audit Committee Mandate                                                   |  |  | C1 | 



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FORWARD-LOOKING INFORMATION



In this Annual Information Form (AIF), unless otherwise specified or the context otherwise
requires, references to we, us, our, its, the Corporation or Cenovus mean Cenovus Energy Inc., the subsidiaries of, and partnership interests held by, Cenovus Energy Inc. and
its subsidiaries. This AIF contains forward-looking statements and other information (collectively forward-looking information) about
Cenovuss current expectations, estimates and projections, made in light of the Corporations experience and perception of historical trends. This forward-looking information is identified by words such as anticipate,
believe, expect, estimate, plan, forecast or F, future, target, position, project, capacity, could,
should, focus, goal, outlook, proposed, potential, may, strategy, forward, opportunity, schedule, on
track or similar expressions and includes suggestions of future outcomes, including statements about Cenovuss strategy and related milestones and schedules including with respect to the development and growth of our business; projected
future value; projections for 2016 and future years; forecast operating and financial results; planned capital expenditures, including the timing and financing thereof; expected future production, including the timing, stability or growth thereof;
expected reserves and related information, including future net revenue and future development costs; broadening market access; expected capacities, including for projects, transportation and refining; improving cost structures, forecast cost
savings and the sustainability thereof; dividend plans and strategy; anticipated timelines for future regulatory, partner or internal approvals; future impact of regulatory measures; forecast commodity prices and expected impacts to Cenovus; future
use and development of technology, including expected effects on environmental impact; and projected shareholder return. Readers are cautioned not to place undue reliance on forward-looking information as the Corporations 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 in general. The factors or assumptions on which the forward-looking information is based include: assumptions inherent in
the Corporations current guidance, available at cenovus.com; projected capital investment levels, the flexibility of capital spending plans and the associated source of funding; estimates of quantities of oil, bitumen, natural gas and natural
gas liquids (NGLs) from properties and other sources not currently classified as proved; Cenovuss ability to obtain necessary regulatory and partner approvals; the successful and timely implementation of capital projects or stages
thereof; Cenovuss ability to generate sufficient cash flow from operations to meet its current and future obligations; and other risks and uncertainties described from time to time in the filings the Corporation makes with securities
regulatory authorities. The risk factors and uncertainties that could cause Cenovuss actual results to differ materially, include:


volatility of and assumptions regarding oil and gas prices; the effectiveness of the Corporations risk management program, including the impact of derivative financial instruments, the
success of Cenovuss hedging strategies and the sufficiency of the Corporations liquidity position; the accuracy of cost estimates; commodity prices, currency and interest rates; product supply and demand; market competition, including
from alternative energy sources; risks inherent in Cenovuss marketing operations, including credit risks; exposure to counterparties and partners, including ability and willingness of such parties to satisfy contractual obligations in a timely
manner; risks inherent in operation of our crude-by-rail terminal, including health, safety and environmental risks; maintaining desirable ratios of debt (and net debt) to adjusted earnings before interest, taxes, depreciation and amortization as
well as debt (and net debt) to capitalization; the Corporations ability to access various sources of debt and equity capital, generally, and on terms acceptable to the Corporation; Cenovuss ability to finance growth and sustaining
capital expenditures; changes in credit ratings applicable to Cenovus or any of Cenovuss securities; changes to Cenovuss dividend plans or strategy, including the dividend reinvestment plan; accuracy of Cenovuss reserves, resources
and future production expense and future net revenue estimates; the Corporations ability to replace and expand oil and gas reserves; Cenovuss ability to maintain its relationship with its partners and to successfully manage and operate
its integrated business; reliability of the Corporations assets including in order to meet production targets; potential disruption or unexpected technical difficulties in developing new products and manufacturing processes; the occurrence of
unexpected events such as fires, severe weather conditions, explosions, blow-outs, equipment failures, transportation incidents and other accidents or similar events; refining and marketing margins; inflationary pressures on operating costs,
including labour, natural gas and other energy sources used in oil sands processes; potential failure of 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 Cenovuss business; the timing and the costs of
well and pipeline construction; the Corporations ability to secure adequate and cost-effective product transportation including sufficient pipeline, crude-by-rail, marine or alternate transportation, including to address any gaps caused by
constraints in the pipeline system; availability of, and Cenovuss ability






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to attract and retain, critical talent; changes in the regulatory framework in any of the locations in which Cenovus operates, including changes to the regulatory approval process and land-use
designations, royalty, tax, environmental, greenhouse gas (GHG), carbon, climate change and other laws or regulations, or changes to the interpretation of such laws and regulations, as adopted or proposed, the impact thereof and the
costs associated with compliance; the expected impact and timing of various accounting pronouncements, rule changes and standards on Cenovuss business, its financial results and its consolidated financial statements; changes in the general
economic, market and business conditions; the political and economic conditions in the countries in which the Corporation operates; 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 Cenovus. Readers are cautioned that the foregoing lists are not exhaustive and are made as at the date hereof. For a full discussion of Cenovuss material
risk factors, see Risk Factors in this AIF. Readers should also refer to Risk Management in the Corporations current Managements Discussion and Analysis (MD&A) and to the risk factors described in
other documents Cenovus files from time to time with securities regulatory authorities, available at sedar.com, sec.gov and on the Corporations website at cenovus.com. Information on or connected to our website cenovus.com does not form part of this AIF.






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CORPORATE STRUCTURE





Cenovus Energy Inc. was formed under the Canada Business Corporations Act (CBCA) by
amalgamation of 7050372 Canada Inc. (7050372) and Cenovus Energy Inc. (formerly Encana Finance Ltd. and referred to as Subco) on November 30, 2009 pursuant to an arrangement under the CBCA (the Arrangement)
involving, among others, 7050372, Subco and Encana Corporation (Encana). On January 1, 2011, Cenovus amalgamated with its wholly owned subsidiary, Cenovus Marketing Holdings Ltd., through a plan of arrangement approved by the
Alberta Court of Queens Bench. On July 31, 2015 Cenovus amalgamated with its wholly owned subsidiary,


9281584 Canada Limited (formerly 1528419 Alberta Ltd.), by way of a vertical short-form amalgamation. Pursuant to a special resolution of the shareholders of the Corporation passed at the annual and special meeting of the Corporations shareholders on
April 29, 2015, the Corporations articles were amended to provide that the aggregate number of preferred shares issued by the Corporation may not exceed 20 percent of the aggregate number of common shares then outstanding. The Corporations head and registered office is located at 2600, 500 Centre Street S.E., Calgary, Alberta, Canada T2G 1A6.






INTERCORPORATE RELATIONSHIPS

Cenovuss material subsidiaries and partnerships as at December 31, 2015 are as follows:



|                                       |  |                     |  |                                                                       |  |  |         
|-------------------------------------- |  | ------------------- |  | --------------------------------------------------------------------- |  |  | --------
|Subsidiaries & Partnerships            |  | Percentage
Owned(1) |  | Jurisdiction of Incorporation,
Continuance, Formation or
Organization
|Cenovus FCCL Ltd.                      |  |                     |  | 100                                                                   |  |  | Alberta 
|Cenovus Energy Marketing Services Ltd. |  |                     |  | 100                                                                   |  |  | Alberta 
|Cenovus US Holdings Inc.               |  |                     |  | 100                                                                   |  |  | Delaware
|FCCL Partnership (FCCL) (2)          |  |                     |  | 50                                                                    |  |  | Alberta 
|WRB Refining LP (WRB) (3)            |  |                     |  | 50                                                                    |  |  | Delaware



|(1) | Reflects all voting securities of all subsidiaries and partnerships beneficially owned, or controlled, or directed; directly or indirectly by Cenovus.
|--- | ------------------------------------------------------------------------------------------------------------------------------------------------------

|(2) | Cenovus interest held through Cenovus FCCL Ltd., the operator and managing partner of FCCL.
|--- | -------------------------------------------------------------------------------------------

|(3) | Cenovus interest held through Cenovus American Holdings Ltd. and Cenovus US Holdings Inc.
|--- | -----------------------------------------------------------------------------------------

The Corporations remaining subsidiaries and partnerships each account for (i) less than 10 percent of the Corporations consolidated
assets as at December 31, 2015 and (ii) less than 10 percent of the Corporations consolidated revenues for the year ended December 31, 2015. In aggregate, Cenovuss unidentified subsidiaries and partnerships did not exceed
20 percent of the Corporations total consolidated assets or total consolidated revenues as at and for the year ended December 31, 2015.



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GENERAL DEVELOPMENT OF THE BUSINESS



OVERVIEW



Cenovus is a Canadian integrated oil company headquartered in Calgary, Alberta. The Corporation began
independent operations on December 1, 2009 following the split of Encana into two independent publicly traded energy companies. Cenovus is in the business of developing, producing and marketing crude oil, natural gas liquids (NGLs)
and natural gas in Canada with marketing activities and refining operations in the United States (U.S.).


All of Cenovuss oil and natural gas reserves and production are located in Canada, within the
provinces of Alberta and Saskatchewan. As at December 31, 2015, Cenovus had a land base of approximately 5.6 million net acres. The estimated proved reserves life index based on working interest production as at December 31, 2015 was
approximately 25 years.






BUSINESS
SEGMENTS

The Corporations reportable segments are as follows:



|                           |  |                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                         |  | 
|-------------------------- |  | ----------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------- |  | 
|                           |  |                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                        
|Oil Sands                  |  | Includes the development and production of bitumen and natural gas in northeast Alberta. Cenovuss bitumen assets include Foster Creek, Christina Lake and Narrows
Lake as well as projects in the early stages of development, such as Grand Rapids and Telephone Lake. Certain of Cenovuss operated oil sands properties, notably Foster Creek, Christina Lake and Narrows Lake, are jointly owned with
ConocoPhillips, an unrelated U.S. public company.                                                                                                                                                            |  | 
|                           |  |                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                        
|Conventional               |  | Includes the development and production of conventional crude oil (1), NGLs and natural gas (2) in Alberta and Saskatchewan, including the heavy oil (3) assets at Pelican Lake, the carbon dioxide (CO2) enhanced oil recovery (EOR) project at Weyburn and emerging tight oil opportunities.                                                                                                                                                                                                                                                                                                                      |  | 
|                           |  |                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                        
|Refining and Marketing     |  | Includes transporting, selling and refining crude oil into petroleum and chemical products. Cenovus jointly owns two refineries in the U.S. with the operator Phillips 66,
an unrelated U.S. public company. In addition, Cenovus owns and operates a crude-by-rail terminal in Alberta. This segment coordinates Cenovuss marketing and transportation initiatives to optimize product mix, delivery points, transportation
commitments and customer diversification.                                                                                                                                                 |  | 
|                           |  |                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                        
|Corporate and Eliminations |  | 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. |  | 



|(1) | For the purpose of this AIF, references to crude oil means heavy crude oil and light crude oil and medium crude oil
combined as those terms are defined in National Instrument 51-101 Standards of Disclosure for Oil and Gas Activities.
|--- | -----------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------

|(2) | For the purpose of this AIF, references to natural gas means conventional natural gas as defined in National Instrument 51-101
Standards of Disclosure for Oil and Gas Activities.
|--- | --------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------

|(3) | For the purpose of this AIF, references to heavy oil means heavy crude oil as defined in National Instrument 51-101 Standards of
Disclosure for Oil and Gas Activities.
|--- | ---------------------------------------------------------------------------------------------------------------------------------------------------------------------------



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THREE YEAR HISTORY



The following describes significant events that have influenced the development of the business during the
last three financial years and year to date in 2016: 2013  ●

Oil Sands regulatory applications. In the first quarter, Cenovus submitted regulatory applications and environmental
impact assessments (EIAs) for Christina Lake phase H and Foster Creek phase J, with approved gross production capacity of 50,000 barrels per day from each phase.  ●

First production at Christina Lake phase E. In the third quarter, phase E of Christina Lake achieved first production,
with gross production capacity of 40,000 barrels per day.  ●

Regulatory approval for Christina Lake optimization. In the third quarter, Cenovus received regulatory approval for the
optimization program at Christina Lake phases C, D and E, with approved incremental gross production capacity of 22,000 barrels per day.  ●

Construction at Narrows Lake phase A initiated. In the third quarter, construction of the Narrows Lake phase A plant was
initiated with expected gross production capacity of 45,000 barrels per day.  ●

Public debt offering completed. In the third quarter, Cenovus completed a public offering in the U.S. of senior unsecured
notes of US$450 million with a coupon rate of 3.8 percent due September 15, 2023 and US$350 million senior unsecured notes with a coupon rate of 5.2 percent due September 15, 2043, for an aggregate amount of US$800 million. The net
proceeds of the offering were used to partially fund the early redemption of the Corporations US$800 million senior unsecured notes due September 2014.  ●

Divestiture of non-core asset. In the third quarter, Cenovus sold its Lower Shaunavon asset to an unrelated third party
for net proceeds of approximately $241 million.  ●

Increased rail takeaway capacity. In the fourth quarter, Cenovus increased its rail takeaway capacity to 10,000 barrels
per day.


●

Telephone Lake dewatering pilot completed. In the fourth quarter, the Telephone Lake dewatering pilot was successfully
completed. Cenovus effectively displaced water with compressed air, removing approximately 70 percent of below-ground non-potable top water.  ●

Receipt of Partnership contribution receivable. In the fourth quarter, Cenovus received US$1.4 billion from
ConocoPhillips, the Corporations partner in FCCL, representing the remaining principal and interest due under the Partnership Contribution Receivable through the Corporations interest in FCCL.  ●

Foster Creek optimization update. Timing of optimization work for Foster Creek phases F, G and H was reassessed as part of
Cenovuss long-term reservoir management plan. Expected total gross production capacity from these three phases, including optimization, remained up to 125,000 barrels per day. 2014  ●

Regulatory approval received for Grand Rapids. In the first quarter, Cenovus received regulatory approval for its Grand
Rapids project with an approved gross production capacity of up to 180,000 barrels per day.  ●

Prepayment of Partnership contribution payable.In the first quarter, Cenovus prepaid its US$2.7 billion partnership
contribution payable to WRB Refining LP, of which Cenovus is a 50 percent owner. This resulted in a net cash payment of approximately US$1.35 billion from Cenovus.  ●

Divestiture of non-core assets. In the second quarter, Cenovus completed the sale of certain of its Bakken assets to an
unrelated third party for net proceeds of $35 million. In the third quarter, Cenovus completed the sale of certain Wainwright properties to an unrelated third party for net proceeds of $234 million.  ●

First production from Foster Creek phase F. In the third quarter, Foster Creek phase F achieved first oil production.
Phase F is expected to add 30,000 barrels per day of gross production capacity.  ●

Increased rail takeaway capacity. In the fourth quarter, Cenovus increased its rail takeaway capacity to 30,000 barrels
per day.  ●

Regulatory approval received for Foster Creek phase J.In the fourth quarter, Cenovus received regulatory approval
for Foster Creek phase J with approved gross production capacity of 50,000 barrels per day.  ●

Regulatory approval received for Telephone Lake. In the fourth quarter, Cenovus received regulatory approval for its 100
percent owned Telephone Lake thermal oil sands project with initial production capacity of 90,000 barrels per day. The project is expected to have gross production capacity in excess of 300,000 barrels per day.






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2015  ●

Reduced capital spending. Due to the low commodity price environment, Cenovus reduced its 2015 capital spending, including
suspension of the bulk of its conventional drilling program in southern Alberta and Saskatchewan and deferral of further construction work on Foster Creek phase H, Christina Lake phase G and Narrows Lake phase A.  ●

Common share issuance. In the first quarter, Cenovus issued 67.5 million common shares at a price of $22.25 per share
for net proceeds of approximately $1.4 billion, a portion of which contributed to funding the Corporations capital investment in 2015.  ●

Permit approval received at Wood River Refinery. In the first quarter, Cenovus received permit approval for the Wood River
Refinery debottlenecking project. Start-up of the project is anticipated in the third quarter of 2016.  ●

Sale of royalty interest and mineral fee title lands business.In the third quarter, Cenovus sold its wholly owned
subsidiary, Heritage Royalty Limited Partnership (HRP), which held approximately 4.8 million gross acres of royalty interest and mineral fee title lands in Alberta, Saskatchewan and Manitoba along with a Gross Overriding Royalty
(GORR) on Cenovuss Pelican Lake heavy oil property in northern Alberta and its EOR project located near Weyburn, Saskatchewan, to an unrelated third party for gross cash proceeds of $3.3 billion, a portion of which was used to
help fund the Corporations capital investment in 2015. Associated third-party royalty interest volumes prior to the divestiture were approximately 6,580 barrels of oil equivalent per day.


●

Rail terminal purchase. In the third quarter, Cenovus purchased a crude-by-rail terminal located in Bruderheim, Alberta,
for $75 million, plus closing adjustments.  ●

Cost reductions. Cenovus achieved total 2015 cost savings of approximately $540 million, including operating, capital and
general and administrative costs. The cost reductions apply across the Corporation and include savings related to improved drilling efficiency, optimized scheduling and prioritization of repair and maintenance activities, lower chemical costs and
improved oil sands waste disposal and handling processes. Additional savings resulted from the deferral of certain capital expenditure projects.  ●

Workforce reductions. Cenovus reduced its workforce by approximately 1,500 positions, including full- and part-time
employees as well as contract workers. As at December 31, 2015 the Company had approximately 24 percent fewer employee and contractor workforce positions than it had at December 31, 2014.  ●

Completed Christina Lake optimization. In the fourth quarter, the Christina Lake optimization program began steam
circulation, and is expected to add up to 22,000 barrels per day gross incremental production capacity and ramp up over the next 12 months, taking total gross production capacity to 160,000 barrels per day.  ●

Regulatory approval received for Christina Lake phase H.In the fourth quarter, Cenovus received regulatory approval for
Christina Lake phase H with approved gross production capacity of 50,000 barrels per day. 2016  ●

Capital spending. Cenovus expects that the commodity price environment will continue to influence the general development
of its business in 2016. The Corporation will continue to assess its plans in light of the commodity price environment and other relevant factors and will make adjustments to its capital spending and other business activities as appropriate.






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DESCRIPTION OF THE BUSINESS



OIL SANDS



Oil Sands includes Cenovuss bitumen assets at Foster Creek, Christina Lake and Narrows Lake as well
as emerging projects such as Grand Rapids and Telephone Lake. The Corporations Athabasca natural gas assets also form part of this segment. Joint Operations Foster Creek, Christina Lake and Narrows Lake are jointly owned through FCCL with ConocoPhillips, an
unrelated U.S. public company. Cenovus FCCL Ltd., Cenovuss wholly owned subsidiary, is the operator, managing partner and owner of 50 percent of FCCL. FCCL has a management committee, which is composed of three Cenovus representatives and
three ConocoPhillips representatives, with each company holding equal voting rights.


Development Approach Cenovus applies a manufacturing-like, phased approach to developing our oil sands assets. This approach incorporates learnings from previous phases into
future growth plans, helping the Corporation to minimize costs. New Technology Focused technology development, research activities and understanding environmental impact play increasingly larger roles in all aspects of Cenovuss
business. Cenovus continues to seek new technologies and is actively developing its own technologies with the goal of increasing recoveries from its reservoirs, while reducing the amount of water, natural gas and electricity consumed in its
operations, potentially reducing costs and minimizing the Corporations environmental footprint.






Landholdings

As at December 31, 2015, Cenovus held bitumen rights of approximately 1.8 million gross acres (1.5 million net acres) within the
Athabasca and Cold Lake areas, as well as the exclusive rights to lease an additional 478,000 net acres on Cenovuss behalf and/or its assignees behalf on the Cold Lake Air Weapons Range.

The following table summarizes Cenovuss Oil Sands landholdings as at December 31, 2015, all of which are located within the Province of
Alberta:



|                     |  |                   |     |  |                     |  |     |               |  |  |                               |  |  |       |       |  |     |  |       |  |  |  |       |  |  |  |      | 
|-------------------- |  | ----------------- | --- |  | ------------------- |  | --- | ------------- |  |  | ----------------------------- |  |  | ----- | ----- |  | --- |  | ----- |  |  |  | ----- |  |  |  | ---- | 
|                     |  | Developed
Acreage |     |  | Undeveloped
Acreage |  |     | Total
Acreage |  |  | AverageWorking    Interest(1) | 
|                     |  |                   |     | 
|(thousands of acres) |  | Gross             |     |  | Net                 |  |     | Gross         |  |  | Net                           |  |  | Gross |       |  | Net |  |      
|                     | 
|Foster Creek         |  |                   | 16  |  |                     |  | 8   |               |  |  | 114                           |  |  |       | 57    |  |     |  | 130   |  |  |  | 65    |  |  |  | 50%  | 
|Christina Lake       |  |                   | 9   |  |                     |  | 4   |               |  |  | 49                            |  |  |       | 24    |  |     |  | 58    |  |  |  | 28    |  |  |  | 50%  | 
|Narrows Lake         |  |                   | -   |  |                     |  | -   |               |  |  | 27                            |  |  |       | 13    |  |     |  | 27    |  |  |  | 13    |  |  |  | 50%  | 
|Grand Rapids (2)     |  |                   | -   |  |                     |  | -   |               |  |  | 61                            |  |  |       | 61    |  |     |  | 61    |  |  |  | 61    |  |  |  | 100% | 
|Telephone Lake       |  |                   | 16  |  |                     |  | 16  |               |  |  | 142                           |  |  |       | 142   |  |     |  | 158   |  |  |  | 158   |  |  |  | 100% | 
|Athabasca            |  |                   | 383 |  |                     |  | 345 |               |  |  | 448                           |  |  |       | 380   |  |     |  | 831   |  |  |  | 725   |  |  |  | 87%  | 
|Other                |  |                   | 29  |  |                     |  | 11  |               |  |  | 1,459                         |  |  |       | 1,173 |  |     |  | 1,488 |  |  |  | 1,184 |  |  |  | 79%  | 
|                     | 
|Total                |  |                   | 453 |  |                     |  | 384 |               |  |  | 2,300                         |  |  |       | 1,850 |  |     |  | 2,753 |  |  |  | 2,234 |  |  |  | 81%  | 
|                     | 



|(1) | Percentages as represented in the above table cannot be calculated based on acreage shown due to rounding.
|--- | ----------------------------------------------------------------------------------------------------------

|(2) | Overlapping landholdings between Grand Rapids and Pelican Lake (included in the Conventional segment) have been allocated to Grand Rapids based on the
projects approved development area.
|--- | -------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------

Production

The following table summarizes Cenovuss share of daily average production for the periods indicated:



|                 |  |                  |         |  |                      |  |         |                          |  |  |      |  |  |      |    |  |      |  |         |  |  |  |         | 
|---------------- |  | ---------------- | ------- |  | -------------------- |  | ------- | ------------------------ |  |  | ---- |  |  | ---- | -- |  | ---- |  | ------- |  |  |  | ------- | 
|                 |  | Bitumen
(bbls/d) |         |  | Natural Gas
(MMcf/d) |  |         | Total Production
(BOE/d) | 
|                 |  |                  |         | 
|(annual average) |  | 2015             |         |  | 2014                 |  |         | 2015                     |  |  | 2014 |  |  | 2015 |    |  | 2014 | 
|                 | 
|Foster Creek     |  |                  | 65,345  |  |                      |  | 59,172  |                          |  |  | -    |  |  |      | -  |  |      |  | 65,345  |  |  |  | 59,172  | 
|Christina Lake   |  |                  | 74,975  |  |                      |  | 69,023  |                          |  |  | -    |  |  |      | -  |  |      |  | 74,975  |  |  |  | 69,023  | 
|Athabasca (1)    |  |                  | -       |  |                      |  | -       |                          |  |  | 19   |  |  |      | 22 |  |      |  | 3,167   |  |  |  | 3,667   | 
|                 | 
|Total            |  |                  | 140,320 |  |                      |  | 128,195 |                          |  |  | 19   |  |  |      | 22 |  |      |  | 143,487 |  |  |  | 131,862 | 
|                 | 



|(1) | Net of internal usage of natural gas used at Foster Creek to produce steam.
|--- | ---------------------------------------------------------------------------



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##### Table of Contents

Producing Wells

The following table summarizes Cenovuss interests in producing wells as at December 31, 2015. These figures exclude wells which were capable of
producing, but that were not producing as at December 31, 2015:



|                  |  |                         |     |  |                     |  |     |                       |  |  |     |  |  |       |     |  |     |  |     |  |  |  |     | 
|----------------- |  | ----------------------- | --- |  | ------------------- |  | --- | --------------------- |  |  | --- |  |  | ----- | --- |  | --- |  | --- |  |  |  | --- | 
|                  |  | Producing
Bitumen Wells |     |  | Producing
Gas Wells |  |     | Total
Producing Wells | 
|                  |  |                         |    
|(number of wells) |  | Gross                   |     |  | Net                 |  |     | Gross                 |  |  | Net |  |  | Gross |     |  | Net | 
|                  | 
|Foster Creek      |  |                         | 255 |  |                     |  | 128 |                       |  |  | -   |  |  |       | -   |  |     |  | 255 |  |  |  | 128 | 
|Christina Lake    |  |                         | 151 |  |                     |  | 76  |                       |  |  | -   |  |  |       | -   |  |     |  | 151 |  |  |  | 76  | 
|Grand Rapids      |  |                         | 2   |  |                     |  | 2   |                       |  |  | -   |  |  |       | -   |  |     |  | 2   |  |  |  | 2   | 
|Athabasca         |  |                         | -   |  |                     |  | -   |                       |  |  | 316 |  |  |       | 303 |  |     |  | 316 |  |  |  | 303 | 
|Other             |  |                         | 3   |  |                     |  | 3   |                       |  |  | -   |  |  |       | -   |  |     |  | 3   |  |  |  | 3   | 
|                  | 
|Total             |  |                         | 411 |  |                     |  | 209 |                       |  |  | 316 |  |  |       | 303 |  |     |  | 727 |  |  |  | 512 | 
|                  | 



Foster Creek Cenovus has a 50 percent working interest in Foster Creek, Cenovuss first commercial steam-assisted gravity drainage (SAGD) operation.
It is located on the Cold Lake Air Weapons Range, an active military base, and has a reservoir depth up to 500 meters below the surface. Foster Creek produces from the McMurray formation using SAGD technology. The Corporation holds surface access rights from the governments of Canada and Alberta and bitumen rights from the Government of Alberta for exploration,
development and transportation from areas within the Cold Lake Air Weapons Range. In addition, Cenovus holds exclusive rights to lease several hundred thousand acres of bitumen rights in other areas on the Cold Lake Air Weapons Range on the
Corporations and/or its assignees behalf. Production from phases A through F at Foster Creek averaged 65,345 barrels per day in 2015.
Plant construction at phase G is nearing completion with first production anticipated in the third quarter of 2016. Phase G is expected to add additional production capacity of 30,000 gross barrels per day. Expansion work on phase H has
been deferred in response to the current low commodity price environment. Cenovus operates an 80 megawatt natural
gas-fired cogeneration facility in conjunction with the SAGD operation at Foster Creek. The steam and power generated by the facility is presently being used within the SAGD operation and any excess power
generated is being sold into the Alberta Power Pool. Christina Lake Cenovus has a 50 percent working interest in Christina Lake. Christina Lake is located approximately 120 kilometers south of Fort McMurray and has a
reservoir depth up to 350 meters below the surface. Christina Lake produces from the McMurray formation using SAGD technology. Production from
phases A through E at Christina Lake averaged 74,975 barrels per day in 2015. Optimization was completed in the fourth quarter of 2015, and is expected to add approximately 22,000 barrels per day gross production once fully ramped up in 12
months. Expansion work at phase F


(including cogeneration) is nearing completion, with first oil expected in the third quarter of 2016. Phase F is anticipated to add production capacity of 50,000 gross barrels per day. Expansion
work on phase G has been deferred in response to the current low commodity price environment. Cenovus received regulatory approval for phase H in the
fourth quarter of 2015, a 50,000 gross barrel per day phase. Several innovations to SAGD technology have been undertaken at Christina Lake over the
past several years. One major innovation is solvent aided process technology (SAP). SAP is a new enhancement to SAGD expected to reduce environmental impact. SAP involves injecting a solvent together with the steam. SAP is expected to
require less steam, which will reduce greenhouse gas emissions and water usage per barrel of oil and increase oil production and oil recovery rates. Various embodiments of SAP related technology are currently being piloted at Christina Lake. Based
on results from the various SAP related pilots, Cenovus plans to commercialize the SAP technology with phase A of its Narrows Lake project. Narrows Lake Cenovus has a 50 percent working interest in Narrows Lake. Narrows Lake is located adjacent to
Christina Lake and has a reservoir depth up to 375 meters below the surface. Narrows Lake will be Cenovuss first commercial application of SAP in conjunction with SAGD. The solvent to be used at Narrows Lake is expected to be butane, which is
already present in the reservoir in small amounts. In 2012, Cenovus received regulatory approval for phases A, B and C for 130,000 gross barrels per
day of production capacity and partner approval for phase A, a 45,000 gross barrels per day phase. Initial work on phase A commenced in the third quarter of 2013. Due to the current low commodity price environment, Cenovus has suspended new
construction spending on phase A. The future development of Narrows Lake should benefit from the existing infrastructure and resources at Christina Lake, which is expected to lower overall costs.






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##### Table of Contents

Telephone Lake Cenovuss 100 percent-owned Telephone Lake property is located in the Borealis Region in northeastern Alberta, approximately 90 kilometers northeast
of Fort McMurray. In 2015, Cenovus continued to advance development plans for Telephone Lake after receiving approval from the Alberta Energy
Regulator (AER) in late 2014 for an initial SAGD project with initial production capacity of 90,000 barrels per day. Telephone Lake is a
unique oil sands project because directly above the oil there is a layer of groundwater that is not suitable for human consumption without treatment (referred to as top water). The top water layer is between 150 and 175 meters below the surface. In
2013, Cenovus completed a dewatering pilot project at Telephone Lake displacing approximately 70 percent of the top water. Although dewatering is not essential to the development of Telephone Lake, Cenovus believes this method will make oil recovery
more efficient and help reduce its impact on the environment by reducing the steam to oil ratio. Grand Rapids Cenovuss 100 percent owned Grand Rapids property is located in the Greater Pelican Region, about 300 kilometers north of
Edmonton, Alberta. The project is adjacent to the Corporations Pelican Lake heavy oil operations and existing facilities. In December 2010, the
Corporation drilled its first pilot SAGD well pair at Grand Rapids. A second well pair was drilled in early 2012 and a third well pair commenced steam circulation in 2015. In March 2014, Cenovus received regulatory approval from the AER for its Grand Rapids SAGD project with total production capacity of 180,000 barrels per
day. As of February 2016, further activity in respect of the SAGD pilot at Grand Rapids has been deferred in response to the current low commodity price environment. Other Emerging Assets Cenovus has a number of emerging assets, including the Steepbank and East McMurray properties located in the Borealis Region in Alberta, which it
continues to evaluate, manage and work to decrease risk associated with potential future development of these assets. Cenovus continues to believe in the long-term potential of its emerging projects as a future resource base. Cenovus completed a pilot program using a helicopter and an experimental lightweight drilling rig, referred to as SkyStratTM, to drill stratigraphic test wells. The SkyStratTM drilling rig is a rig that was developed to improve stratigraphic drilling programs in the oil
sands. Transporting the rig by helicopter allows Cenovus to access remote exploratory drilling locations year-round and eliminates the need for temporary roads, significantly reducing the surface footprint and potentially reducing water use for the
drilling operations by over 50 percent. The Corporation


completed construction on a second SkyStratTM drilling rig in the fourth quarter of 2014. A total of seven stratigraphic wells were drilled
using SkyStratTM drilling technology in 2015. Athabasca Gas Cenovus produces natural gas from the Cold Lake Air Weapons Range and several surrounding landholdings located in northeastern
Alberta. Cenovus holds surface access and natural gas rights for exploration, development and transportation from areas within the Cold Lake Air Weapons Range that were granted by the governments of Canada and Alberta. The majority of the
Corporations natural gas production in the area is processed through compression facilities, wholly-owned and operated by Cenovus. Natural gas
production continues to be impacted by the AERs decisions made between 2003 and 2015 to shut-in natural gas production from the McMurray, Wabiskaw and Clearwater formations that may put the recovery of
bitumen resources in the area at risk. This resulted in a decrease in the Corporations annualized natural gas production of approximately 14 million cubic feet per day in 2015
(2014 - 15 million cubic feet per day). The Alberta Department of Energy has provided a ten year royalty credit which can equal up to 50 percent of lost cash flow to help offset the impact of
the shut-in wells. This royalty credit fluctuates with the price of natural gas. Capital Investment In 2015, the Corporations Oil Sands capital investment was $1.2 billion, primarily related to the expansions at Foster Creek and Christina
Lake. The production capacity for these projects is expected to increase to approximately 390,000 gross barrels per day with completion of Foster Creek phase G and Christina Lake phase F. Ramp up to total production for these phases is expected
to extend into 2017.  ●

Capital at Foster Creek was focused on sustaining capital related to existing production, expansion phase G and the drilling of stratigraphic test wells to
determine pad placement for sustaining well pads and near-term phase expansions.  ●

Capital at Christina Lake was focused on sustaining capital related to existing production, expansion phases F and G, and the optimization project. The
optimization project has been completed and is expected to add approximately 22,000 barrels per day of gross production capacity, with incremental oil production expected to ramp up over a period of twelve months.  ●

Capital at Narrows Lake was focused on detailed engineering and construction wind-down.  ●

Capital at Telephone Lake was focused on front end engineering work on the central processing facility and preliminary infrastructure development.






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##### Table of Contents

●

Capital at Grand Rapids was focused on continued operation of the SAGD pilot project and a third well pair commenced steam circulation. Due to the lower crude oil price environment, 2016 capital spending is planned to be focused on


completion of the Foster Creek phase G and Christina Lake phase F (including cogeneration) expansions. Funding is also planned to maintain current production levels from existing oil sands phases
as well as meeting all maintenance, safety, regulatory and contractual obligations.






CONVENTIONAL



Conventional operations include the development and production of conventional crude oil, NGLs and natural
gas from assets in Alberta and Saskatchewan, including the heavy oil assets at Pelican Lake, the CO2 EOR project near Weyburn, Saskatchewan and emerging tight oil assets in Alberta. The
established assets in this segment are strategically important due to their long life reserves, stable operations and diversity of crude oil produced. In July 2015, Cenovus sold HRP, the holder of Cenovuss royalty interest and mineral fee title lands business in Alberta, Saskatchewan and Manitoba
to an unrelated third party for gross cash proceeds of approximately $3.3 billion. Production from fee lands had comprised approximately 50 percent of the Corporations total conventional production in 2014. Associated third-party royalty
interest


volumes prior to the divestiture were approximately 6,580 barrels of oil equivalent per day. Where Cenovus had current working interest production on these fee lands, the Corporation entered into
lease agreements with HRP. A GORR on Cenovuss production from its Pelican Lake and Weyburn assets was included as part of the sale. Cenovus also retained an option to acquire from HRP leases at pre-determined rates and lease terms for up to
five years on more than 800,000 acres in zones of the fee lands currently being developed by Cenovus, with an option for a further five years to select leases on half of the remaining undeveloped acreage. Conventional operations also include leases of Crown lands primarily in the Suffield area and in Saskatchewan.






Landholdings



|                     |  |                   |       |  |                    |  |       |               |  |  |                            |  |  |       |     |  |     |  |       |  |  |  |       |  |  |  |     | 
|-------------------- |  | ----------------- | ----- |  | ------------------ |  | ----- | ------------- |  |  | -------------------------- |  |  | ----- | --- |  | --- |  | ----- |  |  |  | ----- |  |  |  | --- | 
|                     |  | Developed Acreage |       |  | UndevelopedAcreage |  |       | Total
Acreage |  |  | AverageWorking
Interest(1) | 
|                     |  |                   |       | 
|(thousands of acres) |  | Gross             |       |  | Net                |  |       | Gross         |  |  | Net                        |  |  | Gross |     |  | Net |  |      
|                     | 
|Alberta              |  |                   |       |  |                    |  |       |               |  |  |                            |  |  |       |     |  |     |  |       |  |  |  |       |  |  |  |     | 
|Grassland (2)        |  |                   | 959   |  |                    |  | 920   |               |  |  | 32                         |  |  |       | 27  |  |     |  | 991   |  |  |  | 947   |  |  |  | 96% | 
|Suffield             |  |                   | 935   |  |                    |  | 923   |               |  |  | 89                         |  |  |       | 89  |  |     |  | 1,024 |  |  |  | 1,012 |  |  |  | 99% | 
|Langevin (3)         |  |                   | 669   |  |                    |  | 651   |               |  |  | 63                         |  |  |       | 55  |  |     |  | 732   |  |  |  | 706   |  |  |  | 96% | 
|Pelican Lake (4)     |  |                   | 95    |  |                    |  | 94    |               |  |  | 254                        |  |  |       | 241 |  |     |  | 349   |  |  |  | 335   |  |  |  | 96% | 
|Wainwright           |  |                   | 49    |  |                    |  | 29    |               |  |  | 13                         |  |  |       | 9   |  |     |  | 62    |  |  |  | 38    |  |  |  | 63% | 
|Other                |  |                   | 24    |  |                    |  | 15    |               |  |  | 149                        |  |  |       | 135 |  |     |  | 173   |  |  |  | 150   |  |  |  | 87% | 
|Saskatchewan         |  |                   |       |  |                    |  |       |               |  |  |                            |  |  |       |     |  |     |  |       |  |  |  |       |  |  |  |     | 
|Weyburn              |  |                   | 48    |  |                    |  | 36    |               |  |  | 51                         |  |  |       | 41  |  |     |  | 99    |  |  |  | 77    |  |  |  | 78% | 
|Bakken               |  |                   | 4     |  |                    |  | 4     |               |  |  | 48                         |  |  |       | 48  |  |     |  | 52    |  |  |  | 52    |  |  |  | 98% | 
|                     | 
|Total                |  |                   | 2,783 |  |                    |  | 2,672 |               |  |  | 699                        |  |  |       | 645 |  |     |  | 3,482 |  |  |  | 3,317 |  |  |  | 95% | 
|                     | 



|(1) | Percentages as represented in the above table cannot be calculated based on acreage shown due to rounding.
|--- | ----------------------------------------------------------------------------------------------------------

|(2) | Grassland is located in the Drumheller and Brooks areas.
|--- | --------------------------------------------------------

|(3) | Langevin is located northwest of Medicine Hat.
|--- | ----------------------------------------------

|(4) | Overlapping landholdings between Grand Rapids (included in the Oil Sands segment) and Pelican Lake have been allocated to Grand Rapids based on the
projects approved development area.
|--- | ----------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------



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##### Table of Contents

Production

The following table summarizes Cenovuss share of daily average production (1) for the periods
indicated:



|                 |  |                             |        |  |                      |  |        |                          |  |  |      |  |  |      |     |  |      |  |         |  |  |  |         | 
|---------------- |  | --------------------------- | ------ |  | -------------------- |  | ------ | ------------------------ |  |  | ---- |  |  | ---- | --- |  | ---- |  | ------- |  |  |  | ------- | 
|                 |  | Crude Oil and NGLs (bbls/d) |        |  | Natural Gas
(MMcf/d) |  |        | Total Production (BOE/d) | 
|                 |  |                             |        | 
|(annual average) |  | 2015                        |        |  | 2014                 |  |        | 2015                     |  |  | 2014 |  |  | 2015 |     |  | 2014 | 
|                 | 
|Alberta          |  |                             |        |  |                      |  |        |                          |  |  |      |  |  |      |     |  |      |  |         |  |  |  |         | 
|Grassland (2)    |  |                             | 7,248  |  |                      |  | 8,923  |                          |  |  | 212  |  |  |      | 232 |  |      |  | 42,581  |  |  |  | 47,590  | 
|Suffield         |  |                             | 8,854  |  |                      |  | 10,010 |                          |  |  | 125  |  |  |      | 135 |  |      |  | 29,687  |  |  |  | 32,510  | 
|Langevin (3)     |  |                             | 8,025  |  |                      |  | 9,368  |                          |  |  | 84   |  |  |      | 96  |  |      |  | 22,025  |  |  |  | 25,368  | 
|Pelican Lake     |  |                             | 24,421 |  |                      |  | 24,924 |                          |  |  | -    |  |  |      | -   |  |      |  | 24,421  |  |  |  | 24,924  | 
|Wainwright (4)   |  |                             | 1,638  |  |                      |  | 4,687  |                          |  |  | 1    |  |  |      | 2   |  |      |  | 1,805   |  |  |  | 5,020   | 
|Other            |  |                             | 10     |  |                      |  | 8      |                          |  |  | -    |  |  |      | -   |  |      |  | 10      |  |  |  | 8       | 
|Saskatchewan     |  |                             |        |  |                      |  |        |                          |  |  |      |  |  |      |     |  |      |  |         |  |  |  |         | 
|Weyburn          |  |                             | 15,732 |  |                      |  | 16,196 |                          |  |  | -    |  |  |      | -   |  |      |  | 15,732  |  |  |  | 16,196  | 
|Bakken (4)       |  |                             | 699    |  |                      |  | 1,182  |                          |  |  | -    |  |  |      | 1   |  |      |  | 699     |  |  |  | 1,349   | 
|Other            |  |                             | -      |  |                      |  | -      |                          |  |  | -    |  |  |      | -   |  |      |  | -       |  |  |  | -       | 
|                 | 
|Total            |  |                             | 66,627 |  |                      |  | 75,298 |                          |  |  | 422  |  |  |      | 466 |  |      |  | 136,960 |  |  |  | 152,965 | 
|                 | 



|(1) | Includes production from mineral fee title lands in which Cenovus has a working interest and mineral fee title lands in which Cenovus has retained a
royalty interest. In the third quarter of 2015, Cenovus sold those royalty interests.
|--- | ------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------

|(2) | Grassland is located in the Drumheller and Brooks areas.
|--- | --------------------------------------------------------

|(3) | Langevin is located northwest of Medicine Hat.
|--- | ----------------------------------------------

|(4) | Cenovus sold certain interests in its Bakken and Wainwright crude oil assets in the second and third quarter of 2014, respectively. Cenovus retained
royalty interests on mineral fee title lands in these areas. In the third quarter of 2015, Cenovus sold those royalty interests.
|--- | -------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------

Producing Wells

The following table summarizes Cenovuss interests in producing wells (1) as at
December 31, 2015. These figures exclude wells which were capable of producing, but that were not producing, as at December 31, 2015:



|                  |  |                     |       |  |                     |  |       |                       |  |  |        |  |  |       |        |  |     |  |        |  |  |  |        | 
|----------------- |  | ------------------- | ----- |  | ------------------- |  | ----- | --------------------- |  |  | ------ |  |  | ----- | ------ |  | --- |  | ------ |  |  |  | ------ | 
|                  |  | Producing Oil Wells |       |  | Producing Gas Wells |  |       | Total
Producing Wells | 
|                  |  |                     |       | 
|(number of wells) |  | Gross               |       |  | Net                 |  |       | Gross                 |  |  | Net    |  |  | Gross |        |  | Net | 
|                  | 
|Alberta           |  |                     |       |  |                     |  |       |                       |  |  |        |  |  |       |        |  |     |  |        |  |  |  |        | 
|Grassland (2)     |  |                     | 398   |  |                     |  | 391   |                       |  |  | 8,804  |  |  |       | 8,660  |  |     |  | 9,202  |  |  |  | 9,051  | 
|Suffield          |  |                     | 739   |  |                     |  | 739   |                       |  |  | 10,676 |  |  |       | 10,658 |  |     |  | 11,415 |  |  |  | 11,397 | 
|Langevin (3)      |  |                     | 300   |  |                     |  | 298   |                       |  |  | 4,752  |  |  |       | 4,740  |  |     |  | 5,052  |  |  |  | 5,038  | 
|Pelican Lake      |  |                     | 587   |  |                     |  | 587   |                       |  |  | 1      |  |  |       | 1      |  |     |  | 588    |  |  |  | 588    | 
|Wainwright        |  |                     | 57    |  |                     |  | 52    |                       |  |  | 10     |  |  |       | 2      |  |     |  | 67     |  |  |  | 54     | 
|Other             |  |                     | 10    |  |                     |  | 5     |                       |  |  | 2      |  |  |       | 1      |  |     |  | 12     |  |  |  | 6      | 
|Saskatchewan      |  |                     |       |  |                     |  |       |                       |  |  |        |  |  |       |        |  |     |  |        |  |  |  |        | 
|Weyburn           |  |                     | 644   |  |                     |  | 405   |                       |  |  | -      |  |  |       | -      |  |     |  | 644    |  |  |  | 405    | 
|Bakken            |  |                     | 9     |  |                     |  | 2     |                       |  |  | -      |  |  |       | -      |  |     |  | 9      |  |  |  | 2      | 
|Other             |  |                     | 1     |  |                     |  | 1     |                       |  |  |        |  |  |       |        |  |     |  | 1      |  |  |  | 1      | 
|                  | 
|Total             |  |                     | 2,745 |  |                     |  | 2,480 |                       |  |  | 24,245 |  |  |       | 24,062 |  |     |  | 26,990 |  |  |  | 26,542 | 
|                  | 



|(1) | Includes wells on mineral fee title lands where Cenovus has a working interest. Excludes wells on mineral fee title lands where Cenovus only has a royalty
interest. In the third quarter of 2015, Cenovus sold those royalty interests.
|--- | ----------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------

|(2) | Grassland is located in the Drumheller and Brooks areas.
|--- | --------------------------------------------------------

|(3) | Langevin is located northwest of Medicine Hat.
|--- | ----------------------------------------------



Conventional Crude Oil Assets Cenovuss extensive conventional crude oil assets are located in Alberta and Saskatchewan. Cenovus holds interests in multiple zones in the Suffield,
Grassland and Langevin areas in Alberta with a mix of medium and heavy crude oil production. Cenovus uses a number of EOR techniques to increase production of the Corporations oil assets including waterflooding, CO2 miscible flooding and alkaline surfactant polymer flooding. Cenovus operates one of the
worlds largest CO2 miscible flood projects. The Weyburn unit produces medium sour crude oil and covers approximately 50,000 acres of land in southeastern Saskatchewan. As at
December 31, 2015, approximately 64 percent of the approved CO2 flood pattern development at the Weyburn unit was complete. Since the inception of the project, approximately
27 million tonnes of CO2 have been injected. The CO2 is delivered by pipeline directly to the Weyburn facility from a coal


gasification project in North Dakota, U.S. and from the Boundary Dam Power Station in southeast Saskatchewan. In the unitized portion of the Weyburn field in southwestern Saskatchewan, Cenovus
has a 62.1 percent working interest. However, after taking into consideration a net royalty interest obligation to a third party, Cenovuss economic interest is 50.4 percent. Cenovus is the unit operator and owns 62.1 percent of the CO2pipeline from the Boundary Dam to Weyburn. Using a patterned, horizontal well polymer flood and
waterflood, Cenovus produces heavy crude oil from the Wabiskaw formation at its Pelican Lake property. The property is located within the Greater Pelican Region in northeastern Alberta. Cenovus holds a 38 percent non-operated interest in a 110
kilometer, 20 inch diameter crude oil pipeline which connects the Pelican Lake area to major pipelines that transport crude oil from northern Alberta to crude oil markets.






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Net Wells Drilled and Production

The following table summarizes net oil wells drilled and daily average oil production figures(1) for
the periods indicated:



|               |  |                   |    |  |                                 |  |     |           |  |  |        |  |  |      |        |  |      |  |        |  |  |  |        | 
|-------------- |  | ----------------- | -- |  | ------------------------------- |  | --- | --------- |  |  | ------ |  |  | ---- | ------ |  | ---- |  | ------ |  |  |  | ------ | 
|               |  |                   |    |  | Average Production
(2) (bbls/d) | 
|               |  |                   |    |  |                                 |  |     |           |  |  |        | 
|               |  | Net Wells Drilled |    |  | Light & Medium Oil              |  |     | Heavy Oil | 
|               |  |                   |    | 
|               |  | 2015              |    |  | 2014                            |  |     | 2015      |  |  | 2014   |  |  | 2015 |        |  | 2014 | 
|               | 
|Alberta        |  |                   |    |  |                                 |  |     |           |  |  |        |  |  |      |        |  |      |  |        |  |  |  |        | 
|Grassland(3)   |  |                   | 15 |  |                                 |  | 42  |           |  |  | 6,632  |  |  |      | 8,224  |  |      |  | -      |  |  |  | -      | 
|Suffield       |  |                   | 1  |  |                                 |  | 18  |           |  |  | -      |  |  |      | -      |  |      |  | 8,837  |  |  |  | 9,991  | 
|Langevin(4)    |  |                   | 12 |  |                                 |  | 29  |           |  |  | 7,858  |  |  |      | 9,221  |  |      |  | -      |  |  |  | -      | 
|Wainwright (5) |  |                   | -  |  |                                 |  | 4   |           |  |  | 1      |  |  |      | 42     |  |      |  | 1,630  |  |  |  | 4,631  | 
|Pelican Lake   |  |                   | -  |  |                                 |  | 25  |           |  |  | -      |  |  |      | -      |  |      |  | 24,421 |  |  |  | 24,924 | 
|Other          |  |                   | -  |  |                                 |  | 1   |           |  |  | 10     |  |  |      | 8      |  |      |  | -      |  |  |  | -      | 
|Saskatchewan   |  |                   |    |  |                                 |  |     |           |  |  |        |  |  |      |        |  |      |  |        |  |  |  |        | 
|Weyburn        |  |                   | 6  |  |                                 |  | 7   |           |  |  | 15,343 |  |  |      | 15,921 |  |      |  | -      |  |  |  | -      | 
|Bakken(5)      |  |                   | -  |  |                                 |  | -   |           |  |  | 642    |  |  |      | 1,115  |  |      |  | -      |  |  |  | -      | 
|Other          |  |                   | -  |  |                                 |  | -   |           |  |  | -      |  |  |      | -      |  |      |  | -      |  |  |  | -      | 
|               | 
|Total          |  |                   | 34 |  |                                 |  | 126 |           |  |  | 30,486 |  |  |      | 34,531 |  |      |  | 34,888 |  |  |  | 39,546 | 
|               | 



|(1) | Excludes wells drilled by third parties on mineral fee title lands. In the third quarter of 2015, Cenovus sold those fee lands.
|--- | -------------------------------------------------------------------------------------------------------------------------------

|(2) | Includes production from mineral fee title lands in which Cenovus has a working interest and mineral fee title lands in which Cenovus had retained a
royalty interest. In the third quarter of 2015, Cenovus sold those fee lands.
|--- | ----------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------

|(3) | Grassland landholdings are located in the Drumheller and Brooks areas.
|--- | ----------------------------------------------------------------------

|(4) | Langevin landholdings are located northwest of Medicine Hat.
|--- | ------------------------------------------------------------

|(5) | Cenovus sold certain interests in its Bakken and Wainwright crude oil assets in the second and third quarter of 2014, respectively. Cenovus retained
royalty interests on mineral fee title lands in these areas. In the third quarter of 2015, Cenovus sold those royalty interests.
|--- | -------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------



Conventional Gas Assets Cenovus holds natural gas interests in multiple zones in the Suffield, Grassland and Langevin areas in Alberta. Development in these areas focuses on
recompletions and optimization of existing wells. Suffield is one of the core areas of the Corporations crude oil and natural gas production in
Alberta. The Suffield area is largely made up of the Suffield Block, where operations are carried out pursuant to an agreement among Cenovus, the government of Canada and the Province of Alberta governing surface access to Canadian Forces Base
(CFB) Suffield. In 1999, the parties agreed to permit access to the Suffield military training area to additional operators. Cenovuss predecessor companies, Alberta Energy Company Ltd. and Encana, have operated at CFB Suffield for
over 30 years.


The Corporations natural gas production acts as an economic hedge for the natural gas required as a
fuel source at both its oil sands and refining operations. In 2015, Conventional natural gas production averaged 422 MMcf per day
(2014  466 MMcf per day). Cenovus did not drill any gas wells in 2015 or 2014. Capital Investment In 2015, the Corporations Conventional capital investment was $244 million, primarily related to modest drilling activity at our
tight oil projects in southeast Alberta and at our CO2 EOR project at Weyburn. Spending on natural gas activities was allocated to a small number of higher return opportunities.






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REFINING AND MARKETING



The Refining and Marketing segment is responsible for refining crude oil into petroleum and chemical
products and coordinates Cenovuss marketing and transportation initiatives to optimize the value received for its products. Refining Cenovuss refining operations allow it 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. Through WRB, Cenovus has a 50 percent ownership interest in both the Wood River and Borger


refineries located in Roxana, Illinois and Borger, Texas respectively. Phillips 66 is the operator and managing partner of WRB. WRB has a management committee, which is composed of three Cenovus
representatives and three Phillips 66 representatives, with each company holding equal voting rights. The Corporations refineries have a combined stated processing capacity of approximately 460,000 gross barrels per day of crude oil, including
heavy crude oil processing capability of up to 255,000 gross barrels per day. In addition, the Borger Refinery has an NGL fractionation facility with a capacity of 45,000 gross barrels per day.






The following table summarizes the key
operational results for the refineries in the periods indicated:



|                             |  |      |     |  |      |  |     | 
|---------------------------- |  | ---- | --- |  | ---- |  | --- | 
|Refinery Operations(1)       |  | 2015 |     |  | 2014 | 
|                             | 
|Crude Oil Capacity (Mbbls/d) |  |      | 460 |  |      |  | 460 | 
|Crude Oil Runs (Mbbls/d)     |  |      | 419 |  |      |  | 423 | 
|Heavy Oil                    |  |      | 200 |  |      |  | 199 | 
|Light & Medium Oil           |  |      | 219 |  |      |  | 224 | 
|                             | 
|Crude Utilization (%)        |  |      | 91  |  |      |  | 92  | 
|                             | 
|Refined Products (Mbbls/d)   |  |      |     |  |      |  |     | 
|Gasoline                     |  |      | 228 |  |      |  | 231 | 
|Distillates                  |  |      | 137 |  |      |  | 137 | 
|Other                        |  |      | 79  |  |      |  | 77  | 
|                             | 
|Total                        |  |      | 444 |  |      |  | 445 | 
|                             | 



|(1) | Represents 100 percent of the Wood River and Borger Refinery operations.
|--- | ------------------------------------------------------------------------



Wood River Refinery The Wood River Refinery ranks in the top 10 percent of the approximately 150 refineries in the U.S., based on total crude oil capacity. It is located in
Roxana, Illinois, approximately 25 kilometers northeast of St. Louis, Missouri. The Wood River Refinery processes light low-sulphur and heavy high-sulphur crude oil that
it receives from North American crude oil pipelines to produce gasoline, diesel and jet fuel, petrochemical feedstock as well as coke and asphalt. The gasoline and diesel are transported via pipelines to markets in the upper U.S. Midwest. Other
products are transported via pipeline, truck, barge and railcar to markets in the U.S. Midwest. The Wood River Refinery is a major supplier of jet fuel to Lambert International Airport in St. Louis and OHare International Airport in Chicago. The Wood River Refinerys stated crude oil processing capacity for 2014 was 314,000 gross barrels per day, and is unchanged for 2015. Since the
completed coker construction and start-up of the coker and refinery expansion project, the Wood River Refinery increased its total Canadian heavy crude oil processing capacity up to 220,000 gross barrels per day. Heavy crude oil processing capacity
is planned to increase approximately another 18,000 gross barrels per day in 2016 with the completion of the debottlenecking project; anticipated to start up in the third quarter of 2016. In 2015, almost two thirds of the crude oil processed at the
Wood River Refinery consisted of Canadian heavy crude oil,


including a significant proportion of high total acid number crudes. Borger Refinery The Borger Refinery is located in Borger, Texas, approximately 80 kilometers north of Amarillo, Texas. The Borger Refinery processes mainly medium and
heavy high-sulphur crude oil, and NGLs that it receives from North American pipeline systems to produce gasoline, diesel and jet fuel along with NGLs and solvents. The refined products are transported via
pipelines to markets in Texas, New Mexico, Colorado and the U.S. Mid-Continent. The Borger Refinerys stated oil processing capacity for 2014
was 146,000 gross barrels per day, including 35,000 gross barrels per day of heavy crude oil. The Borger Refinery also has an NGL fractionation facility with stated capacity of 45,000 gross barrels per day. The stated processing capacity is
unchanged for 2015. Marketing Cenovuss marketing activities are focused on enhancing the netback price of the Corporations production, including third-party purchases and
sales of crude oil and natural gas to provide operational flexibility for transportation commitments, product quality, delivery points and customer diversification. Cenovuss crude oil marketing activities are focused on sale of production and
management of condensate supply,






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inventory and storage to meet diluent requirements. Cenovus also manages the marketing of its natural gas, which is primarily sold to industrials, other producers and energy marketing companies.
Prices Cenovus receives are based primarily on prevailing index prices for natural gas. Prices are impacted by competing fuels and by North American regional supply and demand for natural gas. Cenovuss marketing activities also include entering into various risk management contracts aimed at mitigating the impact of commodity price swings.
Details of these transactions are provided in the notes to the Corporations audited Consolidated Financial Statements for the year ended December 31, 2015. Transportation We continue to focus on near and mid-term strategies to broaden market access for our crude oil production. As at December 31, 2015, Cenovus


has entered into various firm transportation and storage commitments totaling $27 billion, most of which relate to pipelines that are subject to regulatory approval. We continue to support
proposed new pipeline projects that would connect us to new markets in the U.S. and globally. The Corporations portfolio of transportation commitments includes feeder pipelines from its production areas to the Edmonton and Hardisty, Alberta
trade centres and major pipeline alternatives to markets downstream of these hubs. Other transportation commitments are primarily related to the reliable supply of diluent, railcar transportation as well as tankage and terminalling of both crude oil
blend and condensate volumes. In the third quarter of 2015, we acquired a crude-by-rail terminal for $75 million, plus adjustments, located at Bruderheim, Alberta as part of our transportation strategy. The terminal has takeaway capacity of 77,000
barrels per day and is operated for Cenovus by a third party contractor.






RESERVES DATA AND OTHER OIL AND GAS INFORMATION





As a Canadian issuer, Cenovus is subject to the reporting requirements of Canadian securities regulatory
authorities, including the reporting of the Corporations reserves in accordance with National Instrument 51-101, Standards of Disclosure for Oil and Gas Activities (NI 51-101). The Corporations reserves are located in Alberta and Saskatchewan, Canada. Cenovus retained two independent qualified reserves evaluators
(IQREs), McDaniel & Associates Consultants Ltd. (McDaniel) and GLJ Petroleum Consultants Ltd. (GLJ), to evaluate and prepare reports on 100 percent of its bitumen, heavy oil, light and medium oil(1), NGLs, natural gas, and coal bed methane (CBM) reserves. McDaniel evaluated approximately 97 percent of Cenovuss proved reserves, located in Alberta, and GLJ evaluated
approximately three percent of the Corporations proved reserves, located in Saskatchewan. The reserves committee (the Reserves
Committee) of Cenovuss board of directors (the Board), composed of independent directors, reviews the qualifications and appointment of the IQREs, the procedures relating to the disclosure of information with respect to oil
and gas activities and the procedures for providing information to the IQREs. The Reserves Committee meets independently with management of Cenovus (Management) and each IQRE to determine whether any restrictions affect the ability of
the IQREs to report on the reserves data without reservation. In addition, the Reserves Committee reviews the reserves data and the report of the IQREs and provides a recommendation regarding approval of the reserves disclosure to the Board.


Cenovuss bitumen reserves will be recovered and produced using SAGD technology. SAGD involves
injecting steam into horizontal wells drilled into the bitumen formation and recovering heated bitumen and water from producing wells located below the injection wells. This technique has a surface footprint comparable to conventional oil
production. Cenovus has no bitumen reserves that require mining techniques to recover the bitumen. 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 petroleum 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. Readers should review the definitions and information
contained in Additional Notes to Reserves Data Tables, Definitions and Pricing Assumptions in conjunction with the disclosure. The reserves estimates provided herein are estimates only and there is no guarantee
that the estimated reserves will be recovered. Actual reserves may be greater than or less than the estimates disclosed. See Risk Factors  Operational Risks  Uncertainty of Reserves and Future Net Revenue Estimates in this
AIF for additional information. The reserves data and other oil and gas information contained in this AIF is dated February 10, 2016, with an
effective date of December 31, 2015. McDaniels preparation date of the information is January 11, 2016, and GLJs preparation date is January 4, 2016.






|(1) | For the purpose of this AIF, references to light and medium oil means light crude oil and medium crude oil combined as defined in
National Instrument 51-101 Standards of Disclosure for Oil and Gas Activities.
|--- | --------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------



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DISCLOSURE OF RESERVES DATA



The reserves data presented summarizes the Corporations bitumen, heavy oil, light and medium oil and
NGLs, and natural gas and CBM reserves and the net present values (NPV) and future net revenue (FNR) for these reserves. The reserves data uses forecast prices and costs prior to provision for interest,


general and administrative expenses or the impact of any hedging activities. Future net revenues have been presented on a before and after income tax basis.






Summary of
Company Interest Oil and Gas Reserves as at December 31, 2015

(Forecast prices and inflation)



|                              |  |                  |       |  |                    |  |     |                                    |  |  |                         |  |  |  |     | 
|----------------------------- |  | ---------------- | ----- |  | ------------------ |  | --- | ---------------------------------- |  |  | ----------------------- |  |  |  | --- | 
|Before Royalties              |  | Bitumen
(MMbbls) |       |  | Heavy Oil
(MMbbls) |  |     | Light & Medium
Oil & NGLs (MMbbls) |  |  | Natural Gas
& CBM (Bcf) | 
|                              | 
|Proved Reserves               |  |                  |       |  |                    |  |     |                                    |  |  |                         |  |  |  |     | 
|Developed Producing           |  |                  | 268   |  |                    |  | 103 |                                    |  |  | 89                      |  |  |  | 703 | 
|Developed Non-Producing       |  |                  | 54    |  |                    |  | 1   |                                    |  |  | 2                       |  |  |  | 14  | 
|Undeveloped                   |  |                  | 1,861 |  |                    |  | 29  |                                    |  |  | 19                      |  |  |  | 4   | 
|                              | 
|Proved Reserves               |  |                  | 2,183 |  |                    |  | 133 |                                    |  |  | 110                     |  |  |  | 721 | 
|                              | 
|Probable Reserves             |  |                  | 1,115 |  |                    |  | 87  |                                    |  |  | 44                      |  |  |  | 232 | 
|                              | 
|Proved plus Probable Reserves |  |                  | 3,298 |  |                    |  | 220 |                                    |  |  | 154                     |  |  |  | 953 | 
|                              | 
|                              |  |                  |       | 
|After Royalties (1)           |  | Bitumen
(MMbbls) |       |  | Heavy Oil
(MMbbls) |  |     | Light & Medium
Oil & NGLs (MMbbls) |  |  | Natural Gas
& CBM (Bcf) | 
|                              | 
|Proved Reserves               |  |                  |       |  |                    |  |     |                                    |  |  |                         |  |  |  |     | 
|Developed Producing           |  |                  | 223   |  |                    |  | 84  |                                    |  |  | 69                      |  |  |  | 658 | 
|Developed Non-Producing       |  |                  | 43    |  |                    |  | 1   |                                    |  |  | 1                       |  |  |  | 13  | 
|Undeveloped                   |  |                  | 1,428 |  |                    |  | 25  |                                    |  |  | 16                      |  |  |  | 3   | 
|                              | 
|Proved Reserves               |  |                  | 1,694 |  |                    |  | 110 |                                    |  |  | 86                      |  |  |  | 674 | 
|                              | 
|Probable Reserves             |  |                  | 862   |  |                    |  | 67  |                                    |  |  | 33                      |  |  |  | 206 | 
|                              | 
|Proved plus Probable Reserves |  |                  | 2,556 |  |                    |  | 177 |                                    |  |  | 119                     |  |  |  | 880 | 
|                              | 



|(1) | As a result of Cenovuss sale in 2015 of HRP, Cenovuss royalty interest and mineral fee title lands business, Cenovus no longer discloses
royalty interest reserves separately.
|--- | --------------------------------------------------------------------------------------------------------------------------------------------------------------------------------

Summary of Net Present Value of Future Net Revenue as at
December 31, 2015 (1)

(Forecast prices and inflation)

|                              |  |                                   |        |  |    |  |                                  |     |  |  |        |  |  |     |        |  |  |  |       |  |  |  |  |  |       | 
|----------------------------- |  | --------------------------------- | ------ |  | -- |  | -------------------------------- | --- |  |  | ------ |  |  | --- | ------ |  |  |  | ----- |  |  |  |  |  | ----- | 
|                              |  | Discounted at %/year ($ millions) |        |  |    |  | Unit Value
Discounted at
10% (2) |    
|                              |  |                                   |        |  |    |  |                                  |     |  | 
|Before Income Taxes           |  | 0%                                |        |  | 5% |  |                                  | 10% |  |  | 15%    |  |  | 20% |        |  |  |  | $/BOE | 
|                              |  |                                   |        |  |    |  |                                 
|Proved Reserves               |  |                                   |        |  |    |  |                                  |     |  |  |        |  |  |     |        |  |  |  |       |  |  |  |  |  |       | 
|Developed Producing           |  |                                   | 4,868  |  |    |  | 6,453                            |     |  |  | 5,992  |  |  |     | 5,361  |  |  |  | 4,798 |  |  |  |  |  | 12.34 | 
|Developed Non-Producing       |  |                                   | 1,308  |  |    |  | 993                              |     |  |  | 776    |  |  |     | 622    |  |  |  | 509   |  |  |  |  |  | 16.40 | 
|Undeveloped                   |  |                                   | 50,517 |  |    |  | 20,376                           |     |  |  | 9,538  |  |  |     | 4,917  |  |  |  | 2,657 |  |  |  |  |  | 6.49  | 
|                              |  |                                   |        |  |    |  |                                 
|Proved Reserves               |  |                                   | 56,693 |  |    |  | 27,822                           |     |  |  | 16,306 |  |  |     | 10,900 |  |  |  | 7,964 |  |  |  |  |  | 8.15  | 
|Probable Reserves             |  |                                   | 35,624 |  |    |  | 12,105                           |     |  |  | 5,260  |  |  |     | 2,763  |  |  |  | 1,642 |  |  |  |  |  | 5.28  | 
|                              |  |                                   |        |  |    |  |                                 
|Proved plus Probable Reserves |  |                                   | 92,317 |  |    |  | 39,927                           |     |  |  | 21,566 |  |  |     | 13,663 |  |  |  | 9,606 |  |  |  |  |  | 7.19  | 
|                              |  |                                   |        |  |    |  |                                 



|                              |  |                                   |        |  |    |  |        |     |  |  |        |  |  |     |        |  |  |  |       | 
|----------------------------- |  | --------------------------------- | ------ |  | -- |  | ------ | --- |  |  | ------ |  |  | --- | ------ |  |  |  | ----- | 
|                              |  | Discounted at %/year ($ millions) |       
|                              |  |                                   |        | 
|After Income Taxes (3)        |  | 0%                                |        |  | 5% |  |        | 10% |  |  | 15%    |  |  | 20% |       
|                              | 
|Proved Reserves               |  |                                   |        |  |    |  |        |     |  |  |        |  |  |     |        |  |  |  |       | 
|Developed Producing           |  |                                   | 3,455  |  |    |  | 5,358  |     |  |  | 5,110  |  |  |     | 4,637  |  |  |  | 4,192 | 
|Developed Non-Producing       |  |                                   | 939    |  |    |  | 734    |     |  |  | 588    |  |  |     | 481    |  |  |  | 401   | 
|Undeveloped                   |  |                                   | 36,922 |  |    |  | 15,077 |     |  |  | 7,110  |  |  |     | 3,685  |  |  |  | 2,002 | 
|                              | 
|Proved Reserves               |  |                                   | 41,316 |  |    |  | 21,169 |     |  |  | 12,808 |  |  |     | 8,803  |  |  |  | 6,595 | 
|                              | 
|Probable Reserves             |  |                                   | 26,583 |  |    |  | 9,021  |     |  |  | 3,900  |  |  |     | 2,038  |  |  |  | 1,208 | 
|                              | 
|Proved plus Probable Reserves |  |                                   | 67,899 |  |    |  | 30,190 |     |  |  | 16,708 |  |  |     | 10,841 |  |  |  | 7,803 | 
|                              | 



|(1) | Due to amendments to NI 51-101 effective July 1, 2015 (the 2015 Amendments), abandonment and reclamation costs included in the
calculation of the NPV and FNR for 2015 are different than abandonment and reclamation costs included in Cenovuss 2014 disclosure of NPV and FNR. The 2015 Amendments require that all abandonment and reclamation costs be included in the
calculation of NPV and FNR including all existing estimated abandonment and reclamation costs, plus all forecast estimates of abandonment and reclamation costs attributable to future development activity associated with the reserves.
|--- | -----------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------

|(2) | Unit values have been calculated using Company Interest After Royalties reserves.
|--- | ---------------------------------------------------------------------------------

|(3) | 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 Corporations Consolidated Financial Statements and Managements Discussion and Analysis for the year ended December 31, 2015.
|--- | ----------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------



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Total Future Net Revenue (undiscounted) as at December 31, 2015

(Forecast prices and inflation - $ millions)

|                              |  |         |         |  |           |  |        |                 |  |  |                   |  |  |                                             |        |  |                                               |  |        |                     |  |  |                                              |  |  |  |        |  |  |  |        | 
|----------------------------- |  | ------- | ------- |  | --------- |  | ------ | --------------- |  |  | ----------------- |  |  | ------------------------------------------- | ------ |  | --------------------------------------------- |  | ------ | ------------------- |  |  | -------------------------------------------- |  |  |  | ------ |  |  |  | ------ | 
|Reserves Category             |  | Revenue |         |  | Royalties |  |        | Operating
Costs |  |  | Development
Costs |  |  | Total
Abandonment and Reclamation
Costs (1) |        |  | Future
Net Revenue Before
Future Income Taxes |  |        | Future
Income Taxes |  |  | Future
Net Revenue After
Future Income Taxes | 
|Proved Reserves               |  |         | 176,710 |  |           |  | 40,459 |                 |  |  | 51,293            |  |  |                                             | 19,671 |  |                                               |  | 8,594  |                     |  |  | 56,693                                       |  |  |  | 15,377 |  |  |  | 41,316 | 
|Proved plus Probable Reserves |  |         | 282,430 |  |           |  | 65,067 |                 |  |  | 80,663            |  |  |                                             | 34,178 |  |                                               |  | 10,205 |                     |  |  | 92,317                                       |  |  |  | 24,418 |  |  |  | 67,899 | 



|(1) | Total abandonment and reclamation costs included for all wells, facilities and other liabilities, known and existing, and to be incurred as a result of
future development activity.
|--- | ------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------

Future Net Revenue by Product Type as at December 31, 2015

(Forecast prices and inflation)



|                              |           |                             |  |                                                                              |        |   |                                               |      |       |  
|----------------------------- | --------- | --------------------------- |  | ---------------------------------------------------------------------------- | ------ | - | --------------------------------------------- | ---- | ----- | -
|Reserves Category             |           | Product Types               |  | Future Net Revenue
Before Income Taxes
(discounted at 10%/year)
($ millions) |        |   | Unit Value
Discounted at 10%/year (1) ($/BOE) |     
|Proved Reserves               |           | Bitumen                     |  |                                                                              | 14,288 |   |                                               |      | 8.44  |  
|                              |           | Heavy Oil                   |  |                                                                              | 1,057  |   |                                               |      | 9.64  |  
|                              |           | Light & Medium Oil and NGLs |  |                                                                              | 1,146  |   |                                               |      | 13.37 |  
|                              |           | Natural Gas                 |  |                                                                              | (185   | ) |                                               |      | (1.65 | )
|                              |           | Total                       |  |                                                                              | 16,306 |   |                                               |      | 8.15  |  
|                              |           |                             | 
|Proved plus Probable Reserves |           | Bitumen                     |  |                                                                              | 18,146 |   |                                               |      | 7.10  |  
|                              | Heavy Oil |                             |  | 1,684                                                                        |        |   |                                               | 9.54 |      
|                              |           | Light & Medium Oil and NGLs |  |                                                                              | 1,699  |   |                                               |      | 14.27 |  
|                              |           | Natural Gas                 |  |                                                                              | 37     |   |                                               |      | 0.25  |  
|                              |           | Total                       |  |                                                                              | 21,566 |   |                                               |      | 7.19  |  



|(1) | Unit values have been calculated using Company Interest After Royalties reserves.
|--- | ---------------------------------------------------------------------------------



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##### Table of Contents

Additional Notes to Reserves Data Tables  ●

The estimates of FNR presented do not represent fair market value.  ●

FNR from reserves excludes cash flows related to Cenovuss risk management activities.  ●

For disclosure purposes, Cenovus has included NGLs with light and medium oil, and CBM gas with natural gas, as the reserves of each are not material relative
to the other reported product types.  ●

Numbers presented may be rounded and tables may not add correctly due to rounding.  ●

Due to amendments to NI 51-101 effective July 1, 2015 (the 2015 Amendments), abandonment and reclamation costs included in the
calculation of the NPV and FNR for 2015 are different than abandonment and reclamation costs included in Cenovuss 2014 disclosure of NPV and FNR. In accordance with the 2015 Amendments, NPV and FNR amounts presented include all of
Cenovuss existing estimated abandonment and reclamation costs, plus all forecast estimates of abandonment and reclamation costs attributable to future development activity associated with the reserves. Definitions  1.
After Royalties means volumes after deduction of royalties and includes Royalty Interest reserves.  2.
Before Royalties means volumes before deduction of royalties and excludes Royalty Interest reserves.  3.
Company Interest means, in relation to production, reserves, resources and property, the interest (operating or
non-operating) held by Cenovus.  4.
Gross means: (a) in relation to wells, the total number of wells in which Cenovus has an interest; and (b) in
relation to properties, the total acreage of properties in which the Corporation has an interest.  5.
Net means: (a) in relation to wells, the number of wells obtained by aggregating Cenovuss working interest in
each of its gross wells; and (b) in relation to the Corporations interest in a property, the total acreage in which it has an interest multiplied by its working interest.


6.
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. 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.






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Pricing Assumptions

The forecast of prices and inflation (the McDaniel Forecast) provided in the table below was obtained from McDaniel and used to estimate FNR
associated with the reserves disclosed herein. The McDaniel Forecast is dated January 1, 2016. The inflation forecast was applied uniformly to prices beyond the forecast interval, and to all future costs. For historical prices realized
during 2015, see Production History in this AIF.



|            |  |                                |        |  |                                    |  |                   |                                 |  |  |                               |  |  |                                  |        |  |  |  |                           |  |  |  |  |                         |        |  |                        |  |  |  |     |  |  |  |       | 
|----------- |  | ------------------------------ | ------ |  | ---------------------------------- |  | ----------------- | ------------------------------- |  |  | ----------------------------- |  |  | -------------------------------- | ------ |  |  |  | ------------------------- |  |  |  |  | ----------------------- | ------ |  | ---------------------- |  |  |  | --- |  |  |  | ----- | 
|            |  | Oil                            |        |  |                                    |  | Natural Gas
& CBM |                                 |  |  |                               |  |  |                                  |        | 
|Year        |  | WTI
Cushing Oklahoma
(US$/bbl) |        |  | Edmonton
Par Price 40 API
(C$/bbl) |  |                   | Cromer
Medium 29.3 API
(C$/bbl) |  |  | Alberta
Heavy 12 API
(C$/bbl) |  |  | Western
Canadian Select
(C$/bbl) |        |  |  |  | AECO
Gas Price
(C$/MMBtu) |  |  |  |  | Inflation
Rate (%/year) |        |  | Exchange
Rate (US$/C$) | 
|2016        |  |                                | 45.00  |  |                                    |  | 56.60             |                                 |  |  | 52.60                         |  |  |                                  | 40.50  |  |  |  | 46.40                     |  |  |  |  |                         | 2.70   |  |                        |  |  |  | 0.0 |  |  |  | 0.730 | 
|2017        |  |                                | 53.60  |  |                                    |  | 66.40             |                                 |  |  | 61.80                         |  |  |                                  | 47.50  |  |  |  | 54.40                     |  |  |  |  |                         | 3.20   |  |                        |  |  |  | 2.0 |  |  |  | 0.750 | 
|2018        |  |                                | 62.40  |  |                                    |  | 72.80             |                                 |  |  | 67.70                         |  |  |                                  | 52.10  |  |  |  | 59.70                     |  |  |  |  |                         | 3.55   |  |                        |  |  |  | 2.0 |  |  |  | 0.800 | 
|2019        |  |                                | 69.00  |  |                                    |  | 80.90             |                                 |  |  | 75.20                         |  |  |                                  | 57.80  |  |  |  | 66.30                     |  |  |  |  |                         | 3.85   |  |                        |  |  |  | 2.0 |  |  |  | 0.800 | 
|2020        |  |                                | 73.10  |  |                                    |  | 83.20             |                                 |  |  | 77.40                         |  |  |                                  | 59.50  |  |  |  | 68.20                     |  |  |  |  |                         | 3.95   |  |                        |  |  |  | 2.0 |  |  |  | 0.825 | 
|2021        |  |                                | 77.30  |  |                                    |  | 88.20             |                                 |  |  | 82.00                         |  |  |                                  | 63.10  |  |  |  | 72.30                     |  |  |  |  |                         | 4.20   |  |                        |  |  |  | 2.0 |  |  |  | 0.825 | 
|2022        |  |                                | 81.60  |  |                                    |  | 93.30             |                                 |  |  | 86.80                         |  |  |                                  | 66.70  |  |  |  | 76.50                     |  |  |  |  |                         | 4.45   |  |                        |  |  |  | 2.0 |  |  |  | 0.825 | 
|2023        |  |                                | 86.20  |  |                                    |  | 98.70             |                                 |  |  | 91.80                         |  |  |                                  | 70.60  |  |  |  | 80.90                     |  |  |  |  |                         | 4.70   |  |                        |  |  |  | 2.0 |  |  |  | 0.825 | 
|2024        |  |                                | 87.90  |  |                                    |  | 100.70            |                                 |  |  | 93.70                         |  |  |                                  | 72.00  |  |  |  | 82.60                     |  |  |  |  |                         | 4.80   |  |                        |  |  |  | 2.0 |  |  |  | 0.825 | 
|2025        |  |                                | 89.60  |  |                                    |  | 102.60            |                                 |  |  | 95.40                         |  |  |                                  | 73.40  |  |  |  | 84.10                     |  |  |  |  |                         | 4.90   |  |                        |  |  |  | 2.0 |  |  |  | 0.825 | 
|2026        |  |                                | 91.40  |  |                                    |  | 104.70            |                                 |  |  | 97.40                         |  |  |                                  | 74.90  |  |  |  | 85.90                     |  |  |  |  |                         | 5.00   |  |                        |  |  |  | 2.0 |  |  |  | 0.825 | 
|There-after |  |                                | +2%/yr |  |                                    |  | +2%/yr            |                                 |  |  | +2%/yr                        |  |  |                                  | +2%/yr |  |  |  | +2%/yr                    |  |  |  |  |                         | +2%/yr |  |                        |  |  |  | 2.0 |  |  |  | 0.825 | 

Future Development Costs

The following table outlines undiscounted future development costs deducted in the estimation of FNR calculated utilizing forecast prices and inflation
for the years indicated:

Reserves Category

|                              |  |      |     |  |      |  |       |      |  |  |       |  |  |      |       |  |           |  |       |       |  |  |        |  |  |  |        | 
|----------------------------- |  | ---- | --- |  | ---- |  | ----- | ---- |  |  | ----- |  |  | ---- | ----- |  | --------- |  | ----- | ----- |  |  | ------ |  |  |  | ------ | 
|($ millions)                  |  | 2016 |     |  | 2017 |  |       | 2018 |  |  | 2019  |  |  | 2020 |       |  | Remainder |  |       | Total | 
|Proved Reserves               |  |      | 534 |  |      |  | 980   |      |  |  | 860   |  |  |      | 1,073 |  |           |  | 934   |       |  |  | 15,290 |  |  |  | 19,671 | 
|Proved plus Probable Reserves |  |      | 593 |  |      |  | 1,308 |      |  |  | 1,378 |  |  |      | 1,445 |  |           |  | 1,103 |       |  |  | 28,351 |  |  |  | 34,178 | 



Cenovus believes that existing cash balances, internally generated cash flows, existing credit facilities,
management of its asset portfolio and access to capital markets will be sufficient to fund the Corporations future development costs. However, there can be no guarantee that the necessary funds will be available or that Cenovus will allocate
funding to develop all of its reserves. Failure to develop those reserves would have a negative impact on the Corporations FNR.


The interest or other costs of external funding are not included in the reserves and FNR estimates and
would reduce FNR depending upon the funding sources utilized. Cenovus does not believe that interest or other funding costs would make development of any property uneconomic.






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##### Table of Contents

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 and CBM for the year ended December 31, 2015, presented using forecast prices and inflation. All reserves are located in Canada.



|                                 |  |                  |       |   |                    |  |     |                                    |  |  |                         |   |  |  |       |  
|-------------------------------- |  | ---------------- | ----- | - | ------------------ |  | --- | ---------------------------------- |  |  | ----------------------- | - |  |  | ----- | -
|Proved                           |  | Bitumen
(MMbbls) |       |   | Heavy Oil
(MMbbls) |  |     | Light &
Medium Oil & NGLs
(MMbbls) |  |  | Natural
Gas & CBM
(Bcf) |  
|As at December 31, 2014          |  |                  | 1,970 |   |                    |  | 156 |                                    |  |  | 120                     |   |  |  | 796   |  
|Extensions and Improved Recovery |  |                  | 188   |   |                    |  | -   |                                    |  |  | 1                       |   |  |  | 8     |  
|Discoveries                      |  |                  | -     |   |                    |  | -   |                                    |  |  | -                       |   |  |  | -     |  
|Technical Revisions              |  |                  | 76    |   |                    |  | (10 | )                                  |  |  | 1                       |   |  |  | 79    |  
|Economic Factors                 |  |                  | -     |   |                    |  | -   |                                    |  |  | (1                      | ) |  |  | (1    | )
|Acquisitions                     |  |                  | -     |   |                    |  | -   |                                    |  |  | -                       |   |  |  | -     |  
|Dispositions                     |  |                  | -     |   |                    |  | -   |                                    |  |  | -                       |   |  |  | -     |  
|Production (1)                   |  |                  | (51   | ) |                    |  | (13 | )                                  |  |  | (11                     | ) |  |  | (161  | )
|As at December 31, 2015          |  |                  | 2,183 |   |                    |  | 133 |                                    |  |  | 110                     |   |  |  | 721   |  
|                                 |  |                  |       |  
|Probable                         |  | Bitumen
(MMbbls) |       |   | Heavy Oil
(MMbbls) |  |     | Light
& Medium
Oil & NGLs (MMbbls) |  |  | Natural
Gas & CBM (Bcf) |  
|As at December 31, 2014          |  |                  | 1,330 |   |                    |  | 123 |                                    |  |  | 46                      |   |  |  | 260   |  
|Extensions and Improved Recovery |  |                  | -     |   |                    |  | -   |                                    |  |  | 1                       |   |  |  | 7     |  
|Discoveries                      |  |                  | -     |   |                    |  | -   |                                    |  |  | -                       |   |  |  | -     |  
|Technical Revisions              |  |                  | (215  | ) |                    |  | (36 | )                                  |  |  | (4                      | ) |  |  | (36   | )
|Economic Factors                 |  |                  | -     |   |                    |  | -   |                                    |  |  | 1                       |   |  |  | 1     |  
|Acquisitions                     |  |                  | -     |   |                    |  | -   |                                    |  |  | -                       |   |  |  | -     |  
|Dispositions                     |  |                  | -     |   |                    |  | -   |                                    |  |  | -                       |   |  |  | -     |  
|Production (1)                   |  |                  | -     |   |                    |  | -   |                                    |  |  | -                       |   |  |  | -     |  
|As at December 31, 2015          |  |                  | 1,115 |   |                    |  | 87  |                                    |  |  | 44                      |   |  |  | 232   |  
|                                 |  |                  |       |  
|Proved plus Probable             |  | Bitumen
(MMbbls) |       |   | Heavy Oil
(MMbbls) |  |     | Light &
Medium Oil & NGLs
(MMbbls) |  |  | Natural
Gas & CBM (Bcf) |  
|As at December 31, 2014          |  |                  | 3,300 |   |                    |  | 279 |                                    |  |  | 166                     |   |  |  | 1,056 |  
|Extensions and Improved Recovery |  |                  | 188   |   |                    |  | -   |                                    |  |  | 2                       |   |  |  | 15    |  
|Discoveries                      |  |                  | -     |   |                    |  | -   |                                    |  |  | -                       |   |  |  | -     |  
|Technical Revisions              |  |                  | (139  | ) |                    |  | (46 | )                                  |  |  | (3                      | ) |  |  | 43    |  
|Economic Factors                 |  |                  | -     |   |                    |  | -   |                                    |  |  | -                       |   |  |  | -     |  
|Acquisitions                     |  |                  | -     |   |                    |  | -   |                                    |  |  | -                       |   |  |  | -     |  
|Dispositions                     |  |                  | -     |   |                    |  | -   |                                    |  |  | -                       |   |  |  | -     |  
|Production (1)                   |  |                  | (51   | ) |                    |  | (13 | )                                  |  |  | (11                     | ) |  |  | (161  | )
|As at December 31, 2015          |  |                  | 3,298 |   |                    |  | 220 |                                    |  |  | 154                     |   |  |  | 953   |  



|(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.
|--- | -------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------



Proved bitumen reserves increased by approximately 11 percent. Increases at Christina Lake were primarily a
result of an area expansion and improved reservoir performance. Increases at Foster Creek were primarily a result of improved reservoir performance. Proved plus probable bitumen reserves were virtually unchanged. Heavy oil proved reserves decreased by approximately 15 percent primarily as a result of production and drilling deferrals, and the loss of undeveloped
reserves at Elk Point as a result of failing to meet economic criteria. Heavy oil probable reserves decreased by approximately 29 percent due to drilling deferrals at Pelican Lake. Overall, heavy oil proved plus probable reserves decreased by
approximately 21 percent.


Light and medium oil and NGLs proved reserves decreased by eight percent. The decreases were primarily due
to production, partially offset by development at Grassland. Light and medium oil and NGLs probable reserves decreased by approximately four percent partly as a result of the conversion of probable reserves to proved reserves. Overall, light and
medium oil and NGLs proved plus probable reserves decreased seven percent, primarily as a result of production. Natural gas and CBM proved reserves
declined by approximately nine percent as extensions and technical revisions did not offset production. Probable natural gas and CBM reserves and proved plus probable natural gas and CBM reserves declined by approximately 11 percent and ten percent,
respectively.






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Undeveloped Reserves Undeveloped reserves are those reserves expected to be recovered from known accumulations where a significant expenditure is required to render them
capable of production.


Proved and probable undeveloped reserves have been estimated by the IQREs in accordance with procedures and
standards contained in the Canadian Oil and Gas Evaluation Handbook. In general, undeveloped reserves are scheduled to be developed within the next one to 45 years.






Company
Interest Proved Undeveloped  Before Royalties

|      |  |                  |       |  |                    |  |       |                                    |  |  |                         |  |  |                  |    |  |                   |  |    |                  |  |  |                   |  |  |  |     |  |  |  |   | 
|----- |  | ---------------- | ----- |  | ------------------ |  | ----- | ---------------------------------- |  |  | ----------------------- |  |  | ---------------- | -- |  | ----------------- |  | -- | ---------------- |  |  | ----------------- |  |  |  | --- |  |  |  | - | 
|      |  | Bitumen
(MMbbls) |       |  | Heavy Oil
(MMbbls) |  |       | Light & Medium
Oil & NGLs (MMbbls) |  |  | Natural Gas & CBM
(Bcf) | 
|      |  | First
Attributed |       |  | Total at
Year-End  |  |       | First
Attributed                   |  |  | Total at
Year-End       |  |  | First
Attributed |    |  | Total at
Year-End |  |    | First
Attributed |  |  | Total at
Year-End | 
|Prior |  |                  | 1,717 |  |                    |  | 1,532 |                                    |  |  | 93                      |  |  |                  | 61 |  |                   |  | 56 |                  |  |  | 22                |  |  |  | 300 |  |  |  | 6 | 
|2013  |  |                  | 158   |  |                    |  | 1,629 |                                    |  |  | 1                       |  |  |                  | 47 |  |                   |  | 3  |                  |  |  | 15                |  |  |  | -   |  |  |  | 4 | 
|2014  |  |                  | 161   |  |                    |  | 1,732 |                                    |  |  | 7                       |  |  |                  | 40 |  |                   |  | 11 |                  |  |  | 21                |  |  |  | 4   |  |  |  | 4 | 
|2015  |  |                  | 238   |  |                    |  | 1,861 |                                    |  |  | -                       |  |  |                  | 29 |  |                   |  | 1  |                  |  |  | 19                |  |  |  | 1   |  |  |  | 4 | 

Company Interest Probable Undeveloped  Before Royalties

|      |  |                  |       |  |                    |  |       |                                    |  |  |                         |  |  |                  |    |  |                   |  |    |                  |  |  |                   |  |  |  |    |  |  |  |    | 
|----- |  | ---------------- | ----- |  | ------------------ |  | ----- | ---------------------------------- |  |  | ----------------------- |  |  | ---------------- | -- |  | ----------------- |  | -- | ---------------- |  |  | ----------------- |  |  |  | -- |  |  |  | -- | 
|      |  | Bitumen
(MMbbls) |       |  | Heavy Oil
(MMbbls) |  |       | Light & Medium
Oil & NGLs (MMbbls) |  |  | Natural Gas & CBM
(Bcf) | 
|      |  | First
Attributed |       |  | Total at
Year-End  |  |       | First
Attributed                   |  |  | Total at
Year-End       |  |  | First
Attributed |    |  | Total at
Year-End |  |    | First
Attributed |  |  | Total at
Year-End | 
|Prior |  |                  | 1,099 |  |                    |  | 646   |                                    |  |  | 66                      |  |  |                  | 42 |  |                   |  | 34 |                  |  |  | 24                |  |  |  | 54 |  |  |  | 16 | 
|2013  |  |                  | 145   |  |                    |  | 649   |                                    |  |  | 56                      |  |  |                  | 86 |  |                   |  | 1  |                  |  |  | 17                |  |  |  | -  |  |  |  | 16 | 
|2014  |  |                  | 649   |  |                    |  | 1,293 |                                    |  |  | 5                       |  |  |                  | 76 |  |                   |  | 8  |                  |  |  | 15                |  |  |  | 7  |  |  |  | 11 | 
|2015  |  |                  | 1     |  |                    |  | 1,074 |                                    |  |  | -                       |  |  |                  | 52 |  |                   |  | 1  |                  |  |  | 14                |  |  |  | 2  |  |  |  | 8  | 

DEVELOPMENT OF PROVED AND PROBABLE UNDEVELOPED RESERVES



Bitumen At the end of 2015, Cenovus had proved undeveloped bitumen reserves of 1,861 million barrels Before Royalties, or approximately 85 percent of the
Corporations proved bitumen reserves. Of Cenovuss 1,115 million barrels of probable bitumen reserves, 1,074 million barrels, or approximately 96 percent are undeveloped. The evaluation of these reserves anticipates they will be
recovered using SAGD. Typical SAGD project development involves the initial installation of a steam generation facility, at a cost much greater than
drilling a production/injection well pair, and then progressively drilling sufficient SAGD well pairs to fully utilize the available steam. Bitumen
reserves can be classified as proved when there is sufficient stratigraphic drilling to have demonstrated to a high degree of certainty the presence of the bitumen in commercially recoverable volumes. McDaniels standard for sufficient drilling
in the McMurray formation is a minimum of eight wells per section with 3D seismic, or 16 wells per section with no seismic. In other formations, such as the Grand Rapids, there may be some variation in the standard. Additionally, all requisite legal
and regulatory approvals must have been obtained, operator and partner funding approvals must be in place, and a reasonable


development timetable must be established. Proved developed bitumen reserves are differentiated from proved undeveloped bitumen reserves by the presence of drilled production/injection well pairs
at the reserves estimation effective date. Because a steam plant has a long life relative to well pairs, in the early stages of a SAGD project, only a small portion of proved reserves will be developed as the number of well pairs drilled will be
limited by the available steam capacity. Recognition of probable reserves requires sufficient drilling of stratigraphic wells to establish reservoir
suitability for SAGD. Reserves will be classified as probable if the number of wells drilled falls between the stratigraphic well requirements for proved reserves and for probable reserves, or if the reserves are not located within an approved
development plan area. McDaniels standard for probable reserves is a minimum of four stratigraphic wells per section. If reserves lie outside the approved development area, approval to include those reserves in the development area must be
obtained before development drilling of SAGD well pairs can commence. Development of the proved undeveloped reserves will take place in an orderly
manner as additional well pairs are drilled to utilize the available steam when existing well pairs reach the end of their steam injection phase. The forecast production of Cenovuss proved bitumen reserves extends approximately 45 years, based
on existing facilities. Production of the current proved developed portion is estimated to take approximately 13 years.






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Crude Oil Cenovus has a significant medium oil CO2 EOR project at Weyburn and a significant heavy oil
waterflood/polymer flood EOR project at Pelican Lake. These projects occur in large, well-developed reservoirs, where undeveloped reserves are not necessarily defined by the absence of drilling, but by anticipated improved recovery associated with
development of the EOR schemes. Extending both


EOR schemes within the projects requires intensive capital investment in infrastructure development and will occur over many years. At Weyburn, investment in proved undeveloped reserves is projected to continue for over 40 years, with drilling of supplementary wells taking place over
the next five years, and CO2 flood advancement continuing many years beyond that. At Pelican Lake, investment in proved undeveloped reserves is projected to continue for four years, with a
combination of infrastructure development, infill drilling and polymer flood advancement.






SIGNIFICANT FACTORS OR UNCERTAINTIES AFFECTING RESERVES DATA



The evaluation of reserves is a continuous process, one that can be significantly impacted by a variety of
internal and external influences. Revisions are often required resulting from changes in pricing, economic conditions, regulatory changes, and historical performance. While these factors can be considered and potentially anticipated, certain


judgments and assumptions are always required. As new information becomes available, these areas are reviewed and revised accordingly. For a discussion of the risk factors and uncertainties
affecting reserves data, see Risk Factors  Operational Risks  Uncertainty of Reserves and Future Net Revenue Estimates.






OTHER OIL AND GAS INFORMATION

Oil and Gas Properties and Wells

The following tables summarize Cenovuss interests in producing and non-producing wells, as at December 31, 2015:



|                    |  |       |       |  |     |  |       |       |  |  |        |  |  |       |        |  |     |  |        |  |  |  |        | 
|------------------- |  | ----- | ----- |  | --- |  | ----- | ----- |  |  | ------ |  |  | ----- | ------ |  | --- |  | ------ |  |  |  | ------ | 
|                    |  | Oil   |       |  | Gas |  |       | Total | 
|Producing Wells (1) |  | Gross |       |  | Net |  |       | Gross |  |  | Net    |  |  | Gross |        |  | Net | 
|Alberta             |  |       |       |  |     |  |       |       |  |  |        |  |  |       |        |  |     |  |        |  |  |  |        | 
|Oil Sands           |  |       | 411   |  |     |  | 209   |       |  |  | 316    |  |  |       | 303    |  |     |  | 727    |  |  |  | 512    | 
|Conventional        |  |       | 2,091 |  |     |  | 2,072 |       |  |  | 24,245 |  |  |       | 24,062 |  |     |  | 26,336 |  |  |  | 26,134 | 
|Total Alberta       |  |       | 2,502 |  |     |  | 2,281 |       |  |  | 24,561 |  |  |       | 24,365 |  |     |  | 27,063 |  |  |  | 26,646 | 
|Saskatchewan        |  |       | 654   |  |     |  | 408   |       |  |  | -      |  |  |       | -      |  |     |  | 654    |  |  |  | 408    | 
|Total               |  |       | 3,156 |  |     |  | 2,689 |       |  |  | 24,561 |  |  |       | 24,365 |  |     |  | 27,717 |  |  |  | 27,054 | 



|(1) | Includes wells containing multiple completions as follows: 22,174 gross gas wells (22,013 net wells) and 1,318 gross oil wells (1,073 net wells).
|--- | -------------------------------------------------------------------------------------------------------------------------------------------------



|                       |  |       |       |  |     |  |     |       |  |  |       |  |  |       |       |  |     |  |       |  |  |  |       | 
|---------------------- |  | ----- | ----- |  | --- |  | --- | ----- |  |  | ----- |  |  | ----- | ----- |  | --- |  | ----- |  |  |  | ----- | 
|                       |  | Oil   |       |  | Gas |  |     | Total | 
|Non-Producing Wells(1) |  | Gross |       |  | Net |  |     | Gross |  |  | Net   |  |  | Gross |       |  | Net | 
|Alberta                |  |       |       |  |     |  |     |       |  |  |       |  |  |       |       |  |     |  |       |  |  |  |       | 
|Oil Sands              |  |       | 61    |  |     |  | 33  |       |  |  | 343   |  |  |       | 246   |  |     |  | 404   |  |  |  | 279   | 
|Conventional           |  |       | 785   |  |     |  | 769 |       |  |  | 971   |  |  |       | 940   |  |     |  | 1,756 |  |  |  | 1,709 | 
|Total Alberta          |  |       | 846   |  |     |  | 802 |       |  |  | 1,314 |  |  |       | 1,186 |  |     |  | 2,160 |  |  |  | 1,988 | 
|Saskatchewan           |  |       | 205   |  |     |  | 92  |       |  |  | 5     |  |  |       | 5     |  |     |  | 210   |  |  |  | 97    | 
|Total                  |  |       | 1,051 |  |     |  | 894 |       |  |  | 1,319 |  |  |       | 1,191 |  |     |  | 2,370 |  |  |  | 2,085 | 



|(1) | Non-producing wells include wells which are capable of producing, but which are currently not producing. Non-producing wells do not include other types of wells such as stratigraphic test wells, service wells, or
wells that have been abandoned.
|--- | ----------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------

Cenovus has no properties with attributed reserves which are capable of producing, but which are
not on production.



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Exploration and Development Activity

The following tables summarize Cenovuss gross participation and net interest in wells drilled in 2015(1):



|                          |  |           |    |  |              |  |    |       |  |  |     |  |  |       |    |  |     |  |     |  |  |  |    | 
|------------------------- |  | --------- | -- |  | ------------ |  | -- | ----- |  |  | --- |  |  | ----- | -- |  | --- |  | --- |  |  |  | -- | 
|                          |  | Oil
Sands |    |  | Conventional |  |    | Total | 
|                          |  |           |    | 
|Development Wells Drilled |  | Gross     |    |  | Net          |  |    | Gross |  |  | Net |  |  | Gross |    |  | Net | 
|                          | 
|Oil                       |  |           | 96 |  |              |  | 49 |       |  |  | 35  |  |  |       | 32 |  |     |  | 131 |  |  |  | 81 | 
|Gas                       |  |           | -  |  |              |  | -  |       |  |  | -   |  |  |       | -  |  |     |  | -   |  |  |  | -  | 
|Dry & Abandoned           |  |           | -  |  |              |  | -  |       |  |  | 1   |  |  |       | 1  |  |     |  | 1   |  |  |  | 1  | 
|                          | 
|Total Working Interest    |  |           | 96 |  |              |  | 49 |       |  |  | 36  |  |  |       | 33 |  |     |  | 132 |  |  |  | 82 | 
|Royalty                   |  |           | -  |  |              |  | -  |       |  |  | 1   |  |  |       | -  |  |     |  | 1   |  |  |  | -  | 
|                          | 
|Total Canada              |  |           | 96 |  |              |  | 49 |       |  |  | 37  |  |  |       | 33 |  |     |  | 133 |  |  |  | 82 | 
|                          | 



|(1) | Cenovus did not have any participation or interest in any exploration wells in 2015.
|--- | ------------------------------------------------------------------------------------

During the
year ended December 31, 2015, Oil Sands drilled 164 gross stratigraphic test wells (73 net wells) and Conventional drilled 13 gross stratigraphic test wells (13 net wells).

During the year ended December 31, 2015, Oil Sands drilled eight gross service wells (four net wells) and Conventional drilled three gross service
wells (1.8 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.

Development activities were focused on sustaining bitumen production at Foster Creek and Christina Lake, and on supporting our EOR projects at Pelican
Lake and Weyburn.

Interest in Material Properties

The following table summarizes Cenovuss landholdings as at December 31, 2015:



|                     |  |                   |       |  |                         |  |       |               |  |  |       |  |  |       |       |  |     |  |       |  |  |  |       | 
|-------------------- |  | ----------------- | ----- |  | ----------------------- |  | ----- | ------------- |  |  | ----- |  |  | ----- | ----- |  | --- |  | ----- |  |  |  | ----- | 
|Landholdings         |  |                   |       |  |                         |  |       |               | 
|(thousands of acres) |  | Developed Acreage |       |  | Undeveloped Acreage (1) |  |       | Total Acreage | 
|                     |  | Gross             |       |  | Net                     |  |       | Gross         |  |  | Net   |  |  | Gross |       |  | Net | 
|Alberta:             |  |                   |       |  |                         |  |       |               |  |  |       |  |  |       |       |  |     |  |       |  |  |  |       | 
|Oil Sands            |  |                   |       |  |                         |  |       |               |  |  |       |  |  |       |       |  |     |  |       |  |  |  |       | 
| Crown (2)          |  |                   | 453   |  |                         |  | 384   |               |  |  | 2,236 |  |  |       | 1,786 |  |     |  | 2,689 |  |  |  | 2,170 | 
|Conventional         |  |                   |       |  |                         |  |       |               |  |  |       |  |  |       |       |  |     |  |       |  |  |  |       | 
| Crown(2)           |  |                   | 1,065 |  |                         |  | 1,019 |               |  |  | 530   |  |  |       | 490   |  |     |  | 1,595 |  |  |  | 1,509 | 
| Freehold(3)        |  |                   | 1,666 |  |                         |  | 1,613 |               |  |  | 70    |  |  |       | 66    |  |     |  | 1,736 |  |  |  | 1,679 | 
|Total Alberta        |  |                   | 3,184 |  |                         |  | 3,016 |               |  |  | 2,836 |  |  |       | 2,342 |  |     |  | 6,020 |  |  |  | 5,358 | 
|Saskatchewan:        |  |                   |       |  |                         |  |       |               |  |  |       |  |  |       |       |  |     |  |       |  |  |  |       | 
|Oil Sands            |  |                   |       |  |                         |  |       |               |  |  |       |  |  |       |       |  |     |  |       |  |  |  |       | 
| Crown(2)           |  |                   | -     |  |                         |  | -     |               |  |  | 64    |  |  |       | 64    |  |     |  | 64    |  |  |  | 64    | 
|Conventional         |  |                   |       |  |                         |  |       |               |  |  |       |  |  |       |       |  |     |  |       |  |  |  |       | 
| Crown(2)           |  |                   | 35    |  |                         |  | 28    |               |  |  | 95    |  |  |       | 87    |  |     |  | 130   |  |  |  | 115   | 
| Freehold(3)        |  |                   | 17    |  |                         |  | 12    |               |  |  | 4     |  |  |       | 2     |  |     |  | 21    |  |  |  | 14    | 
|Total Saskatchewan   |  |                   | 52    |  |                         |  | 40    |               |  |  | 163   |  |  |       | 153   |  |     |  | 215   |  |  |  | 193   | 
|Total                |  |                   | 3,236 |  |                         |  | 3,056 |               |  |  | 2,999 |  |  |       | 2,495 |  |     |  | 6,235 |  |  |  | 5,551 | 



|(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) | Crown/Federal lands are those lands owned by the federal or provincial government or the First Nations, in which Cenovus holds a working interest.
|--- | --------------------------------------------------------------------------------------------------------------------------------------------------

|(3) | Freehold lands are those lands owned by individuals and other entities (other than a government) in which Cenovus holds a working interest.
|--- | -------------------------------------------------------------------------------------------------------------------------------------------



Properties With No Attributed Reserves Cenovus has approximately 4.1 million gross acres (3.6 million net acres) of properties in Canada to which no reserves have been specifically
attributed. These properties are planned for current and future development in both the Corporations oil sands and conventional oil and gas operations. There are currently no work commitments on these properties. Cenovus has rights to explore, develop, and exploit approximately 102,000 net acres that could potentially expire by December 31, 2016, which relate
entirely to Crown and freehold land.


For areas where Cenovus holds interests in different formations under the same surface area through
separate leases, the Corporation has calculated its gross and net acreage on the basis of each individual lease. Properties with no attributed
reserves include Crown lands where bitumen contingent and prospective resources have been identified and Crown lands where exploration activities to date have not identified potential reserves in commercial quantities. See Risk Factors 
Financial Risks  Commodity Prices and Risk Factors  Financial Risks  Development and Operating Costs and






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Risk Factors  Operational Risks  Uncertainty of Reserves and Future Net Revenue Estimates in this AIF for further discussion of economic and risk factors relevant to
Cenovuss properties with no attributed reserves. Additional Information Concerning Abandonment and Reclamation Costs The estimated total future abandonment and reclamation costs for existing wells, facilities, and infrastructure is based on
Managements estimate of costs to remediate, reclaim and abandon wells and facilities having regard to Cenovuss working interest and the estimated timing of the costs to be incurred in future periods. Cenovus has developed a process to
calculate these estimates, which considers applicable regulations, actual and anticipated costs, type and size of the well or facility and the geographic location. Cenovus has estimated undiscounted future abandonment and reclamation costs for its existing upstream assets at approximately $6.5 billion (approximately
$1.3 billion, discounted at 10 percent) at December 31,


2015, of which the Corporation expects to pay between $210 million and $260 million in the next three financial years on a portion of the 34,557 net wells. Of the undiscounted future abandonment and reclamation costs to be incurred over the life of Cenovuss proved reserves, approximately $8.6 billion
has been deducted in estimating the FNR, which represents the Corporations total existing estimated abandonment and reclamation costs, plus all forecast estimates of abandonment and reclamation costs attributable to future development activity
associated with the reserves. Tax Horizon In 2016, Cenovus expects to incur losses for income tax purposes and recover income taxes paid in prior years.






Costs
Incurred



|                     |  |      |       | 
|-------------------- |  | ---- | ----- | 
|($ millions)         |  | 2015 |      
|                     | 
|Acquisitions         |  |      |       | 
|Unproved             |  |      | 4     | 
|Proved               |  |      | -     | 
|                     | 
|Total Acquisitions   |  |      | 4     | 
|Exploration Costs    |  |      | 66    | 
|Development Costs    |  |      | 1,360 | 
|                     | 
|Total Costs Incurred |  |      | 1,430 | 
|                     | 

Forward Contracts

Cenovus may use financial derivatives to manage its exposure to fluctuations in commodity prices, foreign exchange and interest rates. A description of
such instruments is provided in the notes to the Corporations annual audited Consolidated Financial Statements for the year ended December 31, 2015.



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Production Estimates

The following table summarizes the estimated 2016 average daily volume of Company Working Interest Before Royalties reflected in the reserves reports for
all properties held on December 31, 2015 using forecast prices and costs, all of which will be produced in Canada. These estimates assume certain activities take place, such as the development of undeveloped reserves, and that there are no
divestitures.



|                                                     |  |        |         |  |                         |  |         | 
|---------------------------------------------------- |  | ------ | ------- |  | ----------------------- |  | ------- | 
|2016 Estimated Production
 Forecast Prices and Costs |  | Proved |         |  | Proved plus    Probable | 
|Bitumen (bbls/d) (1)                                 |  |        | 152,517 |  |                         |  | 159,881 | 
|Light and Medium Oil (bbls/d)                        |  |        | 28,265  |  |                         |  | 32,060  | 
|Heavy Oil (bbls/d)                                   |  |        | 31,727  |  |                         |  | 32,946  | 
|Natural Gas (MMcf/d)                                 |  |        | 357     |  |                         |  | 390     | 
|Natural Gas Liquids (bbls/d)                         |  |        | 658     |  |                         |  | 732     | 
|Company Working Interest Before Royalties (BOE/d)    |  |        | 272,715 |  |                         |  | 290,620 | 



|(1) | Includes Foster Creek production of 74,929 barrels per day for proved and 77,581 barrels per day for proved plus probable, and Christina Lake production of 77,588 barrels per day for proved and 82,300 barrels per day
for proved plus probable.
|--- | --------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------

Production History



|                                                           |  |      |         |  |    |  |         |    |  |  |         |  |  |    |         |  |  |  |         | 
|---------------------------------------------------------- |  | ---- | ------- |  | -- |  | ------- | -- |  |  | ------- |  |  | -- | ------- |  |  |  | ------- | 
|Average Working Interest Daily Production Volumes - 2015   | 
|                                                           |  | Year |         |  | Q4 |  |         | Q3 |  |  | Q2      |  |  | Q1 |        
|                                                           | 
|Crude Oil and Natural Gas Liquids(bbls/d)                  |  |      |         |  |    |  |         |    |  |  |         |  |  |    |         |  |  |  |         | 
|Oil Sands                                                  |  |      |         |  |    |  |         |    |  |  |         |  |  |    |         |  |  |  |         | 
|Foster Creek (Bitumen)                                     |  |      | 65,345  |  |    |  | 63,680  |    |  |  | 71,414  |  |  |    | 58,363  |  |  |  | 67,901  | 
|Christina Lake (Bitumen)                                   |  |      | 74,975  |  |    |  | 75,733  |    |  |  | 75,329  |  |  |    | 72,371  |  |  |  | 76,471  | 
|                                                           | 
|                                                           |  |      | 140,320 |  |    |  | 139,413 |    |  |  | 146,743 |  |  |    | 130,734 |  |  |  | 144,372 | 
|Conventional Liquids                                       |  |      |         |  |    |  |         |    |  |  |         |  |  |    |         |  |  |  |         | 
|Heavy Oil                                                  |  |      | 34,260  |  |    |  | 32,363  |    |  |  | 33,693  |  |  |    | 34,790  |  |  |  | 36,244  | 
|Light and Medium Oil                                       |  |      | 28,607  |  |    |  | 26,576  |    |  |  | 27,551  |  |  |    | 28,886  |  |  |  | 31,481  | 
|Natural Gas Liquids (1)                                    |  |      | 1,148   |  |    |  | 1,154   |    |  |  | 1,130   |  |  |    | 1,139   |  |  |  | 1,171   | 
|                                                           | 
|Total Crude Oil and Natural Gas Liquids                    |  |      | 204,335 |  |    |  | 199,506 |    |  |  | 209,117 |  |  |    | 195,549 |  |  |  | 213,268 | 
|                                                           | 
|Natural Gas(MMcf/d)                                        |  |      |         |  |    |  |         |    |  |  |         |  |  |    |         |  |  |  |         | 
|Oil Sands                                                  |  |      | 19      |  |    |  | 19      |    |  |  | 19      |  |  |    | 21      |  |  |  | 20      | 
|Conventional                                               |  |      | 412     |  |    |  | 405     |    |  |  | 405     |  |  |    | 415     |  |  |  | 423     | 
|                                                           | 
|Total Natural Gas                                          |  |      | 431     |  |    |  | 424     |    |  |  | 424     |  |  |    | 436     |  |  |  | 443     | 
|                                                           | 
|Total (BOE/d)                                              |  |      | 276,168 |  |    |  | 270,173 |    |  |  | 279,784 |  |  |    | 268,216 |  |  |  | 287,101 | 
|                                                           | 
|(1)        Natural gas liquids include condensate volumes. |  |      |         |  |    |  |         |    |  |  |         |  |  |    |         |  |  |  |         | 
|Average Royalty Interest Daily Production
Volumes - 2015   | 
|                                                           |  | Year |         |  | Q4 |  |         | Q3 |  |  | Q2      |  |  | Q1 |        
|                                                           | 
|Crude Oil and Natural Gas Liquids(bbls/d)                  |  |      |         |  |    |  |         |    |  |  |         |  |  |    |         |  |  |  |         | 
|Conventional Liquids (1)                                   |  |      |         |  |    |  |         |    |  |  |         |  |  |    |         |  |  |  |         | 
|Heavy Oil                                                  |  |      | 628     |  |    |  | -       |    |  |  | 304     |  |  |    | 1,309   |  |  |  | 911     | 
|Light and Medium Oil                                       |  |      | 1,879   |  |    |  | 49      |    |  |  | 940     |  |  |    | 2,923   |  |  |  | 3,654   | 
|Natural Gas Liquids (2)                                    |  |      | 105     |  |    |  | 1       |    |  |  | 61      |  |  |    | 173     |  |  |  | 187     | 
|                                                           | 
|Total Crude Oil and Natural Gas Liquids                    |  |      | 2,612   |  |    |  | 50      |    |  |  | 1,305   |  |  |    | 4,405   |  |  |  | 4,752   | 
|                                                           | 
|Natural Gas(MMcf/d)                                        |  |      |         |  |    |  |         |    |  |  |         |  |  |    |         |  |  |  |         | 
|Conventional                                               |  |      | 10      |  |    |  | -       |    |  |  | 6       |  |  |    | 14      |  |  |  | 19      | 
|                                                           | 
|Total (BOE/d)                                              |  |      | 4,279   |  |    |  | 50      |    |  |  | 2,305   |  |  |    | 6,738   |  |  |  | 7,919   | 
|                                                           | 



|(1) | Cenovus sold the majority of its royalty interest and mineral fee title lands in the third quarter of 2015.
|--- | -----------------------------------------------------------------------------------------------------------

|(2) | Natural gas liquids include condensate volumes.
|--- | -----------------------------------------------



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##### Table of Contents

Per-Unit Results

The following tables summarize Cenovuss per-unit results, as well as the impact of realized financial
hedging, on a quarterly basis, before deduction of royalties, for the periods indicated:



|                                                                                      |  |      |       |  |    |  |       |    |  |  |       |  |  |    |       |  |  |  |       |  
|------------------------------------------------------------------------------------- |  | ---- | ----- |  | -- |  | ----- | -- |  |  | ----- |  |  | -- | ----- |  |  |  | ----- | -
|Per-Unit Results  2015
(excluding impact of realized gain (loss) on risk management) |  | Year |       |  | Q4 |  |       | Q3 |  |  | Q2    |  |  | Q1 |      
|Bitumen - Foster Creek($/bbl)(1) (2) (3)                                              |  |      |       |  |    |  |       |    |  |  |       |  |  |    |       |  |  |  |       |  
|Price                                                                                 |  |      | 33.65 |  |    |  | 25.09 |    |  |  | 33.35 |  |  |    | 48.25 |  |  |  | 29.42 |  
|Royalties                                                                             |  |      | 0.47  |  |    |  | 0.12  |    |  |  | 0.20  |  |  |    | 1.97  |  |  |  | (0.25 | )
|Transportation and blending                                                           |  |      | 8.84  |  |    |  | 8.53  |    |  |  | 8.50  |  |  |    | 9.04  |  |  |  | 9.39  |  
|Operating expenses                                                                    |  |      | 12.60 |  |    |  | 11.66 |    |  |  | 11.27 |  |  |    | 13.29 |  |  |  | 14.50 |  
|Netback                                                                               |  |      | 11.74 |  |    |  | 4.78  |    |  |  | 13.38 |  |  |    | 23.95 |  |  |  | 5.78  |  
|Bitumen - Christina Lake($/bbl)(1) (2) (3)                                            |  |      |       |  |    |  |       |    |  |  |       |  |  |    |       |  |  |  |       |  
|Price                                                                                 |  |      | 28.45 |  |    |  | 21.34 |    |  |  | 27.46 |  |  |    | 43.36 |  |  |  | 23.30 |  
|Royalties                                                                             |  |      | 0.67  |  |    |  | 0.30  |    |  |  | 0.83  |  |  |    | 0.99  |  |  |  | 0.61  |  
|Transportation and blending                                                           |  |      | 4.72  |  |    |  | 5.40  |    |  |  | 5.00  |  |  |    | 4.29  |  |  |  | 4.17  |  
|Operating expenses                                                                    |  |      | 8.01  |  |    |  | 7.80  |    |  |  | 7.80  |  |  |    | 8.20  |  |  |  | 8.24  |  
|Netback                                                                               |  |      | 15.05 |  |    |  | 7.84  |    |  |  | 13.83 |  |  |    | 29.88 |  |  |  | 10.28 |  
|Total Bitumen - Oil Sands($/bbl)(1) (2) (3)                                           |  |      |       |  |    |  |       |    |  |  |       |  |  |    |       |  |  |  |       |  
|Price                                                                                 |  |      | 30.88 |  |    |  | 23.08 |    |  |  | 30.35 |  |  |    | 45.61 |  |  |  | 26.04 |  
|Royalties                                                                             |  |      | 0.58  |  |    |  | 0.22  |    |  |  | 0.52  |  |  |    | 1.44  |  |  |  | 0.22  |  
|Transportation and blending                                                           |  |      | 6.64  |  |    |  | 6.85  |    |  |  | 6.72  |  |  |    | 6.48  |  |  |  | 6.50  |  
|Operating expenses                                                                    |  |      | 10.13 |  |    |  | 9.59  |    |  |  | 9.46  |  |  |    | 10.57 |  |  |  | 10.99 |  
|Netback                                                                               |  |      | 13.53 |  |    |  | 6.42  |    |  |  | 13.65 |  |  |    | 27.12 |  |  |  | 8.33  |  
|Heavy Crude Oil - Conventional($/bbl)(1) (2) (3)                                      |  |      |       |  |    |  |       |    |  |  |       |  |  |    |       |  |  |  |       |  
|Price                                                                                 |  |      | 39.95 |  |    |  | 32.84 |    |  |  | 37.09 |  |  |    | 52.63 |  |  |  | 35.85 |  
|Royalties                                                                             |  |      | 2.97  |  |    |  | 2.24  |    |  |  | 1.73  |  |  |    | 5.34  |  |  |  | 2.34  |  
|Transportation and blending                                                           |  |      | 3.36  |  |    |  | 3.63  |    |  |  | 3.36  |  |  |    | 3.09  |  |  |  | 3.42  |  
|Operating expenses                                                                    |  |      | 15.92 |  |    |  | 15.20 |    |  |  | 15.59 |  |  |    | 15.45 |  |  |  | 17.30 |  
|Production and mineral taxes                                                          |  |      | 0.04  |  |    |  | (0.03 | )  |  |  | 0.07  |  |  |    | 0.08  |  |  |  | 0.02  |  
|Netback                                                                               |  |      | 17.66 |  |    |  | 11.80 |    |  |  | 16.34 |  |  |    | 28.67 |  |  |  | 12.77 |  
|Total Bitumen and Heavy Crude Oil($/bbl)(1) (2) (3)                                   |  |      |       |  |    |  |       |    |  |  |       |  |  |    |       |  |  |  |       |  
|Price                                                                                 |  |      | 32.73 |  |    |  | 24.87 |    |  |  | 31.63 |  |  |    | 47.24 |  |  |  | 28.15 |  
|Royalties                                                                             |  |      | 1.07  |  |    |  | 0.59  |    |  |  | 0.75  |  |  |    | 2.35  |  |  |  | 0.68  |  
|Transportation and blending                                                           |  |      | 5.97  |  |    |  | 6.26  |    |  |  | 6.08  |  |  |    | 5.69  |  |  |  | 5.83  |  
|Operating expenses                                                                    |  |      | 11.31 |  |    |  | 10.62 |    |  |  | 10.62 |  |  |    | 11.70 |  |  |  | 12.35 |  
|Production and mineral taxes                                                          |  |      | 0.01  |  |    |  | (0.01 | )  |  |  | 0.01  |  |  |    | 0.02  |  |  |  | -     |  
|Netback                                                                               |  |      | 14.37 |  |    |  | 7.41  |    |  |  | 14.17 |  |  |    | 27.48 |  |  |  | 9.29  |  

|                                                                                                                                                                                                                                                                     |  |  |  |  |  |  |  |  |  | 
|-------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------- |  |  |  |  |  |  |  |  |  | 
|(1)   Netbacks do not reflect non-cash write-downs of product inventory.
(2)   Cost of condensate per barrel of unblended crude oil ($/bbl).
(3)   Employee long-term incentive costs were reclassified from operating expenses to general and
administrative costs.



| | Bitumen and heavy crude oil price and transportation and blending costs exclude the costs of purchased condensate, which is blended with the bitumen and heavy crude oil. On a per-barrel of unblended bitumen and heavy
crude oil basis, the cost of condensate is as follows:
| | -------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------

Bitumen  Foster Creek ($/bbl)


27.44



25.96



24.20



29.82



30.57Bitumen  Christina Lake ($/bbl)


29.50



27.39



26.42



32.90



31.60Bitumen  Oil Sands ($/bbl)


28.54



26.72



25.33



31.48



31.14Heavy Crude Oil  Conventional ($/bbl)


10.94



9.99



9.56



12.42



11.50Total Bitumen and Heavy Crude Oil($/bbl)


24.94



23.64



22.34



27.06



26.91




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|                                                                                                                                                                                                   |  |      |       |  |    |  |       |    |  |  |       |  |  |    |       |  |  |  |       | 
|-------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------- |  | ---- | ----- |  | -- |  | ----- | -- |  |  | ----- |  |  | -- | ----- |  |  |  | ----- | 
|Per-Unit Results  2015                                                                                                                                                                            |  |      |       |  |    |  |       |    |  |  |       |  |  |    |      
|(excluding impact of realized gain (Loss) on risk management)                                                                                                                                      |  | Year |       |  | Q4 |  |       | Q3 |  |  | Q2    |  |  | Q1 |      
|Light and Medium Crude Oil($/bbl)(1)                                                                                                                                                               |  |      |       |  |    |  |       |    |  |  |       |  |  |    |       |  |  |  |       | 
|Price                                                                                                                                                                                              |  |      | 50.64 |  |    |  | 45.35 |    |  |  | 49.57 |  |  |    | 61.66 |  |  |  | 45.81 | 
|Royalties                                                                                                                                                                                          |  |      | 5.66  |  |    |  | 6.97  |    |  |  | 7.02  |  |  |    | 5.67  |  |  |  | 3.56  | 
|Transportation and blending                                                                                                                                                                        |  |      | 2.91  |  |    |  | 2.80  |    |  |  | 2.88  |  |  |    | 3.06  |  |  |  | 2.88  | 
|Operating expenses                                                                                                                                                                                 |  |      | 16.27 |  |    |  | 17.37 |    |  |  | 15.92 |  |  |    | 15.90 |  |  |  | 16.04 | 
|Production and mineral taxes                                                                                                                                                                       |  |      | 1.41  |  |    |  | 0.76  |    |  |  | 1.60  |  |  |    | 1.95  |  |  |  | 1.28  | 
|Netback                                                                                                                                                                                            |  |      | 24.39 |  |    |  | 17.45 |    |  |  | 22.16 |  |  |    | 35.08 |  |  |  | 22.05 | 
|Total Bitumen and Crude Oil
(Heavy, Light and Medium)($/bbl)(1) (2)                                                                                                                                |  |      |       |  |    |  |       |    |  |  |       |  |  |    |       |  |  |  |       | 
|Price                                                                                                                                                                                              |  |      | 35.41 |  |    |  | 27.62 |    |  |  | 34.08 |  |  |    | 49.55 |  |  |  | 31.09 | 
|Royalties                                                                                                                                                                                          |  |      | 1.75  |  |    |  | 1.44  |    |  |  | 1.60  |  |  |    | 2.88  |  |  |  | 1.16  | 
|Transportation and blending                                                                                                                                                                        |  |      | 5.51  |  |    |  | 5.79  |    |  |  | 5.64  |  |  |    | 5.27  |  |  |  | 5.34  | 
|Operating expenses                                                                                                                                                                                 |  |      | 12.05 |  |    |  | 11.52 |    |  |  | 11.35 |  |  |    | 12.37 |  |  |  | 12.97 | 
|Production and mineral taxes                                                                                                                                                                       |  |      | 0.22  |  |    |  | 0.10  |    |  |  | 0.23  |  |  |    | 0.33  |  |  |  | 0.22  | 
|Netback                                                                                                                                                                                            |  |      | 15.88 |  |    |  | 8.77  |    |  |  | 15.26 |  |  |    | 28.70 |  |  |  | 11.40 | 
|Natural Gas Liquids($/bbl)                                                                                                                                                                         |  |      |       |  |    |  |       |    |  |  |       |  |  |    |       |  |  |  |       | 
|Price                                                                                                                                                                                              |  |      | 30.98 |  |    |  | 30.70 |    |  |  | 24.57 |  |  |    | 39.64 |  |  |  | 28.51 | 
|Royalties                                                                                                                                                                                          |  |      | 1.74  |  |    |  | 3.94  |    |  |  | 1.75  |  |  |    | 0.87  |  |  |  | 0.66  | 
|Netback                                                                                                                                                                                            |  |      | 29.24 |  |    |  | 26.76 |    |  |  | 22.82 |  |  |    | 38.77 |  |  |  | 27.85 | 
|Total Bitumen, Crude Oil (Heavy, Light and Medium)
and Natural Gas Liquids($/bbl)(1) (2)                                                                                                           |  |      |       |  |    |  |       |    |  |  |       |  |  |    |       |  |  |  |       | 
|Price                                                                                                                                                                                              |  |      | 35.38 |  |    |  | 27.63 |    |  |  | 34.03 |  |  |    | 49.48 |  |  |  | 31.08 | 
|Royalties                                                                                                                                                                                          |  |      | 1.75  |  |    |  | 1.46  |    |  |  | 1.60  |  |  |    | 2.86  |  |  |  | 1.16  | 
|Transportation and blending                                                                                                                                                                        |  |      | 5.48  |  |    |  | 5.76  |    |  |  | 5.61  |  |  |    | 5.24  |  |  |  | 5.31  | 
|Operating expenses                                                                                                                                                                                 |  |      | 11.98 |  |    |  | 11.46 |    |  |  | 11.28 |  |  |    | 12.29 |  |  |  | 12.89 | 
|Production and mineral taxes                                                                                                                                                                       |  |      | 0.22  |  |    |  | 0.10  |    |  |  | 0.23  |  |  |    | 0.33  |  |  |  | 0.22  | 
|Netback                                                                                                                                                                                            |  |      | 15.95 |  |    |  | 8.85  |    |  |  | 15.31 |  |  |    | 28.76 |  |  |  | 11.50 | 
|Total Natural Gas($/Mcf)(1)                                                                                                                                                                        |  |      |       |  |    |  |       |    |  |  |       |  |  |    |       |  |  |  |       | 
|Price                                                                                                                                                                                              |  |      | 2.92  |  |    |  | 2.78  |    |  |  | 3.00  |  |  |    | 2.82  |  |  |  | 3.05  | 
|Royalties                                                                                                                                                                                          |  |      | 0.07  |  |    |  | 0.10  |    |  |  | 0.11  |  |  |    | 0.03  |  |  |  | 0.05  | 
|Transportation and blending                                                                                                                                                                        |  |      | 0.11  |  |    |  | 0.11  |    |  |  | 0.10  |  |  |    | 0.10  |  |  |  | 0.12  | 
|Operating expenses                                                                                                                                                                                 |  |      | 1.20  |  |    |  | 1.25  |    |  |  | 1.16  |  |  |    | 1.14  |  |  |  | 1.26  | 
|Production and mineral taxes                                                                                                                                                                       |  |      | 0.01  |  |    |  | 0.02  |    |  |  | 0.01  |  |  |    | 0.02  |  |  |  | 0.01  | 
|Netback                                                                                                                                                                                            |  |      | 1.53  |  |    |  | 1.30  |    |  |  | 1.62  |  |  |    | 1.53  |  |  |  | 1.61  | 
|Total($/BOE)(1) (2)                                                                                                                                                                                |  |      |       |  |    |  |       |    |  |  |       |  |  |    |       |  |  |  |       | 
|Price                                                                                                                                                                                              |  |      | 30.67 |  |    |  | 24.78 |    |  |  | 29.95 |  |  |    | 40.50 |  |  |  | 27.73 | 
|Royalties                                                                                                                                                                                          |  |      | 1.40  |  |    |  | 1.23  |    |  |  | 1.36  |  |  |    | 2.13  |  |  |  | 0.93  | 
|Transportation and blending                                                                                                                                                                        |  |      | 4.21  |  |    |  | 4.43  |    |  |  | 4.35  |  |  |    | 3.95  |  |  |  | 4.11  | 
|Operating expenses                                                                                                                                                                                 |  |      | 10.72 |  |    |  | 10.43 |    |  |  | 10.18 |  |  |    | 10.78 |  |  |  | 11.49 | 
|Production and mineral taxes                                                                                                                                                                       |  |      | 0.18  |  |    |  | 0.10  |    |  |  | 0.19  |  |  |    | 0.27  |  |  |  | 0.17  | 
|Netback                                                                                                                                                                                            |  |      | 14.16 |  |    |  | 8.59  |    |  |  | 13.87 |  |  |    | 23.37 |  |  |  | 11.03 | 
|(1)    Employee long-term incentive costs were reclassified from operating expenses to
general and administrative costs. (2)    Netbacks do not reflect non-cash
write-downs of product inventory. |  |      |       |  |    |  |       |    |  |  |       |  |  |    |       |  | 
|Impact of Realized Gain (Loss) on Risk Management  2015                                                                                                                                           |  | Year |       |  | Q4 |  |       | Q3 |  |  | Q2    |  |  | Q1 |      
|Liquids ($/bbl)                                                                                                                                                                                    |  |      | 7.51  |  |    |  | 11.39 |    |  |  | 10.07 |  |  |    | 1.75  |  |  |  | 6.58  | 
|Natural Gas ($/Mcf)                                                                                                                                                                                |  |      | 0.37  |  |    |  | 0.42  |    |  |  | 0.37  |  |  |    | 0.39  |  |  |  | 0.29  | 
|Total ($/BOE)                                                                                                                                                                                      |  |      | 6.11  |  |    |  | 9.08  |    |  |  | 8.07  |  |  |    | 1.92  |  |  |  | 5.31  | 



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Capital Expenditures, Acquisitions and Divestitures

Cenovus has a large inventory of internal growth opportunities and continues to examine select acquisition opportunities to develop and expand its oil and
gas properties. Acquisition opportunities may include corporate or asset acquisitions. Cenovus may finance any such acquisitions with debt, equity, cash generated from operations, proceeds from asset divestitures or a combination of these sources.

2015: Cenovus has an active program to divest its non-core assets in order to increase its focus on key assets within the long range business plan,
as well as generate proceeds to partially fund its capital investment. In the third quarter, Cenovus sold HRP, the holder of its royalty interest and mineral fee title lands business in Alberta, Saskatchewan and Manitoba to an unrelated third party
for gross cash proceeds of $3.3 billion. Also in the third quarter, Cenovus acquired the Bruderheim rail terminal, a crude-by-rail terminal at Bruderheim, Alberta for $75 million plus adjustments.

2014: Early in the second quarter, Cenovus completed the sale of certain of its Bakken assets for net proceeds of $35 million. Immediately prior to the
disposition, the properties were producing an average of 396 barrels per day during the first quarter of 2014. Late in the third quarter, Cenovus also completed the sale of certain Wainwright properties for net proceeds of $234 million. The
properties were producing an average of 2,775 barrels per day during the first nine months of 2014.

The following table summarizes Cenovuss net
capital investment for 2015 and 2014:



|                                         |  |      |        |   |      |  |       | 
|---------------------------------------- |  | ---- | ------ | - | ---- |  | ----- | 
|Net Capital Investment                   |  |      |        |   |      | 
|($ millions)                             |  | 2015 |        |   | 2014 | 
|                                         | 
|Capital Investment                       |  |      |        |   |      |  |       | 
|Oil Sands                                |  |      |        |   |      |  |       | 
|Foster Creek                             |  |      | 403    |   |      |  | 796   | 
|Christina Lake                           |  |      | 647    |   |      |  | 794   | 
|                                         | 
|Total                                    |  |      | 1,050  |   |      |  | 1,590 | 
|Other Oil Sands                          |  |      | 135    |   |      |  | 396   | 
|                                         | 
|                                         |  |      | 1,185  |   |      |  | 1,986 | 
|Conventional                             |  |      | 244    |   |      |  | 840   | 
|                                         | 
|Refining and Marketing                   |  |      | 248    |   |      |  | 163   | 
|Corporate                                |  |      | 37     |   |      |  | 62    | 
|                                         | 
|Capital Investment                       |  |      | 1,714  |   |      |  | 3,051 | 
|                                         | 
|Acquisitions                             |  |      | 87     |   |      |  | 18    | 
|Divestitures                             |  |      | (3,344 | ) |      |  | (277) | 
|                                         | 
|Net Acquisition and Divestiture Activity |  |      | (3,257 | ) |      |  | (259) | 
|                                         | 
|Net Capital Investment (1)               |  |      | (1,543 | ) |      |  | 2,792 | 
|                                         | 



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

OTHER INFORMATION





COMPETITIVE CONDITIONS All aspects of the oil and gas industry are highly competitive. Refer to Risk Factors  Operational Risks 
Competition for further information on the competitive conditions affecting Cenovus. ENVIRONMENTAL CONSIDERATIONS Cenovuss operations are subject to laws and regulations concerning protection of the environment, pollution and the handling and transport of
hazardous materials. These laws and regulations generally require the Corporation to remove or remedy the effect of its activities on the environment at present and former operating sites, including dismantling production facilities and remediating
damage caused by the use or release of specified substances. The Safety, Environment and Responsibility Committee of the Corporations Board reviews and recommends policies pertaining to corporate responsibility, including the environment, and
oversees compliance with government 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 event and remediation/reclamation programs have been put in place and utilized to restore the environment. Cenovus recognizes that there is a cost associated with carbon emissions and it believes that greenhouse gas (GHG) regulations and the cost of
carbon at various price levels can be adequately accounted for as part of business planning. As part of the Corporations future planning, Management and the Board review the impact of a variety of carbon constrained scenarios on Cenovuss
strategy. Although uncertainty remains regarding potential future emissions regulation, the Corporation will continue to assess and evaluate the cost of carbon relative to its investments across a range of scenarios. For a discussion of the risks
associated with this uncertainty, see Risk Factors  Environment & Regulatory Risks  Climate Change.






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Cenovus also examines the impact of carbon regulation on its major projects, including its oil sands
operations and its refining assets. Cenovus continues to closely monitor potential GHG legislation and litigation developments both in Canada and in the U.S. Cenovus expects to incur abandonment and site reclamation costs as existing oil and gas properties are abandoned and reclaimed. In 2015, expenditures
beyond normal compliance with environmental regulations were considered to be in the ordinary course of business. Cenovus does not anticipate material expenditures beyond amounts paid in respect of normal compliance with environmental regulations in
2016. Refer to Risk Factors  Environment & Regulatory Risks  Environmental Regulations for further information on environmental protection matters affecting Cenovus.


CORPORATE RESPONSIBILITY We are committed to operating in a responsible manner and integrating our corporate responsibility principles in the way we conduct our business. Our
Corporate Responsibility (CR) policy guides our activities in the areas of: Leadership; Corporate Governance and Business Practices; People; Environmental Performance; Stakeholder and Aboriginal Engagement; and Community Involvement and
Investment. We published our 2014 CR report in June 2015, detailing our efforts to accelerate our environmental performance, protect the health and
safety of our staff, invest in and engage with the communities where we operate and maintain the highest standards of corporate governance. Our CR report also lists external recognition we received for our commitment to corporate responsibility and
our efforts to balance economic, governance, social and environmental performance. Our CR policy and CR report are available on our website at cenovus.com.






EMPLOYEES

The following table summarizes Cenovuss full-time equivalent (FTE) employees as at December 31, 2015:



|           |  |               |       | 
|---------- |  | ------------- | ----- | 
|           |  | FTE Employees |      
|           | 
|Upstream   |  |               | 2,001 | 
|Downstream |  |               | 127   | 
|Corporate  |  |               | 877   | 
|           | 
|Total      |  |               | 3,005 | 
|           | 

Cenovus also engages a number of contractors and service providers. Refer to Risk
Factors - Operational Risks - Leadership and Talent for further information on employee matters affecting Cenovus.

FOREIGN OPERATIONS

Cenovus, and its reportable segments, are not dependent upon foreign operations outside North America. As a result, the Corporations exposure to
risks and uncertainties in countries considered politically and economically unstable is limited. Any future operations outside North America may be adversely affected by changes in government policy, social instability or other political or
economic developments which are not within Cenovuss control, including the expropriation of property, the cancellation or modification of contract rights and restrictions on repatriation of cash. Refer to Risk Factors  Financial
Risks  Foreign Exchange Rates for information on foreign exchange rate matters affecting Cenovus.



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DIRECTORS AND EXECUTIVE OFFICERS



DIRECTORS

The following individuals are directors of Cenovus.



|                                                          |  |                          |  |                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                 
|--------------------------------------------------------- |  | ------------------------ |  | ----------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------
|Name and
Residence                                        |  | Director
Since (1)       |  | Principal Occupation During the Past Five Years                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                 
|                                                          |  |                         
|Ralph S.
Cunningham (3,4,6)
Houston, Texas, United States |  | 2009 Independent         |  | Mr. Cunningham is a director of TETRA Technologies, Inc., a publicly traded energy services and chemicals company, and served as Chairman from December 2006 to
May 2015. Mr. Cunningham also served as Chairman of Enterprise Products Holdings, LLC, the successor general partner of Enterprise Products Partners L.P., a publicly traded midstream energy limited partnership, from November 2010
to February 2013, and as a director from February 2013 to April 2014; and as a director of Agrium Inc., a publicly traded agricultural chemicals company from December 1996 to April 2013.                                                                                                                                                                                                                                                                                                                                                                                                                
|                                                          |  |                         
|Patrick D.
Daniel(2,3,4)
Calgary, Alberta, Canada         |  | 2009 Independent         |  | Mr. Daniel is a director of Canadian Imperial Bank of Commerce; and Capital Power Corporation, a publicly traded North American power producer; and Chair of the North
American Review Board of American Air Liquide Holdings, Inc., a subsidiary of a publicly traded industrial gases service company. Mr. Daniel served as a director of Enbridge Inc., a publicly traded energy delivery company from
April 2000 to October 2012. During his tenure with Enbridge, he also served as President & Chief Executive Officer from January 2001 to February 2012 and as Chief Executive Officer from February 2012 to
October 2012. He is a member of the Association of Professional Engineers and Geoscientists of Alberta.                                                                                                                                                                                                                                                                                    
|                                                          |  |                         
|Ian W.
Delaney (3,4,6)
Toronto, Ontario, Canada           |  | 2009 Independent         |  | Mr. Delaney is Chairman of The Westaim Corporation, a publicly traded investment company; and Ontario Air Ambulance Services Co. (Ornge) a not-for-profit medical air and ground transportation organization. Mr. Delaney served as a director of Sherritt International Corporation (Sherritt), a
publicly traded diversified natural resource company that produces nickel, cobalt, thermal coal, oil and gas and electricity from October 1995 to May 2013. He also served as Chairman and Chief Executive Officer of Sherritt from
January 2009 to December 2011 and Chairman of Sherritt from January 2012 to May 2013. Mr. Delaney also served as Chairman of UrtheCast Corp. (formerly Longford Energy Inc.), a publicly traded video technology
development company, from August 2012 to October 2013 and as a director of Dacha Strategic Metals Inc., a publicly traded investment company focused on the acquisition, storage and trading of strategic metals from November 2012
to September 2014.
|                                                          |  |                         
|Brian C.
Ferguson
(7) Calgary, Alberta,
Canada            |  | 2009                     |  | Mr. Ferguson has been President & Chief Executive Officer of Cenovus since its formation on November 30, 2009. Mr. Ferguson is a Fellow of the
Chartered Professional Accountants of Alberta and a member of the Chartered Professional Accountants of Canada. Mr. Ferguson has served as a director of The Toronto-Dominion Bank since
April 2015.                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                             
|                                                          |  |                         
|Michael A.
Grandin (4,8)
Calgary, Alberta, Canada         |  | 2009 (Chair) Independent |  | Mr. Grandin is the Chair of Cenovuss Board. He is also a director of BNS Split Corp. II, a publicly traded investment company; and HSBC Bank
Canada.                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                           



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|                                                           |  |                    |  |                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                              
|---------------------------------------------------------- |  | ------------------ |  | ---------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------
|Name and
Residence                                         |  | Director
Since (1) |  | Principal Occupation During the Past Five Years                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                              
|                                                           |  |                   
|Steven F. Leer (2,4,5)
Boca Grande, Florida, United States |  | 2015 Independent   |  | Mr. Leer is a lead director of Norfolk Southern Corporation, a publicly traded North American rail transportation provider; a lead director of USG Corporation
(USG), a publicly traded manufacturer and distributor of high performance building systems; and a director of Parsons Corporation, a private engineering, construction, technical, and management services firm. Mr. Leer served as
Chairman of Arch Coal, Inc. (Arch Coal), a publicly traded coal producing company, from April 2006 to April 2014, and served as a director of Arch Coal and its predecessor company from 1992. During his tenure with Arch
Coal and its predecessor company, he also served as Chief Executive Officer from July 1992 to April 2012.  
|                                                           |  |                   
|Valerie A.A.
Nielsen(2,4,5)
Calgary, Alberta, Canada       |  | 2009 Independent   |  | Ms. Nielsen was a director of Wajax Corporation, a publicly traded industrial parts and service company, from June 1995 to May 2012.                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                         
|                                                           |  |                   
|Charles M.
Rampacek(4,5,6)
Dallas, Texas, United States    |  | 2009 Independent   |  | Mr. Rampacek is a director of Flowserve Corporation, a publicly traded manufacturer of industrial equipment; and Energy Services Holdings, LLC, a private
industrial services company that was formed in 2012 from the combination of Ardent Holdings, LLC and another company. Mr. Rampacek previously served as Chair of Ardent Holdings, LLC, from December 2008 to July 2012.
Mr. Rampacek also served as a director of Enterprise Products Holdings, LLC, the sole general partner of Enterprise Products Partners, L.P., a publicly traded midstream energy limited partnership from November 2006 to
September 2011; and Pilko & Associates L.P., a private chemical and energy advisory company from September 2011 to February 2014.
|                                                           |  |                   
|Colin Taylor (2,3,4)
Toronto, Ontario, Canada              |  | 2009 Independent   |  | Mr. Taylor served two consecutive four-year terms as Chief Executive & Managing Partner of Deloitte LLP and then
acted as Senior Counsel until his retirement in May 2008. Mr. Taylor is a Fellow of the Chartered Professional Accountants of Ontario and a member of the Chartered Professional Accountants of Canada.                                                                                                                                                                                                                                                                                                                                                                                                                     
|                                                           |  |                   
|Wayne G. Thomson
(4,5,6)
Calgary, Alberta, Canada          |  | 2009 Independent   |  | Mr. Thomson is a director of TVI Pacific Inc., a publicly traded international
mining company; Chairman of Maha Energy Inc., a private North American oil and gas company; Chairman of Inventys Thermal Technologies Inc., a private carbon capture technology company; a director of Iskander Energy Corp., a private
international oil and gas company; and Chairman and President of Enviro Valve Inc., a private company manufacturing proprietary pressure relief valves. Mr. Thomson served as Chief Executive Officer of Iskander Energy Corp. from
November 2011 to August 2014. Mr. Thomson is a member of the Association of Professional Engineers and Geoscientists of Alberta.                                                  



| | (1) | Each of the directors first became members of Cenovuss Board pursuant to the Arrangement, with the exception of Mr. Leer who was elected as a
director of Cenovuss Board at the April 29, 2015 Annual and Special Meeting of Shareholders. The term of each of the directors is from the date of the meeting at which he or she is elected or appointed until the next annual meeting of
shareholders or until a successor is elected or appointed.
| | --- | -----------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------

| | (2) | Member of the Audit Committee.
| | --- | ------------------------------

| | (3) | Member of the Human Resources and Compensation Committee.
| | --- | ---------------------------------------------------------

| | (4) | Member of the Nominating and Corporate Governance Committee.
| | --- | ------------------------------------------------------------

| | (5) | Member of the Reserves Committee.
| | --- | ---------------------------------

| | (6) | Member of the Safety, Environment and Responsibility Committee.
| | --- | ---------------------------------------------------------------

| | (7) | As an officer and a non-independent director, Mr. Ferguson is not a member of any of the committees of
Cenovuss Board.
| | --- | -----------------------------------------------------------------------------------------------------------------------

| | (8) | Ex-officio, by standing invitation, non-voting member of all other
committees of Cenovuss Board. As an ex-officio non-voting member, Mr. Grandin attends as his schedule permits and may vote when necessary to achieve a quorum.
| | --- | ----------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------



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EXECUTIVE OFFICERS

The following individuals served as executive officers of Cenovus as at December 31, 2015.



|                                                              |  |                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                       
|------------------------------------------------------------- |  | ----------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------
|Name and Residence                                            |  | Office Held and Principal Occupation During the Past Five Years                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                       
|                                                              | 
|Brian C. Ferguson
Calgary, Alberta, Canada                    |  | President & Chief Executive Officer
Mr. Fergusons biographical information is included under Directors.                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                            
|                                                              | 
|Ivor M. Ruste
Calgary, Alberta, Canada                        |  | Executive Vice-President & Chief Financial Officer
Mr. Ruste has been Executive Vice-President & Chief Financial Officer of Cenovus since its formation on November 30, 2009.                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                         
|                                                              | 
|Harbir S. Chhina
Calgary, Alberta, Canada                     |  | Executive Vice-President, Oil Sands Development
Mr. Chhina became Executive Vice-President, Oil Sands Development on September 1, 2015. From December 2010 to August 2015, Mr. Chhina was
Cenovuss Executive Vice-President, Oil Sands. From November 2009 to November 2010, Mr. Chhina was Cenovuss Executive Vice-President, Enhanced Oil Development & New Resource Plays.                                                                                                                                                                                                                                                                                                                                                                                       
|                                                              | 
|Judy A. Fairburn
Calgary, Alberta, Canada                     |  | Executive Vice-President, Business Innovation
Ms. Fairburn became Executive Vice-President, Business Innovation on December 1, 2015. From February 2013 to November 2015, Ms. Fairburn was
Cenovuss Executive Advisor. From November 2009 to January 2013, Ms. Fairburn was Cenovuss Executive Vice-President, Environment & Strategic Planning.                                                                                                                                                                                                                                                                                                                                                                                                                    
|                                                              | 
|Jacqueline (Jacqui) A.T. McGillivray
Calgary, Alberta, Canada |  | Executive Vice-President, Safety & Organization Effectiveness
Ms. McGillivray became Executive Vice-President, Safety & Organization Effectiveness on July 1, 2015. From October 2012 to June 2015, Ms.
McGillivray was Cenovuss Senior Vice-President & Chief People Officer. From November 2010 to October 2012, Ms. McGillivray was Head of Global Human Resources at Talisman Energy Inc.                                                                                                                                                                                                                                                                                                                                                                        
|                                                              | 
|Robert W. Pease
Calgary, Alberta, Canada                      |  | Executive Vice-President, Corporate Strategy & President, Downstream
Mr. Pease became Executive Vice-President, Corporate Strategy & President, Downstream on July 1, 2015. From June 2014 to June 2015, Mr. Pease was
Cenovuss Executive Vice-President, Markets, Products & Transportation. From February 2014 to May 2014, Mr. Pease was Vice President, Global Business Excellence, Supply & Trading of Shell Trading (US) Company, a corporation that acts as
the market interface for Royal Dutch Shell companies and affiliates in the U.S.; and from November 2008 until January 2014, he was President and Chief Executive Officer of Motiva Enterprises LLC, a refiner, distributer and marketer of fuels in the
eastern and Gulf Coast regions of the U.S.
|                                                              | 
|Alan C. Reid
Calgary, Alberta, Canada                         |  | Executive Vice-President, Environment, Corporate Affairs, Legal & General Counsel
Mr. Reid became Executive Vice-President, Environment, Corporate Affairs, Legal & General Counsel on December 1, 2015. From September 2015 to
November 2015, Mr. Reid was Cenovuss Executive Vice-President, Environment, Corporate Affairs & Legal. From January 2014 to August 2015, Mr. Reid was Cenovuss Senior Vice-President, Christina Lake & Narrows Lake. From January
2012 to January 2014, Mr. Reid was Cenovuss Senior Vice-President, Christina Lake. From November 2009 to January 2012, Mr. Reid was Cenovuss Vice-President, Regulatory, Health & Safety.                                                                                                       
|                                                              | 
|J. Drew Zieglgansberger
Calgary, Alberta, Canada              |  | Executive Vice-President, Oil Sands Manufacturing
Mr. Zieglgansberger became Executive Vice-President, Oil Sands Manufacturing on September 1, 2015. From June 2015 to August 2015, Mr.
Zieglgansberger was Cenovuss Executive Vice-President, Operations Shared Services. From June 2012 to May 2015, Mr. Zieglgansberger was Cenovuss Senior Vice-President, Operations Shared Services. From January 2012 to May 2012,
Mr. Zieglgansberger was Cenovuss Senior Vice-President, Regulatory, Local Community & Military. From December 2010 to January 2012, Mr. Zieglgansberger was Cenovuss Senior Vice-President, Christina Lake.                                                                                                                             



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As of December 31, 2015, all of Cenovuss directors and executive officers, as a group,
beneficially owned or exercised control or direction over, directly or indirectly, 1,055,623 common shares of Cenovus (Common Shares) or approximately 0.127 percent of the number of Common Shares that were outstanding as of such date.

Investors should be aware that some of Cenovuss directors and officers are directors and officers of other private and public companies. Some
of these private and public companies may, from time to time, be involved in business transactions or banking relationships which may create situations in which conflicts might arise. Any such conflicts shall be resolved in accordance with the
procedures and requirements of the relevant provisions of the CBCA, including the duty of such directors and officers to act honestly and in good faith with a view to the best interests of Cenovus.

CEASE TRADE ORDERS, BANKRUPTCIES, PENALTIES OR SANCTIONS



To the Corporations knowledge, none of its current directors or executive officers are, as at the
date of this AIF, or have been, within 10 years prior to the date of this AIF, a director, chief executive officer or chief financial officer of any company that:  (a)
was subject to a cease trade order, an order similar to a cease trade order or an order that denied the relevant company access to any exemption under
securities legislation, that was in effect for a period of more than 30 consecutive days (collectively, an Order) and that was issued while that person was acting in the capacity as director, chief executive officer or chief
financial officer; or  (b)
was subject to an Order that was issued after the director or executive officer ceased to be a director, chief executive officer or chief financial officer of
the Corporation being the subject of such an Order and which resulted from an event that occurred while that person was acting in the capacity as director, chief executive officer or chief financial officer. To the Corporations knowledge, other than as described below, none of its directors or executive officers:  (a)
is, as at the date of this AIF, or has been within 10 years prior to the date of this AIF, a director or executive officer of any company that, while that
person was acting in that capacity, or within a year of that person ceasing to act in that capacity, became bankrupt, made a proposal under any legislation relating to bankruptcy or insolvency or was subject to or instituted any proceedings,
arrangement or compromise with creditors or had a receiver, receiver manager or trustee appointed to hold its assets; or  (b)
has, within 10 years prior to the date of this AIF, become bankrupt, made a proposal under any legislation relating to bankruptcy or insolvency, or become
subject to or instituted any proceedings, arrangement or compromise with creditors, or had a receiver, receiver manager or trustee appointed to hold the assets of the director or executive officer.


To the Corporations knowledge, none of its directors or executive officers has been subject to:  (a)
any penalties or sanctions imposed by a court relating to securities legislation or by a securities regulatory authority or has entered into a settlement
agreement with a securities regulatory authority; or  (b)
any other penalty or sanctions imposed by a court or regulatory body that would likely be considered important to a reasonable investor in making an
investment decision. Mr. Delaney was a director of OPTI Canada Inc. (OPTI) when it commenced proceedings for
creditor protection under the Companies Creditors Arrangement Act (Canada) (CCAA) on July 13, 2011. Ernst & Young Inc. was appointed as monitor of OPTI. On November 28, 2011, OPTI announced that it had
closed a transaction whereby a subsidiary of CNOOC Limited acquired all of the outstanding securities of OPTI pursuant to a plan of arrangement under the CCAA and the Canada Business Corporations Act. On June 25, 2001, USG and 10 of its subsidiaries filed for reorganization under Chapter 11 of the Bankruptcy Code (U.S.). On June 20, 2005,
Mr. Leer joined the board of directors of USG. On February 17, 2006, USG announced a joint plan of reorganization pursuant to which all creditors would be paid in full. On June 20, 2006, the plan received court approval and USG and
those subsidiaries emerged from bankruptcy. Mr. Rampacek was the Chairman and President & Chief Executive Officer of Probex Corporation
(Probex) in 2003 when it filed a petition seeking relief under Chapter 7 of the Bankruptcy Code (U.S.). In 2005, as a result of the bankruptcy, two complaints seeking recovery of certain alleged losses were filed against former Probex
officers and directors, including Mr. Rampacek. These complaints were defended by American International Group, Inc. (AIG) in accordance with the Probex director and officer insurance policy and settlement was reached and paid by
AIG, with bankruptcy court approval, in 2006. An additional complaint was filed in 2005 against noteholders of certain Probex debt, of which Mr. Rampacek was a party. A settlement of $2,000 was reached, with bankruptcy court approval, in 2006.






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AUDIT COMMITTEE



The Audit Committee mandate is included as
Appendix C to this AIF.

COMPOSITION OF THE AUDIT COMMITTEE



The Audit Committee consists of four members, each of whom is independent and financially literate in
accordance with National Instrument 52-110 Audit Committees (NI 52-110). The education and experience of each of the members of the Audit Committee relevant to the performance of the responsibilities as an Audit Committee member
is outlined below. Patrick D. Daniel Mr. Daniel holds a Bachelor of Science (University of Alberta) and a Master of Science (University of British Columbia), both in chemical
engineering. He also completed Harvard Universitys Advanced Management Program. He is a past Chief Executive Officer and director of Enbridge Inc., a publicly traded energy delivery company. He is also a past director and member of the audit
committee of Enerflex Systems Income Fund, a compression systems manufacturer and a past director and Chair of the finance committee of Synenco Energy Inc., an oil sands mining company which was acquired by Total E&P Canada Ltd. in August 2008. Steven F. Leer Mr. Leer holds a Bachelor of Electrical Engineering (University of the Pacific) and a Master of Business Administration (Olin School of Business,
Washington University). He was awarded an honorary doctorate by University of the Pacific in May 1993. Mr. Leer is a lead director of Norfolk Southern Corporation, a publicly traded North American rail transportation provider; a lead director
of USG Corporation (USG), a publicly traded manufacturer and distributor of high performance building systems; and a director of Parsons Corporation, a private engineering, construction, technical, and management services firm.
Mr. Leer served as Chairman of Arch Coal, Inc. (Arch Coal), a publicly traded coal producing company, from April 2006 to April 2014, and served as a director of Arch Coal and its predecessor company from 1992. During
his tenure with Arch Coal and its predecessor company he also served as Chief Executive Officer from July 1992 to April 2012 and President from July 1992 to April 2006. He is a member of the Board of Trustees of Washington
University in St. Louis and he is a former director of the Business Roundtable and the National Association of Manufacturers. Valerie A.A. Nielsen Ms. Nielsen holds a Bachelor of Science (Hon.) (Dalhousie University). She is a professional
geophysicist who has held management positions and provided consulting services to the oil and gas industry for over 30 years. She has also completed


several finance and accounting courses at the university level. Ms. Nielsen was a member and past chair of an advisory group on the General Agreement on Tariffs and Trade (GATT), the North
America Free Trade Agreement (NAFTA) and international trade matters pertaining to energy, chemicals and plastics from 1986 to 2002. She is a past director and served on the audit committee of Wajax Corporation, a publicly traded company engaged in
the sale and after-sales parts and service support of mobile equipment, diesel engines and industrial components. She is a past director of the Bank of Canada and of the Canada Olympic Committee. Colin Taylor (Financial Expert and Audit Committee Chair) Mr. Taylor is a chartered professional accountant, a Fellow of the
Chartered Professional Accountants of Ontario and a member of the Chartered Professional Accountants of Canada. He also completed Harvard Universitys Advanced Management Program. Mr. Taylor served two consecutive four-year terms (June
1996 to May 2004) as Chief Executive and Managing Partner of Deloitte LLP and continued as Senior Counsel until his retirement in May 2008. He has held a number of international management and governance responsibilities throughout his
professional career. Mr. Taylor also served as Advisory Partner to a number of public and private company clients of Deloitte LLP. The
above list does not include Michael A. Grandin who is, by standing invitation, an ex-officio member of Cenovuss Audit Committee. Pre-Approval Policies and Procedures Cenovus has adopted policies and procedures with respect to the pre-approval of
audit and permitted non-audit services to be provided by PricewaterhouseCoopers LLP. The Audit Committee has established a budget for the provision of a specified list of audit and permitted non-audit services that the Audit Committee believes to be
typical, recurring or otherwise likely to be provided by PricewaterhouseCoopers LLP. Subject to the Audit Committees discretion, the budget generally covers the period between the adoption of the budget and the next meeting of the Audit
Committee. The list of permitted services is sufficiently detailed to ensure that: (i) the Audit Committee knows precisely what services it is being asked to pre-approve; and (ii) it is not necessary for any member of Management to make a
judgment as to whether a proposed service fits within the pre-approved services. Subject to the following paragraph, the Audit Committee has
delegated authority to the Chair of






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the Audit Committee (or if the Chair is unavailable, any other member of the Audit Committee) to pre-approve the provision of permitted services by PricewaterhouseCoopers LLP which are not
otherwise pre-approved by the Audit Committee, including the fees and terms of the proposed services (Delegated Authority). Any required determination about the Chairs unavailability will be required to be made by the good faith
judgment of the applicable other member(s) of the Audit Committee after considering all facts and circumstances deemed by such member(s) to be relevant. All pre-approvals granted pursuant to Delegated Authority must be presented by the member(s) who
granted the pre-approvals to the full Audit Committee at its next meeting.


The fees payable in connection with any particular service to be provided by PricewaterhouseCoopers LLP
that has been pre-approved pursuant to Delegated Authority: (i) may not exceed $200,000, in the case of pre-approvals granted by the Chair of the Audit Committee; and (ii) may not exceed $50,000, in the case of pre-approvals granted by any
other member of the Audit Committee. All proposed services or the fees payable in connection with such services that have not already been
pre-approved must be pre-approved by either the Audit Committee or pursuant to Delegated Authority. Prohibited services may not be pre-approved by the Audit Committee or pursuant to Delegated Authority.






External
Auditor Service Fees

The following table provides information about the fees billed to Cenovus for professional services rendered by
PricewaterhouseCoopers LLP in the years ended December 31, 2015 and 2014:



|                       |  |      |       |  |      |  |       | 
|---------------------- |  | ---- | ----- |  | ---- |  | ----- | 
|($ thousands)          |  | 2015 |       |  | 2014 | 
|                       |  |     
|Audit Fees (1)         |  |      | 2,692 |  |      |  | 2,597 | 
|Audit-Related Fees (2) |  |      | 482   |  |      |  | 202   | 
|Tax Fees (3)           |  |      | 99    |  |      |  | 110   | 
|All Other Fees (4)     |  |      | -     |  |      |  | 6     | 
|Total                  |  |      | 3,273 |  |      |  | 2,915 | 



| | (1) | Audit Fees consist of the aggregate fees billed for the audit of the Corporations annual financial statements or services that are normally provided
in connection with statutory and regulatory filings or engagements.
| | --- | -------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------

| | (2) | Audit-Related Fees consist of the aggregate fees billed for assurance and related services that are reasonably related to the performance of the audit or
review of the Corporations financial statements and are not reported as Audit Fees. The services provided in this category included audit-related services in relation to Cenovuss debt shelf prospectuses, systems development, controls
testing and participation fees levied by the Canadian Public Accountability Board.
| | --- | ----------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------

| | (3) | Tax Fees consist of the aggregate fees billed for audit related fees, tax compliance, tax advice and tax planning.
| | --- | ------------------------------------------------------------------------------------------------------------------

| | (4) | All Other Fees consist of subscriptions to auditor-provided and supported tools.
| | --- | --------------------------------------------------------------------------------



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DESCRIPTION OF CAPITAL STRUCTURE



The following is a summary of the rights,
privileges, restrictions and conditions which are attached to Common Shares and Cenovuss first and second preferred shares (collectively the Preferred Shares). Cenovus is authorized to issue an unlimited number of Common Shares and
First Preferred Shares and Second Preferred Shares not exceeding, in aggregate, 20 percent of the number of issued and outstanding Common Shares. As at December 31, 2015, there were approximately 833.3 million Common Shares and no
Preferred Shares outstanding.



COMMON SHARES The holders of Common Shares are entitled: (i) to receive dividends if, as and when declared by Cenovuss Board; (ii) to receive notice of,
to attend, and to vote on the basis of one vote per Common Share held, at all meetings of shareholders; and (iii) to participate in any distribution of the Corporations assets in the event of liquidation, dissolution or winding up or
other distribution of its assets among its shareholders for the purpose of winding up its affairs. PREFERRED SHARES Preferred Shares may be issued in one or more series. Cenovuss Board may determine the designation, rights, privileges, restrictions
and conditions attached to each series of Preferred Shares before the issue of such series. Holders of Preferred Shares are not entitled to vote at any meeting of shareholders, but may be entitled to vote if the Corporation fails to pay dividends on
that series of Preferred Shares. The First Preferred Shares are entitled to priority over the Second Preferred Shares and the Common Shares with respect to the payment of dividends and the distribution of assets in the event of any liquidation,
dissolution or winding up of Cenovuss affairs. The Corporations Board is restricted from issuing First Preferred Shares or Second Preferred Shares if by doing so the aggregate number of First Preferred and Second Preferred Shares that
would then be issued and outstanding would exceed 20 percent of the aggregate number of Common Shares then issued and outstanding. SHAREHOLDER RIGHTS PLAN Cenovus has a Shareholder Rights Plan that was adopted in 2009 to ensure, to the extent
possible, that all its shareholders are treated fairly in connection with any take-over bid for Cenovus. The Shareholder Rights Plan creates a right that attaches to each issued Common Share. Until the separation time, which typically occurs at the
time of an unsolicited take-over bid, whereby a person acquires or attempts to acquire 20 percent or more of Cenovuss Common Shares, the rights are not separable from the Common Shares, are not exercisable and no separate rights certificates
are issued. Each right entitles the holder, other than the 20 percent acquirer, from and after the separation time (unless delayed by the Corporations Board)


and before certain expiration times, to acquire Common Shares at 50 percent of the market price at the time of exercise. The Shareholder Rights Plan was reconfirmed at the 2015 annual and special
meeting of shareholders and must be reconfirmed by the Corporations shareholders at every third annual shareholder meeting. DIVIDEND REINVESTMENT PLAN Cenovus has a dividend reinvestment plan (the DRIP), which permits holders of
Common Shares to automatically reinvest all or any portion of the cash dividends paid on their Common Shares in additional Common Shares. At the discretion of the Corporation, the additional Common Shares may be issued from treasury at the average
market price or purchased on the market. On July 30, 2015 the temporary discount on Common Shares issued to participants under the DRIP
introduced on February 12, 2015, was discontinued. The discount allowed shareholders to reinvest their dividends in Common Shares at a three percent discount to the average market price (as defined in the DRIP). EMPLOYEE STOCK OPTION PLAN Cenovus has an Employee Stock Option Plan that provides employees with the opportunity to exercise options to purchase Common Shares. 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 expired after five years, while options granted on or after February 17, 2010 expire after seven years. Each option granted prior to February 24, 2011
has an associated tandem stock appreciation right which gives the option holder the right to elect to receive a cash payment equal to the excess of the market price of the Common Shares at the time of exercise over the exercise price of the option
in exchange for surrendering the option. Each option granted on or after February 24, 2011 has an associated net settlement right. In lieu of exercising the option, the net settlement right grants 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 the Common Shares at the time of exercise over the exercise price of the option.






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RATINGS

The following information relating to Cenovuss credit ratings is provided as it relates to the Corporations financing costs and liquidity.
Specifically, credit ratings affect Cenovuss ability to obtain short-term and long-term financing and the cost of such financing. A reduction in the current rating on Cenovuss debt by the Corporations rating agencies or a negative
change in its ratings outlook could adversely affect Cenovuss cost of financing and its access to sources of liquidity and capital. See Risk Factors in this AIF for further information.

The following table outlines the current ratings and outlooks of Cenovuss debt:



|                                   |  |                                            |  |                                       |  |                      
|---------------------------------- |  | ------------------------------------------ |  | ------------------------------------- |  | ---------------------
|                                   |  | Standard & Poors
Ratings Services (S&P) |  | Moodys Investors
Service (Moodys) |  | DBRS Limited
(DBRS)
|Senior Unsecured
Long-Term Rating  |  | BBB                                        |  | Baa2                                  |  | BBB (high)           
|Commercial Paper
Short-Term Rating |  | A-2                                        |  | P-2                                   |  | R-2 (high)           
|                                   |  |                                            | 
|Outlook/Trend                      |  | Stable                                     |  | Rating Under Review for
downgrade     |  | Negative             



Credit ratings are intended to provide an independent measure of the credit quality of an issue of
securities. The credit ratings assigned by the rating agencies are not recommendations to purchase, hold or sell the securities nor do the ratings comment on market price or suitability for a particular investor. A rating may not remain in effect
for any given period of time and, at any time, may be revised or withdrawn entirely by a rating agency in the future if, in its judgment, circumstances so warrant. S&Ps long-term credit ratings are on a rating scale that ranges from AAA to D, which represents the range from highest to lowest quality of such
securities rated. A rating of BBB by S&P is within the fourth highest of 10 categories and indicates that the obligation exhibits adequate protection parameters. However, adverse economic conditions or changing circumstances are more likely to
lead to a weakened capacity of the obligor to meet its financial commitment on the obligation. The addition of a plus (+) or minus (-) designation after a rating indicates the relative standing within the major rating categories. S&Ps
short-term issue credit ratings scale ranges from A-1 to D, which represents the range from highest to lowest quality. A rating of A-2 is the second highest of six categories and indicates that the obligor is somewhat more susceptible to the adverse
effects of changes in circumstances and economic conditions than obligations in higher rating categories. However, the obligors capacity to meet its financial commitment on the obligation is satisfactory. A S&P rating outlook assesses the
potential direction of a long-term credit rating over the intermediate term (typically six months to two years). In determining a rating outlook, consideration is given to any changes in the economic and/or fundamental business conditions. A
Stable outlook indicates that a rating is not likely to change. Moodys long-term credit ratings are on a rating scale that ranges
from Aaa to C, which represents the range from highest to lowest quality of such securities rated. A rating of Baa2 by Moodys is


within the fourth highest of nine categories and is assigned to debt securities which are considered medium-grade and subject to moderate credit risk and as such may possess certain speculative
characteristics. The addition of a 1, 2 or 3 modifier after a rating indicates the relative standing within a particular rating category. The modifier 1 indicates that the issue ranks in the higher end of its generic rating category, the
modifier 2 indicates a mid-range ranking and the modifier 3 indicates a ranking in the lower end of that generic rating category. Moodys short-term credit ratings are on a scale that ranges from P-1 (highest quality) to NP (lowest
quality). A rating of P-2 is the second highest of four categories and indicates that the issuer has a strong ability to repay short-term debt obligations. A designation of Rating Under Review indicates that
the rating is under review for a change in the near term, which overrides the outlook designation. A review may end with a rating being upgraded, downgraded, or confirmed without a change to the rating. Ratings are placed on review when a rating
action may be warranted in the near-term but further information or analysis is needed to reach a decision on the need for a rating change or the magnitude of the potential change. DBRSs long-term credit ratings are on a rating scale that ranges from AAA to D, which represents the range from highest to lowest quality of such
securities rated. A rating of BBB (high) by DBRS is within the fourth highest of 10 categories and is assigned to debt securities considered to be of adequate credit quality. The capacity for payment of financial obligations is considered
acceptable. Entities in the BBB category may be vulnerable to future events. The assignment of a (high) or (low) modifier within each rating category indicates relative standing within such category. DBRSs short-term
credit ratings are on a scale ranging from R-1 (high) to D, which represents the range from highest to lowest quality. A rating of R-2 (high) is the fourth highest of 10 categories and indicates that the short-term debt is in the upper end
of adequate credit quality. The capacity for the






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payment of short-term financial obligations as they fall due is acceptable. Cenovus may be vulnerable to future events. Rating trends provide guidance in respect of DBRS opinion regarding
the outlook for the rating in question, with rating trends falling into one of three categories - Positive, Stable or Negative. The rating trend indicates the direction in
which DBRS considers the rating is headed should


present tendencies continue, or in some cases, unless challenges are addressed. Throughout the
last two years, Cenovus has made payments to S&P, Moodys, and DBRS related to the rating of the Corporations debt. Additionally, Cenovus has purchased products and services from S&P and Moodys.






DIVIDENDS



The declaration of dividends is at the sole
discretion of Cenovuss Board and is considered each quarter. Effective the third quarter of 2015, Cenovus reduced the quarterly dividend by 40 percent from $0.2662 to $0.16 per common share. The Board has approved a first quarter dividend of
$0.05 per share payable on March 31, 2016 to holders of Common Shares of record as of March 15, 2016. Readers should also refer to risk factors Risk Factors  Financial Risks  Ability to Pay Dividends for additional
information.

Cenovus paid the following dividends over the last three years:



|               |  |      |        |  |    |  |        |    |  |  |        |  |  |    |        |  |  |       
|-------------- |  | ---- | ------ |  | -- |  | ------ | -- |  |  | ------ |  |  | -- | ------ |  |  | ------
|Dividends Paid |  |      |        |  |    |  |        |    |  |  |        |  |  |   
|($ per share)  |  | Year |        |  | Q4 |  |        | Q3 |  |  | Q2     |  |  | Q1
|2015           |  |      | 0.8524 |  |    |  | 0.16   |    |  |  | 0.16   |  |  |    | 0.2662 |  |  | 0.2662
|2014           |  |      | 1.0648 |  |    |  | 0.2662 |    |  |  | 0.2662 |  |  |    | 0.2662 |  |  | 0.2662
|2013           |  |      | 0.968  |  |    |  | 0.242  |    |  |  | 0.242  |  |  |    | 0.242  |  |  | 0.242 



MARKET FOR SECURITIES



All of the outstanding Common Shares are
listed and posted for trading on the Toronto Stock Exchange (TSX) and the New York Stock Exchange (NYSE) under the symbol CVE. The following table outlines the share price trading range and volume of shares traded by month in
2015:



|          |  |                           |       |  |             |  |       |                           |  |  |              |  |  |      |         |  |     |  |       |       |  |  |              |  |  |  |       |  |  |       
|--------- |  | ------------------------- | ----- |  | ----------- |  | ----- | ------------------------- |  |  | ------------ |  |  | ---- | ------- |  | --- |  | ----- | ----- |  |  | ------------ |  |  |  | ----- |  |  | ------
|          |  | TSX                       |       |  | NYSE       
|          |  | Share Price Trading Range |       |  |             |  |       | Share Price Trading Range |  |  |             
|          |  | High                      |       |  | Low         |  |       | Close                     |  |  | Share
Volume |  |  | High |         |  | Low |  |       | Close |  |  | Share
Volume
|          |  | ($ per share)             |       |  | (thousands) |  |       | (US$ per share)           |  |  | (thousands) 
|          |  |                           |       |  |             |  |       |                          
|January   |  |                           | 24.95 |  |             |  | 21.87 |                           |  |  | 24.09        |  |  |      | 86,649  |  |     |  | 20.89 |       |  |  | 17.37        |  |  |  | 18.89 |  |  | 49,901
|February  |  |                           | 26.42 |  |             |  | 21.56 |                           |  |  | 21.57        |  |  |      | 99,513  |  |     |  | 21.12 |       |  |  | 17.24        |  |  |  | 17.29 |  |  | 56,777
|March     |  |                           | 22.48 |  |             |  | 20.45 |                           |  |  | 21.34        |  |  |      | 101,794 |  |     |  | 17.93 |       |  |  | 16.29        |  |  |  | 16.88 |  |  | 47,505
|April     |  |                           | 24.28 |  |             |  | 21.32 |                           |  |  | 22.69        |  |  |      | 95,632  |  |     |  | 19.72 |       |  |  | 16.89        |  |  |  | 18.82 |  |  | 42,962
|May       |  |                           | 23.25 |  |             |  | 20.23 |                           |  |  | 20.52        |  |  |      | 77,995  |  |     |  | 19.28 |       |  |  | 16.20        |  |  |  | 16.49 |  |  | 38,034
|June      |  |                           | 21.69 |  |             |  | 19.53 |                           |  |  | 19.98        |  |  |      | 84,576  |  |     |  | 17.76 |       |  |  | 15.69        |  |  |  | 16.01 |  |  | 49,516
|July      |  |                           | 20.07 |  |             |  | 16.98 |                           |  |  | 19.06        |  |  |      | 86,880  |  |     |  | 15.97 |       |  |  | 13.04        |  |  |  | 14.58 |  |  | 50,471
|August    |  |                           | 19.28 |  |             |  | 15.75 |                           |  |  | 19.07        |  |  |      | 84,803  |  |     |  | 14.67 |       |  |  | 11.85        |  |  |  | 14.47 |  |  | 51,293
|September |  |                           | 20.91 |  |             |  | 17.00 |                           |  |  | 20.24        |  |  |      | 135,093 |  |     |  | 15.80 |       |  |  | 12.76        |  |  |  | 15.16 |  |  | 74,684
|October   |  |                           | 22.35 |  |             |  | 18.75 |                           |  |  | 19.48        |  |  |      | 90,746  |  |     |  | 17.23 |       |  |  | 14.17        |  |  |  | 14.91 |  |  | 65,312
|November  |  |                           | 21.81 |  |             |  | 19.10 |                           |  |  | 19.81        |  |  |      | 65,882  |  |     |  | 16.68 |       |  |  | 14.32        |  |  |  | 14.80 |  |  | 39,867
|December  |  |                           | 20.56 |  |             |  | 16.85 |                           |  |  | 17.50        |  |  |      | 76,299  |  |     |  | 15.38 |       |  |  | 12.10        |  |  |  | 12.62 |  |  | 38,971

RISK FACTORS





Cenovuss operations are exposed to a number of risks, some that impact the oil and gas industry as a
whole and others that are unique to the Corporations operations. The impact of any risk or a combination of risks may adversely affect, among other things, the Corporations business, reputation, financial condition, results of operations
and cash flow, which may reduce or restrict Cenovuss ability to pay a dividend to its shareholders and may materially affect the market price of its securities. The Corporations approach to risk management includes compliance with the Board approved


Enterprise Risk Management Policy and the related enterprise risk management framework and program as well as integration with Cenovuss Operations Management System (COMS). It
includes an annual review of Cenovuss principal and emerging risks, an analysis of the severity and likelihood of each principal risk, consideration of the Corporations current mitigation and an evaluation if additional mitigation or
treatment of the risk is required. In addition, Cenovus continuously monitors its risk profile as well as industry best practices.






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FINANCIAL RISKS



Financial risks include, but are not limited to: fluctuations in commodity prices; royalty regimes and tax
laws; volatile capital markets; development and operating costs; availability of capital and access to sufficient liquidity; fluctuations in foreign exchange and interest rates; risks related to Cenovuss hedging activities; and risks related
to the Corporations ability to pay a dividend to shareholders. Changes in global economic conditions could impact a number of factors including, but not limited to, Cenovuss cash flows, financial condition, results of operations and
growth, the maintenance of Cenovuss existing operations, financial strength of the Corporations counterparties, access to capital and cost of borrowing. Commodity Prices The Corporations financial performance is substantially dependent on the prevailing prices of crude oil, natural gas and refined products. Crude oil
prices are impacted by a number of factors including, but not limited to: the supply of and demand for crude oil; economic conditions; the actions of the Organization of Petroleum Exporting Countries; government regulation; political stability; the
ability to transport crude to markets; the availability of alternate fuel sources; and weather conditions. Cenovuss natural gas price realizations are impacted by a number of factors including, but not limited to: North American supply and
demand; developments related to the market for liquefied natural gas; weather conditions; and prices of alternate sources of energy. The Corporations refined product prices are impacted by a number of factors including, but not limited to:
global supply and demand for refined products; market competitiveness; weather; and industry planned and unplanned refinery maintenance. All of these factors are beyond Cenovuss control and can result in a high degree of price volatility.
Fluctuations in currency exchange rates further compound this volatility when the commodity prices, which are generally set in U.S. dollars, are stated in Canadian dollars. Cenovuss financial performance also depends on revenues from the sale of commodities which differ in quality and location from underlying commodity
prices quoted on financial exchanges. Of particular importance are the price differentials between the Corporations light/medium oil, heavy oil (in particular the light/heavy differential) and bitumen and quoted market prices. Not only are
these discounts influenced by regional supply and demand factors, they are also influenced by other factors such as transportation costs, capacity and interruptions; refining demand; the availability and cost of diluent used to blend and transport
product; and the quality of the oil produced, all of which are beyond Cenovuss control. The financial performance of Cenovuss refining
operations is impacted by the relationship, or margin, between refined product prices and the prices of refinery feedstock. Margin volatility is


impacted by numerous conditions including, but not limited to: fluctuations in the supply and demand for refined products; market competitiveness; crude oil costs; and weather. Refining margins
are subject to seasonal factors as production changes to match seasonal demand. Sales volumes, prices, inventory levels and inventory values will fluctuate accordingly. Future refining margins are uncertain and decreases in refining margins may have
a negative impact on the Corporations business. Fluctuations in the price of commodities, associated price differentials and refining margins
may impact the value of Cenovuss assets, the Corporations ability to maintain its business and to fund growth projects including, but not limited to, the continued development of its oil sands properties. Prolonged periods of commodity
price volatility may also negatively impact Cenovuss ability to meet guidance targets and meet all of its financial obligations as they come due. Any substantial or extended decline in these commodity prices may result in a delay or
cancellation of existing or future drilling, development or construction programs, curtailment in production, unutilized long-term transportation commitments and/or low utilization levels at the Corporations refineries. Cenovus conducts an annual assessment of the carrying value of its assets in accordance with International Financial Reporting Standards. If crude oil and
natural gas prices decline significantly and remain at low levels for an extended period of time, the carrying value of the Corporations assets may be subject to impairment. Development and Operating Costs Cenovuss financial performance is significantly affected by the cost of developing and operating its assets. Development and operating costs are
affected by a number of factors including, but not limited to: inflationary price pressure; scheduling delays; failure to maintain quality construction and manufacturing standards; and supply chain disruptions, including access to skilled labour.
Electricity, water, diluent, chemicals, supplies, reclamation, abandonment and labour costs are examples of operating costs that are susceptible to significant fluctuation. Hedging Activities Cenovuss Market Risk Mitigation Policy, which has been approved by the Board, allows Management to use derivative instruments to help mitigate the
impact of changes in oil and natural gas prices, diluent or condensate supply prices and refining margins. Cenovus also uses derivative instruments in various operational markets to help optimize its supply cost or sales. The Corporation may also
utilize derivative instruments to help mitigate the potential impact of changes in interest rates and foreign exchange rates.






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The use of such hedging activities exposes the Corporation to risks which may cause significant loss. These
risks include, but are not limited to: changes in the valuation of the hedge instrument being not well correlated to the change in the valuation of the underlying exposures being hedged; deficiency in the Corporations systems or controls;
human error; and the unenforceability of Cenovuss contracts. There is risk that the consequences of hedging to protect against downside price
risk may limit the benefit to Cenovus of commodity price increases or changes in interest rates and foreign exchange rates. The Corporation may also suffer financial loss due to hedging arrangements if it is unable to produce oil, natural gas or
refined products to fulfill its delivery obligations related to the underlying physical transaction. Exposure to
Counterparties In the normal course of business, Cenovus enters into contractual relationships with suppliers, partners and other
counterparties in the energy industry and other industries for the provision and sale of goods and services. If such counterparties do not fulfill their contractual obligations, the Corporation may suffer financial losses, may have to delay its
development plans or may have to forego other opportunities which may materially impact its financial condition or operational results. Credit, Liquidity and Availability of Future Financing The future development of Cenovuss business may be
dependent on its ability to obtain additional capital including, but not limited to, debt and equity financing. Unpredictable financial markets and the associated credit impacts may impede the Corporations ability to secure and maintain cost
effective financing and limit its ability to achieve timely access to capital markets on acceptable terms and conditions. An inability to access capital could affect Cenovuss ability to make future capital expenditures and to meet all of its
financial obligations as they come due. The Corporations ability to obtain additional capital is dependent on, among other things, interest in investments in the energy industry in general and interest in its securities in particular. As at December 31, 2015, Cenovus had US$4.75 billion in debt outstanding with no principal payments due until October 2019 (US$1.3 billion). The
Corporation has a $4.0 billion committed credit facility, with a $1.0 billion tranche maturing on November 30, 2017 and a $3.0 billion tranche maturing on November 30, 2019. The entire amount of the committed credit facility was available
at December 31, 2015, to meet operating and capital requirements. Going forward, an inability to access the capital markets, a sustained downturn in the prices of crude oil, refined products, natural gas or significant unanticipated expenses
related to development and maintenance of Cenovuss existing properties and facilities could negatively impact the


Corporations liquidity, its credit ratings and its ability to access additional sources of capital. Cenovus is also required to comply with various financial and operating covenants under
its credit facilities and the indentures governing its debt securities. The Corporation routinely reviews the covenants and may make changes to its development plans, dividend policy, or may take alternative actions to ensure compliance. In the
event that Cenovus does not comply with such covenants, its access to capital could be restricted or repayment could be required. If external sources of capital become limited or unavailable, and/or if repayment is required before maturity, the
Corporations ability to make capital investments, continue its business plan, meet all of its financial obligations as they come due and maintain existing properties and facilities may be impaired. Credit Ratings The credit rating agencies regularly evaluate the Corporation, and their ratings are based on a number of factors not entirely within the
Corporations control, including conditions affecting the oil and gas industry generally, and the wider state of the economy. There can be no assurance that one or more of the Corporations credit ratings will not be downgraded. A
reduction in any of the Corporations current credit ratings could adversely affect the cost and availability of borrowing, and access to sources of liquidity and capital. Foreign Exchange Rates Fluctuations in foreign exchange rates may affect Cenovuss results as global prices for crude oil, natural gas and refined products are generally
set in U.S. dollars, while many of the Corporations operating and capital costs as well as its Consolidated Financial Statements are denominated in Canadian dollars. Cenovus has chosen to borrow U.S. dollar long-term debt. An increase in the
value of the Canadian dollar relative to the U.S. dollar will decrease the revenues received from the sale of the Corporations oil, natural gas and refined products. In addition, a change in the value of the Canadian dollar against the U.S.
dollar will result in an increase or decrease in Cenovuss U.S. dollar denominated debt and related interest expense, as expressed in Canadian dollars. Exchange rate fluctuations could have a material adverse effect on the Corporations
financial condition, results of operations and cash flow. Interest Rates The Corporation may be exposed to fluctuations in interest rates as a result of the use of floating rate securities or borrowings. An increase in interest
rates could increase Cenovuss net interest expense and negatively impact its financial results. Additionally, the Corporation is exposed to interest rates upon the refinancing of maturing long-term debt and anticipated future financing needs
at prevailing interest rates.






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Ability to Pay Dividends The payment of dividends is at the discretion of the Board. All dividends will be reviewed by the Board and may be increased, reduced or suspended from
time to time. Cenovuss ability to pay dividends and the actual amount of such dividends is dependent upon, among other things, the Corporations


financial performance, its debt covenants and obligations, its ability to meet its financial obligations as they come due, its working capital requirements, its future tax obligations, its future
capital requirements, commodity prices and the risk factors set forth in this AIF.






OPERATIONAL
RISKS



Operational risks are those risks that affect the Corporations ability to continue operations in the
ordinary course of business. In general, Cenovuss operations are subject to general risks affecting the oil and gas industry. The Corporations operational risks include, but are not limited to: operational and safety considerations;
market access constraints and transportation interruptions (pipeline, marine or rail); phased growth execution; uncertainty of reserves and resources estimates; reservoir performance and technical challenges; partner risks; competition; technology
limitations; third-party claims; land claims; leadership and talent gaps; and information system failures. Health and
Safety The operation of Cenovuss properties is subject to hazards of finding, recovering, transporting and processing hydrocarbons,
including but not limited to: blowouts; fires; explosions; railcar incident or derailment; gaseous leaks; migration of harmful substances; oil spills; corrosion; and acts of vandalism and terrorism. Any of these hazards can interrupt operations,
impact the Corporations reputation, cause loss of life or personal injury, result in loss of or damage to equipment, property, information technology systems, related data and control systems, and cause environmental damage that may include
polluting water, land or air. Market Access Constraints and Transportation Interruptions Cenovuss production is transported through various pipelines and its refineries are reliant on various pipelines to receive feedstock. Disruptions
in, or restricted availability of pipeline service, marine or rail transport, could adversely affect the Corporations crude oil and natural gas sales, projected production growth, refining operations and its cash flow. Interruptions or
restrictions in the availability of these pipeline systems may limit the ability to deliver production volumes and could adversely impact commodity prices, sales volumes or the prices received for Cenovuss products. These interruptions and
restrictions may be caused by the inability of the pipeline to operate, or they may be related to capacity constraints as the supply of feedstock into the system exceeds the infrastructure capacity. There can be no certainty that investments in new
pipeline projects which would result in extra long-term takeaway capacity will be made by applicable third party pipeline providers or that any applications to expand capacity will receive the required regulatory approval. There is also no certainty
that short-term operational constraints on


the pipeline system, arising from pipeline interruption and/or increased supply of crude oil, will not occur. There is no certainty that crude-by-rail, marine transport and other alternative types of transportation for the Corporations production will be
sufficient to address any gaps caused by operational constraints on the pipeline system. In addition, Cenovuss crude-by-rail and marine shipments may be impacted by service delays, inclement weather, railcar derailment or other rail or marine
transport incident and could adversely impact its crude oil sales volumes or the price received for its product or impact the Corporations reputation or result in legal liability, loss of life or personal injury, loss of equipment or property,
or environmental damage. In addition, new regulations were introduced in 2015 requiring tank cars used to transport crude oil to be replaced with newer, safer tank cars, or to be retrofitted to meet the same standards. The costs of complying with
the new standards, or any further revised standards, will likely be passed on to rail shippers and may adversely affect Cenovuss ability to transport crude-by-rail or the economics associated with rail transportation. Finally, planned or
unplanned shutdowns or closures of the Corporations refinery customers may limit Cenovuss ability to deliver product with negative implications on sales and cash from operating activities. Operational Considerations The Corporations crude oil and natural gas operations are subject to all of the risks normally incidental to: (i) the storing, transporting,
processing, refining and marketing of crude oil, natural gas and other related products; (ii) drilling and completion of crude oil and natural gas wells; and (iii) the operation and development of crude oil and natural gas properties,
including, but not limited to: encountering unexpected formations or pressures; premature declines of reservoir pressure or productivity; blowouts; equipment failures and other accidents; sour gas releases; uncontrollable flows of crude oil, natural
gas or well fluids; adverse weather conditions; pollution; and other environmental risks. Producing and refining oil requires high levels of
investment and involves particular risks and uncertainties. Cenovuss oil operations are susceptible to loss of production, slowdowns, shutdowns, or restrictions on the Corporations ability to produce higher value products due to the
interdependence of its component systems. Delineation of the resources, the costs associated with production, including drilling wells for SAGD operations, and the costs associated with refining oil can entail significant capital outlays. The
operating






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costs associated with oil production are largely fixed in the short-term and, as a result, operating costs per unit are largely dependent on levels of production. Cenovuss refining and marketing business is subject to all of the risks inherent in the operation of refineries, terminals, pipelines and other
transportation and distribution facilities including, but not limited to: loss of product; slowdowns due to equipment failure or transportation disruptions; weather; fires, and explosions; unavailability of feedstock; and price and quality of
feedstock. The Corporation does not insure against all potential occurrences and disruptions and it cannot be guaranteed that its insurance will be
sufficient to cover any such occurrences or disruptions. Cenovuss operations could also be interrupted by natural disasters or other events beyond its control. Uncertainty of Reserves and Future Net Revenue Estimates The reserves estimates included in this AIF are estimates only. There are numerous uncertainties inherent in estimating quantities of reserves, including
many factors beyond the Corporations control. In general, estimates of economically recoverable crude oil and natural gas reserves and the future net cash flows and revenue derived therefrom are based upon a number of variable factors and
assumptions, including but not limited to: product prices; future operating and capital costs; historical production from the properties and the assumed effects of regulation by governmental agencies, including royalty payments and taxes; initial
production rates; production decline rates; and the availability, proximity and capacity of oil and gas gathering systems, pipelines, rail transportation and processing facilities, all of which may vary considerably from actual results. All such estimates are to some degree uncertain and classifications of reserves are only attempts to define the degree of uncertainty involved. For those
reasons, estimates of the economically recoverable crude oil and natural gas reserves attributable to any particular group of properties, classification of such reserves based on risk of recovery and estimates of FNR expected therefrom, prepared by
different engineers or by the same engineers at different times, may vary substantially. Cenovuss actual production, revenues, taxes and development and operating expenditures with respect to its reserves may vary from current estimates and
such variances may be material. Estimates with respect to reserves that may be developed and produced in the future are often based upon volumetric
calculations and upon analogy to similar types of reserves, rather than upon actual production history. Subsequent evaluation of the same reserves based upon


production history will result in variations, which may be material, in the estimated reserves. If the Corporation fails to acquire, develop or find additional crude oil and natural gas reserves, its reserves and production will decline materially
from their current levels and therefore Cenovuss business, financial condition, results of operations and cash flows are highly dependent upon successfully producing current reserves and acquiring, discovering or developing additional
reserves. Project Execution There are risks associated with the execution and operation of the Corporations upstream and refining growth and development projects. These risks
include, but are not limited to, Cenovuss ability to: obtain the necessary environmental and regulatory approvals; risks relating to schedule, resources and costs, including the availability and cost of materials, equipment and qualified
personnel; the impact of general economic, business and market conditions; the impact of weather conditions; risk related to the accuracy of project cost estimates; ability to finance growth; ability to source or complete strategic transactions; and
the effect of changing government regulation and public expectations in relation to the impact of oil sands development on the environment. The commissioning and integration of new facilities within the Corporations existing asset base could
cause delays in achieving targets and objectives. Failure to manage these risks could have a material adverse effect on our financial condition, results of operations and cash flows. Partner Risks Some of the Corporations assets are not operated by Cenovus or are held in partnership with others. Therefore, the Corporations results of
operations may be affected by the actions of third-party operators or partners. Interests in certain of the Corporations upstream
assets are held in a partnership with ConocoPhillips, an unrelated U.S. public company, and are operated by Cenovus. The Corporations refining assets are held in a partnership with Phillips 66 and operated by Phillips 66. The
success of Cenovuss refining operations is dependent on the ability of Phillips 66 to successfully operate this business and maintain the refining assets. The Corporation relies on the judgment and operating expertise of Phillips 66 in respect
of the operation of such refining assets and Cenovus also relies on Phillips 66 to provide information on the status of such refining assets and related results of operations. ConocoPhillips or Phillips 66, as unrelated third parties, may have objectives and interests that do not coincide with and may conflict with the
Corporations interests. Major capital decisions affecting these upstream and refining assets require agreement between each respective partner, while certain operational decisions may be made by the operator of the applicable assets. While
Cenovus and its partners generally seek consensus with respect to major decisions concerning the direction and operation of these upstream and refining assets, no assurance can be provided that the future






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demands or expectations of either party relating to such assets will be satisfactorily met or met in a timely manner or at all. Unmet demands or expectations by either party or demands and
expectations which are not satisfactorily met may affect Cenovuss participation in the operation of such assets, the Corporations ability to obtain or maintain necessary licenses or approvals or affect the timing of undertaking various
activities. Competition The Canadian and international petroleum industry is highly competitive in all aspects, including the exploration for, and the development of, new and
existing sources of supply, the acquisition of crude oil and natural gas interests and the distribution and marketing of petroleum products. Cenovus competes with other producers and refiners, some of which may have lower operating costs or greater
resources than the Corporation does. Competing producers may develop and implement recovery techniques and technologies which are superior to those Cenovus employs. The petroleum industry also competes with other industries in supplying energy, fuel
and related products to consumers. Companies may announce plans to enter the oil sands business, to begin production or to expand existing
operations. Expansion of existing operations and development of new projects could materially increase the supply of crude oil in the marketplace which may decrease the market price of crude oil, constrain transportation and increase the
Corporations input costs for skilled labour and materials. Technology Current SAGD technologies for the recovery of bitumen are energy intensive, requiring significant consumption of natural gas in the production of steam
that is used in the recovery process. The amount of steam required in the production process varies and therefore impacts costs. The performance of the reservoir can also affect the timing and levels of production using this technology. A large
increase in recovery costs could cause certain projects that rely on SAGD technology to become uneconomical, which could have a negative effect on Cenovuss business, financial condition, results of operations and cash flow. There are risks
associated with growth and other capital projects that rely largely or partly on new technologies and the incorporation of such technologies into new or existing operations. The success of projects incorporating new technologies cannot be assured.


Third-Party Claims From time to time, the Corporation may be the subject of litigation arising out of its operations. Claims under such litigation may be material or may be
indeterminate. The outcome of such litigation may materially impact Cenovuss financial condition or results of operations. The Corporation may be required to incur significant expenses or devote significant resources in defense against any
such litigation. Land Claims In western Canada, aboriginal groups have historically filed claims in respect of their aboriginal rights and treaty rights against the governments of
Canada and Alberta, and other government bodies, which may affect Cenovuss business. In particular, aboriginal groups have claimed aboriginal title and rights to a substantial portion of western Canada. In 2014, the Supreme Court of Canada
granted aboriginal title over non-treaty lands, representing the first occurrence of such a declaration. There exist outstanding aboriginal and treaty rights claims, which may include aboriginal title claims, on lands where Cenovus operates. Such
claims have the potential to have an adverse effect on operations in affected areas. No certainty exists that any lands currently unaffected by claims brought by aboriginal groups will remain unaffected by future claims. Recent outcomes of
litigation concerning aboriginal rights may result in increased claims and litigation activity in the future. Leadership
and Talent Cenovuss success is dependent upon its Management, its leadership capabilities and the quality and competency of its
talent. Failure to retain critical talent or to attract and retain new talent with the necessary leadership traits, skills and competencies could have a material adverse effect on the Corporations results of operations, pace of growth and
financial condition. Information Systems The Corporation depends on a variety of information systems to operate effectively. A failure or act of sabotage of certain business critical information
systems could result in operational difficulties or mishap, damage or loss of data, productivity losses or result in unauthorized knowledge and use of information.






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ENVIRONMENTAL & REGULATORY RISKS

Cenovuss industry and its operations are subject to regulation and intervention under federal,
provincial, state and municipal legislation in Canada and the U.S. in matters such as, but not limited to: land tenure; permitting of production projects; royalties; taxes (including income taxes); government fees; production rates; environmental
protection controls; protection of certain species or lands; provincial and federal land use designations; the reduction of greenhouse gas and other emissions; the export of crude oil, natural gas and other products; the transportation of
crude-by-rail or marine transport; the awarding or acquisition of exploration and production, oil sands or other interests; the imposition of specific drilling obligations; control over the development, abandonment and reclamation of fields
(including restrictions on production); and/or facilities and possibly expropriation or cancellation of contract rights. Changes to government
regulation could impact Cenovuss existing and planned projects or increase capital investment or operating expenses, adversely impacting our financial condition, results of operations and cash flows. Regulatory Approvals Cenovuss operations require the Corporation to obtain approvals from various regulatory authorities and there are no guarantees that it will be able
to obtain all necessary licenses, permits and other approvals that may be required to carry out certain exploration and development activities on its properties. In addition, obtaining certain approvals from regulatory authorities can involve, among
other things, stakeholder and aboriginal consultation, environmental impact assessments and public hearings. Regulatory approvals obtained may be subject to the satisfaction of certain conditions, including, but not limited to: security deposit
obligations; regulatory oversight of projects by third parties; mitigating or avoiding project impacts; habitat assessments; and other commitments or obligations. Failure to obtain applicable regulatory approvals or satisfy any of the conditions
thereto on a timely basis on satisfactory terms could result in delays, abandonment or restructuring of projects and increased costs. Royalty Regimes The Corporations cash flow may be directly affected by changes to royalty regimes. The
governments of Alberta and Saskatchewan receive royalties on the production of hydrocarbons from lands in which they


respectively own the mineral rights. The royalty rate that Cenovus is charged on its oil sands production is determined based on the Canadian dollar equivalent price of West Texas Intermediate
(WTI), and therefore increases in WTI or decreases in the CDN$/US$ exchange rate could significantly increase its royalties, which may have a negative impact on the Corporations business, financial conditions, results of operations
and cash flow. There is also a mineral tax in each province levied on hydrocarbon production from lands to which the Crown does not own the mineral rights. The potential for changes in the royalty and mineral tax regimes applicable in the provinces
Cenovus operates creates uncertainty relating to the ability to accurately estimate future Crown burdens. Alberta Royalty
Review The Government of Alberta released its Royalty Review Advisory Panel Report on January 29, 2016 (the Review). The
Review recommends new rules coming into effect in 2017, but also recommends grandfathering, under the current rules, all wells drilled before 2017 for a ten year period and recommends no change to the oil sands royalty structure. The Review
recommended modernization of Albertas conventional oil and gas royalty regime, but did not provide detail. The Government of Alberta has accepted the recommendations set out in the Review and is expected to adopt those recommendations in
spring 2016. It is not anticipated that the new rules will materially impact Cenovuss financial condition; however, the specific nature in which the new rules will be applied has not yet been determined and may alter this view. Tax Laws Income
tax laws, other laws or government incentive programs may in the future be changed or interpreted in a manner that adversely affects Cenovus and its shareholders. Tax authorities having jurisdiction over Cenovus may disagree with the manner in which
the Corporation calculates its tax liabilities such that its provision for income taxes may not be sufficient or could change their administrative practices to Cenovuss detriment or the detriment of its shareholders. In addition, all of the
Corporations tax filings are subject to audit by tax authorities who may disagree with such filings in a manner that adversely affects Cenovus and its shareholders. Environmental Regulations All phases of crude oil, natural gas and refining operations are subject to environmental regulation pursuant to a variety of Canadian and U.S. federal,
provincial, territorial, state and municipal laws and regulations (collectively, environmental regulations). Environmental regulations provide that wells, facility sites, refineries and other properties and practices associated with the
Corporations operations be constructed, operated, maintained, abandoned, reclaimed and undertaken in accordance with the requirement set out therein. In addition, certain types of operations, including exploration and development projects and
changes to certain existing projects, may require the submission and approval of environmental impact assessments or permit applications. Environmental regulations impose, among other things, restrictions, liabilities






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and obligations in connection with the generation, handling, use, storage, transportation, treatment and disposal of hazardous substances and waste and in connection with spills, releases and
emissions of various substances in the environment. They also impose restrictions, liabilities and obligations in connection with the management of fresh or potable water sources that are being used, or whose use is contemplated, in connection with
oil and gas operations. The complexities of changes in environmental regulations make it difficult to predict the potential future impact to Cenovus. Compliance with environmental regulations can require significant expenditures, including costs and damages arising from releases or contaminated
properties or spills. We anticipate that future capital expenditures and operating expenses could continue to increase as a result of the implementation of new environmental regulations. Failure to comply with environmental regulations may result in
the imposition of fines, penalties and environmental protection orders. The costs of complying with environmental regulation may have a material adverse effect on Cenovuss financial condition, results of operations and cash flows. The
implementation of new environmental regulations or the modification of existing environmental regulations affecting the crude oil and natural gas industry generally could reduce demand for crude oil and natural gas and increase costs. Failure to comply with environmental regulations could have an adverse impact on Cenovuss reputation. There is also risk that Cenovus could face
litigation initiated by third parties relating to climate change or other environmental regulations. Climate Change Various federal, provincial and state governments have announced intentions to regulate greenhouse gas (GHG) emissions and
other air pollutants. Some of these regulations are in effect while others remain in various phases of review, discussion or implementation in the U.S. and Canada. Uncertainties exist relating to the timing and effects of these regulations.
Additionally, lack of certainty regarding how any future federal legislation will harmonize with provincial or state regulations makes it difficult to accurately determine the cost estimate of climate change legislation compliance with certainty,
including the effects of compliance with such initiatives on the Corporations suppliers and service providers.


Alberta Climate Leadership Plan We are subject to the Specified Gas Emitters Regulation (Alberta) (the SGER), which imposes GHG emissions intensity emit 100,000 tonnes per
year or more of GHG, which was recently amended. Previously, an owner of such a facility was required to reduce the emissions intensity of that facility by a minimum of 12 percent. The amendments have increased the minimum emission intensity
reduction requirement for facility owners to 15 percent in 2016 and 20 percent starting in 2017. One of the options for complying with the SGER is for facility owners to purchase technology fund credits. The amendments have increased the price for
such credits from $15/tonne to $20/tonne for 2016 and $30/tonne beginning in 2017. limits and reduction requirements for owners of facilities that In November, 2015, the Alberta government announced its climate leadership plan (the CLP) and released to the public the climate
leadership report to the Minister of Environment and Parks (the Report) that it commissioned from the Climate Change Advisory Plan and on which the CLP is based. The CLP includes four strategies that the government will implement to
address climate change: (i) the complete phase-out of coal-fired sources of electricity by 2030; (ii) implementing an Alberta economy-wide price on GHG emissions of $30 per tonne; (iii) reducing oil sands emissions to a province-wide
total of 100 megatonnes per year (compared to current industry emissions levels of approximately 70 megatonnes per year), with certain exceptions for cogeneration power sources and new upgrading capacity; and (iv) reducing methane emissions
from oil and gas activities by 45% by 2025. Uncertainties exist with respect to the implementation of the CLP and the effects that the CLP, including the overall emissions limit, may have on the industry. Adverse impacts to Cenovuss business as a result of comprehensive GHG legislation or regulation, including legislation to implement the CLP and the
amendments to the SGER, to be enacted and applied to the Corporations business in Alberta or any jurisdiction in which the Corporation operates, may include, but are not limited to: increased compliance costs; permitting delays; substantial
costs to generate or purchase emission credits or allowances adding costs to the products Cenovus produces; and reduced demand for crude oil and certain refined products. Emission allowances or offset credits may not be available for acquisition or
may not be available on an economic basis. Required emission reductions may not be technically or economically feasible to implement, in whole or in part, and failure to meet such emission reduction requirements or other compliance mechanisms may
have a material adverse effect on the Corporations business resulting in, among other things, fines, permitting delays, penalties and the suspension of operations. Consequently, no assurances can be given that the effect of future climate
change regulations will not be significant to Cenovus. Beyond existing legal requirements, the extent and magnitude of any adverse impacts of any
additional programs or additional regulations cannot be reliably or accurately estimated at this time because specific legislative and regulatory requirements have not been finalized and uncertainty exists with respect to the additional measures
being considered and the time frames for compliance.






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The Paris Agreement In December 2015, Canada and 195 other countries that are members of the United Nations Framework Convention on Climate Change met in Paris, France and
signed the Paris Agreement on climate change. The stated objective of the Paris Agreement is to hold the increase in global average temperature to well below 2 degrees Celsius above pre-industrial levels and to pursue efforts to limit the
temperature increase to 1.5 degrees Celsius. The countries which agreed to the Paris Agreement committed to meeting every five years to review their individual progress on GHG emissions reductions and to consider amendments to non-binding
individual country targets. Canada is required to report and monitor its GHG emissions, though the implementation of such reporting and monitoring has yet to be determined. The Paris Agreement also contemplates that by 2020 the parties thereto will
develop a new market-based mechanism related to carbon trading, which is expected to be based largely on lessons learned from the Kyoto Protocol. The government of Canada has announced that it will develop a country-wide approach to implementing the
Paris Agreement in 2016. The Corporation is unable to predict the impact of the Paris Agreement on its operations. It is possible that mandatory
emissions reduction requirements may have a material adverse effect on Cenovuss financial condition, results of operations and cash flow. Low Carbon Fuel Standards Existing and proposed environmental legislation in certain U.S. states, Canadian provinces
and in the European Union, regulating carbon fuel standards could result in increased costs and reduced revenue. The potential regulation may negatively affect the marketing of Cenovuss bitumen, crude oil or refined products, and may require
the Corporation to purchase emissions credits in order to affect sales in such jurisdictions. The state of California has implemented climate change
regulation in the form of a Low Carbon Fuel Standard that requires the reduction of life cycle carbon emissions from transportation fuels. As an oil sands producer, Cenovus is not directly regulated and is not expected to have a compliance
obligation. Refiners in California are required to comply with the legislation. Renewable Fuel Standards Cenovuss U.S. refining operations are subject to various laws and regulations that impose stringent and costly requirements. Of specific note is the
Energy Independence and Security Act of 2007 (EISA 2007) that established energy management goals and requirements. Pursuant to EISA 2007, among other things,


the Environmental Protection Agency issued the Renewable Fuel Standard program that mandates the total volume of renewable transportation fuel sold or introduced in the U.S. and requires 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 finished products, they must purchase credits, referred to as Renewable Identification Numbers (RINs), in the open market. A RIN is a number assigned to each gallon of renewable fuel produced or imported into
the U.S. RIN numbers were implemented to provide refiners with flexibility in complying with the renewable fuel standards. The Corporations
refineries do not blend renewable fuels into the motor fuel products they produce and, consequently, Cenovus is obligated to purchase RINs in the open market, where prices fluctuate. In the future, the regulations could change the volume of
renewable fuels required to be blended with refined products, creating volatility in the price for RINs or an insufficient number of RINs being available in order to meet the requirements. The Corporations financial condition, results of
operations, and cash flow may be materially adversely impacted as a result. Albertas Land-Use Framework Albertas Land-Use Framework has been implemented under the Alberta Land Stewardship Act (ALSA) which sets out the
Government of Albertas approach to managing Albertas land and natural resources to achieve long-term economic, environmental and social goals. In some cases, ALSA amends or extinguishes previously issued consents such as regulatory
permits, licenses, approvals and authorizations in order to achieve or maintain an objective or policy resulting from the implementation of a regional plan. The Government of Alberta has approved the Lower Athabasca Regional Plan (LARP), which was issued under the ALSA. The LARP identifies
legally-binding management frameworks for air, land and water that will incorporate cumulative limits and triggers as well as identifying areas related to conservation, tourism and recreation. Cenovus received financial compensation from the
Government of Alberta related to some of its non-core oil sands mineral rights that were cancelled. The cancelled mineral rights had no direct impact on the Corporations business plan, its current operations at Foster Creek and Christina Lake,
or on any of its filed applications. Uncertainty exists with respect to the impact to future development applications in the areas covered by the LARP, including the potential for development restrictions and mineral rights cancellation. The Government of Alberta has also approved the South Saskatchewan Regional Plan (SSRP), the second and similar regional plan to be developed
under the ALSA. This plan applies to Cenovuss conventional oil and gas operations in southern Alberta. To date, the SSRP is not expected to materially impact Cenovuss existing conventional oil and gas operations, but no assurance can be
given that future expansion of these operations will not be affected.






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The Government of Alberta has commenced development of the North Saskatchewan Regional Plan
(NSRP). This plan will apply to Cenovuss operations in central Alberta. No assurance can be given that the NSRP, or any future regional plans developed and implemented by the Government of Alberta, will not materially impact
operations or future operations in this region. The Government of Alberta has also announced four additional regional plans which are to come into
effect under ALSA which may apply to Cenovuss landholdings and operations in other areas of Alberta, but development of these plans has not yet begun. Species at Risk Act The Canadian federal legislation, Species at Risk Act, and provincial counterparts regarding threatened or endangered species may limit the pace
and the amount of development in areas identified as critical habitat for species of concern (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 the Corporations 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. Federal Air Quality Management System In June 2014, under the Federal Air Quality Management System, Environment Canada announced draft Multi-sector Air Pollutants Regulations
(MAPR). The draft MAPR are aimed at equipment-specific Base-Level Industrial Emissions Requirements (BLIERs). Under the draft MAPR, nitrogen oxide BLIERs from the Corporations non-utility boilers, heaters and
reciprocating engines will be regulated in accordance with specified performance standards. Due to the recent change in government, it is unclear when these regulations will come into force. Cenovus does not anticipate a material impact to existing
or future operations as a result of the MAPR.


Water Licenses Cenovus currently utilizes fresh water in certain operations, which is obtained under licenses issued pursuant to the Water Act (Alberta) to
provide, for example, domestic and utility water at the Corporations SAGD facilities and for its bitumen delineation programs. Currently, the Corporation is not required to pay for the water it uses under these licenses. If a change under
these licenses reduces the amount of water available for the Corporations use, its production could decline or operating expenses could increase, both of which may have a material adverse effect on the Corporations 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 Cenovus 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 the Corporations 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 Cenovus, or at all, or that such additional water will in fact be available to divert under such licenses. Alberta Wetlands Policy In September 2013, the Government of Alberta approved a new wetlands policy to be fully
implemented by June 2015 in southern Alberta (White Area) and June 2016 for the boreal region (Green Area). This new policy is not expected to affect Cenovuss existing operations in Foster Creek, Christina Lake and
Narrows Lake, where the Corporations ten year wetlands mitigation and monitoring plans were approved under the previously existing wetlands policy. New project developments and future phase expansions will likely be affected by this policy. Cenovuss oil sands leases are in areas where wetlands
cover over 50% of the landscape. Avoidance may not be an option for new project developments and phase expansions. Additional details of the wetlands assessment and compensation requirements are still to be determined within the policy.
Based on written statements in the Alberta Wetland Mitigation Directive, 2015, Cenovus does not anticipate a material impact; however with the change in the provincial government it is unclear how this policy will be implemented. At this time, no
assurance can be given that the policy will not have an impact on future development plans.






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REPUTATION RISKS



Cenovus relies on its reputation to build and maintain positive relationships with its stakeholders, to
recruit and retain staff, and to be a credible, trusted company. Any actions the Corporation takes that cause negative public opinion have the potential to negatively impact Cenovuss reputation which may adversely affect its share price, its
development plans and its ability to continue operations. Public Perception and Influence on Regulatory Regime Development of the Alberta oil sands has received considerable attention in recent public commentary on the subjects of environmental
impact, climate change and GHG emissions. Despite that much of the focus is on bitumen mining operations and not in-situ production, public concerns about oil sands generally and GHG emissions and water and land use practices in oil sands
developments specifically may, directly or indirectly, impair the profitability of


the Corporations current oil sands projects, and the viability of future oil sands projects, by creating significant regulatory uncertainty leading to uncertain economic modeling of current
and future projects and delays relating to the sanctioning of future projects. Negative consequences which could arise as a result of changes to the
current regulatory environment include, but are not limited to, extraordinary environmental and emissions regulation of current and future projects by governmental authorities, which could result in changes to facility design and operating
requirements, thereby potentially increasing the cost of construction, operation and abandonment. In addition, legislation or policies that limit the purchase of crude oil or bitumen produced from the oil sands may be adopted in domestic and/or
foreign jurisdictions, which, in turn, may limit the world market for this crude oil, reduce its price and may result in stranded assets or an inability to further develop oil resources.






OTHER RISK
FACTORS

Arrangement Related Risk Cenovus has certain post-Arrangement indemnification and other obligations under each of the arrangement agreement (the Arrangement Agreement)
and the separation and transition agreement (the Separation Agreement), both of which are among Encana, 7050372 and Subco, dated October 20, 2009 and November 30, 2009 respectively, entered in connection with the Arrangement.
Encana and Cenovus have agreed to indemnify each other for certain liabilities and obligations associated with, among other things, in the case of Encanas indemnity, the business and assets retained by Encana, and in the case of Cenovuss
indemnity, the Cenovus business and


assets. At the present time, the Corporation cannot determine whether it will have to indemnify Encana for any substantial obligations under the terms of the Arrangement. Cenovus also cannot
assure that if Encana has to indemnify Cenovus and its affiliates for any substantial obligations, Encana will be able to satisfy such obligations. A
discussion of additional risks, should they arise after the date of this AIF, which may impact Cenovuss business, prospects, financial condition, results of operation and cash flows, and in some cases its reputation, can be found in the
Corporations most recent Managements Discussion and Analysis, available at sedar.com, sec.gov and cenovus.com.






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LEGAL PROCEEDINGS AND REGULATORY ACTIONS



During the year ended
December 31, 2015, there were no legal proceedings to which Cenovus is or was a party, or that any of its property is or was the subject of, which involves a claim for damages in an amount, exclusive of interest and costs, that exceeds 10
percent of Cenovuss current assets and it is not aware of any such legal proceedings that are contemplated.

During the year ended
December 31, 2015, there were no penalties or sanctions imposed against Cenovus by a court relating to provincial and territorial securities legislation or by a securities regulatory authority, nor have there been any other penalties or
sanctions imposed by a court or regulatory body against the Corporation that would likely be considered important to a reasonable investor in making an investment decision, and it has not entered into any settlement agreements before a court
relating to provincial and territorial securities legislation or with a securities regulatory authority.

INTEREST OF MANAGEMENT AND OTHERS IN MATERIAL TRANSACTIONS



None of the Corporations directors or executive officers or any person or company that beneficially owns, or controls or directs, directly or
indirectly, more than 10 percent of any class or series of Cenovuss outstanding voting securities, of which there are none that the Corporation is aware, or any associate or affiliate of any of the foregoing persons or companies, in each case,
as at the date of this AIF, has or has had any material interest, direct or indirect, in any past transaction or any proposed transaction that has materially affected or is reasonably expected to materially affect Cenovus.

MATERIAL CONTRACTS



During the year ended December 31, 2015,
Cenovus has not entered into any contracts, nor are there any contracts still in effect, that are material to the business, other than contracts entered into in the ordinary course of business, and each of the Arrangement Agreement and the
Separation Agreement, as described under Risk Factors  Other Risk Factors  Arrangement Related Risk.

INTERESTS OF EXPERTS



The Corporations independent auditors
are PricewaterhouseCoopers LLP, Chartered Professional Accountants, who have issued an independent auditors report dated February 10, 2016 in respect of Cenovuss Consolidated Financial Statements which comprise the Consolidated
Balance Sheets as at December 31, 2015 and December 31, 2014 and the Consolidated Statements of Earnings and Comprehensive Income, Shareholders Equity and Cash Flows for the years ended December 31, 2015, 2014, and 2013 and
Cenovuss internal control over financial reporting as at December 31, 2015. PricewaterhouseCoopers LLP has advised that they are independent with respect to Cenovus within the meaning of the Code of Professional Conduct of the Chartered
Professional Accountants of Alberta and the rules of the SEC.

Information relating to reserves in this AIF has been calculated by GLJ Petroleum
Consultants Ltd. and McDaniel & Associates Consultants Ltd. as independent qualified reserves evaluators. The principals of each of GLJ Petroleum Consultants Ltd. and McDaniel & Associates Consultants Ltd., in each case, as a group
own beneficially, directly or indirectly, less than one percent of any class of the Corporations securities.

TRANSFER AGENTS AND REGISTRARS





|                                                                                                 |  |                                                                    
|------------------------------------------------------------------------------------------------ |  | -------------------------------------------------------------------
|In Canada:                                                                                       |  | In the United States:                                              
|Computershare Investor Services Inc.
8th Floor, 100 University Avenue
Toronto, ON M5J 2Y1
Canada |  | Computershare Trust Company NA
250 Royall St.
Canton, MA 02021
U.S.



|                                                                    
|--------------------------------------------------------------------
|Tel: 1-866-332-8898          Website: www.investorcentre.com/cenovus



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ADDITIONAL INFORMATION



Additional information relating to Cenovus is available on SEDAR at sedar.com, and EDGAR at sec.gov.
Additional financial information is contained in the Corporations audited Consolidated Financial Statements and MD&A for the year ended December 31, 2015. Additional disclosure, including directors and officers
remuneration and indebtedness, principal holders of Cenovuss securities, securities authorized for issuance under its equity-based compensation plans and its statement of corporate governance practices, is included in the Corporations
management proxy circular for its most recent annual meeting of shareholders. Additional financial information, including disclosure regarding the
contribution of each reportable segment to revenues and earnings can be found in Cenovuss audited Consolidated Financial Statements and MD&A for the year ended December 31, 2015, which disclosure is incorporated by reference into this
AIF. As a Canadian corporation listed on the NYSE, Cenovus is not required to comply with most of the NYSEs corporate governance standards, and
instead may comply with Canadian corporate governance


practices. However, the Corporation is required to disclose the significant differences between its corporate governance practices and the requirements applicable to U.S. domestic companies
listed on the NYSE. Except as summarized on Cenovuss website at cenovus.com, it is in compliance with the NYSE corporate governance standards in all significant respects. ACCOUNTING MATTERS Unless otherwise specified, all dollar amounts are expressed in Canadian dollars. All references to dollars, C$ or to
$ are to Canadian dollars and all references to US$ are to U.S. dollars. The information contained in this AIF is dated as at December 31, 2015 unless otherwise indicated. Numbers presented are rounded to the nearest
whole number and tables may not add due to rounding. Unless otherwise indicated, all financial information included in this AIF has been prepared in
accordance with International Financial Reporting Standards, which are also generally accepted accounting principles for publicly accountable enterprises in Canada.






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ABBREVIATIONS AND CONVERSIONS





|                            |  |                                   |  |        |  |                              
|--------------------------- |  | --------------------------------- |  | ------ |  | -----------------------------
|Oil and Natural Gas Liquids |  | Natural Gas                      
|                            |  |                                   | 
|bbl                         |  | barrel                            |  | Bcf    |  | billion cubic feet           
|bbls/d                      |  | barrels per day                   |  | Mcf    |  | thousand cubic feet          
|Mbbls/d                     |  | thousand barrels per day          |  | MMcf   |  | million cubic feet           
|MMbbls                      |  | million barrels                   |  | MMcf/d |  | million cubic feet per day   
|NGLs                        |  | natural gas liquids               |  | MMBtu  |  | million British thermal units
|BOE                         |  | barrel of oil equivalent          |  | CBM    |  | Coal Bed Methane             
|BOE/d                       |  | barrels of oil equivalent per day |  |        |  |                              
|WTI                         |  | West Texas Intermediate           |  |        |  |                              

In this AIF, certain natural gas volumes have been converted to BOE on the basis of six Mcf to one bbl. BOE may be
misleading, particularly if used in isolation. A conversion ratio of six Mcf to one bbl is based on an energy equivalency conversion method primarily applicable at the burner tip and does not represent value equivalency at the wellhead.

TM denotes a trademark of Cenovus Energy Inc.



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APPENDIX A



REPORT ON RESERVES
DATA BY INDEPENDENT QUALIFIED RESERVES EVALUATORS

To the Board of Directors of Cenovus Energy Inc. (the Corporation):



|1. | We have evaluated the Corporations reserves data as at December 31, 2015. The reserves data are estimates of proved reserves and probable reserves
and related future net revenue as at December 31, 2015, estimated using forecast prices and costs.
|-- | ------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------



|2. | The reserves data are the responsibility of the Corporations management. Our responsibility is to express an opinion on the reserves data based on our
evaluation.
|-- | -------------------------------------------------------------------------------------------------------------------------------------------------------------------



|3. | We carried out our evaluation in accordance with standards set out in the Canadian Oil and Gas Evaluation Handbook as amended from time to time (the
COGE Handbook) and maintained by the Society of Petroleum Evaluation Engineers (Calgary Chapter).
|-- | --------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------



|4. | Those standards require that we plan and perform an evaluation to obtain reasonable assurance as to whether the reserves data are free of material
misstatement. An evaluation also includes assessing whether the reserves data are in accordance with principles and definitions presented in the COGE Handbook.
|-- | ------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------



|5. | The following table sets forth the estimated future net revenue (before deduction of income taxes) attributed to proved plus probable reserves, estimated
using forecast prices and costs and calculated using a discount rate of 10 percent, included in the reserves data of the Corporation evaluated for the year ended December 31, 2015, and identifies the respective portions thereof that we have
evaluated and reported on to the Corporations Board of Directors:
|-- | -----------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------



| |  |                                          |  |                                     |  |                     |  |                                                                                                       
| |  | ---------------------------------------- |  | ----------------------------------- |  | ------------------- |  | ------------------------------------------------------------------------------------------------------
| |  | Independent Qualified
Reserves Evaluator |  | Effective Date of
Evaluation Report |  | Location ofReserves |  | Evaluated Net Present
Value of Future Net  Revenue
(before income taxes,
10% discount rate)
$ millions
| |  |                                         
| |  |                                          |  |                                    
| |  | McDaniel & Associates
Consultants Ltd.   |  | December 31, 2015                   |  | Canada              |  | $20,280                                                                                               
| |  |                                          |  |                                    
| |  | GLJ Petroleum
Consultants Ltd.           |  | December 31, 2015                   |  | Canada              |  | $1,286                                                                                                
| |  |                                          |  |                                     |  |                     |  |                                                                                                       
| |  |                                          |  |                                     |  |                     |  |                                                                                                       
| |  |                                          |  |                                     |  |                     |  | $21,566                                                                                               
| |  |                                          |  |                                     |  |                     |  |                                                                                                       



|6. | In our opinion, the reserves data respectively evaluated by us have, in all material respects, been determined and are in accordance with the COGE Handbook,
consistently applied.
|-- | ----------------------------------------------------------------------------------------------------------------------------------------------------------------------------------



|7. | We have no responsibility to update our reports referred to in paragraph five for events and circumstances occurring after their respective effective dates.
|-- | ------------------------------------------------------------------------------------------------------------------------------------------------------------



|8. | Because the reserves data are based on judgments regarding future events, actual results will vary and the variations may be material.
|-- | --------------------------------------------------------------------------------------------------------------------------------------

Executed as to our report referred to above:



|                                                                          |  |                                                                              
|------------------------------------------------------------------------- |  | -----------------------------------------------------------------------------
|/s/ P.A. Welch P.A. Welch, P. Eng.
McDaniel & Associates Consultants Ltd. |  | /s/ Keith M. Braaten Keith M. Braaten, P. Eng.
GLJ Petroleum Consultants Ltd.
|Calgary, Alberta, Canada                                                  |  | Calgary, Alberta, Canada                                                     

February 9, 2016



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APPENDIX B



REPORT OF
MANAGEMENT AND DIRECTORS

ON RESERVES DATA AND OTHER INFORMATION

Management and directors of Cenovus Energy Inc. (the Corporation) are responsible for the preparation and disclosure of information with
respect to the Corporations oil and gas activities in accordance with securities regulatory requirements. This information includes reserves data.

Independent qualified reserves evaluators have evaluated the Corporations reserves data. A report from the independent qualified reserves evaluators
will be filed with securities regulatory authorities concurrently with this report.

The Reserves Committee of the Board of Directors of the
Corporation has:



| | (a) | reviewed the Corporations procedures for providing information to the independent qualified reserves evaluators;
| | --- | -----------------------------------------------------------------------------------------------------------------



| | (b) | met with the independent qualified reserves evaluators to determine whether any restrictions affected the ability of the independent qualified reserves
evaluators to report without reservation; and
| | --- | -----------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------



| | (c) | reviewed the reserves data with management and each of the independent qualified reserves evaluators.
| | --- | -----------------------------------------------------------------------------------------------------

The Board of Directors of the Corporation has reviewed the Corporations procedures for assembling and reporting other information associated with
oil and gas activities and has reviewed that information with management. The Board of Directors, on the recommendation of the Reserves Committee, has approved:



| | (a) | the content and filing with securities regulatory authorities of the reserves data and other oil and gas information;
| | --- | ---------------------------------------------------------------------------------------------------------------------



| | (b) | the filing of the report of the independent qualified reserves evaluators on the reserves data; and
| | --- | ---------------------------------------------------------------------------------------------------



| | (c) | the content and filing of this report.
| | --- | --------------------------------------

Because the reserves data are based on judgments regarding future events, actual results will vary and the variations may be material.



|                                          |  |                                             
|----------------------------------------- |  | --------------------------------------------
|/s/ Brian C. Ferguson Brian C. Ferguson   |  | /s/ Ivor M. Ruste Ivor M. Ruste             
|President & Chief Executive Officer       |  | Executive Vice-President &                  
|                                          |  | Chief Financial Officer                     
|                                          | 
|/s/ Michael A. Grandin Michael A. Grandin |  | /s/ Wayne G. Thomson Wayne G. Thomson       
|Director and Chair of the Board           |  | Director and Chair of the Reserves Committee

February 10, 2016



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APPENDIX C



AUDIT COMMITTEE
MANDATE



|I. | PURPOSE
|-- | -------

The Audit Committee (the Committee) is a committee of the Board of Directors (the Board) of Cenovus Energy Inc.
(Cenovus or the Corporation) appointed to assist the Board in fulfilling its oversight responsibilities.

The Committees
primary duties and responsibilities are to:



|● |  | Oversee and monitor the effectiveness and integrity of the Corporations accounting and financial reporting processes, financial statements and system of
internal controls regarding accounting and financial reporting compliance.
|- |  | ------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------

|● |  | Oversee audits of the Corporations financial statements.
|- |  | ---------------------------------------------------------

|● |  | Review and evaluate the Corporations risk management framework and related processes including the supporting guidelines and practice documents.
|- |  | -------------------------------------------------------------------------------------------------------------------------------------------------

|● |  | Review and approve managements identification of principal financial risks and monitor the process to manage such risks.
|- |  | -------------------------------------------------------------------------------------------------------------------------

|● |  | Oversee and monitor the Corporations compliance with legal and regulatory requirements.
|- |  | ----------------------------------------------------------------------------------------

|● |  | Oversee and monitor the qualifications, independence and performance of the Corporations external auditors and internal auditing group.
|- |  | ----------------------------------------------------------------------------------------------------------------------------------------

|● |  | Provide an avenue of communication among the external auditors, management, the internal auditing group, and the Board.
|- |  | -----------------------------------------------------------------------------------------------------------------------

|● |  | Report to the Board regularly.
|- |  | ------------------------------

The
Committee has the authority to conduct any review or investigation appropriate to fulfilling its responsibilities. The Committee shall have unrestricted access to personnel and information, and any resources necessary to carry out its
responsibility. In this regard, the Committee may direct internal audit personnel to particular areas of examination.



|II. | COMPOSITION AND MEETINGS
|--- | ------------------------

Composition

The Committee shall consist of not less than three and not more than eight directors as determined by the Board, all of whom shall qualify as independent
directors pursuant to National Instrument 52-110 Audit Committees (as implemented by the Canadian Securities Administrators (CSA) and as amended from time to time) (NI 52-110).

All members of the Committee shall be financially literate, as defined in NI 52-110, and at least one member shall have accounting or related financial
managerial expertise. In particular, at least one member shall have, through (i) education and experience as a principal financial officer, principal accounting officer, controller, public accountant or auditor or experience in one or more
positions that involve the performance of similar functions; (ii) experience actively supervising a principal financial officer, principal accounting officer, controller, public accountant, auditor or person performing similar functions;
(iii) experience overseeing or assessing the performance of companies or public accountants with respect to the preparation, auditing or evaluation of financial statements; or (iv) other relevant experience:



|● |  | An understanding of accounting principles and financial statements;
|- |  | -------------------------------------------------------------------

|● |  | The ability to assess the general application of such principles in connection with the accounting for estimates, accruals and reserves;
|- |  | ----------------------------------------------------------------------------------------------------------------------------------------

|● |  | Experience preparing, auditing, analyzing or evaluating financial statements that present a breadth and level of complexity of accounting issues that are
generally comparable to the breadth and complexity of issues that can reasonably be expected to be raised by the Corporations financial statements, or experience actively supervising one or more persons engaged in such activities;
|- |  | -------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------

|● |  | An understanding of internal controls and procedures for financial reporting; and
|- |  | ---------------------------------------------------------------------------------

|● |  | An understanding of audit committee functions.
|- |  | ----------------------------------------------

Committee members may not, other than in their respective capacities as members of the Committee, the Board or any other committee of the Board, accept
directly or indirectly any consulting, advisory or other compensatory fee from the Corporation or any subsidiary of the Corporation, or be an affiliated person (as such term is defined in the United States Securities Exchange Act of
1934, as amended (the Exchange Act), and the rules, if any, adopted by the U.S. Securities and Exchange Commission (SEC) thereunder) of the Corporation or any subsidiary of the Corporation. For greater certainty,
directors fees and fixed amounts of compensation under a retirement plan (including deferred compensation) for prior service with the Corporation that are not contingent on continued service should be the only compensation an Audit Committee
member receives from the Corporation.

At least one member shall have experience in the oil and gas industry.



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Committee members shall not simultaneously serve on the audit committees of more than two other public
companies, unless the Board first determines that such simultaneous service will not impair the ability of the relevant members to effectively serve on the Committee, and required public disclosure is made.

The non-executive Board Chair shall be a non-voting member of the Committee. See Quorum for further details.

Appointment of Committee Members

Committee members shall be appointed by the Board, effective after the election of directors at the annual meeting of shareholders, provided that any
member may be removed or replaced at any time by the Board and shall, in any event, cease to be a member of the Committee upon ceasing to be a member of the Board.

Vacancies

Where a vacancy occurs at any time in the membership of the Committee, it may be filled by the Board.

Chair

The
Nominating and Corporate Governance Committee will recommend for approval to the Board an unrelated Director to act as Chair of the Committee. The Board shall appoint the Chair of the Committee.

If unavailable or unable to attend a meeting of the Committee, the Chair shall ask another member to chair the meeting, failing which a member of the
Committee present at the meeting shall be chosen to preside over the meeting by a majority of the members of the Committee present at such meeting.

The Chair presiding at any meeting of the Committee shall not have a casting vote.

The items pertaining to the Chair in this section should be read in conjunction with the Committee Chair section of the Chair of the Board of Directors
and Committee Chair General Guidelines.

Secretary

The Committee shall appoint a Secretary who need not be a member of the Committee. The Secretary shall keep minutes of the meetings of the Committee.

Meetings

The Committee shall meet at least quarterly. The Chair of the Committee may call additional meetings as required. In addition, a meeting may be called by
the non-executive Board Chair, the President & Chief Executive Officer, or any member of the Committee or by the external auditors.

Committee meetings may, by agreement of the Chair of the Committee, be held in person, by video conference, by means of telephone or by a combination of
any of the foregoing.

Notice of Meeting

Notice of the time and place of each Committee meeting may be given orally, or in writing, or by facsimile, or by electronic means to each member of the
Committee at least 24 hours prior to the time fixed for such meeting. Notice of each meeting shall also be given to the external auditors of the Corporation.

A member and the external auditors may, in any manner, waive notice of the Committee meeting. Attendance of a member at a meeting shall constitute waiver
of notice of the meeting except where a member attends a meeting for the express purpose of objecting to the transaction of any business on the grounds that the meeting was not lawfully called.

Quorum

A
majority of Committee members, present in person, by video conference, by telephone, or by a combination thereof, shall constitute a quorum. In addition, if an ex officio, non-voting members presence is required to attain a quorum of the
Committee, then the said member shall be allowed to cast a vote at the meeting.

Attendance at Meetings

The President & Chief Executive Officer, the Executive Vice-President & Chief Financial Officer, the Comptroller and
the head of internal audit are expected to be available to attend the Committees meetings or portions thereof.

The Committee may, by specific
invitation, have other resource persons in attendance.

The Committee shall have the right to determine who shall, and who shall not, be present at
any time during a meeting of the Committee.

Directors, who are not members of the Committee, may attend Committee meetings, on an ad hoc basis, upon
prior consultation and approval by the Committee Chair or by a majority of the members of the Committee.



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Minutes

Minutes of each Committee meeting should be succinct yet comprehensive in describing substantive issues discussed by the Committee. However, they should
clearly identify those items of responsibilities scheduled by the Committee for the meeting that have been discharged by the Committee and those items of responsibilities that are outstanding.

Minutes of Committee meetings shall be sent to all Committee members and to the external auditors. The full Board of Directors shall be kept informed of
the Committees activities by a report following each Committee meeting.



|III. | RESPONSIBILITIES
|---- | ----------------

Review Procedures

Review and update the Committees mandate annually, or sooner if the Committee deems it appropriate to do so. Review the summary of the
Committees composition and responsibilities in the Corporations annual report, annual information form or other public disclosure documentation.

Review the summary of all approvals by the Committee of the provision of audit, audit-related, tax and other services by the external auditors for
inclusion in the Corporations annual report and Annual Information Form filed with the CSA and the SEC.

Annual
Financial Statements



|1. | Discuss and review with management and the external auditors the Corporations and any subsidiary with public securities annual audited financial
statements and related documents prior to their filing or distribution. Such review shall include:
|-- | -----------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------



| | (a) | The annual financial statements and related notes including significant issues regarding accounting principles, practices and significant management estimates
and judgments, including any significant changes in the Corporations selection or application of accounting principles, any major issues as to the adequacy of the Corporations internal controls and any special steps adopted in light of
material control deficiencies.
| | --- | -------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------

| | (b) | Managements Discussion and Analysis.
| | --- | -------------------------------------

| | (c) | The use of off-balance sheet financing including managements risk assessment and adequacy of disclosure.
| | --- | ---------------------------------------------------------------------------------------------------------

| | (d) | The external auditors audit examination of the financial statements and their report thereon.
| | --- | ----------------------------------------------------------------------------------------------

| | (e) | Any significant changes required in the external auditors audit plan.
| | --- | ----------------------------------------------------------------------

| | (f) | Any serious difficulties or disputes with management encountered during the course of the audit, including any restrictions on the scope of the external
auditors work or access to required information.
| | --- | ----------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------

| | (g) | Other matters related to the conduct of the audit, which are to be communicated to the Committee under generally accepted auditing standards.
| | --- | ---------------------------------------------------------------------------------------------------------------------------------------------



|2. | Review and formally recommend approval to the Board of the Corporations:
|-- | -------------------------------------------------------------------------



| | (a) | Year-end audited financial statements. Such review shall include discussions with management and the external auditors as to:
| | --- | -----------------------------------------------------------------------------------------------------------------------------

| | (i) | The accounting policies of the Corporation and any changes thereto.
| | --- | -------------------------------------------------------------------

| | (ii) | The effect of significant judgments, accruals and estimates.
| | ---- | ------------------------------------------------------------

| | (iii) | The manner of presentation of significant accounting items.
| | ----- | -----------------------------------------------------------

| | (iv) | The consistency of disclosure.
| | ---- | ------------------------------

| | (b) | Managements Discussion and Analysis.
| | --- | -------------------------------------

| | (c) | Annual Information Form as to financial information.
| | --- | ----------------------------------------------------

| | (d) | All prospectuses and information circulars as to financial information.
| | --- | -----------------------------------------------------------------------



| | The review shall include a report from the external auditors about the quality of the most critical accounting principles upon which the Corporations
financial status depends, and which involve the most complex, subjective or significant judgmental decisions or assessments.
| | -----------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------

Quarterly Financial Statements



|3. | Review with management and the external auditors and either approve (such approval to include the authorization for public release) or formally recommend for
approval to the Board the Corporations:
|-- | ------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------



| | (a) | Quarterly unaudited financial statements and related documents, including Managements Discussion and Analysis.
| | --- | ---------------------------------------------------------------------------------------------------------------

| | (b) | Any significant changes to the Corporations accounting principles.
| | --- | -------------------------------------------------------------------



| | Review quarterly unaudited financial statements prior to their distribution of any subsidiary of the Corporation with public securities.
| | ----------------------------------------------------------------------------------------------------------------------------------------



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Other Financial Filings and Public Documents



|4. | Review and discuss with management financial information, including earnings press releases, the use of pro forma or non-GAAP financial
information and earnings guidance, contained in any filings with the CSA or SEC or news releases related thereto, and consider whether the information is consistent with the information contained in the financial statements of the Corporation or any
subsidiary with public securities.
|-- | --------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------

Internal Control Environment



|5. | Receive and review from management, the external auditors and the internal auditors an annual report on the Corporations control environment as it
pertains to the Corporations financial reporting process and controls.
|-- | ---------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------



|6. | Review and discuss significant financial risks or exposures and assess the steps management has taken to monitor, control, report and mitigate such risk to
the Corporation.
|-- | ----------------------------------------------------------------------------------------------------------------------------------------------------------------------------



|7. | Review in consultation with the internal auditors and the external auditors the degree of coordination in the audit plans of the internal auditors and the
external auditors and enquire as to the extent the planned scope can be relied upon to detect weaknesses in internal controls, fraud, or other illegal acts. The Committee will assess the coordination of audit effort to assure completeness of
coverage and the effective use of audit resources. Any significant recommendations made by the auditors for the strengthening of internal controls shall be reviewed and discussed with management.
|-- | ----------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------



|8. | Review with the President & Chief Executive Officer, the Executive Vice-President & Chief Financial Officer of the Corporation and the
external auditors: (i) all significant deficiencies and material weaknesses in the design or operation of the Corporations internal controls and procedures for financial reporting which could adversely affect the Corporations
ability to record, process, summarize and report financial information required to be disclosed by the Corporation in the reports that it files or submits under the Exchange Act or applicable Canadian federal and provincial legislation and
regulations within the required time periods, and (ii) any fraud, whether or not material, that involves management of the Corporation or other employees who have a significant role in the Corporations internal controls and procedures for
financial reporting.
|-- | -----------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------



|9. | Review significant findings prepared by the external auditors and the internal auditing department together with managements responses.
|-- | ----------------------------------------------------------------------------------------------------------------------------------------

Risk Oversight



|10. | Review and evaluate the Corporations risk management framework and related processes including the supporting guidelines and practice documents.
|--- | -------------------------------------------------------------------------------------------------------------------------------------------------

Other Review Items



|11. | Review policies and procedures with respect to officers and directors expense accounts and perquisites, including their use of corporate assets,
and consider the results of any review of these areas by the internal auditor or the external auditors.
|--- | ----------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------



|12. | Review all related party transactions between the Corporation and any executive officers or directors, including affiliations of any executive officers or
directors.
|--- | ---------------------------------------------------------------------------------------------------------------------------------------------------------------------



|13. | Review with the General Counsel, the head of internal audit and the external auditors the results of their review of the Corporations monitoring
compliance with each of the Corporations published codes of business conduct and applicable legal requirements.
|--- | ------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------



|14. | Review legal and regulatory matters, including correspondence with and reports received from regulators and government agencies, that may have a material
impact on the interim or annual financial statements and related corporate compliance policies and programs. Members from the Legal and Tax groups should be at the meeting in person to deliver their respective reports.
|--- | ------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------



|15. | Review policies and practices with respect to off-balance sheet transactions and trading and hedging activities, and consider the results of any review of
these areas by the internal auditors or the external auditors.
|--- | -------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------



|16. | Ensure that the Corporations presentation of hydrocarbon reserves has been reviewed with the Reserves Committee of the Board.
|--- | ------------------------------------------------------------------------------------------------------------------------------



|17. | Review managements processes in place to prevent and detect fraud.
|--- | -------------------------------------------------------------------



|18. | Review:
|--- | -------



| | (a) | procedures for the receipt, retention and treatment of complaints received by the Corporation, including confidential, anonymous submissions by employees of
the Corporation, regarding accounting, internal accounting controls, or auditing matters; and
| | --- | ----------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------



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| | (b) | a summary of any significant investigations regarding such matters.
| | --- | -------------------------------------------------------------------



|19. | Meet on a periodic basis separately with management.
|--- | ----------------------------------------------------

External Auditors



|20. | Be directly responsible, in the Committees capacity as a committee of the Board and subject to the rights of shareholders and applicable law, for the
appointment, compensation, retention and oversight of the work of the external auditors (including resolution of disagreements between management and the external auditors regarding financial reporting) for the purpose of preparing or issuing an
audit report, or performing other audit, review or attest services for the Corporation. The external auditors shall report directly to the Committee.
|--- | ------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------



|21. | Meet on a regular basis with the external auditors (without management present) and have the external auditors be available to attend Committee meetings or
portions thereof at the request of the Chair of the Committee or by a majority of the members of the Committee.
|--- | ---------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------



|22. | Review and discuss a report from the external auditors at least quarterly regarding:
|--- | ------------------------------------------------------------------------------------



| | (a) | All critical accounting policies and practices to be used;
| | --- | ----------------------------------------------------------

| | (b) | All alternative treatments within accounting principles for policies and practices related to material items that have been discussed with management,
including the ramifications of the use of such alternative disclosures and treatments, and the treatment preferred by the external auditors; and
| | --- | -------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------

| | (c) | Other material written communications between the external auditors and management, such as any management letter or schedule of unadjusted differences.
| | --- | --------------------------------------------------------------------------------------------------------------------------------------------------------



|23. | Obtain and review a report from the external auditors at least annually regarding:
|--- | ----------------------------------------------------------------------------------



| | (a) | The external auditors internal quality-control procedures.
| | --- | -----------------------------------------------------------

| | (b) | Any material issues raised by the most recent internal quality-control review, or peer review, of the external auditors, or by any inquiry or investigation by
governmental or professional authorities, within the preceding five years, respecting one or more independent audits carried out by the external auditors, and any steps taken to deal with those issues.
| | --- | ------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------

| | (c) | To the extent contemplated in the following paragraph, all relationships between the external auditors and the Corporation.
| | --- | ---------------------------------------------------------------------------------------------------------------------------



|24. | Review and discuss at least annually with the external auditors all relationships that the external auditors and their affiliates have with the Corporation
and its affiliates in order to determine the external auditors independence, including, without limitation, (i) receiving and reviewing, as part of the report described in the preceding paragraph, a formal written statement from the
external auditors delineating all relationships that may reasonably be thought to bear on the independence of the external auditors with respect to the Corporation and its affiliates, (ii) discussing with the external auditors any disclosed
relationships or services that the external auditors believe may affect the objectivity and independence of the external auditors, and (iii) recommending that the Board take appropriate action in response to the external auditors report
to satisfy itself of the external auditors independence.
|--- | --------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------



|25. | Review and evaluate annually:
|--- | -----------------------------



| | (a) | The external auditors and the lead partner of the external auditors teams performance, and make a recommendation to the Board of Directors
regarding the reappointment of the external auditors at the annual meeting of the Corporations shareholders or regarding the discharge of such external auditors.
| | --- | ----------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------

| | (b) | The terms of engagement of the external auditors together with their proposed fees.
| | --- | -----------------------------------------------------------------------------------

| | (c) | External audit plans and results.
| | --- | ---------------------------------

| | (d) | Any other related audit engagement matters.
| | --- | -------------------------------------------

| | (e) | The engagement of the external auditors to perform non-audit services, together with the fees therefor, and the impact thereof, on the independence of the
external auditors.
| | --- | -----------------------------------------------------------------------------------------------------------------------------------------------------------------------------

| | (f) | Review the Annual Report of the Canadian Public Accountability Board (CPAB) concerning audit quality in Canada and discuss implications for
Cenovus.
| | --- | ------------------------------------------------------------------------------------------------------------------------------------------------------

| | (g) | Review any reports issued by CPAB regarding the audit of Cenovus.
| | --- | -----------------------------------------------------------------



|26. | Conduct periodically a comprehensive review of the external auditor, with the outcome intended to assist the Committee to identify potential areas for
improvement for the audit firm, and to reach a final conclusion on whether the auditor should be reappointed or the audit put out for tender.
|--- | ----------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------



|27. | Upon reviewing and discussing the information provided to the Committee in accordance with paragraphs 22 through 25, evaluate the external auditors
qualifications, performance and independence, including whether or not the external auditors quality controls are adequate and the provision of permitted non-audit services is compatible with maintaining auditor independence, taking into
account the opinions of management and the head of internal audit. The Committee shall present to the Board its conclusions in this respect.
|--- | ------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------



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|28. | Review the rotation of partners on the audit engagement team in accordance with applicable law. Consider whether, in order to assure continuing external
auditor independence, it is appropriate to adopt a policy of rotating the external auditing firm on a regular basis.
|--- | -----------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------



|29. | Set clear hiring policies for the Corporations hiring of employees or former employees of the external auditors.
|--- | -----------------------------------------------------------------------------------------------------------------



|30. | Consider with management and the external auditors the rationale for employing audit firms other than the principal external auditors.
|--- | --------------------------------------------------------------------------------------------------------------------------------------



|31. | Consider and review with the external auditors, management and the head of internal audit:
|--- | ------------------------------------------------------------------------------------------



| | (a) | Significant findings during the year and managements responses and follow-up thereto.
| | --- | --------------------------------------------------------------------------------------

| | (b) | Any difficulties encountered in the course of their audits, including any restrictions on the scope of their work or access to required information, and
managements response.
| | --- | -------------------------------------------------------------------------------------------------------------------------------------------------------------------------------

| | (c) | Any significant disagreements between the external auditors or internal auditors and management.
| | --- | ------------------------------------------------------------------------------------------------

| | (d) | Any changes required in the planned scope of their audit plan.
| | --- | --------------------------------------------------------------

| | (e) | The resources, budget, reporting relationships, responsibilities and planned activities of the internal auditors.
| | --- | -----------------------------------------------------------------------------------------------------------------

| | (f) | The internal audit department mandate.
| | --- | --------------------------------------

| | (g) | Internal audits compliance with the Institute of Internal Auditors standards.
| | --- | -------------------------------------------------------------------------------

Internal Audit Group and Independence



|32. | Meet on a periodic basis separately with the head of internal audit.
|--- | --------------------------------------------------------------------



|33. | Review and concur in the appointment, compensation, replacement, reassignment, or dismissal of the head of internal audit.
|--- | --------------------------------------------------------------------------------------------------------------------------



|34. | Confirm and assure, annually, the independence of the internal audit group and the external auditors.
|--- | -----------------------------------------------------------------------------------------------------

Approval of Audit and Non-Audit Services



|35. | Review and, where appropriate, approve the provision of all permitted non-audit services (including the fees and terms thereof) in advance of the provision of
those services by the external auditors (subject to the de minimus exception for non-audit services described in the Exchange Act or applicable CSA and SEC legislation and regulations, which services are approved by the Committee prior to the
completion of the audit).
|--- | -------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------



|36. | Review and, where appropriate and permitted, approve the provision of all audit services (including the fees and terms thereof) in advance of the provision of
those services by the external auditors.
|--- | -------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------



|37. | If the pre-approvals contemplated in paragraphs 34 and 35 are not obtained, approve, where appropriate and permitted, the provision of all audit and non-audit
services promptly after the Committee or a member of the Committee to whom authority is delegated becomes aware of the provision of those services.
|--- | ------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------



|38. | Delegate, if the Committee deems necessary or desirable, to subcommittees consisting of one or more members of the Committee, the authority to grant the
pre-approvals and approvals described in paragraphs 34 through 36. The decision of any such subcommittee to grant pre-approval shall be presented to the full Committee at the next scheduled Committee meeting.
|--- | -------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------



|39. | Establish policies and procedures for the pre-approvals described in paragraphs 34 and 35 so long as such policies and procedures are detailed as to the
particular service, the Committee is informed of each service and such policies and procedures do not include delegation to management of the Committees responsibilities under the Exchange Act or applicable CSA and SEC legislation and
regulations.
|--- | -----------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------

Other Matters



|40. | Review and concur in the appointment, replacement, reassignment, or dismissal of the Chief Financial Officer.
|--- | -------------------------------------------------------------------------------------------------------------



|41. | Upon a majority vote of the Committee outside resources may be engaged where and if deemed advisable.
|--- | -----------------------------------------------------------------------------------------------------



|42. | Report Committee actions to the Board of Directors with such recommendations as the Committee may deem appropriate.
|--- | -------------------------------------------------------------------------------------------------------------------



|43. | Conduct or authorize investigations into any matters within the Committees scope of responsibilities. The Committee shall be empowered to retain, obtain
advice or otherwise receive assistance from independent counsel, accountants, or others to assist it in the conduct of any investigation as it deems necessary and the carrying out of its duties.
|--- | ------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------



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|44. | Determine the appropriate funding for payment by the Corporation (i) of compensation to the external auditors for the purpose of preparing or issuing an
audit report or performing other audit, review or attest services for the Corporation, (ii) of compensation to any advisors employed by the Committee, and (iii) of ordinary administrative expenses of the Committee that are necessary or
appropriate in carrying out its duties.
|--- | --------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------



|45. | Obtain assurance from the external auditors that no disclosure to the Committee is required pursuant to the provisions of the Exchange Act regarding the
discovery of illegal acts by the external auditors.
|--- | ------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------



|46. | Review and reassess the adequacy of this Mandate annually and recommend any proposed changes to the Board for approval.
|--- | -----------------------------------------------------------------------------------------------------------------------



|47. | Consider for implementation any recommendations of the Nominating and Corporate Governance Committee of the Board with respect to the Committees
effectiveness, structure, processes or mandate.
|--- | -------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------



|48. | Perform such other functions as required by law, the Corporations by-laws or the Board of Directors.
|--- | -----------------------------------------------------------------------------------------------------



|49. | Consider any other matters referred to it by the Board of Directors.
|--- | --------------------------------------------------------------------



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LOGO

MANAGEMENTS DISCUSSION AND ANALYSIS

FOR
THE YEAR ENDED DECEMBER 31, 2015







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|WHERE TO FIND:                                                   |  |  |    | 
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|OVERVIEW OF CENOVUS                                              |  |  | 2  | 
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|2015 HIGHLIGHTS                                                  |  |  | 4  | 
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|OPERATING RESULTS                                                |  |  | 5  | 
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|COMMODITY PRICES UNDERLYING OUR FINANCIAL RESULTS                |  |  | 6  | 
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|FINANCIAL RESULTS                                                |  |  | 8  | 
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|REPORTABLE SEGMENTS                                              |  |  | 13 | 
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|OIL SANDS                                                        |  |  | 13 | 
|CONVENTIONAL                                                     |  |  | 18 | 
|REFINING AND MARKETING                                           |  |  | 22 | 
|CORPORATE AND ELIMINATIONS                                       |  |  | 24 | 
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|QUARTERLY RESULTS                                                |  |  | 26 | 
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|OIL AND GAS RESERVES AND RESOURCES                               |  |  | 28 | 
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|LIQUIDITY AND CAPITAL RESOURCES                                  |  |  | 29 | 
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|RISK MANAGEMENT                                                  |  |  | 33 | 
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|CRITICAL ACCOUNTING JUDGMENTS, ESTIMATES AND ACCOUNTING POLICIES |  |  | 38 | 
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|CONTROL ENVIRONMENT                                              |  |  | 40 | 
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|CORPORATE RESPONSIBILITY                                         |  |  | 41 | 
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|OUTLOOK                                                          |  |  | 41 | 
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|ADVISORY                                                         |  |  | 43 | 
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|ABBREVIATIONS                                                    |  |  | 45 | 





This Managements Discussion and Analysis (MD&A) for Cenovus Energy Inc. (we, our, us,
its, Cenovus, or the Company) dated February 10, 2016, should be read in conjunction with our December 31, 2015 audited Consolidated Financial Statements and accompanying notes (Consolidated
Financial Statements). All of the information and statements contained in this MD&A are made as of February 10, 2016, unless otherwise indicated. This MD&A contains forward-looking information about our current expectations, estimates,
projections and assumptions. See the Advisory for information on the risk factors that could cause actual results to differ materially and the assumptions underlying our forward-looking information. Cenovus Management prepared the MD&A. The
Audit Committee of the Cenovus Board of Directors (the Board) reviewed and recommended the MD&A for approval by the Board, which occurred on February 10, 2016. Additional information about Cenovus, including our quarterly and annual
reports, the Annual Information Form (AIF) and Form 40-F, is available on SEDAR at sedar.com, EDGAR at sec.gov and on our website at cenovus.com. Information on or connected to our website, even if referred to in this MD&A, does not
constitute part of this MD&A.

Basis of Presentation

This MD&A and the Consolidated Financial Statements and comparative information have been prepared in Canadian dollars, except where another
currency has been indicated, and in accordance with International Financial Reporting Standards (IFRS or GAAP) as issued by the International Accounting Standards Board (IASB). Production volumes are presented on
a before royalties basis.

Non-GAAP Measures

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, Net Debt, Capitalization and Adjusted Earnings before Interest, Taxes,
Depreciation and Amortization (Adjusted EBITDA) and therefore are considered non-GAAP measures. These measures may not be comparable to similar measures presented by other issuers. These measures have been described and presented in
order to provide shareholders and potential investors with additional 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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|Cenovus Energy Inc. |  | 1 |  | 2015 Managements Discussion and Analysis



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##### Table of Contents

OVERVIEW OF CENOVUS



We are a Canadian integrated oil company
headquartered in Calgary, Alberta, with our shares listed on the Toronto and New York stock exchanges. On December 31, 2015, we had a market capitalization of approximately $15 billion. We are in the business of developing, producing and
marketing crude oil, natural gas liquids (NGLs) and natural gas in Canada with marketing activities and refining operations in the United States (U.S.). Our average crude oil and NGLs (collectively, crude oil)
production in 2015 was approximately 207,000 barrels per day and our average natural gas production was 441 MMcf per day. Our refineries processed an average of 419,000 gross barrels per day of crude oil feedstock into an average of
444,000 gross barrels per day of refined products.

Our Key Message for 2015

2015 was a challenging year for the oil and gas industry as the low commodity price environment prompted significant reductions in capital spending
programs and extensive efforts to reduce costs. The deterioration of crude oil prices resulted in a significant decline in our cash flow and earnings.

During these volatile times, Cenovus has remained focused on delivering value through preserving financial resilience, achieving sustainable cost
reductions and exercising capital discipline. Together, our common share issuance and the sale of our royalty interest and mineral fee title lands business raised cash proceeds of approximately $4.7 billion. These transactions significantly
strengthened our balance sheet and our net debt to capitalization ratio was 16 percent at December 31, 2015. We also reduced our capital, operating and general and administrative spending, capturing savings of approximately $540 million,
relative to our budget.

We expect commodity prices to remain low for the foreseeable future and continue to make adjustments to our capital spending
and cost structure. For more information, we direct our readers to review the news release for our revised 2016 guidance dated February 11, 2016. The news release is available on our website at cenovus.com, on SEDAR at sedar.com and on EDGAR at
sec.gov.

Our Strategy

Our strategy is to create value by developing our vast oil sands resources and by achieving stronger global prices for our products. It is based on our
disciplined execution, focused innovation and our financial strength. The manufacturing approach we use to produce crude oil is a key factor in how we execute our strategy. Applying standardized and repeatable designs and processes to the
construction and operation of our facilities provides us with opportunities to reduce costs, and improve productivity and efficiencies at every phase of our oil sands projects. We are focused on driving total shareholder returns.

Our integrated approach positions us to capture the full value chain from production to high-quality end products like transportation fuels. It relies on:

| |  | Our producing asset mix, including:
|- |  | -----------------------------------

| | ¡ |  | Oil sands for long-term growth;
| | - |  | -------------------------------

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

| | ¡ |  | Natural gas for the fuel we use at our oil sands and refining facilities, and for the cash flow it provides to help fund our capital spending programs.
| | - |  | -------------------------------------------------------------------------------------------------------------------------------------------------------

| |  | Our marketing, products and transportation activities, including:
|- |  | -----------------------------------------------------------------

| | ¡ |  | Refining oil into various products to reduce the impact of commodity price fluctuations;
| | - |  | ----------------------------------------------------------------------------------------

| | ¡ |  | Creating a variety of oil blends to help maximize our transportation and refining options; and
| | - |  | ----------------------------------------------------------------------------------------------

| | ¡ |  | Accessing new markets that will position us to achieve the best pricing for our oil.
| | - |  | ------------------------------------------------------------------------------------

We have adopted a more moderate and staged approach to future oil sands expansions. We will consider expanding existing projects and developing emerging
projects only when we believe we will maximize cost savings and capital efficiencies.

Oil Development

We are focusing on the development of our substantial crude oil resources, predominantly from Foster Creek and Christina Lake. Our
future opportunities are currently based on the development of the land positions that we hold in the oil sands in northern Alberta, including Narrows Lake, Telephone Lake and Grand Rapids, as well as our conventional oil opportunities.

We are positioned to increase our annual net crude oil production, including our conventional crude oil operations, by fully developing our production
projects and those that currently have regulatory approval.

Disciplined Manufacturing

We apply a manufacturing-like, phased approach to developing our oil sands assets. This approach incorporates learnings from previous phases into future
growth plans, positioning us to minimize costs. We continue to focus on executing our business plan in a safe, predictable and reliable way, leveraging the strong foundation we have built to date. We are committed to developing our resources safely
and responsibly.



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|Cenovus Energy Inc. |  | 2 |  | 2015 Managements Discussion and Analysis



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##### Table of Contents

Financial Strength

Maintaining a strong balance sheet is necessary to execute our strategy. We anticipate our total annual capital investment for 2016 to be between $1.2
billion and $1.3 billion. This is 27 percent lower than in 2015, reflecting moderate spending in response to the sustained low commodity price environment. At December 31, 2015, we had $4.1 billion of cash on hand, $4.0 billion of undrawn
capacity on our committed credit facility, and no debt maturing until the fourth quarter of 2019. To help ensure our continued financial flexibility, we will pursue further cost reductions, manage our asset portfolio and consider other corporate and
financial opportunities that may be available to us.

Dividend

In 2015, we paid a dividend of $0.8524 per share compared with $1.0648 per share in 2014 (2013  $0.968 per share). We reduced our dividend by 40
percent in the third quarter of 2015, from $0.2662 per share to $0.16 per share, as part of our strategy to maintain our long-term financial resilience. Our dividend was further reduced to $0.05 per share in the first quarter of 2016. The
declaration of dividends is at the sole discretion of our Board and is considered each quarter.

Focused Innovation

Technology development, research activities and understanding our impact on the environment play increasingly larger roles in all
aspects of our business. We continue to seek out new technologies and are actively developing technologies with a focus on increasing recoveries from our reservoirs, and improving cycle times, margins and environmental performance. We have a track
record of developing innovative solutions that unlock challenging crude oil resources, building on our history of excellent project execution. Environmental considerations are embedded into our business approach with the objective of reducing our
environmental impact.

Our Operations

Oil Sands

Our operations include the following steam-assisted gravity drainage (SAGD) oil sands projects in northern Alberta:



|                  |  |                              |     |  |  |  |                                 |  |        |  |  |                                   |  |  |         | 
|----------------- |  | ---------------------------- | --- |  |  |  | ------------------------------- |  | ------ |  |  | --------------------------------- |  |  | ------- | 
|                  |  | 2015                         |    
|                  |  | Ownership
Interest (percent) |     |  |  |  | Net
Production
Volumes (bbls/d) |  |        |  |  | Gross
Production
Volumes (bbls/d) | 
|                  |  |                              |     |  | 
|Existing Projects |  |                              |     |  |  |  |                                 |  |        |  |  |                                   |  |  |         | 
|Foster Creek      |  |                              | 50  |  |  |  |                                 |  | 65,345 |  |  |                                   |  |  | 130,690 | 
|Christina Lake    |  |                              | 50  |  |  |  |                                 |  | 74,975 |  |  |                                   |  |  | 149,950 | 
|Narrows Lake      |  |                              | 50  |  |  |  |                                 |  | -      |  |  |                                   |  |  | -       | 
|Emerging Projects |  |                              |     |  |  |  |                                 |  |        |  |  |                                   |  |  |         | 
|Telephone Lake    |  |                              | 100 |  |  |  |                                 |  | -      |  |  |                                   |  |  | -       | 
|Grand Rapids      |  |                              | 100 |  |  |  |                                 |  | -      |  |  |                                   |  |  | -       | 

Foster Creek, Christina Lake and Narrows Lake are operated by Cenovus and jointly owned with ConocoPhillips, an unrelated
U.S. public company. Foster Creek and Christina Lake are producing and Narrows Lake is in the initial stages of development. These projects are located in the Athabasca region of northeastern Alberta. Two of our 100 percent-owned emerging
projects are Telephone Lake and Grand Rapids, located within the Borealis and Greater Pelican Lake regions of northeastern Alberta, respectively.



|                                                      |  |           |       |   |  |  |             |  |    | 
|----------------------------------------------------- |  | --------- | ----- | - |  |  | ----------- |  | -- | 
|                                                      |  | 2015      |      
|($ millions)                                          |  | Crude Oil |       |   |  |  | Natural Gas | 
|                                                      |  |           |      
|Operating Cash Flow                                   |  |           | 1,046 |   |  |  |             |  | 10 | 
|Capital Investment                                    |  |           | 1,184 |   |  |  |             |  | 1  | 
|Operating Cash Flow Net of Related Capital Investment |  |           | (138  | ) |  |  |             |  | 9  | 

Conventional

Crude oil production from our Conventional business segment continues to generate dependable near-term cash flows. This production provides
diversification to our revenue stream and enables further development of our oil sands assets. Our natural gas production acts as an economic hedge for the natural gas required as a fuel source at both our oil sands and refining operations and
provides cash flow to help fund our growth opportunities.



|                                                      |  |               |     |  |  |  |             |  |     | 
|----------------------------------------------------- |  | ------------- | --- |  |  |  | ----------- |  | --- | 
|                                                      |  | 2015          |    
|($ millions)                                          |  | Crude Oil (1) |     |  |  |  | Natural Gas | 
|                                                      |  |               |    
|Operating Cash Flow                                   |  |               | 683 |  |  |  |             |  | 297 | 
|Capital Investment                                    |  |               | 231 |  |  |  |             |  | 13  | 
|Operating Cash Flow Net of Related Capital Investment |  |               | 452 |  |  |  |             |  | 284 | 

|(1) | Includes NGLs.
|--- | --------------



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|Cenovus Energy Inc. |  | 3 |  | 2015 Managements Discussion and Analysis



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##### Table of Contents

We have established crude oil and natural gas producing assets, including heavy oil assets at Pelican Lake,
a carbon dioxide (CO2) enhanced oil recovery project in Weyburn, Saskatchewan, and emerging tight oil assets in Alberta.

Refining and Marketing

Our operations include two refineries located in Illinois and Texas that are jointly owned with and operated by Phillips 66, an unrelated U.S. public
company.



|           |  |                              |    |  |  |  |                                    |  |     | 
|---------- |  | ---------------------------- | -- |  |  |  | ---------------------------------- |  | --- | 
|           |  | 2015                         |   
|           |  | Ownership
Interest (percent) |    |  |  |  | Gross
Nameplate
Capacity (Mbbls/d) | 
|           |  |                              |   
|Wood River |  |                              | 50 |  |  |  |                                    |  | 314 | 
|Borger     |  |                              | 50 |  |  |  |                                    |  | 146 | 

Our refining operations allow us to capture the value from crude oil production through to refined products, such as
diesel, gasoline and jet fuel, to partially mitigate volatility associated with regional North American crude oil price differential fluctuations. This segment also includes our crude-by-rail terminal operations, located in Bruderheim, Alberta, and
the marketing of third-party purchases and sales of product undertaken to provide operational flexibility for transportation commitments, product quality, delivery points and customer diversification.



|                                                      |  |      |     | 
|----------------------------------------------------- |  | ---- | --- | 
|($ millions)                                          |  | 2015 |    
|                                                      | 
|Operating Cash Flow                                   |  |      | 385 | 
|Capital Investment                                    |  |      | 248 | 
|Operating Cash Flow Net of Related Capital Investment |  |      | 137 | 

2015 HIGHLIGHTS



In 2015, Cenovus delivered on the commitments
we made to our shareholders. We met our production targets, achieved significant sustainable cost savings in all areas of our business and strengthened our balance sheet. However, our financial results continued to be significantly impacted by low
crude oil prices. Average crude oil benchmark prices declined approximately 50 percent from 2014. The expectation of sustained low commodity prices resulted in asset impairments of $338 million, further decreasing our earnings.

During 2015, Cenovus remained focused on delivering value through preserving financial resilience, achieving sustainable cost reductions and exercising
capital discipline. We captured savings of approximately $540 million, relative to our budget, by reducing our capital, operating, and general and administrative spending. Approximately 50 percent of these savings came from lower than budgeted
operating costs and 40 percent from reduced capital expenditures, including supply chain management initiatives.

In 2015, we also:

| |  | Issued 67.5 million common shares at $22.25 per share for net proceeds of $1.4 billion;
|- |  | ---------------------------------------------------------------------------------------

| |  | Completed the sale of our royalty interest and mineral fee title lands business for cash proceeds of approximately $3.3 billion;
|- |  | --------------------------------------------------------------------------------------------------------------------------------

| |  | Renegotiated our $3.0 billion committed credit facility, extending the maturity date to November 30, 2019 and added a new $1.0 billion tranche under the
same facility with a maturity date of November 30, 2017;
|- |  | -----------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------

| |  | Reduced capital investment by 44 percent or $1.3 billion, compared with 2014;
|- |  | -----------------------------------------------------------------------------

| |  | Realized gains of $656 million from crude oil and natural gas risk management activities;
|- |  | -----------------------------------------------------------------------------------------

| |  | Reduced our workforce by 24 percent to align with our more moderate approach to oil sands expansions;
|- |  | -----------------------------------------------------------------------------------------------------

| |  | Decreased our total crude oil operating costs by 20 percent or $228 million, compared with 2014;
|- |  | ------------------------------------------------------------------------------------------------

| |  | Increased proved bitumen reserves by 11 percent primarily due to approval of an area expansion at Christina Lake;
|- |  | -----------------------------------------------------------------------------------------------------------------

| |  | Closed the purchase of a crude-by-rail terminal for $75 million, plus adjustments, to expand our portfolio of transportation options;
|- |  | -------------------------------------------------------------------------------------------------------------------------------------

| |  | Received regulatory approval for Christina Lake phase H, a 50,000 gross barrels per day phase; and
|- |  | --------------------------------------------------------------------------------------------------

| |  | Reduced our annual dividend from $1.0648 per share to $0.8524 per share.
|- |  | ------------------------------------------------------------------------



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|Cenovus Energy Inc. |  | 4 |  | 2015 Managements Discussion and Analysis



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##### Table of Contents

OPERATING RESULTS



Our upstream assets continued to perform well
in 2015. Total crude oil production averaged 206,947 barrels per day during the year.

Crude Oil Production Volumes



|                           |  |      |         |  |  |  |                       |  |       |  |  |      |  |  |         |  |                   |  |  |  |      |      |  |  |  |  |         | 
|-------------------------- |  | ---- | ------- |  |  |  | --------------------- |  | ----- |  |  | ---- |  |  | ------- |  | ----------------- |  |  |  | ---- | ---- |  |  |  |  | ------- | 
|(barrels per day)          |  | 2015 |         |  |  |  | Percent        Change |  |       |  |  | 2014 |  |  |         |  | Percent    Change |  |  |  |      | 2013 | 
|                           |  |      |         |  |  |  |                       |  |      
|Oil Sands                  |  |      |         |  |  |  |                       |  |       |  |  |      |  |  |         |  |                   |  |  |  |      |      |  |  |  |  |         | 
|Foster Creek               |  |      | 65,345  |  |  |  |                       |  | 10%   |  |  |      |  |  | 59,172  |  |                   |  |  |  | 11%  |      |  |  |  |  | 53,190  | 
|Christina Lake             |  |      | 74,975  |  |  |  |                       |  | 9%    |  |  |      |  |  | 69,023  |  |                   |  |  |  | 40%  |      |  |  |  |  | 49,310  | 
|                           |  |      | 140,320 |  |  |  |                       |  | 9%    |  |  |      |  |  | 128,195 |  |                   |  |  |  | 25%  |      |  |  |  |  | 102,500 | 
|Conventional               |  |      |         |  |  |  |                       |  |       |  |  |      |  |  |         |  |                   |  |  |  |      |      |  |  |  |  |         | 
|Heavy Oil                  |  |      | 34,888  |  |  |  |                       |  | (12)% |  |  |      |  |  | 39,546  |  |                   |  |  |  | (2)% |      |  |  |  |  | 40,245  | 
|Light and Medium Oil       |  |      | 30,486  |  |  |  |                       |  | (12)% |  |  |      |  |  | 34,531  |  |                   |  |  |  | (3)% |      |  |  |  |  | 35,467  | 
|NGLs (1)                   |  |      | 1,253   |  |  |  |                       |  | 3%    |  |  |      |  |  | 1,221   |  |                   |  |  |  | 15%  |      |  |  |  |  | 1,063   | 
|                           |  |      | 66,627  |  |  |  |                       |  | (12)% |  |  |      |  |  | 75,298  |  |                   |  |  |  | (2)% |      |  |  |  |  | 76,775  | 
|Total Crude Oil Production |  |      | 206,947 |  |  |  |                       |  | 2%    |  |  |      |  |  | 203,493 |  |                   |  |  |  | 14%  |      |  |  |  |  | 179,275 | 



|(1) | NGLs include condensate volumes.
|--- | --------------------------------

Foster Creek production increased in 2015 due to
the ramp-up of production from phase F and production from additional wells, partially offset by the impact of a forest fire in the second quarter, which decreased full-year production by approximately 2,600 barrels per day. Fourth quarter
production was lower compared with 2014. Improved wellbore conformance accelerated production from more mature wells, resulting in faster declines from these wells. To preserve capital, we chose in 2015 to defer some planned well pads, which
combined with the faster declines, contributed to lower fourth quarter volumes. In addition, while well downtime at Foster Creek was within expected ranges for 2015, a higher than average number of wells were down for servicing in the second half of
the year, which further impacted production.

Production from Christina Lake increased compared with 2014 due to production from additional wells and
improved performance of our facilities.

In 2015, our Conventional crude oil production decreased from 2014. An increase in production from successful
horizontal well performance in southern Alberta was more than offset by expected natural declines, the divestiture of non-core assets in 2014, and the sale of our royalty interest and mineral fee title lands business. Production also declined due to
reduced capital investment. Divested assets contributed 2,555 barrels per day (2014  6,532 barrels per day) to annual production.

Natural Gas Production Volumes



|               |  |      |     |  |  |  |      |  |     |  |  |      |  |  |     | 
|-------------- |  | ---- | --- |  |  |  | ---- |  | --- |  |  | ---- |  |  | --- | 
|(MMcf per day) |  | 2015 |     |  |  |  | 2014 |  |     |  |  | 2013 | 
|Conventional   |  |      | 422 |  |  |  |      |  | 466 |  |  |      |  |  | 508 | 
|Oil Sands      |  |      | 19  |  |  |  |      |  | 22  |  |  |      |  |  | 21  | 
|               |  |      | 441 |  |  |  |      |  | 488 |  |  |      |  |  | 529 | 

Our natural gas production declined 10 percent in 2015. Production decreased primarily due to expected natural declines
and the sale of our royalty interest and mineral fee title lands business, which produced 10 MMcf per day during the year (2014  20 MMcf per day).

Oil and Gas Reserves

Our proved bitumen reserves increased 11 percent to approximately 2.2 billion barrels and our proved plus probable bitumen reserves remained at
approximately at 3.3 billion barrels. Additional information about our reserves and resources is included in the Oil and Gas Reserves and Resources section of this MD&A.

Operating Netbacks



|                                           |  |                      |       |  |  |  |      |  |                    |  |  |      |  |  |       |  |  |  |      |  |  |  |      |      |  |  |  |  |      |  |  |  |  |  |      | 
|------------------------------------------ |  | -------------------- | ----- |  |  |  | ---- |  | ------------------ |  |  | ---- |  |  | ----- |  |  |  | ---- |  |  |  | ---- | ---- |  |  |  |  | ---- |  |  |  |  |  | ---- | 
|                                           |  | Crude Oil (1)($/bbl) |       |  |  |  |      |  | Natural Gas($/Mcf) | 
|                                           |  | 2015                 |       |  |  |  | 2014 |  |                    |  |  | 2013 |  |  |       |  |  |  | 2015 |  |  |  |      | 2014 |  |  |  |  | 2013 | 
|Price (2)                                  |  |                      | 35.38 |  |  |  |      |  | 71.35              |  |  |      |  |  | 67.01 |  |  |  |      |  |  |  | 2.92 |      |  |  |  |  | 4.37 |  |  |  |  |  | 3.20 | 
|Royalties                                  |  |                      | 1.75  |  |  |  |      |  | 6.18               |  |  |      |  |  | 5.01  |  |  |  |      |  |  |  | 0.07 |      |  |  |  |  | 0.08 |  |  |  |  |  | 0.04 | 
|Transportation and Blending (2) (3)        |  |                      | 5.48  |  |  |  |      |  | 2.98               |  |  |      |  |  | 3.12  |  |  |  |      |  |  |  | 0.11 |      |  |  |  |  | 0.12 |  |  |  |  |  | 0.11 | 
|Operating Expenses (4)                     |  |                      | 11.98 |  |  |  |      |  | 15.40              |  |  |      |  |  | 15.49 |  |  |  |      |  |  |  | 1.20 |      |  |  |  |  | 1.22 |  |  |  |  |  | 1.16 | 
|Production and Mineral Taxes               |  |                      | 0.22  |  |  |  |      |  | 0.50               |  |  |      |  |  | 0.48  |  |  |  |      |  |  |  | 0.01 |      |  |  |  |  | 0.05 |  |  |  |  |  | 0.02 | 
|Netback Excluding Realized Risk Management |  |                      | 15.95 |  |  |  |      |  | 46.29              |  |  |      |  |  | 42.91 |  |  |  |      |  |  |  | 1.53 |      |  |  |  |  | 2.90 |  |  |  |  |  | 1.87 | 
|Realized Risk Management Gain (Loss)       |  |                      | 7.51  |  |  |  |      |  | 0.50               |  |  |      |  |  | 1.09  |  |  |  |      |  |  |  | 0.37 |      |  |  |  |  | 0.04 |  |  |  |  |  | 0.32 | 
|Netback Including Realized Risk Management |  |                      | 23.46 |  |  |  |      |  | 46.79              |  |  |      |  |  | 44.00 |  |  |  |      |  |  |  | 1.90 |      |  |  |  |  | 2.94 |  |  |  |  |  | 2.19 | 



|(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 $21.09 per barrel (2014  $30.49 per barrel; 2013  $28.33 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. See the Oil Sands
and Conventional Reportable Segments sections of this MD&A for more details.
|--- | ---------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------

|(4) | For all periods presented, we reclassified employee long-term incentive costs from operating expenses to general and administrative costs.
|--- | ------------------------------------------------------------------------------------------------------------------------------------------



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|Cenovus Energy Inc. |  | 5 |  | 2015 Managements Discussion and Analysis



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##### Table of Contents

Our average crude oil netback in 2015, excluding realized risk management gains and losses, decreased
significantly compared with 2014. Lower sales prices, consistent with the decline in benchmark prices, were partially offset by weakening of the Canadian dollar relative to the U.S. dollar and a decline in royalties and operating costs. The
weakening of the Canadian dollar compared with 2014 had a positive impact on our crude oil price of approximately $4.81 per barrel.

In 2015, our
average natural gas netback, excluding realized risk management gains and losses, decreased primarily due to lower sales prices, consistent with the decline in the AECO benchmark price.

Refining

In 2015,
we successfully completed planned turnarounds at both of our Borger and Wood River refineries and received permit approval for the Wood River debottlenecking project.



|                                |  |      |     |  |  |  |                           |  |      |      |  |  |                               |  |  |      |       |  |  |  |     | 
|------------------------------- |  | ---- | --- |  |  |  | ------------------------- |  | ---- | ---- |  |  | ----------------------------- |  |  | ---- | ----- |  |  |  | --- | 
|                                |  | 2015 |     |  |  |  | Percent            Change |  |      | 2014 |  |  | Percent                Change |  |  | 2013 |      
|Crude Oil Runs (1) (Mbbls/d)    |  |      | 419 |  |  |  |                           |  | (1)% |      |  |  | 423                           |  |  |      | (4)%  |  |  |  | 442 | 
|Heavy Crude Oil (1)             |  |      | 200 |  |  |  |                           |  | 1%   |      |  |  | 199                           |  |  |      | (10)% |  |  |  | 222 | 
|Refined Product (1) (Mbbls/d)   |  |      | 444 |  |  |  |                           |  | -    |      |  |  | 445                           |  |  |      | (4)%  |  |  |  | 463 | 
|Crude Utilization
(1) (percent) |  |      | 91  |  |  |  |                           |  | (1)% |      |  |  | 92                            |  |  |      | (5)%  |  |  |  | 97  | 



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

Further information on the changes in our production volumes, items included in our operating netbacks and refining results can be found in the
Reportable Segments section of this MD&A. Further information on our risk management activities can be found in the Risk Management section of this MD&A and in the notes to the Consolidated Financial Statements.

COMMODITY PRICES UNDERLYING OUR FINANCIAL RESULTS



Key performance drivers for our financial
results include commodity prices, price differentials, refining crack spreads as well as the U.S./Canadian dollar exchange rate. The following table shows selected market benchmark prices and the U.S./Canadian dollar average exchange rates to assist
in understanding our financial results.

Selected Benchmark Prices and Exchange Rates (1)



|                                                       |  |         |         |  |  |  |               |  |       |         |  |  |         |  |  |      |         |  |      |  |         |  |  |  |         | 
|------------------------------------------------------ |  | ------- | ------- |  |  |  | ------------- |  | ----- | ------- |  |  | ------- |  |  | ---- | ------- |  | ---- |  | ------- |  |  |  | ------- | 
|                                                       |  | Q4
2015 |         |  |  |  | PercentChange |  |       | Q4
2014 |  |  | 2015    |  |  | 2014 |         |  | 2013 | 
|Crude Oil
Prices (US$/bbl)                             |  |         |         |  |  |  |               |  |       |         |  |  |         |  |  |      |         |  |      |  |         |  |  |  |         | 
|Brent                                                  |  |         |         |  |  |  |               |  |       |         |  |  |         |  |  |      |         |  |      |  |         |  |  |  |         | 
|Average                                                |  |         | 44.71   |  |  |  |               |  | (42)% |         |  |  | 76.98   |  |  |      | 53.64   |  |      |  | 99.51   |  |  |  | 108.76  | 
|End of Period                                          |  |         | 37.28   |  |  |  |               |  | (35)% |         |  |  | 57.33   |  |  |      | 37.28   |  |      |  | 57.33   |  |  |  | 110.80  | 
|WTI                                                    |  |         |         |  |  |  |               |  |       |         |  |  |         |  |  |      |         |  |      |  |         |  |  |  |         | 
|Average                                                |  |         | 42.18   |  |  |  |               |  | (42)% |         |  |  | 73.15   |  |  |      | 48.80   |  |      |  | 93.00   |  |  |  | 97.97   | 
|End of Period                                          |  |         | 37.04   |  |  |  |               |  | (30)% |         |  |  | 53.27   |  |  |      | 37.04   |  |      |  | 53.27   |  |  |  | 98.42   | 
|Average Differential Brent-WTI                         |  |         | 2.53    |  |  |  |               |  | (34)% |         |  |  | 3.83    |  |  |      | 4.84    |  |      |  | 6.51    |  |  |  | 10.79   | 
|WCS (2)                                                |  |         |         |  |  |  |               |  |       |         |  |  |         |  |  |      |         |  |      |  |         |  |  |  |         | 
|Average                                                |  |         | 27.69   |  |  |  |               |  | (53)% |         |  |  | 58.91   |  |  |      | 35.28   |  |      |  | 73.60   |  |  |  | 72.77   | 
|End of Period                                          |  |         | 24.98   |  |  |  |               |  | (34)% |         |  |  | 37.59   |  |  |      | 24.98   |  |      |  | 37.59   |  |  |  | 74.80   | 
|Average Differential WTI-WCS                           |  |         | 14.49   |  |  |  |               |  | 2%    |         |  |  | 14.24   |  |  |      | 13.52   |  |      |  | 19.40   |  |  |  | 25.20   | 
|Condensate (C5 @ Edmonton) (3)                         |  |         |         |  |  |  |               |  |       |         |  |  |         |  |  |      |         |  |      |  |         |  |  |  |         | 
|Average                                                |  |         | 41.67   |  |  |  |               |  | (41)% |         |  |  | 70.57   |  |  |      | 47.36   |  |      |  | 92.95   |  |  |  | 101.69  | 
|Average Differential WTI-Condensate (Premium)/Discount |  |         | 0.51    |  |  |  |               |  | (80)% |         |  |  | 2.58    |  |  |      | 1.44    |  |      |  | 0.05    |  |  |  | (3.72)  | 
|Average Differential WCS-Condensate (Premium)/Discount |  |         | (13.98) |  |  |  |               |  | 20%   |         |  |  | (11.66) |  |  |      | (12.08) |  |      |  | (19.35) |  |  |  | (28.92) | 
|Average Refined Product Prices (US$/bbl)               |  |         |         |  |  |  |               |  |       |         |  |  |         |  |  |      |         |  |      |  |         |  |  |  |         | 
|Chicago Regular Unleaded Gasoline (RUL)              |  |         | 55.24   |  |  |  |               |  | (32)% |         |  |  | 81.26   |  |  |      | 67.68   |  |      |  | 107.40  |  |  |  | 116.35  | 
|Chicago Ultra-low Sulphur Diesel (ULSD)              |  |         | 59.23   |  |  |  |               |  | (42)% |         |  |  | 101.48  |  |  |      | 68.12   |  |      |  | 117.55  |  |  |  | 126.31  | 
|Refining Margin: Average 3-2-1 Crack Spreads (US$/bbl) |  |         |         |  |  |  |               |  |       |         |  |  |         |  |  |      |         |  |      |  |         |  |  |  |         | 
|Chicago                                                |  |         | 14.47   |  |  |  |               |  | (1)%  |         |  |  | 14.60   |  |  |      | 19.11   |  |      |  | 17.61   |  |  |  | 21.77   | 
|Group 3                                                |  |         | 13.82   |  |  |  |               |  | 4%    |         |  |  | 13.28   |  |  |      | 18.16   |  |      |  | 16.27   |  |  |  | 20.80   | 
|Average Natural Gas Prices                             |  |         |         |  |  |  |               |  |       |         |  |  |         |  |  |      |         |  |      |  |         |  |  |  |         | 
|AECO (C$/Mcf)                                          |  |         | 2.65    |  |  |  |               |  | (34)% |         |  |  | 4.01    |  |  |      | 2.77    |  |      |  | 4.42    |  |  |  | 3.17    | 
|NYMEX (US$/Mcf)                                        |  |         | 2.27    |  |  |  |               |  | (43)% |         |  |  | 4.00    |  |  |      | 2.66    |  |      |  | 4.42    |  |  |  | 3.65    | 
|Basis Differential NYMEX-AECO (US$/Mcf)                |  |         | 0.27    |  |  |  |               |  | (39)% |         |  |  | 0.44    |  |  |      | 0.49    |  |      |  | 0.40    |  |  |  | 0.58    | 
|Foreign Exchange Rates (US$ per C$1)                   |  |         |         |  |  |  |               |  |       |         |  |  |         |  |  |      |         |  |      |  |         |  |  |  |         | 
|Average                                                |  |         | 0.749   |  |  |  |               |  | (15)% |         |  |  | 0.881   |  |  |      | 0.782   |  |      |  | 0.905   |  |  |  | 0.971   | 



|(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 average Canadian dollar WCS benchmark price for 2015 was $45.12 per barrel (2014  $81.33 per barrel; 2013  $74.94 per barrel); fourth
quarter average WCS benchmark price was $36.97 per barrel (2014  $66.87 per barrel).
|--- | ---------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------

|(3) | The average Canadian dollar condensate benchmark price for 2015 was $60.56 per barrel (2014  $102.71 per barrel; 2013  $104.73 per barrel);
fourth quarter average condensate benchmark price was $55.63 per barrel (2014  $80.10 per barrel).
|--- | -------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------



|                    |  |   |  |                                          
|------------------- |  | - |  | -----------------------------------------
|Cenovus Energy Inc. |  | 6 |  | 2015 Managements Discussion and Analysis



---

##### Table of Contents

Crude Oil Benchmarks

The average Brent, WTI and WCS benchmark prices continued to be impacted by a global imbalance of supply and demand which began in the second half of
2014. This imbalance, created by weak global demand for oil and strong growth in North American crude oil supply, was further amplified by the sustained decision of the Organization of Petroleum Exporting Countries (OPEC) to maintain its
level of crude oil output and discontinue its role as the swing supplier of crude oil. Despite significantly lower crude oil prices and increased global demand in 2015, the imbalance has only slightly improved. Economic uncertainty in China,
resilient U.S. production, continued strong production from Saudi Arabia and Iraq, as well as concerns regarding the return of Iranian production have contributed to sustained low crude oil prices.

The Brent benchmark is representative of global crude oil prices and, we believe, a better indicator than WTI of inland refined product prices.

WTI is an important benchmark for Canadian crude oil since it reflects inland North American crude oil prices and its Canadian dollar equivalent is the
basis for determining royalties for a number of our crude oil properties. The average Brent-WTI differential narrowed compared with 2014. WTI benchmark prices strengthened relative to Brent as a result of high global crude oil inventory levels and
continued strong demand in the U.S., leaving transportation costs as the primary driver of the Brent-WTI differential.

WCS is blended heavy oil which
consists of both conventional heavy oil and unconventional diluted bitumen. The average WTI-WCS differential narrowed in 2015. The narrower differential resulted primarily from increased demand for WCS due to new pipeline infrastructure to the U.S.
Gulf Coast, growing rail capacity and the slow return of heavy crude oil supply forced offline due to forest fires in northeastern Alberta during the second quarter of 2015.

Blending condensate with bitumen and heavy oil enables our production to be transported through pipelines. Our blending ratios range from approximately 10
percent to 33 percent. The WCS-Condensate differential is an important benchmark as a narrower differential generally results in an increase in the recovery of condensate costs when selling a barrel of blended crude oil. When the supply of
condensate in Alberta does not meet the demand, Edmonton condensate prices may be driven by U.S. Gulf Coast condensate prices plus the value attributed to transporting the condensate to Edmonton.

The average WCS-Condensate differential narrowed in 2015 due to condensate supply growth as well as improved diluent transportation infrastructure for
condensate imports into Alberta and heavy oil exports to market.



LOGO

Refining Benchmarks

The Chicago Regular Unleaded Gasoline (RUL) and Chicago Ultra-low Sulphur Diesel (ULSD) benchmark prices are representative of
inland refined product prices and are used to derive the Chicago 3-2-1 crack spread. The 3-2-1 crack spread is an indicator of the refining margin generated by
converting three barrels of crude oil into two barrels of regular unleaded gasoline and one barrel of ultra-low sulphur diesel using current month WTI based crude oil feedstock prices and valued on a last in, first out accounting basis.

Average Chicago 3-2-1 crack spreads increased in 2015 compared with 2014 driven by stronger product demand. Average Group 3 crack spreads increased as a
major unplanned refinery outage in August 2015 caused product inventory drawdowns during the driving season.

Our realized crack spreads are affected
by many other factors such as the variety of feedstock crude oil, refinery configuration and product output, the time lag between the purchase and delivery of crude oil feedstock, and the cost of feedstock which is valued on a first in, first out
(FIFO) accounting basis.



|                    |  |   |  |                                          
|------------------- |  | - |  | -----------------------------------------
|Cenovus Energy Inc. |  | 7 |  | 2015 Managements Discussion and Analysis



---

##### Table of Contents

LOGO

Natural Gas Benchmarks

Average natural gas prices decreased in 2015 primarily due to increased supply from the U.S. and Canada.

Foreign Exchange Benchmarks

Revenues are subject to foreign exchange exposure as the sales prices of our crude oil, natural gas and refined products are determined by reference to
U.S. benchmark prices. A decrease in the value of the Canadian dollar compared with the U.S. dollar has a positive impact on our reported results. Likewise, as the Canadian dollar strengthens, our reported results are lower. In addition to our
revenues being denominated in U.S. dollars, we have chosen to borrow U.S. dollar long-term debt. In periods of a weakening Canadian dollar, our U.S. dollar debt gives rise to unrealized foreign exchange losses when translated to Canadian dollars.

In 2015 compared with 2014, the Canadian dollar weakened relative to the U.S. dollar due to lower commodity prices, strengthening of the U.S.
economy, and Canadian political and economic uncertainty. The weakening of the Canadian dollar compared with 2014 had a positive impact of approximately $1,772 million on our revenues and also resulted in $1,064 million of unrealized foreign
exchange losses on the translation of our U.S. dollar debt.

FINANCIAL RESULTS





Selected Consolidated Financial Results

Sustained low commodity prices in 2015 significantly impacted our financial results. The following key performance measures are discussed in more detail
within this MD&A.



|                                          |  |      |        |   |  |  |                |  |        |      |  |  |                |  |  |      |       |  |  |  |        | 
|----------------------------------------- |  | ---- | ------ | - |  |  | -------------- |  | ------ | ---- |  |  | -------------- |  |  | ---- | ----- |  |  |  | ------ | 
|($ millions, except per share amounts)    |  | 2015 |        |   |  |  | Percent
Change |  |        | 2014 |  |  | Percent
Change |  |  | 2013 |      
|                                          |  |      |        |   |  | 
|Revenues                                  |  |      | 13,064 |   |  |  |                |  | (33)%  |      |  |  | 19,642         |  |  |      | 5%    |  |  |  | 18,657 | 
|Operating Cash Flow (1) (2)               |  |      | 2,439  |   |  |  |                |  | (42)%  |      |  |  | 4,179          |  |  |      | (7)%  |  |  |  | 4,484  | 
|Cash Flow (1)                             |  |      | 1,691  |   |  |  |                |  | (51)%  |      |  |  | 3,479          |  |  |      | (4)%  |  |  |  | 3,609  | 
|Per Share  Diluted                       |  |      | 2.07   |   |  |  |                |  | (55)%  |      |  |  | 4.59           |  |  |      | (4)%  |  |  |  | 4.76   | 
|Operating Earnings (Loss) (1)             |  |      | (403   | ) |  |  |                |  | (164)% |      |  |  | 633            |  |  |      | (46)% |  |  |  | 1,171  | 
|Per Share  Diluted                       |  |      | (0.49  | ) |  |  |                |  | (158)% |      |  |  | 0.84           |  |  |      | (46)% |  |  |  | 1.55   | 
|Net Earnings (Loss)                       |  |      | 618    |   |  |  |                |  | (17)%  |      |  |  | 744            |  |  |      | 12%   |  |  |  | 662    | 
|Per Share  Basic                         |  |      | 0.75   |   |  |  |                |  | (23)%  |      |  |  | 0.98           |  |  |      | 11%   |  |  |  | 0.88   | 
|Per Share  Diluted                       |  |      | 0.75   |   |  |  |                |  | (23)%  |      |  |  | 0.98           |  |  |      | 13%   |  |  |  | 0.87   | 
|                                          |  |      |        |   |  | 
|Total Assets                              |  |      | 25,791 |   |  |  |                |  | 4%     |      |  |  | 24,695         |  |  |      | (2)%  |  |  |  | 25,224 | 
|Total Long-Term Financial Liabilities (3) |  |      | 6,552  |   |  |  |                |  | 19%    |      |  |  | 5,484          |  |  |      | (10)% |  |  |  | 6,113  | 
|                                          |  |      |        |   |  | 
|Capital Investment (4)                    |  |      | 1,714  |   |  |  |                |  | (44)%  |      |  |  | 3,051          |  |  |      | (6)%  |  |  |  | 3,262  | 
|Dividends                                 |  |      |        |   |  |  |                |  |        |      |  |  |                |  |  |      |       |  |  |  |        | 
|Cash Dividends                            |  |      | 528    |   |  |  |                |  | (34)%  |      |  |  | 805            |  |  |      | 10%   |  |  |  | 732    | 
|In Shares from Treasury                   |  |      | 182    |   |  |  |                |  | -      |      |  |  | -              |  |  |      | -     |  |  |  | -      | 
|Per Share                                 |  |      | 0.8524 |   |  |  |                |  | (20)%  |      |  |  | 1.0648         |  |  |      | 10%   |  |  |  | 0.968  | 



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

|(2) | For all periods presented, we reclassified employee long-term incentive costs from operating expenses to general and administrative costs. There were no changes to Cash Flow, Operating Earnings or Net Earnings.
|--- | ------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------

|(3) | Includes Long-Term Debt, Partnership Contribution Payable, Risk Management Liability and other financial liabilities included within Other Liabilities on the Consolidated Balance Sheets.
|--- | ------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------

|(4) | Includes expenditures on Property, Plant and Equipment (PP&E) and Exploration and Evaluation (E&E) assets.
|--- | --------------------------------------------------------------------------------------------------------------



|                    |  |   |  |                                          
|------------------- |  | - |  | -----------------------------------------
|Cenovus Energy Inc. |  | 8 |  | 2015 Managements Discussion and Analysis



---

##### Table of Contents

Revenues

|                            |  |               |         |  |  |  |               |  |        | 
|--------------------------- |  | ------------- | ------- |  |  |  | ------------- |  | ------ | 
|($ millions)                |  | 2015
vs. 2014 |         |  |  |  | 2014
vs. 2013 | 
|Revenues,
Comparative Year  |  |               | 19,642  |  |  |  |               |  | 18,657 | 
|Increase (Decrease) due to: |  |               |         |  |  |  |               |  |        | 
|Oil Sands                   |  |               | (1,799) |  |  |  |               |  | 1,020  | 
|Conventional                |  |               | (1,401) |  |  |  |               |  | 220    | 
|Refining and Marketing      |  |               | (3,853) |  |  |  |               |  | (48)   | 
|Corporate and Eliminations  |  |               | 475     |  |  |  |               |  | (207)  | 
|Revenues, End of Year       |  |               | 13,064  |  |  |  |               |  | 19,642 | 

Combined Oil Sands and Conventional revenues declined 41 percent in 2015 due to lower crude oil blend and natural gas
sales prices, partially offset by higher crude oil sales volumes, weakening of the Canadian dollar relative to the U.S. dollar and lower royalties. The sale of our royalty interest and mineral fee title lands business also reduced revenues.

Revenues from our Refining and Marketing segment decreased 30 percent from 2014. Refining revenues declined due to the decrease in refined product
pricing, consistent with lower Chicago RUL and Chicago ULSD benchmark prices. The decrease in our reported revenues was partially offset by the weakening of the Canadian dollar relative to the U.S. dollar. Revenues from third-party crude oil and natural gas sales undertaken by the marketing group in 2015 decreased 36 percent from 2014, primarily due to a decline in sales prices, partially offset by an increase in purchased crude
oil volumes.

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

Overall, revenues increased in 2014 compared with 2013 primarily due to higher blended crude oil sales volumes and higher
average sales prices for blended crude oil and natural gas, partially offset by an increase in royalties.

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

Operating Cash Flow

Operating Cash Flow is a non-GAAP measure used to provide a consistent measure of the cash generating performance of our assets for comparability of our
underlying financial performance between periods. Operating Cash Flow is defined as revenues less purchased product, transportation and blending, operating expenses and production and mineral taxes plus realized gains less realized losses on risk
management activities. Items within the Corporate and Eliminations segment are excluded from the calculation of Operating Cash Flow.



|                                                   |  |      |        |  |  |  |      |  |        |  |  |      |  |  |        | 
|-------------------------------------------------- |  | ---- | ------ |  |  |  | ---- |  | ------ |  |  | ---- |  |  | ------ | 
|($ millions)                                       |  | 2015 |        |  |  |  | 2014 |  |        |  |  | 2013 | 
|Revenues                                           |  |      | 13,401 |  |  |  |      |  | 20,454 |  |  |      |  |  | 19,262 | 
|(Add) Deduct:                                      |  |      |        |  |  |  |      |  |        |  |  |      |  |  |        | 
|Purchased Product                                  |  |      | 7,709  |  |  |  |      |  | 11,767 |  |  |      |  |  | 11,004 | 
|Transportation and Blending                        |  |      | 2,045  |  |  |  |      |  | 2,477  |  |  |      |  |  | 2,074  | 
|Operating Expenses (1)                             |  |      | 1,846  |  |  |  |      |  | 2,051  |  |  |      |  |  | 1,787  | 
|Production and Mineral Taxes                       |  |      | 18     |  |  |  |      |  | 46     |  |  |      |  |  | 35     | 
|Realized (Gain) Loss on Risk Management Activities |  |      | (656)  |  |  |  |      |  | (66)   |  |  |      |  |  | (122)  | 
|Operating Cash Flow                                |  |      | 2,439  |  |  |  |      |  | 4,179  |  |  |      |  |  | 4,484  | 

|(1) | For all periods presented, we reclassified employee long-term incentive costs from operating expenses to general and administrative costs.
|--- | ------------------------------------------------------------------------------------------------------------------------------------------



LOGO

Operating Cash Flow declined 42 percent in 2015 primarily due to:

| |  | A 50 percent decrease in our average crude oil sales price and a 33 percent decrease in our average natural gas sales price, consistent with lower associated
benchmark prices; and
|- |  | -----------------------------------------------------------------------------------------------------------------------------------------------------------------------------------

| |  | A 10 percent decline in our natural gas sales volumes.
|- |  | ------------------------------------------------------



|                    |  |   |  |                                          
|------------------- |  | - |  | -----------------------------------------
|Cenovus Energy Inc. |  | 9 |  | 2015 Managements Discussion and Analysis



---

##### Table of Contents

These declines to Operating Cash Flow were partially offset by:

| |  | Realized risk management gains of $613 million, excluding Refining and Marketing, compared with $39 million in 2014;
|- |  | --------------------------------------------------------------------------------------------------------------------

| |  | Lower royalties primarily due to a decrease in crude oil sales prices;
|- |  | ----------------------------------------------------------------------

| |  | A decrease of $3.42 per barrel in crude oil operating expenses primarily due to a decline in workover activities, a reduction in fuel costs due to lower
natural gas prices, and lower repairs and maintenance costs;
|- |  | ---------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------

| |  | Higher Operating Cash Flow from Refining and Marketing as a result of improved margins on the sale of secondary products, such as coke and asphalt, and
weakening of the Canadian dollar relative to the U.S. dollar, partially offset by higher heavy crude oil feedstock costs relative to the WTI benchmark price and higher operating costs; and
|- |  | ----------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------

| |  | An inventory write-down of $66 million compared with an inventory write-down of $131 million in 2014.
|- |  | -----------------------------------------------------------------------------------------------------

Operating Cash Flow Variance





LOGO

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

Cash Flow

Cash Flow is a non-GAAP measure commonly used in the oil and gas industry to assist in measuring a companys ability to finance its capital programs
and meet its financial obligations. Cash Flow is defined as cash from operating activities excluding net change in other assets and liabilities and net change in non-cash working capital.



|                                           |  |      |       |  |  |  |      |  |       |  |  |      |  |  |       | 
|------------------------------------------ |  | ---- | ----- |  |  |  | ---- |  | ----- |  |  | ---- |  |  | ----- | 
|($ millions)                               |  | 2015 |       |  |  |  | 2014 |  |       |  |  | 2013 | 
|Cash From
Operating Activities             |  |      | 1,474 |  |  |  |      |  | 3,526 |  |  |      |  |  | 3,539 | 
|(Add) Deduct:                              |  |      |       |  |  |  |      |  |       |  |  |      |  |  |       | 
|Net Change in Other Assets and Liabilities |  |      | (107) |  |  |  |      |  | (135) |  |  |      |  |  | (120) | 
|Net Change in Non-Cash Working Capital     |  |      | (110) |  |  |  |      |  | 182   |  |  |      |  |  | 50    | 
|Cash Flow                                  |  |      | 1,691 |  |  |  |      |  | 3,479 |  |  |      |  |  | 3,609 | 

In 2015, Cash Flow decreased due to a combination of lower Operating Cash Flow, as discussed above, and higher current
income tax. Current income tax rose due to the timing of recognition of partnership income for tax purposes.

Operating
Earnings (Loss)

Operating Earnings (Loss) is a non-GAAP measure used to provide a consistent measure of the comparability of our
underlying financial performance between periods by removing non-operating items. Operating Earnings (Loss) is defined as Earnings (Loss) Before Income Tax excluding gain (loss) on discontinuance, gain on bargain purchase, unrealized risk management
gains (losses) on derivative instruments, unrealized foreign exchange gains (losses) on translation of U.S. dollar denominated notes issued from Canada, foreign exchange gains (losses) on settlement of intercompany transactions, gains (losses) on
divestiture of assets, less income taxes on Operating Earnings (Loss) before tax, excluding the effect of changes in statutory income tax rates and the recognition of an increase in U.S. tax basis.



|                    |  |    |  |                                          
|------------------- |  | -- |  | -----------------------------------------
|Cenovus Energy Inc. |  | 10 |  | 2015 Managements Discussion and Analysis



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##### Table of Contents

|                                                                                           |  |      |        |   |  |  |      |  |       |   |  |      |  |  |       | 
|------------------------------------------------------------------------------------------ |  | ---- | ------ | - |  |  | ---- |  | ----- | - |  | ---- |  |  | ----- | 
|($ millions)                                                                               |  | 2015 |        |   |  |  | 2014 |  |       |   |  | 2013 | 
|                                                                                           |  |      |        |   | 
|Earnings, Before Income Tax                                                                |  |      | 537    |   |  |  |      |  | 1,195 |   |  |      |  |  | 1,094 | 
|Add (Deduct):                                                                              |  |      |        |   |  |  |      |  |       |   |  |      |  |  |       | 
|Unrealized Risk Management (Gain) Loss (1)                                                 |  |      | 195    |   |  |  |      |  | (596  | ) |  |      |  |  | 415   | 
|Non-operating Unrealized Foreign Exchange (Gain) Loss (2)                                  |  |      | 1,064  |   |  |  |      |  | 458   |   |  |      |  |  | 52    | 
|Realized Foreign Exchange Loss on Early Receipt of the Partnership Contribution Receivable |  |      | -      |   |  |  |      |  | -     |   |  |      |  |  | 146   | 
|(Gain) Loss on Divestiture of Assets                                                       |  |      | (2,392 | ) |  |  |      |  | (156  | ) |  |      |  |  | 1     | 
|Operating Earnings (Loss), Before Income Tax                                               |  |      | (596   | ) |  |  |      |  | 901   |   |  |      |  |  | 1,708 | 
|Income Tax Expense (Recovery)                                                              |  |      | (193   | ) |  |  |      |  | 268   |   |  |      |  |  | 537   | 
|Operating Earnings (Loss)                                                                  |  |      | (403   | ) |  |  |      |  | 633   |   |  |      |  |  | 1,171 | 



|(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 foreign exchange (gains) losses
on settlement of intercompany transactions.
|--- | ------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------

Operating Earnings decreased compared with 2014 primarily due to lower Cash Flow,
and higher depreciation, depletion and amortization (DD&A) and exploration expense due to asset impairments. These items were partially offset by a recovery of deferred income tax compared with an expense in 2014 and a goodwill
impairment of $497 million recorded in 2014.

Net Earnings



|                                         |  |               |        |   |  |  |               |  |       |  
|---------------------------------------- |  | ------------- | ------ | - |  |  | ------------- |  | ----- | -
|($ millions)                             |  | 2015
vs. 2014 |        |   |  |  | 2014
vs. 2013 | 
|                                         |  |               |       
|Net Earnings, Comparative Year           |  |               | 744    |   |  |  |               |  | 662   |  
|Increase (Decrease) due to:              |  |               |        |   |  |  |               |  |       |  
|Operating Cash Flow (1) (2)              |  |               | (1,740 | ) |  |  |               |  | (305  | )
|Corporate and Eliminations:              |  |               |        |   |  |  |               |  |       |  
|Unrealized Risk Management Gain (Loss)   |  |               | (791   | ) |  |  |               |  | 1,011 |  
|Unrealized Foreign Exchange Gain (Loss)  |  |               | (686   | ) |  |  |               |  | (371  | )
|Gain (Loss) on Divestiture of Assets     |  |               | 2,236  |   |  |  |               |  | 157   |  
|Expenses (2) (3)                         |  |               | 46     |   |  |  |               |  | 191   |  
|Depreciation, Depletion and Amortization |  |               | (168   | ) |  |  |               |  | (113  | )
|Goodwill Impairment                      |  |               | 497    |   |  |  |               |  | (497  | )
|Exploration Expense                      |  |               | (52    | ) |  |  |               |  | 28    |  
|Income Tax Expense                       |  |               | 532    |   |  |  |               |  | (19   | )
|Net Earnings, End of Year                |  |               | 618    |   |  |  |               |  | 744   |  



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

|(2) | For all periods presented, we reclassified employee long-term incentive costs from operating expenses to general and administrative costs.
|--- | ------------------------------------------------------------------------------------------------------------------------------------------

|(3) | Includes general and administrative, finance costs, interest income, realized foreign exchange (gains) losses, research costs, other (income) loss, net and
Corporate and Eliminations revenues, purchased product, transportation and blending, and operating expenses.
|--- | ------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------

In 2015, Net
Earnings declined as an after-tax gain of approximately $1.9 billion from the divestiture of our royalty interest and mineral fee title lands business, and a deferred tax recovery related to non-operating
items compared with an expense in 2014, were more than offset by:

| |  | A decline in Operating Earnings, as discussed above;
|- |  | ----------------------------------------------------

| |  | Unrealized risk management losses, after-tax, of $141 million (2014  unrealized gains of $444 million); and
|- |  | ------------------------------------------------------------------------------------------------------------

| |  | Non-operating unrealized foreign exchange losses, after-tax, of $1,064 million (2014  $458 million).
|- |  | -----------------------------------------------------------------------------------------------------

Net Earnings increased in 2014 compared with 2013 primarily due to unrealized risk management gains compared with losses in 2013, a
gain on the sale of non-core assets and no realized foreign exchange loss in 2014 related to the Partnership Contribution Receivable, partially offset by a decline in operating earnings and higher non-operating unrealized foreign exchange losses.

Net Capital Investment



|                           |  |      |        |   |  |  |  |  |      |  |       |   |  |  |  |      |  |  |       |  
|-------------------------- |  | ---- | ------ | - |  |  |  |  | ---- |  | ----- | - |  |  |  | ---- |  |  | ----- | -
|($ millions)               |  | 2015 |        |   |  |  |  |  | 2014 |  |       |   |  |  |  | 2013 | 
|                           |  |      |        |   |  |  | 
|Oil Sands                  |  |      | 1,185  |   |  |  |  |  |      |  | 1,986 |   |  |  |  |      |  |  | 1,885 |  
|Conventional               |  |      | 244    |   |  |  |  |  |      |  | 840   |   |  |  |  |      |  |  | 1,189 |  
|Refining and Marketing     |  |      | 248    |   |  |  |  |  |      |  | 163   |   |  |  |  |      |  |  | 107   |  
|Corporate and Eliminations |  |      | 37     |   |  |  |  |  |      |  | 62    |   |  |  |  |      |  |  | 81    |  
|Capital Investment         |  |      | 1,714  |   |  |  |  |  |      |  | 3,051 |   |  |  |  |      |  |  | 3,262 |  
|Acquisitions               |  |      | 87     |   |  |  |  |  |      |  | 18    |   |  |  |  |      |  |  | 32    |  
|Divestitures               |  |      | (3,344 | ) |  |  |  |  |      |  | (277  | ) |  |  |  |      |  |  | (283  | )
|Net Capital Investment(1)  |  |      | (1,543 | ) |  |  |  |  |      |  | 2,792 |   |  |  |  |      |  |  | 3,011 |  



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



|                    |  |    |  |                                          
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|Cenovus Energy Inc. |  | 11 |  | 2015 Managements Discussion and Analysis



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##### Table of Contents

Capital investment in 2015 declined 44 percent as we reduced our capital investment in light of the low
commodity price environment.

In 2015, Oil Sands capital investment focused on sustaining capital related to existing production, the phase G
expansion at Foster Creek, and Christina Lake optimization project and phase F expansion. We drilled 164 gross stratigraphic test wells at Foster Creek and Christina Lake to determine pad placement for sustaining wells and near-term expansion
phases.

Conventional capital investment focused on maintenance capital and spending for our
CO2 enhanced oil recovery project at Weyburn and drilling activity in the second half of the year at our tight oil projects in southeast Alberta.

Capital investment in the Refining and Marketing segment focused on the debottlenecking project at Wood River, in addition to capital maintenance,
projects improving our refinery reliability and safety, and environmental initiatives.

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

Acquisitions and Divestitures

In 2015, we completed the sale of our royalty interest and mineral fee title lands business for cash proceeds of approximately $3.3 billion, recording an
after-tax gain of approximately $1.9 billion. The sale included approximately 4.8 million gross acres of royalty interest and mineral fee title lands in Alberta, Saskatchewan and Manitoba. A royalty on Cenovuss working interest production
on these fee lands and a Gross Overriding Royalty (GORR) on production from our Pelican Lake and Weyburn assets were also included.

In
2015, we purchased a crude-by-rail terminal for $75 million, plus adjustments, to expand our portfolio of transportation options.

Divestitures in
2014 primarily included the sale of certain of our Bakken assets in southeastern Saskatchewan and the sale of certain of our Wainwright assets in Alberta for net proceeds of $269 million, resulting in a gain of $153 million. In 2013, divestitures
included the sale of our Lower Shaunavon asset for net proceeds of $241 million, resulting in a loss of $2 million.

We had no material acquisitions
in 2014 or 2013.

Capital Investment Decisions

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

| |  | First, to capital for our existing business operations;
|- |  | -------------------------------------------------------

| |  | Second, to paying a dividend as part of providing strong total shareholder return; and
|- |  | --------------------------------------------------------------------------------------

| |  | Third, for growth or discretionary capital.
|- |  | -------------------------------------------

Our approach to capital allocation includes evaluating all opportunities using specific rigorous criteria within the context of achieving our objectives
of maintaining a prudent and flexible capital structure and strong balance sheet metrics, which position us to be financially resilient in times of lower cash flow. In addition, we continue to evaluate other corporate and financial opportunities,
including generating cash from our existing portfolio. Refer to the Liquidity and Capital Resources section of this MD&A for further information.



|                                          |  |      |       |   |  |  |      |  |       |   |  |      |  |  |       |  
|----------------------------------------- |  | ---- | ----- | - |  |  | ---- |  | ----- | - |  | ---- |  |  | ----- | -
|($ millions)                              |  | 2015 |       |   |  |  | 2014 |  |       |   |  | 2013 | 
|                                          |  |      |       |   | 
|Cash Flow(1)                              |  |      | 1,691 |   |  |  |      |  | 3,479 |   |  |      |  |  | 3,609 |  
|Capital Investment (Committed and Growth) |  |      | 1,714 |   |  |  |      |  | 3,051 |   |  |      |  |  | 3,262 |  
|Free Cash Flow (2)                        |  |      | (23   | ) |  |  |      |  | 428   |   |  |      |  |  | 347   |  
|Cash Dividends                            |  |      | 528   |   |  |  |      |  | 805   |   |  |      |  |  | 732   |  
|                                          |  |      | (551  | ) |  |  |      |  | (377  | ) |  |      |  |  | (385  | )



|(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.
|--- | ----------------------------------------------------------------------------------

We
expect our capital investment for 2016 to be funded from internally generated cash flow and our cash balance on hand.



|                    |  |    |  |                                          
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|Cenovus Energy Inc. |  | 12 |  | 2015 Managements Discussion and Analysis



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##### Table of Contents

REPORTABLE SEGMENTS







Our reportable segments are as follows: Oil Sands,which includes the development and production of
bitumen and natural gas in northeast Alberta. Cenovuss bitumen assets include Foster Creek, Christina Lake and Narrows Lake as well as projects in the early stages of development, such as Grand Rapids and Telephone Lake. Certain of
Cenovuss operated oil sands properties, notably Foster Creek, Christina Lake and Narrows Lake, are jointly owned with ConocoPhillips, an unrelated U.S. public company. Conventional,which includes the development and production
of conventional crude oil, NGLs and natural gas in Alberta and Saskatchewan, including the heavy oil assets at Pelican Lake, the carbon
dioxide enhanced oil recovery project at Weyburn and emerging tight oil opportunities. Refining
and Marketing,which is responsible for transporting, selling and refining crude oil into petroleum and chemical products. Cenovus jointly owns two refineries in the U.S. with the operator Phillips 66, an
unrelated U.S. public company. In addition, Cenovus owns and operates a crude-by-rail terminal in Alberta. This segment coordinates Cenovuss marketing and transportation initiatives to optimize product mix, delivery points, transportation
commitments and customer diversification.


LOGO






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)               |  | 2015 |        |   |  |  | 2014 |  |        |   |  | 2013 | 
|                           |  |      |        |   | 
|Oil Sands                  |  |      | 3,001  |   |  |  |      |  | 4,800  |   |  |      |  |  | 3,780  |  
|Conventional               |  |      | 1,595  |   |  |  |      |  | 2,996  |   |  |      |  |  | 2,776  |  
|Refining and Marketing     |  |      | 8,805  |   |  |  |      |  | 12,658 |   |  |      |  |  | 12,706 |  
|Corporate and Eliminations |  |      | (337   | ) |  |  |      |  | (812   | ) |  |      |  |  | (605   | )
|                           |  |      | 13,064 |   |  |  |      |  | 19,642 |   |  |      |  |  | 18,657 |  

OIL SANDS

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

Significant developments in our Oil Sands segment in
2015 compared with 2014 include:

| |  | Production at Foster Creek increasing 10 percent, to an average of 65,345 barrels per day, primarily as a result of the ramp-up of phase F, partially offset
by the impact of a forest fire in the second quarter. Fourth quarter production was lower compared with 2014. Improved wellbore conformance accelerated production from more mature wells, resulting in faster declines from these wells. To preserve
capital, we chose in 2015 to defer some planned well pads, which combined with the faster declines, contributed to lower fourth quarter volumes. In addition, while well downtime at Foster Creek was within expected ranges for 2015, a higher than
average number of wells were down for servicing in the second half of the year, which further impacted production;
|- |  | ------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------

| |  | Christina Lake production increasing nine percent, to an average of 74,975 barrels per day primarily due to production from additional wells, and improved
performance of our facilities;
|- |  | -----------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------

| |  | Completion of the optimization project at Christina Lake, which is expected to add 22,000 barrels per day of gross production capacity. Incremental production
from the project is anticipated in 2016;
|- |  | -------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------

| |  | Reducing our crude oil operating costs by $104 million or $3.37 per barrel; and
|- |  | -------------------------------------------------------------------------------

| |  | Receiving regulatory approval for Christina Lake phase H, a 50,000 gross barrels per day phase.
|- |  | -----------------------------------------------------------------------------------------------



|                    |  |    |  |                                          
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|Cenovus Energy Inc. |  | 13 |  | 2015 Managements Discussion and Analysis



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##### Table of Contents

Oil Sands  Crude Oil

Financial and Per-unit Results



|                                                      |  |      |       |               |  |  |      |  |    |   |               |      |  |  |       |   |  |               |  |  |     |   |  |  |  |  |       |   |  |  |  |  |     |  
|----------------------------------------------------- |  | ---- | ----- | ------------- |  |  | ---- |  | -- | - | ------------- | ---- |  |  | ----- | - |  | ------------- |  |  | --- | - |  |  |  |  | ----- | - |  |  |  |  | --- | -
|                                                      |  | 2015 |       |               |  |  | 2014 |  |    |   |               | 2013 | 
|($ millions, unless otherwise noted)                  |  |      |       | $ per-unit(1) |  |  |      |  |    |   | $ per-unit(1) |      |  |  |       |   |  | $ per-unit(1) | 
|                                                      |  |      |       |               |  |  |      |  |    |   |              
|Gross Sales                                           |  |      | 3,000 |               |  |  |      |  | 60 |   |               |      |  |  | 4,963 |   |  |               |  |  | 109 |   |  |  |  |  | 3,850 |   |  |  |  |  | 103 |  
|Less: Royalties                                       |  |      | 29    |               |  |  |      |  | 1  |   |               |      |  |  | 233   |   |  |               |  |  | 5   |   |  |  |  |  | 131   |   |  |  |  |  | 4   |  
|Revenues                                              |  |      | 2,971 |               |  |  |      |  | 59 |   |               |      |  |  | 4,730 |   |  |               |  |  | 104 |   |  |  |  |  | 3,719 |   |  |  |  |  | 99  |  
|Expenses                                              |  |      |       |               |  |  |      |  |    |   |               |      |  |  |       |   |  |               |  |  |     |   |  |  |  |  |       |   |  |  |  |  |     |  
|Transportation and Blending                           |  |      | 1,814 |               |  |  |      |  | 36 |   |               |      |  |  | 2,130 |   |  |               |  |  | 47  |   |  |  |  |  | 1,748 |   |  |  |  |  | 47  |  
|Operating (2)                                         |  |      | 511   |               |  |  |      |  | 10 |   |               |      |  |  | 615   |   |  |               |  |  | 14  |   |  |  |  |  | 527   |   |  |  |  |  | 14  |  
|(Gain) Loss on Risk Management                        |  |      | (400  | )             |  |  |      |  | (8 | ) |               |      |  |  | (38   | ) |  |               |  |  | (1  | ) |  |  |  |  | (33   | ) |  |  |  |  | (1  | )
|Operating Cash Flow                                   |  |      | 1,046 |               |  |  |      |  | 21 |   |               |      |  |  | 2,023 |   |  |               |  |  | 44  |   |  |  |  |  | 1,477 |   |  |  |  |  | 39  |  
|Capital Investment                                    |  |      | 1,184 |               |  |  |      |  |    |   |               |      |  |  | 1,980 |   |  |               |  |  |     |   |  |  |  |  | 1,880 |   |  |  |  |  |     |  
|Operating Cash Flow Net of Related Capital Investment |  |      | (138  | )             |  |  |      |  |    |   |               |      |  |  | 43    |   |  |               |  |  |     |   |  |  |  |  | (403  | ) |  |  |  |  |     |  

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

|(2) | For all periods presented, we reclassified employee long-term incentive costs from operating expenses to general and administrative costs.
|--- | ------------------------------------------------------------------------------------------------------------------------------------------

Capital investment in excess of Operating Cash Flow from Oil Sands was funded through Operating Cash Flow generated by our
Conventional and Refining and Marketing segments in 2015 and 2013. Proceeds from our common share issuance and the sale of our royalty interest and mineral fee title lands business also contributed to funding our capital investment in 2015.

Operating Cash Flow Variance



LOGO



|(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 2015,
our average crude oil sales price was $30.88 per barrel, a 53 percent decrease from 2014 as the prices we received were adversely impacted by the worldwide low commodity price environment. The decline in our crude oil price was consistent with
the decrease in the WCS and CDB benchmark prices, partially offset by weakening of the Canadian dollar relative to the U.S. dollar and increased sales into the U.S. market which generally secure a higher sales price. The WCS-CDB differential
narrowed by 40 percent to a discount of US$2.37 per barrel (2014  a discount of US$3.94 per barrel), primarily due to greater access to refineries on the U.S. Gulf Coast that can process a wider variety of heavier crude oils. In
2015, 86 percent of our Christina Lake production was sold as CDB (2014  88 percent), with the remainder sold into the WCS stream. Christina Lake production, whether sold as CDB or blended with WCS and subject to a quality
equalization charge, is priced at a discount to WCS.

Production Volumes



|                  |  |      |         |  |  |  |                |  |     |  |  |      |  |  |         |  |                |  |  |  |     |      |  |  |  |  |         | 
|----------------- |  | ---- | ------- |  |  |  | -------------- |  | --- |  |  | ---- |  |  | ------- |  | -------------- |  |  |  | --- | ---- |  |  |  |  | ------- | 
|(barrels per day) |  | 2015 |         |  |  |  | Percent
Change |  |     |  |  | 2014 |  |  |         |  | Percent
Change |  |  |  |     | 2013 | 
|                  |  |      |         |  |  |  |                |  |    
|Foster Creek      |  |      | 65,345  |  |  |  |                |  | 10% |  |  |      |  |  | 59,172  |  |                |  |  |  | 11% |      |  |  |  |  | 53,190  | 
|Christina Lake    |  |      | 74,975  |  |  |  |                |  | 9%  |  |  |      |  |  | 69,023  |  |                |  |  |  | 40% |      |  |  |  |  | 49,310  | 
|                  |  |      | 140,320 |  |  |  |                |  | 9%  |  |  |      |  |  | 128,195 |  |                |  |  |  | 25% |      |  |  |  |  | 102,500 | 

Foster Creek production increased in 2015 primarily due to the ramp-up of phase F and production from additional wells.
The ramp-up of phase F, our eleventh oil sands phase, is expected to take approximately 18 months from start-up, which occurred in the third quarter of 2014. Production increases were partially offset when production at Foster Creek was shut down
for 11 full days as a safety precaution due to a nearby forest fire. The forest fire decreased production by approximately 2,600 barrels per day. Fourth quarter production was lower compared with 2014. Improved wellbore conformance accelerated
production from more mature wells, resulting in faster declines from these wells. To preserve capital, we chose in 2015 to defer some planned well pads, which combined with the faster declines, contributed to lower fourth quarter volumes. In
addition, while well downtime at Foster Creek was within expected ranges for 2015, a higher than average number of wells were down for servicing in the second half of the year, which further impacted production.



|                    |  |    |  |                                          
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|Cenovus Energy Inc. |  | 14 |  | 2015 Managements Discussion and Analysis



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##### Table of Contents

Production from Christina Lake increased in 2015 due to production from additional wells, phase E reaching
nameplate production capacity in the second quarter of 2014, and improved performance of our facilities.

Condensate

The bitumen currently produced by Cenovus must be blended with condensate to reduce its thickness in order to transport it to market.
Revenues represent the total value of blended crude oil sold and include the value of condensate.

Royalties

Royalty calculations for our oil sands projects are based on government prescribed pre- and post-payout royalty rates which are determined on a sliding
scale using the Canadian dollar equivalent WTI benchmark price. Royalty calculations differ between properties.

Royalties at Foster Creek, a
post-payout project, are based on an annualized calculation which uses the greater of: (1) the gross revenues multiplied by the applicable royalty rate (one to nine percent, based on the Canadian dollar equivalent WTI benchmark price); or
(2) the net profits of the project multiplied by the applicable royalty rate (25 to 40 percent, based on the Canadian dollar equivalent WTI benchmark price). Gross revenues are a function of sales volumes and realized sales prices. Net profits
are a function of sales volumes, realized sales prices and allowed operating and capital costs.

Royalties at Christina Lake, a pre-payout project,
are based on a monthly calculation that applies a royalty rate (ranging from one to nine percent, based on the Canadian dollar equivalent WTI benchmark price) to the gross revenues from the project.

Effective Royalty Rates



|               |  |      |     |  |  |  |      |  |     |  |  |      |  |  |     | 
|-------------- |  | ---- | --- |  |  |  | ---- |  | --- |  |  | ---- |  |  | --- | 
|(percent)      |  | 2015 |     |  |  |  | 2014 |  |     |  |  | 2013 | 
|               |  |      |     |  | 
|Foster Creek   |  |      | 1.9 |  |  |  |      |  | 8.8 |  |  |      |  |  | 5.8 | 
|Christina Lake |  |      | 2.8 |  |  |  |      |  | 7.5 |  |  |      |  |  | 6.8 | 

Royalties decreased $204 million, primarily related to the decline in crude oil sales prices, partially offset by an
increase in sales volumes. At Foster Creek, the royalty calculation was based on gross revenues as compared with a calculation based on net profits for 2014. In the first quarter of 2015, we received regulatory approval to include certain capital
costs incurred in previous years in our royalty calculation and recorded an associated credit, decreasing the overall royalty rate. Excluding the credit, the effective royalty rate for Foster Creek would have been 3.1 percent in 2015. The
Christina Lake royalty rate decreased in 2015 as a result of lower realized sales prices.

Expenses

Transportation and Blending

Transportation and blending costs decreased $316 million or 15 percent. Blending costs declined primarily due to lower condensate prices, partially offset
by an increase in condensate volumes, consistent with the rise in production. In 2015, we recorded a $44 million (2014  $6 million) write-down of our blended crude oil and condensate inventory to net realizable value as a result of the decline
in crude oil prices. Our condensate costs were higher than the average benchmark price in 2015 primarily due to the utilization of higher-priced inventory and the transportation costs associated with moving
the condensate to our oil sands projects.

Transportation costs increased primarily due to higher pipeline tariffs and higher tariffs from additional
sales to the U.S. market, which generally secure higher sales prices. To help ensure adequate capacity for our expected future production growth, we have capacity commitments in excess of our current production. Future production growth is expected
to reduce our per-barrel transportation costs.

We incurred higher transportation charges on the Trans Mountain pipeline system, with our long-term
commitment for firm service. Transportation costs also increased as lower volumes moved by rail were more than offset by new lease costs for railcars, and higher loading fees and storage costs. In 2015, we transported an average of 7,057 gross
barrels per day of crude oil by rail, consisting of 43 unit train shipments (2014  7,325 gross barrels per day, 47 unit train shipments).

Operating

Primary drivers of our operating expenses for 2015 were workforce, fuel, repairs and maintenance, chemical
costs and workovers. Total operating expenses decreased $104 million or $3.37 per barrel, primarily as a result of lower natural gas prices that reduced fuel costs, higher production, a decline in workover activities and efforts from our supply
chain management.



|                    |  |    |  |                                          
|------------------- |  | -- |  | -----------------------------------------
|Cenovus Energy Inc. |  | 15 |  | 2015 Managements Discussion and Analysis



---

##### Table of Contents

Per-unit Operating Expenses



|               |  |      |       |  |  |  |                |  |       |  |  |      |  |  |       |  |                |  |  |  |       |      |  |  |  |  |       | 
|-------------- |  | ---- | ----- |  |  |  | -------------- |  | ----- |  |  | ---- |  |  | ----- |  | -------------- |  |  |  | ----- | ---- |  |  |  |  | ----- | 
|($/bbl)        |  | 2015 |       |  |  |  | Percent
Change |  |       |  |  | 2014 |  |  |       |  | Percent
Change |  |  |  |       | 2013 | 
|               |  |      |       |  |  |  |                |  |      
|Foster Creek   |  |      |       |  |  |  |                |  |       |  |  |      |  |  |       |  |                |  |  |  |       |      |  |  |  |  |       | 
|Fuel           |  |      | 2.80  |  |  |  |                |  | (37)% |  |  |      |  |  | 4.46  |  |                |  |  |  | 55%   |      |  |  |  |  | 2.88  | 
|Non-fuel (1)   |  |      | 9.80  |  |  |  |                |  | (18)% |  |  |      |  |  | 11.89 |  |                |  |  |  | (7)%  |      |  |  |  |  | 12.74 | 
|Total          |  |      | 12.60 |  |  |  |                |  | (23)% |  |  |      |  |  | 16.35 |  |                |  |  |  | 5%    |      |  |  |  |  | 15.62 | 
|Christina Lake |  |      |       |  |  |  |                |  |       |  |  |      |  |  |       |  |                |  |  |  |       |      |  |  |  |  |       | 
|Fuel           |  |      | 2.20  |  |  |  |                |  | (40)% |  |  |      |  |  | 3.65  |  |                |  |  |  | 20%   |      |  |  |  |  | 3.03  | 
|Non-fuel (1)   |  |      | 5.81  |  |  |  |                |  | (22)% |  |  |      |  |  | 7.44  |  |                |  |  |  | (20)% |      |  |  |  |  | 9.34  | 
|Total          |  |      | 8.01  |  |  |  |                |  | (28)% |  |  |      |  |  | 11.09 |  |                |  |  |  | (10)% |      |  |  |  |  | 12.37 | 
|Total          |  |      | 10.13 |  |  |  |                |  | (25)% |  |  |      |  |  | 13.50 |  |                |  |  |  | (4)%  |      |  |  |  |  | 14.07 | 



|(1) | For all periods presented, we reclassified employee long-term incentive costs from operating expenses to general and administrative costs.
|--- | ------------------------------------------------------------------------------------------------------------------------------------------

At Foster Creek, fuel costs decreased due to lower natural gas prices and a decline in fuel consumption on a per-barrel basis.
Non-fuel operating expenses declined primarily due to:

| |  | Higher production volumes;
|- |  | --------------------------

| |  | A reduction in workover expenses due to lower costs associated with well servicing and pump changes; and
|- |  | --------------------------------------------------------------------------------------------------------

| |  | Lower electricity costs.
|- |  | ------------------------

Foster Creek
non-fuel operating expenses included approximately $2.6 million or $0.11 per barrel of incremental costs associated with the shut-down due to a nearby forest fire that occurred in the second quarter of 2015.

At Christina Lake, fuel costs decreased due to lower natural gas prices and a decrease in fuel consumption on a per-barrel basis. Non-fuel operating
expenses decreased primarily due to:

| |  | Increased production;
|- |  | ---------------------

| |  | Lower workover costs related to fewer pump changes; and
|- |  | -------------------------------------------------------

| |  | A decrease in repairs and maintenance costs due to a focus on critical operational activities and no turnaround costs in 2015.
|- |  | ------------------------------------------------------------------------------------------------------------------------------

Operating Netbacks



LOGO



|(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 2015 was $27.44 per barrel (2014  $42.01 per barrel; 2013  $42.41 per barrel) for Foster Creek, and $29.50 per barrel (2014 
$45.45 per barrel; 2013  $45.25 per barrel) for Christina Lake. Our blending ratios range from approximately 25 percent to 33 percent.
|--- | ---------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------

|(2) | The netbacks do not reflect non-cash write-downs of product inventory in 2015 and 2014. There was no product inventory write-down recorded in 2013.
|--- | ---------------------------------------------------------------------------------------------------------------------------------------------------

Risk Management

Risk management activities in 2015 resulted in realized gains of $400 million (2014  $38 million), consistent with our contract prices exceeding
average benchmark prices.

Oil Sands  Natural Gas

Oil Sands includes our natural gas operations in northeastern Alberta. A portion of the natural gas produced from our Athabasca property is used as fuel
at Foster Creek. Our natural gas production for 2015, net of internal usage, was 19 MMcf per day (2014  22 MMcf per day). Operating Cash Flow was $10 million in 2015 (2014  $46 million) primarily due to the decline in natural
gas sales prices.



|                    |  |    |  |                                          
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|Cenovus Energy Inc. |  | 16 |  | 2015 Managements Discussion and Analysis



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##### Table of Contents

Oil Sands  Capital Investment



|                       |  |      |       |  |  |  |      |  |       |  |  |      |  |  |       | 
|---------------------- |  | ---- | ----- |  |  |  | ---- |  | ----- |  |  | ---- |  |  | ----- | 
|($ millions)           |  | 2015 |       |  |  |  | 2014 |  |       |  |  | 2013 | 
|                       |  |      |       |  | 
|Foster Creek           |  |      | 403   |  |  |  |      |  | 796   |  |  |      |  |  | 797   | 
|Christina Lake         |  |      | 647   |  |  |  |      |  | 794   |  |  |      |  |  | 688   | 
|                       |  |      | 1,050 |  |  |  |      |  | 1,590 |  |  |      |  |  | 1,485 | 
|Narrows Lake           |  |      | 47    |  |  |  |      |  | 175   |  |  |      |  |  | 152   | 
|Telephone Lake         |  |      | 24    |  |  |  |      |  | 112   |  |  |      |  |  | 93    | 
|Grand Rapids           |  |      | 38    |  |  |  |      |  | 63    |  |  |      |  |  | 39    | 
|Other (1)              |  |      | 26    |  |  |  |      |  | 46    |  |  |      |  |  | 116   | 
|Capital Investment (2) |  |      | 1,185 |  |  |  |      |  | 1,986 |  |  |      |  |  | 1,885 | 



|(1) | Includes new resource plays and Athabasca natural gas.
|--- | ------------------------------------------------------

|(2) | Includes expenditures on PP&E and E&E assets.
|--- | ---------------------------------------------

Existing Projects

Capital
investment at Foster Creek in 2015 focused on sustaining capital related to existing production, expansion phase G and the drilling of stratigraphic test wells. In 2015, capital investment declined mainly due to the start-up of phase F in the third
quarter of 2014.

In 2015, Christina Lake capital investment focused on sustaining capital related to existing production, expansion phases F and G,
and the optimization project. The optimization project has been completed and is expected to add 22,000 barrels per day of gross production capacity. Incremental production from the optimization project is anticipated in 2016. Capital investment in
2015 decreased from 2014 due to lower spending on phase F facilities, partially offset by increased investment in sustaining activities.

Capital
investment at Narrows Lake in 2015 was mainly on detailed engineering and construction wind-down. Capital investment declined in 2015 compared with 2014 due to the suspension of construction at Narrows Lake.

Emerging Projects

In 2015,
Telephone Lake capital investment focused primarily on completing front-end engineering work on the central processing facility and preliminary infrastructure development. Capital spending decreased in 2015 as
we did not drill any stratigraphic test wells during the year (2014  45 stratigraphic test wells).

Capital investment at Grand Rapids in 2015
focused on continued operation of the SAGD pilot project. A third well pair was drilled, completed and commenced steam circulation. Capital investment decreased in 2015 compared with 2014 as there were no stratigraphic test wells drilled in 2015
(2014  10 stratigraphic test wells) and all work related to the dismantling and removal of an existing SAGD facility purchased in 2014 was completed.

Drilling Activity (1)



|               |  |                                    |     |  |  |  |                            |  |     |  |  |      |  |  |     |  |      |  |  |  |    |      |  |  |  |  |      |  |  |  |  |  |    | 
|-------------- |  | ---------------------------------- | --- |  |  |  | -------------------------- |  | --- |  |  | ---- |  |  | --- |  | ---- |  |  |  | -- | ---- |  |  |  |  | ---- |  |  |  |  |  | -- | 
|               |  | Gross Stratigraphic
Test Wells (2) |     |  |  |  | Gross Production
Wells (3) | 
|               |  | 2015                               |     |  |  |  | 2014                       |  |     |  |  | 2013 |  |  |     |  | 2015 |  |  |  |    | 2014 |  |  |  |  | 2013 | 
|               |  |                                    |     |  |  |  |                            |  |     |  | 
|Foster Creek   |  |                                    | 124 |  |  |  |                            |  | 165 |  |  |      |  |  | 112 |  |      |  |  |  | 28 |      |  |  |  |  | 63   |  |  |  |  |  | 56 | 
|Christina Lake |  |                                    | 40  |  |  |  |                            |  | 57  |  |  |      |  |  | 74  |  |      |  |  |  | 67 |      |  |  |  |  | 67   |  |  |  |  |  | 35 | 
|               |  |                                    | 164 |  |  |  |                            |  | 222 |  |  |      |  |  | 186 |  |      |  |  |  | 95 |      |  |  |  |  | 130  |  |  |  |  |  | 91 | 
|Narrows Lake   |  |                                    | -   |  |  |  |                            |  | 22  |  |  |      |  |  | 26  |  |      |  |  |  | -  |      |  |  |  |  | -    |  |  |  |  |  | -  | 
|Telephone Lake |  |                                    | -   |  |  |  |                            |  | 45  |  |  |      |  |  | 28  |  |      |  |  |  | -  |      |  |  |  |  | -    |  |  |  |  |  | -  | 
|Grand Rapids   |  |                                    | -   |  |  |  |                            |  | 10  |  |  |      |  |  | 3   |  |      |  |  |  | 1  |      |  |  |  |  | -    |  |  |  |  |  | -  | 
|Other          |  |                                    | -   |  |  |  |                            |  | 21  |  |  |      |  |  | 96  |  |      |  |  |  | -  |      |  |  |  |  | -    |  |  |  |  |  | -  | 
|               |  |                                    | 164 |  |  |  |                            |  | 320 |  |  |      |  |  | 339 |  |      |  |  |  | 96 |      |  |  |  |  | 130  |  |  |  |  |  | 91 | 



|(1) | In addition to the drilling activity included within the table, we drilled eight gross service wells in 2015 (2014  three gross service wells;
2013  27 gross service wells).
|--- | -------------------------------------------------------------------------------------------------------------------------------------------------------------------------------

|(2) | Includes wells drilled using our SkyStratTM drilling rig, which uses a helicopter and a lightweight
drilling rig to allow safe stratigraphic well drilling to occur year-round in remote drilling locations. In 2015, we drilled seven wells (2014  14 wells; 2013  24 wells) and commissioned our second SkyStratTMdrilling rig.
|--- | -----------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------

|(3) | SAGD well pairs are counted as a single producing well.
|--- | -------------------------------------------------------

Stratigraphic test wells were drilled at Foster Creek and Christina Lake to help identify well pad locations for sustaining wells and near-term expansion
phases.

Future Capital Investment

Due to our expectation that low commodity prices will persist for an extended period, we have adopted a more moderate and staged approach to future oil
sands expansions. Expanding existing projects and developing emerging projects will depend upon commodity prices, achieving further cost reductions as well as additional fiscal and regulatory certainty.



|                    |  |    |  |                                          
|------------------- |  | -- |  | -----------------------------------------
|Cenovus Energy Inc. |  | 17 |  | 2015 Managements Discussion and Analysis



---

##### Table of Contents

Existing Projects

Foster Creek is currently producing from phases A through F. Capital investment for 2016 is forecast to be between $325 million and $350 million. We plan
to continue focusing on sustaining capital related to existing production as well as completing expansion phase G. We expect phase G to add initial design capacity of 30,000 gross barrels per day and first production is anticipated in the third
quarter of 2016. Spending related to construction work on phase H was deferred in response to the low commodity price environment, pushing the expected start-up to beyond 2017. Phase H has an initial design capacity of 30,000 gross barrels per day.
In December 2014, we received regulatory approval for expansion phase J, a 50,000 gross barrels per day phase.

Christina Lake is producing from
phases A through E. Capital investment for 2016 is forecast to be between $350 million and $375 million, focused on sustaining capital related to existing production and expansion phase F. We anticipate adding gross production capacity of
50,000 barrels per day from phase F in the third quarter of 2016. Construction work on phase G was deferred earlier in 2015 in response to the low commodity price environment, pushing the expected start-up to beyond 2017. Phase G has an initial
design capacity of 50,000 gross barrels per day. We received regulatory approval in December 2015 for the phase H expansion, a 50,000 gross barrels per day phase.

Capital investment at Narrows Lake in 2016 is forecast to be between $10 million and $20 million, focusing on completing phase A detailed
engineering.

Emerging Projects

Capital investment for our new resource plays is forecast to be between $45 million and $55 million in 2016. As of February 2016, further activity in
respect of the SAGD pilot at Grand Rapids has been deferred in response to the current low commodity price environment.

DD&A and
Exploration Expense

DD&A

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

In 2015, Oil Sands DD&A increased $72 million primarily due to
higher sales volumes and the impairment of a sulphur recovery facility for $16 million. The average depletion rate was approximately $11.65 per barrel compared with $10.85 per barrel in 2014 as the impact of higher PP&E and future development
expenditures were only partially offset by proved reserves additions. Future development costs, which compose approximately 60 percent of the depletable base, increased due to the inclusion of Foster Creek phase J.

Exploration Expense

In
2015, $67 million of previously capitalized E&E costs, related to exploration assets within the Northern Alberta cash-generating unit (CGU), were deemed not to be technically feasible and commercially viable and were recorded as
exploration expense. In 2014, $4 million of costs related to the expiry of leases in the Borealis CGU were recorded as exploration expense.

CONVENTIONAL

Our Conventional operations include dependable cash flow producing crude oil and natural gas assets in Alberta and Saskatchewan, including a CO2 enhanced oil recovery project in Weyburn, our heavy oil asset at Pelican Lake that uses polymer flood technology and emerging tight oil assets in Alberta. The established assets in this segment
are strategically important for their long life reserves, stable operations and diversity of crude oil produced. The cash flow generated in our Conventional operations helps to fund future growth opportunities in our Oil Sands segment while our
natural gas production acts as an economic hedge for the natural gas required as a fuel source at both our oil sands and refining operations.

On
July 29, 2015, we completed the sale of our royalty interest and mineral fee title lands business, which included approximately 4.8 million gross acres of royalty interest and mineral fee title lands in Alberta, Saskatchewan and Manitoba.
A royalty on our working interest production from these fee lands and a GORR on production from our Pelican Lake and Weyburn assets were also included in the sale. We received cash proceeds of approximately $3.3 billion and recorded an after-tax
gain of approximately $1.9 billion. Associated third-party royalty interest volumes prior to the divestiture were approximately 6,580 barrels of oil equivalent per day.



|                    |  |    |  |                                          
|------------------- |  | -- |  | -----------------------------------------
|Cenovus Energy Inc. |  | 18 |  | 2015 Managements Discussion and Analysis



---

##### Table of Contents

Additional developments in our Conventional segment in 2015 compared with 2014 include:

| |  | Crude oil production averaging 66,627 barrels per day, decreasing 12 percent, as an increase in production from successful horizontal well performance in
southern Alberta was more than offset by expected natural declines, the divestiture of non-core assets in 2014, and the sale of our royalty interest and mineral fee title lands business. Production also
declined due to reduced capital investment;
|- |  | ----------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------

| |  | Reducing our crude oil operating costs by $124 million or $2.77 per barrel;
|- |  | ---------------------------------------------------------------------------

| |  | Generating Operating Cash Flow net of capital investment of $751 million, a decrease of 29 percent;
|- |  | ---------------------------------------------------------------------------------------------------

| |  | Recording an impairment of $184 million associated with our Northern Alberta CGU due to lower crude oil prices and a slowing down of the development plan; and
|- |  | --------------------------------------------------------------------------------------------------------------------------------------------------------------

| |  | Recording an exploration expense of $71 million related to previously capitalized exploration assets deemed not to be technically feasible and commercially
viable.
|- |  | -------------------------------------------------------------------------------------------------------------------------------------------------------------------

Conventional  Crude Oil

Financial and Per-unit Results



|                                                      |  |               |       |  |  |  |               |  |     |  |  |               |  |  |       |  |  |  |  |  |    |  |  |  |  |  |       |  |  |  |  |  |     | 
|----------------------------------------------------- |  | ------------- | ----- |  |  |  | ------------- |  | --- |  |  | ------------- |  |  | ----- |  |  |  |  |  | -- |  |  |  |  |  | ----- |  |  |  |  |  | --- | 
|                                                      |  | 2015          |       |  |  |  | 2014          |  |     |  |  | 2013          | 
|($ millions, unless otherwise noted)                  |  | $ per-unit(1) |       |  |  |  | $ per-unit(1) |  |     |  |  | $ per-unit(1) | 
|Gross
Sales                                           |  |               | 1,239 |  |  |  |               |  | 51  |  |  |               |  |  | 2,456 |  |  |  |  |  | 90 |  |  |  |  |  | 2,373 |  |  |  |  |  | 85  | 
|Less: Royalties                                       |  |               | 103   |  |  |  |               |  | 4   |  |  |               |  |  | 217   |  |  |  |  |  | 8  |  |  |  |  |  | 196   |  |  |  |  |  | 7   | 
|Revenues                                              |  |               | 1,136 |  |  |  |               |  | 47  |  |  |               |  |  | 2,239 |  |  |  |  |  | 82 |  |  |  |  |  | 2,177 |  |  |  |  |  | 78  | 
|Expenses                                              |  |               |       |  |  |  |               |  |     |  |  |               |  |  |       |  |  |  |  |  |    |  |  |  |  |  |       |  |  |  |  |  |     | 
|Transportation and Blending                           |  |               | 213   |  |  |  |               |  | 9   |  |  |               |  |  | 326   |  |  |  |  |  | 12 |  |  |  |  |  | 305   |  |  |  |  |  | 11  | 
|Operating (2)                                         |  |               | 381   |  |  |  |               |  | 15  |  |  |               |  |  | 505   |  |  |  |  |  | 19 |  |  |  |  |  | 489   |  |  |  |  |  | 18  | 
|Production and Mineral Taxes                          |  |               | 16    |  |  |  |               |  | 1   |  |  |               |  |  | 37    |  |  |  |  |  | 1  |  |  |  |  |  | 32    |  |  |  |  |  | 1   | 
|(Gain) Loss on Risk Management                        |  |               | (157) |  |  |  |               |  | (6) |  |  |               |  |  | 4     |  |  |  |  |  | -  |  |  |  |  |  | (43)  |  |  |  |  |  | (2) | 
|Operating Cash Flow                                   |  |               | 683   |  |  |  |               |  | 28  |  |  |               |  |  | 1,367 |  |  |  |  |  | 50 |  |  |  |  |  | 1,394 |  |  |  |  |  | 50  | 
|Capital Investment                                    |  |               | 231   |  |  |  |               |  |     |  |  |               |  |  | 812   |  |  |  |  |  |    |  |  |  |  |  | 1,167 |  |  |  |  |  |     | 
|Operating Cash Flow Net of Related Capital Investment |  |               | 452   |  |  |  |               |  |     |  |  |               |  |  | 555   |  |  |  |  |  |    |  |  |  |  |  | 227   |  |  |  |  |  |     | 

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

|(2) | For all periods presented, we reclassified employee long-term incentive costs from operating expenses to general and administrative costs.
|--- | ------------------------------------------------------------------------------------------------------------------------------------------

Operating Cash Flow Variance



LOGO



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

Revenues

Pricing

Our
average crude oil sales price was $44.63 per barrel in 2015, 45 percent lower than in 2014, consistent with the decline in crude oil benchmark prices.

Production Volumes



|                     |  |      |        |  |  |  |                |  |       |  |  |      |  |  |        |  |                |  |  |  |      |      |  |  |  |  |        | 
|-------------------- |  | ---- | ------ |  |  |  | -------------- |  | ----- |  |  | ---- |  |  | ------ |  | -------------- |  |  |  | ---- | ---- |  |  |  |  | ------ | 
|(barrels per day)    |  | 2015 |        |  |  |  | Percent
Change |  |       |  |  | 2014 |  |  |        |  | Percent
Change |  |  |  |      | 2013 | 
|Heavy Oil            |  |      | 34,888 |  |  |  |                |  | (12)% |  |  |      |  |  | 39,546 |  |                |  |  |  | (2)% |      |  |  |  |  | 40,245 | 
|Light and Medium Oil |  |      | 30,486 |  |  |  |                |  | (12)% |  |  |      |  |  | 34,531 |  |                |  |  |  | (3)% |      |  |  |  |  | 35,467 | 
|NGLs                 |  |      | 1,253  |  |  |  |                |  | 3%    |  |  |      |  |  | 1,221  |  |                |  |  |  | 15%  |      |  |  |  |  | 1,063  | 
|                     |  |      | 66,627 |  |  |  |                |  | (12)% |  |  |      |  |  | 75,298 |  |                |  |  |  | (2)% |      |  |  |  |  | 76,775 | 

Increased production from successful horizontal well performance in southern Alberta was more than offset by expected
natural declines, the divestiture of non-core assets in 2014, and the sale of our royalty interest and



|                    |  |    |  |                                          
|------------------- |  | -- |  | -----------------------------------------
|Cenovus Energy Inc. |  | 19 |  | 2015 Managements Discussion and Analysis



---

##### Table of Contents

mineral fee title lands business. Production also declined due to reduced capital investment. Divested assets contributed 2,555 barrels per day (2014  6,532 barrels per day) to annual
production.

Condensate

Revenues represent the total value of blended crude oil sold and include the value of condensate.

Royalties

Royalties decreased $114 million primarily due to lower realized sales prices, partially offset by additional royalty burdens at Pelican Lake, Weyburn and
other conventional assets resulting from the sale of our royalty interest and mineral fee title lands business. For 2015, the effective crude oil royalty rate for our Conventional properties was 9.9 percent (2014  10.1 percent).

Crown royalties at Pelican Lake are determined under oil sands royalty calculations. Pelican Lake is a post-payout project, therefore royalties are based
on an annualized calculation which uses the greater of: (1) the gross revenues multiplied by the applicable royalty rate (one to nine percent, based on the Canadian dollar equivalent WTI benchmark price); or (2) the net profits of the
project multiplied by the applicable royalty rate (25 to 40 percent, based on the Canadian dollar equivalent WTI benchmark price). Gross revenues are a function of sales volumes and realized sales prices. Net profits are a function of sales volumes,
realized sales prices and allowed operating and capital costs. The Pelican Lake royalty calculation was based on net profits in 2015 as compared with a calculation based on gross revenues in 2014.

In 2015, production and mineral taxes decreased, consistent with the decline in crude oil prices and due to the sale of our royalty interest and mineral
fee title lands business.

Expenses

Transportation and Blending

Transportation and blending costs decreased $113 million. Blending costs declined primarily due to lower condensate prices. In 2015, we recorded a $7
million (2014  $12 million) write-down of our crude oil and condensate inventory to net realizable value as a result of the decline in crude oil prices.

Transportation charges were lower largely due to a decline in sales volumes and a reduction in volumes moved by rail. We transported an average of 597
barrels per day of crude oil by rail (2014  2,706 barrels per day).

Operating

Primary drivers of our operating expenses for 2015 were workforce costs, workover activities, electricity and chemical consumption. Operating expenses
declined $124 million or $2.77 per barrel.

The per-unit decline was primarily due to:

| |  | A decline in workover costs and lower repairs and maintenance as a result of focusing on critical activities and achieving operational efficiencies;
|- |  | ----------------------------------------------------------------------------------------------------------------------------------------------------

| |  | Lower trucking expenses as we added pipeline infrastructure;
|- |  | ------------------------------------------------------------

| |  | Lower chemical costs associated with reduced polymer consumption; and
|- |  | ---------------------------------------------------------------------

| |  | Lower electricity costs as a result of a decrease in consumption due in part to the disposition of non-core assets, and a decline in price.
|- |  | -------------------------------------------------------------------------------------------------------------------------------------------

These decreases were partially offset by lower production.

Operating Netbacks



LOGO



|(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 $10.94 per barrel (2014 $15.71 per barrel; 2013 $14.60 per barrel). Our blending
ratios range from approximately 10 percent to 16 percent.
|--- | ------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------

|(2) | The netbacks do not reflect non-cash write-downs of product inventory in 2015 and 2014. There was no product inventory write-down recorded in 2013.
|--- | ---------------------------------------------------------------------------------------------------------------------------------------------------



|                    |  |    |  |                                          
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|Cenovus Energy Inc. |  | 20 |  | 2015 Managements Discussion and Analysis



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##### Table of Contents

Risk Management

Risk management activities for 2015 resulted in realized gains of $157 million (2014  realized losses of $4 million), consistent with our
contract prices exceeding average benchmark prices.

Conventional  Natural Gas

Financial Results



|                                                      |  |      |      |  |  |  |      |  |     |  |  |      |  |  |      | 
|----------------------------------------------------- |  | ---- | ---- |  |  |  | ---- |  | --- |  |  | ---- |  |  | ---- | 
|($ millions)                                          |  | 2015 |      |  |  |  | 2014 |  |     |  |  | 2013 | 
|Gross
Sales                                           |  |      | 450  |  |  |  |      |  | 744 |  |  |      |  |  | 594  | 
|Less: Royalties                                       |  |      | 11   |  |  |  |      |  | 12  |  |  |      |  |  | 8    | 
|Revenues                                              |  |      | 439  |  |  |  |      |  | 732 |  |  |      |  |  | 586  | 
|Expenses                                              |  |      |      |  |  |  |      |  |     |  |  |      |  |  |      | 
|Transportation and Blending                           |  |      | 17   |  |  |  |      |  | 20  |  |  |      |  |  | 20   | 
|Operating (1)                                         |  |      | 175  |  |  |  |      |  | 198 |  |  |      |  |  | 208  | 
|Production and Mineral Taxes                          |  |      | 2    |  |  |  |      |  | 9   |  |  |      |  |  | 3    | 
|(Gain) Loss on Risk Management                        |  |      | (52) |  |  |  |      |  | (5) |  |  |      |  |  | (61) | 
|Operating Cash Flow                                   |  |      | 297  |  |  |  |      |  | 510 |  |  |      |  |  | 416  | 
|Capital Investment                                    |  |      | 13   |  |  |  |      |  | 28  |  |  |      |  |  | 22   | 
|Operating Cash Flow Net of Related Capital Investment |  |      | 284  |  |  |  |      |  | 482 |  |  |      |  |  | 394  | 

|(1) | For all periods presented, we reclassified employee long-term incentive costs from operating expenses to general and administrative costs.
|--- | ------------------------------------------------------------------------------------------------------------------------------------------

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

Revenues

Pricing

In 2015, our average natural gas sales price decreased 33 percent to $2.93 per Mcf, consistent with the
decline in the AECO benchmark price.

Production

Production decreased nine percent to 422 MMcf per day in 2015 (2014  eight percent to 466 MMcf per day) due to expected natural declines and from
the sale of our royalty interest and mineral fee title lands business, which produced 10 MMcf per day in 2015 (2014  20 MMcf per day).

Royalties

Royalties decreased slightly compared with 2014. Reduced royalties as a result of lower prices and
production declines were offset by additional royalty burdens due to the sale of our royalty interest and mineral fee title lands business. The average royalty rate in 2015 was 2.7 percent (2014  1.6 percent).

Expenses

Transportation

In 2015, transportation costs decreased as a result of lower production volumes, partially offset by
higher pipeline tariffs.

Operating

Primary drivers of our operating expenses were property taxes and lease costs, and workforce. In 2015, operating expenses decreased by $23 million
primarily due to lower workforce costs, and repairs and maintenance, partially offset by lower production volumes.

Risk
Management

Risk management activities resulted in realized gains of $52 million in 2015 (2014  $5 million), consistent with our
contract prices exceeding average benchmark prices.

Conventional  Capital Investment



|                       |  |      |     |  |  |  |      |  |     |  |  |      |  |  |       | 
|---------------------- |  | ---- | --- |  |  |  | ---- |  | --- |  |  | ---- |  |  | ----- | 
|($ millions)           |  | 2015 |     |  |  |  | 2014 |  |     |  |  | 2013 | 
|Heavy Oil              |  |      | 63  |  |  |  |      |  | 338 |  |  |      |  |  | 598   | 
|Light and Medium Oil   |  |      | 168 |  |  |  |      |  | 474 |  |  |      |  |  | 569   | 
|Natural Gas            |  |      | 13  |  |  |  |      |  | 28  |  |  |      |  |  | 22    | 
|Capital Investment (1) |  |      | 244 |  |  |  |      |  | 840 |  |  |      |  |  | 1,189 | 

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



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|Cenovus Energy Inc. |  | 21 |  | 2015 Managements Discussion and Analysis



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##### Table of Contents

Capital investment declined in 2015 primarily due to spending reductions on crude oil activities in response
to the low commodity price environment. Capital investment in 2015 was primarily related to maintenance capital, spending for our CO2 enhanced oil recovery project at Weyburn and drilling
activities at our tight oil projects in southeast Alberta.

Drilling Activity



|                                     |  |  |      |  |  |  |      |  |  |  |      | 
|------------------------------------ |  |  | ---- |  |  |  | ---- |  |  |  | ---- | 
|(net wells, unless otherwise stated) |  |  | 2015 |  |  |  | 2014 |  |  |  | 2013 | 
|                                     |  |  |     
|Crude Oil                            |  |  | 32   |  |  |  | 126  |  |  |  | 212  | 
|Recompletions                        |  |  | 724  |  |  |  | 803  |  |  |  | 751  | 
|Gross Stratigraphic Test Wells       |  |  | 13   |  |  |  | 30   |  |  |  | 54   | 
|Other (1)                            |  |  | 3    |  |  |  | 40   |  |  |  | 77   | 



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

Drilling activity declined in 2015,
reflecting the decision to suspend the majority of our 2015 drilling program in southern Alberta and Saskatchewan as a result of the low commodity price environment. In the second half of the year, modest drilling activities resumed at our tight oil
projects in southeast Alberta and at our CO2 enhanced oil recovery project at Weyburn.

Future Capital Investment

Consistent with our expectation that commodity prices will continue to be low for a
prolonged period of time, we are taking a more moderate approach to developing our conventional crude oil opportunities. We plan to focus on drilling projects that are considered to be relatively low risk, with short production cycle times and
strong expected returns.

Our 2016 crude oil capital investment forecast is between $125 million and $150 million with spending plans mainly focused
on maintaining and optimizing current production volumes.

DD&A, Goodwill Impairment and Exploration Expense

DD&A

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

Conventional DD&A increased $66 million in 2015 as a decline in
sales volumes was more than offset by impairment losses and higher DD&A rates. The average depletion rate increased approximately five percent in 2015 as the impact of lower proved reserves due to the slowdown of our development plans was
partially offset by lower PP&E. Future development costs, which compose approximately 30 percent of the depletable base, were consistent with 2014.

In 2015, we recorded an impairment loss of $184 million associated with our Northern Alberta CGU due to lower crude oil prices and a slowing down of our
development plan. In 2014, an impairment loss of $52 million was recorded on equipment and in 2013, we recorded a $57 million impairment loss related to our Lower Shaunavon asset sold in July 2013.

Goodwill Impairment

In 2014, we recorded $497 million of goodwill impairment associated with our Pelican Lake property. There was no goodwill impairment in 2015 or 2013.

Exploration Expense

In 2015, $71 million (2014  $82 million) of previously capitalized E&E costs related to exploration assets within the Northern Alberta and
Saskatchewan CGUs that were deemed not to be technically feasible and commercially viable and were recorded as exploration expense.

In 2013, $50
million of exploration expense and $64 million of pre-exploration expense was recorded.

REFINING AND MARKETING

We are a 50 percent partner in the Wood River and Borger refineries, which are located in the U.S. Our Refining and Marketing segment positions us to
capture the value from crude oil production through to refined products such as diesel, gasoline and jet fuel. Our integrated approach provides a natural economic hedge against widening crude oil price differentials by providing lower feedstock
prices to our refineries.



|                    |  |    |  |                                          
|------------------- |  | -- |  | -----------------------------------------
|Cenovus Energy Inc. |  | 22 |  | 2015 Managements Discussion and Analysis



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##### Table of Contents

Significant developments in our Refining and Marketing segment in 2015 compared with 2014 include:

| |  | Closing the purchase of a crude-by-rail terminal for $75 million, plus adjustments. We commenced operating the terminal in August 2015 and loaded 34 unit
trains, including 20 unit trains for third parties;
|- |  | -------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------

| |  | Operating Cash Flow increasing 79 percent to $385 million primarily due to improved margins on the sale of secondary products, weakening of the Canadian
dollar relative to the U.S. dollar and an increase in average market crack spreads, partially offset by higher heavy crude oil feedstock costs relative to the WTI benchmark price and higher operating costs;
|- |  | -----------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------

| |  | Receiving permit approval for the Wood River debottlenecking project;
|- |  | ---------------------------------------------------------------------

| |  | Successfully completing planned turnarounds at both of our Borger and Wood River refineries; and
|- |  | ------------------------------------------------------------------------------------------------

| |  | Exporting crude oil from the U.S. Gulf Coast to broaden market access for our crude oil production.
|- |  | ---------------------------------------------------------------------------------------------------

Refinery Operations (1)



|                                |  |      |     |  |  |  |      |  |     |  |  |      |  |  |     | 
|------------------------------- |  | ---- | --- |  |  |  | ---- |  | --- |  |  | ---- |  |  | --- | 
|                                |  | 2015 |     |  |  |  | 2014 |  |     |  |  | 2013 | 
|                                |  |      |     |  | 
|Crude Oil Capacity
(2)(Mbbls/d) |  |      | 460 |  |  |  |      |  | 460 |  |  |      |  |  | 457 | 
|Crude Oil Runs(Mbbls/d)         |  |      | 419 |  |  |  |      |  | 423 |  |  |      |  |  | 442 | 
|Heavy Crude Oil                 |  |      | 200 |  |  |  |      |  | 199 |  |  |      |  |  | 222 | 
|Light/Medium                    |  |      | 219 |  |  |  |      |  | 224 |  |  |      |  |  | 220 | 
|Refined Products(Mbbls/d)       |  |      | 444 |  |  |  |      |  | 445 |  |  |      |  |  | 463 | 
|Gasoline                        |  |      | 228 |  |  |  |      |  | 231 |  |  |      |  |  | 232 | 
|Distillate                      |  |      | 137 |  |  |  |      |  | 137 |  |  |      |  |  | 144 | 
|Other                           |  |      | 79  |  |  |  |      |  | 77  |  |  |      |  |  | 87  | 
|Crude Utilization(percent)      |  |      | 91  |  |  |  |      |  | 92  |  |  |      |  |  | 97  | 



|(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.
|--- | --------------------------------------------------------------------------------------------------------------------------

On a 100-percent basis, our refineries have total capacity of approximately 460,000 gross barrels per day of crude oil, excluding NGLs, including
processing capability of up to 255,000 gross barrels per day of blended heavy crude oil, and capacity of 45,000 gross barrels per day of NGLs. The ability to refine heavy crude oil demonstrates our ability to economically integrate our heavy crude
oil production. The discount of WCS relative to WTI benefits our refining operations due to the feedstock cost advantage provided by processing heavy crude oil.

In 2015, crude oil runs and refined product output were slightly lower compared with 2014. The unplanned outages and planned turnarounds at both of our
refineries in 2015 had a similar impact on crude oil runs and refined product output as the outage and turnarounds in 2014.

Our crude utilization
represents the percentage of total crude oil processed in our refineries relative to the total capacity. Due to our ability to process a wide slate of crude oils, a feedstock cost advantage is created by processing less expensive crude oil. The
amount of heavy crude oil processed, such as WCS and CDB, is dependent on the quality and quantity of available crude oil with the total input slate being optimized at each refinery to maximize economic benefit. The volume of heavy crude oil
processed in 2015 increased slightly from 2014.

Financial Results



|                                                      |  |      |       |   |  |  |      |  |        |   |  |      |  |  |        | 
|----------------------------------------------------- |  | ---- | ----- | - |  |  | ---- |  | ------ | - |  | ---- |  |  | ------ | 
|($ millions)                                          |  | 2015 |       |   |  |  | 2014 |  |        |   |  | 2013 | 
|                                                      |  |      |       |   | 
|Revenues                                              |  |      | 8,805 |   |  |  |      |  | 12,658 |   |  |      |  |  | 12,706 | 
|Purchased Product                                     |  |      | 7,709 |   |  |  |      |  | 11,767 |   |  |      |  |  | 11,004 | 
|Gross Margin                                          |  |      | 1,096 |   |  |  |      |  | 891    |   |  |      |  |  | 1,702  | 
|Expenses                                              |  |      |       |   |  |  |      |  |        |   |  |      |  |  |        | 
|Operating (1)                                         |  |      | 754   |   |  |  |      |  | 703    |   |  |      |  |  | 538    | 
|(Gain) Loss on Risk Management                        |  |      | (43   | ) |  |  |      |  | (27    | ) |  |      |  |  | 19     | 
|Operating Cash Flow                                   |  |      | 385   |   |  |  |      |  | 215    |   |  |      |  |  | 1,145  | 
|Capital Investment                                    |  |      | 248   |   |  |  |      |  | 163    |   |  |      |  |  | 107    | 
|Operating Cash Flow Net of Related Capital Investment |  |      | 137   |   |  |  |      |  | 52     |   |  |      |  |  | 1,038  | 



|(1) | For all periods presented, we reclassified employee long-term incentive costs from operating expenses to general and administrative costs.
|--- | ------------------------------------------------------------------------------------------------------------------------------------------

Gross Margin

Our realized crack spreads are affected by many factors, such as the variety of feedstock crude oil, refinery configuration and the proportion of
gasoline, distillate and secondary product output; the time lag between the purchase of crude oil feedstock and the processing of that crude oil through our refineries; and the cost of feedstock. Our feedstock costs are valued on a FIFO accounting
basis.

In 2015, the increase in gross margin was primarily due to:

| |  | Improved margins on the sale of our secondary products, such as coke and asphalt, due to lower overall feedstock costs consistent with the decline in WTI;
|- |  | ----------------------------------------------------------------------------------------------------------------------------------------------------------

| |  | Weakening of the Canadian dollar relative to the U.S. dollar; and
|- |  | -----------------------------------------------------------------

| |  | An inventory write-down of $15 million related to our refined product inventory, compared with a write-down of $113 million in 2014.
|- |  | ------------------------------------------------------------------------------------------------------------------------------------



|                    |  |    |  |                                          
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|Cenovus Energy Inc. |  | 23 |  | 2015 Managements Discussion and Analysis



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##### Table of Contents

The increase in gross margin was partially offset by higher heavy crude oil feedstock costs relative to WTI,
consistent with the narrowing of the WTI-WCS differential.

The weakening of the Canadian dollar relative to the U.S. dollar in 2015, compared with
2014, had a positive impact of approximately $143 million on our refining gross margin.

Our refineries do not blend renewable fuels into the
motor fuel products we produce. Consequently, we are obligated to purchase Renewable Identification Numbers (RINs). In 2015, the cost of our RINs was $200 million (2014  $123 million). The increase is consistent with the rise in
the ethanol RINs benchmark price.

Revenues and purchased product from third-party crude oil and natural gas
sales undertaken by the marketing group in 2015 decreased 36 percent and 38 percent, respectively, from 2014, primarily due to a decline in sales prices, partially offset by an increase in purchased crude oil volumes.

Operating Expense

Primary drivers of operating expenses in 2015 were maintenance, labour, utilities and supplies. Reported operating expenses increased compared with 2014
primarily due to weakening of the Canadian dollar relative to the U.S. dollar, partially offset by a decline in utility costs resulting from lower natural gas prices.

Refining and Marketing  Capital Investment



|                    |  |  |      |  |  |  |  |  |      |  |  |  |  |  |      | 
|------------------- |  |  | ---- |  |  |  |  |  | ---- |  |  |  |  |  | ---- | 
|($ millions)        |  |  | 2015 |  |  |  |  |  | 2014 |  |  |  |  |  | 2013 | 
|                    |  |  |      |  | 
|Wood River Refinery |  |  | 162  |  |  |  |  |  | 101  |  |  |  |  |  | 64   | 
|Borger Refinery     |  |  | 78   |  |  |  |  |  | 61   |  |  |  |  |  | 42   | 
|Marketing           |  |  | 8    |  |  |  |  |  | 1    |  |  |  |  |  | 1    | 
|                    |  |  | 248  |  |  |  |  |  | 163  |  |  |  |  |  | 107  | 

Capital expenditures in 2015 focused on the debottlenecking project at Wood River, capital maintenance, projects improving
our refinery reliability and safety, and environmental initiatives. We received permit approval in the first quarter of 2015 for the Wood River debottlenecking project and start-up is anticipated in the third quarter of 2016.

In 2016, we expect to invest between $240 million and $290 million mainly related to the debottlenecking project at Wood River, in addition to
maintenance, reliability and environmental initiatives.

DD&A

Refining and the crude-by-rail terminal assets are depreciated on a straight-line basis over the estimated service life of each component of the
facilities, which range from 3 to 40 years. The service lives of these assets are reviewed on an annual basis. Refining and Marketing DD&A increased by $35 million in 2015, primarily due to the change in the U.S./Canadian dollar exchange rate.

CORPORATE AND ELIMINATIONS

The Corporate and Eliminations segment includes intersegment eliminations relating to transactions that have been recorded at transfer prices based on
current market prices, as well as unrealized intersegment profits in inventory. The gains and losses on risk management represent the unrealized mark-to-market gains and losses related to derivative financial instruments used to mitigate
fluctuations in commodity prices, and the unrealized mark-to-market gains and losses on the long-term power purchase contract and interest rate swaps. In 2015, our risk
management activities resulted in $195 million of unrealized losses (2014  $596 million of unrealized gains). The Corporate and Eliminations segment also includes Cenovus-wide costs for general and administrative, financing costs and research
costs.



|                                     |  |  |        |   |  |  |  |  |       |   |  |  |  |  |       |  
|------------------------------------ |  |  | ------ | - |  |  |  |  | ----- | - |  |  |  |  | ----- | -
|($ millions)                         |  |  | 2015   |   |  |  |  |  | 2014  |   |  |  |  |  | 2013  |  
|                                     |  |  |        |   | 
|General and Administrative (1)       |  |  | 335    |   |  |  |  |  | 379   |   |  |  |  |  | 365   |  
|Finance Costs                        |  |  | 482    |   |  |  |  |  | 445   |   |  |  |  |  | 529   |  
|Interest Income                      |  |  | (28    | ) |  |  |  |  | (33   | ) |  |  |  |  | (96   | )
|Foreign Exchange (Gain) Loss, Net    |  |  | 1,036  |   |  |  |  |  | 411   |   |  |  |  |  | 208   |  
|Research Costs                       |  |  | 27     |   |  |  |  |  | 15    |   |  |  |  |  | 24    |  
|(Gain) Loss on Divestiture of Assets |  |  | (2,392 | ) |  |  |  |  | (156  | ) |  |  |  |  | 1     |  
|Other (Income) Loss, Net             |  |  | 2      |   |  |  |  |  | (4    | ) |  |  |  |  | 2     |  
|                                     |  |  | (538   | ) |  |  |  |  | 1,057 |   |  |  |  |  | 1,033 |  



|(1) | For all periods presented, we reclassified employee long-term incentive costs from operating expenses to general and administrative costs.
|--- | ------------------------------------------------------------------------------------------------------------------------------------------

Expenses

General and Administrative

Primary drivers of our general and administrative expenses in 2015 were workforce, office
rent and information technology costs. General and administrative expenses decreased by $87 million primarily due to workforce reductions and lower employee long-term incentive costs driven by the decline in our share price, offset by



|                    |  |    |  |                                          
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|Cenovus Energy Inc. |  | 24 |  | 2015 Managements Discussion and Analysis



---

##### Table of Contents

severance costs of approximately $43 million. Lower discretionary spending also contributed to the reduction of general and administration costs.

Finance Costs

Finance costs include interest expense on our long-term debt, short-term borrowings and U.S. dollar denominated Partnership Contribution Payable, as well
as the unwinding of the discount on decommissioning liabilities. Finance costs increased $37 million in 2015 compared with 2014 as weakening of the Canadian dollar relative to the U.S. dollar increased interest incurred on our U.S. dollar
denominated debt, partially offset by lower interest incurred on the Partnership Contribution Payable, which was repaid in the first quarter of 2014.

The weighted average interest rate on outstanding debt, excluding the U.S. dollar denominated Partnership Contribution Payable, for 2015 was 5.3 percent
(2014  5.0 percent).

Foreign Exchange



|                                        |  |       |  |  |  |      |  |  |  |     
|--------------------------------------- |  | ----- |  |  |  | ---- |  |  |  | ----
|($ millions)                            |  | 2015  |  |  |  | 2014 |  |  |  | 2013
|                                        |  |       |  |  | 
|Unrealized Foreign Exchange (Gain) Loss |  | 1,097 |  |  |  | 411  |  |  |  | 40  
|Realized Foreign Exchange (Gain) Loss   |  | (61)  |  |  |  | -    |  |  |  | 168 
|                                        |  | 1,036 |  |  |  | 411  |  |  |  | 208 

The majority of unrealized foreign exchange losses stem from translation of our U.S. dollar denominated debt. The
Canadian dollar relative to the U.S. dollar was 16 percent weaker at December 31, 2015 compared with December 31, 2014, resulting in an unrealized loss of $1,097 million.

DD&A

Corporate and Eliminations DD&A includes provisions in respect of corporate assets, such as computer equipment, leasehold improvements and office
furniture. Costs associated with corporate assets are depreciated on a straight-line basis over the estimated service life of the assets, which range from three to 25 years. The service lives of these assets
are reviewed on an annual basis. DD&A in 2015 was $78 million (2014  $83 million).

Income Tax



|                                     |  |       |  |  |  |      |  |  |  |     
|------------------------------------ |  | ----- |  |  |  | ---- |  |  |  | ----
|($ millions)                         |  | 2015  |  |  |  | 2014 |  |  |  | 2013
|                                     |  |       |  |  | 
|Current Tax                          |  |       |  |  |  |      |  |  |  |     
|Canada                               |  | 586   |  |  |  | 94   |  |  |  | 143 
|United States                        |  | (12)  |  |  |  | (2)  |  |  |  | 45  
|Total Current Tax Expense (Recovery) |  | 574   |  |  |  | 92   |  |  |  | 188 
|Deferred Tax Expense (Recovery)      |  | (655) |  |  |  | 359  |  |  |  | 244 
|                                     |  | (81)  |  |  |  | 451  |  |  |  | 432 

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



|                                                                     |  |         |  |  |  |       |  |  |  |      
|-------------------------------------------------------------------- |  | ------- |  |  |  | ----- |  |  |  | -----
|($ millions)                                                         |  | 2015    |  |  |  | 2014  |  |  |  | 2013 
|                                                                     |  |         |  |  | 
|Earnings Before Income Tax                                           |  | 537     |  |  |  | 1,195 |  |  |  | 1,094
|Canadian Statutory Rate                                              |  | 26.1%   |  |  |  | 25.2% |  |  |  | 25.2%
|Expected Income Tax                                                  |  | 140     |  |  |  | 301   |  |  |  | 276  
|Effect of Taxes Resulting From:                                      |  |         |  |  |  |       |  |  |  |      
|Foreign Tax Rate Differential                                        |  | (41)    |  |  |  | (43)  |  |  |  | 87   
|Non-Deductible Stock-Based Compensation                              |  | 7       |  |  |  | 13    |  |  |  | 10   
|Non-Taxable Capital Losses                                           |  | 137     |  |  |  | 74    |  |  |  | 6    
|Unrecognized Capital Losses Arising from Unrealized Foreign Exchange |  | 135     |  |  |  | 50    |  |  |  | 25   
|Adjustments Arising From Prior Year Tax Filings                      |  | (55)    |  |  |  | (16)  |  |  |  | (13) 
|Derecognition (Recognition) of Capital Losses                        |  | (149)   |  |  |  | (9)   |  |  |  | 15   
|Recognition of U.S. Tax Basis                                        |  | (415)   |  |  |  | -     |  |  |  | -    
|Change in Statutory Rate                                             |  | 161     |  |  |  | -     |  |  |  | -    
|Foreign Exchange Gain (Loss) not Included in Net Earnings            |  | -       |  |  |  | (13)  |  |  |  | 19   
|Goodwill Impairment                                                  |  | -       |  |  |  | 125   |  |  |  | -    
|Other                                                                |  | (1)     |  |  |  | (31)  |  |  |  | 7    
|Total Tax                                                            |  | (81)    |  |  |  | 451   |  |  |  | 432  
|Effective Tax Rate                                                   |  | (15.1)% |  |  |  | 37.7% |  |  |  | 39.5%



|                    |  |    |  |                                          
|------------------- |  | -- |  | -----------------------------------------
|Cenovus Energy Inc. |  | 25 |  | 2015 Managements Discussion and Analysis



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##### Table of Contents

Tax interpretations, regulations and legislation in the various jurisdictions in which Cenovus and its
subsidiaries operate are subject to change. We believe that our provision for income taxes is adequate. There are usually a number of tax matters under review and as a result, income taxes are subject to measurement uncertainty. The timing of the
recognition of income and deductions for the purpose of current tax expense is determined by relevant tax legislation.

In 2015, current tax increased
due to the sale of our royalty interest and mineral fee title lands business and the timing of recognition of partnership income for tax purposes. Of the $574 million of current tax, $391 million is attributed to the sale of the royalty interest and
mineral fee title lands business.

We recorded a deferred tax recovery of $415 million arising from an adjustment to the tax basis of our refining
assets. The increase in tax basis was a result of our partner recognizing a taxable gain on its interest in WRB Refining LP (WRB) which, due to an election filed with the U.S. tax authorities, was added to the tax basis of WRBs
assets. Additionally, the deferred tax recovery was due to the timing of recognition of partnership income, unrealized risk management losses, reversal of other temporary differences and current year operating losses. This was partially offset by a
one-time charge of approximately $161 million from the revaluation of the deferred tax liability due to an increase in the Alberta corporate income tax rate from 10 percent to 12 percent on July 1, 2015.

Our effective tax rate is a function of the relationship between total tax expense and the amount of earnings before income taxes. The effective tax rate
differs from the statutory tax rate as it reflects higher U.S. tax rates, permanent differences, adjustments for changes in tax rates and other tax legislation, variations in the estimate of reserves and differences between the provision and the
actual amounts subsequently reported on the tax returns.

Our effective tax rate for 2015 differs from the statutory rate due to an increase in tax
basis of our U.S. assets, and the recognition of the benefit of capital losses, partially offset by non-deductible unrealized foreign exchange losses and a one-time deferred tax expense arising from the
Alberta corporate income tax rate increase.

QUARTERLY RESULTS



Our quarterly results over the last eight
quarters were impacted primarily by rising crude oil production volumes and fluctuations in commodity prices. Crude oil production in the fourth quarter of 2015 was six percent higher than in the fourth quarter of 2013, while and natural gas
production decreased 18 percent from the fourth quarter of 2013. Our average crude oil and natural gas prices in the fourth quarter of 2015 were 53 percent and 13 percent lower compared with the fourth quarter of 2013.



|                                                                   |    |      |         |    |      |  |         |      |  |    |         |  |    |  |         |    |  |  |         |   |  |    |         |  |    |  |         |  |  |  |         |  |  |  |         |  
|------------------------------------------------------------------ | -- | ---- | ------- | -- | ---- |  | ------- | ---- |  | -- | ------- |  | -- |  | ------- | -- |  |  | ------- | - |  | -- | ------- |  | -- |  | ------- |  |  |  | ------- |  |  |  | ------- | -
|($ millions, except per share amounts or whereotherwise indicated) |    | 2015 |         |    | 2014 |  |         | 2013 | 
|                                                                   | Q4 |      |         | Q3 |      |  | Q2      |      |  | Q1 |         |  | Q4 |  |         | Q3 |  |  | Q2      |   |  | Q1 |         |  | Q4 | 
|                                                                   |    |      |         |    |      |  |         |      | 
|Production Volumes                                                 |    |      |         |    |      |  |         |      |  |    |         |  |    |  |         |    |  |  |         |   |  |    |         |  |    |  |         |  |  |  |         |  |  |  |         |  
|Crude Oil (bbls/d)                                                 |    |      | 199,556 |    |      |  | 210,422 |      |  |    | 199,954 |  |    |  | 218,020 |    |  |  | 216,177 |   |  |    | 199,089 |  |    |  | 201,688 |  |  |  | 196,854 |  |  |  | 188,743 |  
|Natural Gas (MMcf/d)                                               |    |      | 424     |    |      |  | 430     |      |  |    | 450     |  |    |  | 462     |    |  |  | 479     |   |  |    | 489     |  |    |  | 507     |  |  |  | 476     |  |  |  | 514     |  
|                                                                   |    |      |         |    |      |  |         |      | 
|Refinery Operations                                                |    |      |         |    |      |  |         |      |  |    |         |  |    |  |         |    |  |  |         |   |  |    |         |  |    |  |         |  |  |  |         |  |  |  |         |  
|Crude Oil Runs (Mbbls/d)                                           |    |      | 405     |    |      |  | 394     |      |  |    | 441     |  |    |  | 439     |    |  |  | 420     |   |  |    | 407     |  |    |  | 466     |  |  |  | 400     |  |  |  | 447     |  
|Refined Products (Mbbls/d)                                         |    |      | 430     |    |      |  | 414     |      |  |    | 462     |  |    |  | 469     |    |  |  | 442     |   |  |    | 429     |  |    |  | 489     |  |  |  | 420     |  |  |  | 469     |  
|                                                                   |    |      |         |    |      |  |         |      | 
|Revenues                                                           |    |      | 2,924   |    |      |  | 3,273   |      |  |    | 3,726   |  |    |  | 3,141   |    |  |  | 4,238   |   |  |    | 4,970   |  |    |  | 5,422   |  |  |  | 5,012   |  |  |  | 4,747   |  
|Operating Cash Flow (1) (2)                                        |    |      | 357     |    |      |  | 602     |      |  |    | 932     |  |    |  | 548     |    |  |  | 537     |   |  |    | 1,156   |  |    |  | 1,305   |  |  |  | 1,181   |  |  |  | 976     |  
|Cash Flow (1)                                                      |    |      | 275     |    |      |  | 444     |      |  |    | 477     |  |    |  | 495     |    |  |  | 401     |   |  |    | 985     |  |    |  | 1,189   |  |  |  | 904     |  |  |  | 835     |  
|Per Share  Diluted                                                |    |      | 0.33    |    |      |  | 0.53    |      |  |    | 0.58    |  |    |  | 0.64    |    |  |  | 0.53    |   |  |    | 1.30    |  |    |  | 1.57    |  |  |  | 1.19    |  |  |  | 1.10    |  
|Operating Earnings (Loss) (1)                                      |    |      | (438    | )  |      |  | (28     | )    |  |    | 151     |  |    |  | (88     | )  |  |  | (590    | ) |  |    | 372     |  |    |  | 473     |  |  |  | 378     |  |  |  | 212     |  
|Per Share  Diluted                                                |    |      | (0.53   | )  |      |  | (0.03   | )    |  |    | 0.18    |  |    |  | (0.11   | )  |  |  | (0.78   | ) |  |    | 0.49    |  |    |  | 0.62    |  |  |  | 0.50    |  |  |  | 0.28    |  
|Net Earnings (Loss)                                                |    |      | (641    | )  |      |  | 1,801   |      |  |    | 126     |  |    |  | (668    | )  |  |  | (472    | ) |  |    | 354     |  |    |  | 615     |  |  |  | 247     |  |  |  | (58     | )
|Per Share  Basic                                                  |    |      | (0.77   | )  |      |  | 2.16    |      |  |    | 0.15    |  |    |  | (0.86   | )  |  |  | (0.62   | ) |  |    | 0.47    |  |    |  | 0.81    |  |  |  | 0.33    |  |  |  | (0.08   | )
|Per Share  Diluted                                                |    |      | (0.77   | )  |      |  | 2.16    |      |  |    | 0.15    |  |    |  | (0.86   | )  |  |  | (0.62   | ) |  |    | 0.47    |  |    |  | 0.81    |  |  |  | 0.33    |  |  |  | (0.08   | )
|Capital Investment (3)                                             |    |      | 428     |    |      |  | 400     |      |  |    | 357     |  |    |  | 529     |    |  |  | 786     |   |  |    | 750     |  |    |  | 686     |  |  |  | 829     |  |  |  | 898     |  
|Dividends                                                          |    |      |         |    |      |  |         |      |  |    |         |  |    |  |         |    |  |  |         |   |  |    |         |  |    |  |         |  |  |  |         |  |  |  |         |  
|Cash Dividends                                                     |    |      | 132     |    |      |  | 133     |      |  |    | 125     |  |    |  | 138     |    |  |  | 201     |   |  |    | 201     |  |    |  | 201     |  |  |  | 202     |  |  |  | 183     |  
|In Shares from Treasury                                            |    |      | -       |    |      |  | -       |      |  |    | 98      |  |    |  | 84      |    |  |  | -       |   |  |    | -       |  |    |  | -       |  |  |  | -       |  |  |  | -       |  
|Per Share                                                          |    |      | 0.16    |    |      |  | 0.16    |      |  |    | 0.2662  |  |    |  | 0.2662  |    |  |  | 0.2662  |   |  |    | 0.2662  |  |    |  | 0.2662  |  |  |  | 0.2662  |  |  |  | 0.242   |  



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

|(2) | For all periods presented, we reclassified employee long-term incentive costs from operating expenses to general and administrative costs. There were no
changes to Cash Flow, Operating Earnings or Net Earnings.
|--- | ------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------

|(3) | Includes expenditures on PP&E and E&E assets.
|--- | ---------------------------------------------



|                    |  |    |  |                                          
|------------------- |  | -- |  | -----------------------------------------
|Cenovus Energy Inc. |  | 26 |  | 2015 Managements Discussion and Analysis



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##### Table of Contents

A substantial downward shift in the commodity price environment occurred late in 2014 and continued
throughout 2015. Declining crude oil and refining benchmark prices impacted our fourth quarter financial results. Average Brent and WTI benchmark prices decreased 42 percent in the fourth quarter of 2015 compared with 2014, while the U.S.
dollar average WCS price decreased 53 percent.



LOGO

Fourth Quarter 2015 Results as Compared with the Fourth Quarter 2014

Production Volumes

Total crude oil production declined eight percent primarily due to expected natural declines, the sale of our royalty interest and mineral fee title lands
business, and lower production at Foster Creek. Fourth quarter production was lower compared with 2014. Improved wellbore conformance accelerated production from more mature wells, resulting in faster declines from these wells. To preserve capital,
we chose in 2015 to defer some planned well pads, which combined with the faster declines, contributed to lower fourth quarter volumes. In addition, while well downtime at Foster Creek was within expected ranges for 2015, a higher than average
number of wells were down for servicing in the second half of the year, which further impacted production.

These reductions were partially offset by
higher production at Christina Lake and from successful horizontal well performance in southern Alberta. Third-party royalty interest volumes prior to the divestiture in the third quarter were approximately 6,580 barrels of oil equivalent per day.

Natural gas production in the fourth quarter of 2015 decreased 11 percent due to expected natural declines. We continued to focus capital investment
on high rate of return projects and directed the majority of our total capital investment to our crude oil properties.

Refinery Operations

Crude oil runs decreased and refined product output decreased as the planned turnaround at Wood River in 2015 was larger in scale than in 2014. In
addition, our Wood River refinery experienced unplanned outages in the fourth quarter of 2015.

Revenue

Revenues decreased $1,314 million or 31 percent primarily due to:

| |  | A decline in Refining and Marketing revenues of $743 million largely due a decrease in refined product prices, consistent with a 37 percent decline in average
refined product benchmark prices, and lower refined product output;
|- |  | ----------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------

| |  | Crude oil and natural gas sales volumes decreasing two percent and 11 percent, respectively;
|- |  | --------------------------------------------------------------------------------------------

| |  | Our average crude oil sales price (excluding financial hedging) decreasing 50 percent to $27.63 per barrel; and
|- |  | ---------------------------------------------------------------------------------------------------------------

| |  | A decline in natural gas sales prices (excluding financial hedging) of 29 percent to $2.78 per Mcf.
|- |  | ---------------------------------------------------------------------------------------------------

The decreases to revenues were partially offset by:

| |  | Crude oil royalties decreasing $68 million; and
|- |  | -----------------------------------------------

| |  | An increase in condensate volumes used for blending with our bitumen and heavy oil production.
|- |  | ----------------------------------------------------------------------------------------------

Operating Cash Flow

Operating Cash Flow decreased $180 million, or 34 percent, in the three months ended December 31, 2015 compared with 2014. Upstream Operating Cash
Flow decreased 54 percent due to lower crude oil and natural gas sales prices, and lower crude oil and natural gas sales volumes, partially offset by higher realized risk management gains and lower royalties due to a decrease in crude oil sales
prices.

Refining and Marketing Operating Cash Flow increased by 88 percent to a loss of $40 million. The increase was due to improved margins on
the sale of secondary products, weakening of the Canadian dollar relative to the U.S. dollar, an increase in average market crack spreads and lower refined product inventory impairments, partially offset by lower refined product output and higher
operating costs.

Cash Flow

Cash Flow decreased $126 million or 31 percent in the fourth quarter of 2015 compared with 2014, primarily due to lower Operating Cash Flow, as discussed
above, and an increase in our general and administrative expenses mainly driven by severance costs related to the previously announced workforce reductions, partially offset by a higher current income tax recovery.



|                    |  |    |  |                                          
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|Cenovus Energy Inc. |  | 27 |  | 2015 Managements Discussion and Analysis



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##### Table of Contents

Operating Earnings (Loss)

In the fourth quarter of 2015, our Operating Loss was $438 million compared with a loss of $590 million in the same period in 2014. The improvement was
primarily due to no goodwill impairment in 2015 compared with a goodwill impairment of $497 million in 2014 and a higher income tax recovery, partially offset by lower Cash Flow and an increase in DD&A and exploration expense.

Net Earnings (Loss)

In 2015, our Net Loss included unrealized risk management losses of $26 million and non-operating foreign exchange losses of $212 million in addition to
the Operating Loss discussed above. In 2014, our Net Loss was smaller due to unrealized risk management gains of $416 million, partially offset by a larger Operating Loss and non-operating foreign exchange losses of $186 million.

Capital Investment

Capital investment in the fourth quarter of 2015 was $428 million, a 46 percent decrease from the same period in 2014 primarily due to lower spending in
our Oil Sands and Conventional segments. Capital investment was reduced with the intent of conserving cash and maintaining the strength of our balance sheet in light of the low commodity price environment.

OIL AND GAS RESERVES AND RESOURCES



We retain independent qualified reserves
evaluators (IQREs) to evaluate and prepare reports on 100 percent of our bitumen, heavy oil, light and medium oil, NGLs, natural gas and coal bed methane (CBM) reserves and 100 percent of our bitumen contingent and
prospective resources producible with established technology.

The sale of our royalty interest and mineral fee title lands business had a minimal
effect on our reserves, before royalties. However, our proved and proved plus probable reserves, after royalties, decreased by 27 MMBOE and 39 MMBOE, respectively.

Additional developments in 2015 compared with 2014 include:

| |  | Proved bitumen reserves increasing 11 percent due to Christina Lake proved reserves additions of 234 million barrels from improved reservoir performance
and regulatory approval of the Kirby East area expansion converting probable reserves to proved reserves;
|- |  | ------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------

| |  | Proved plus probable bitumen reserves remaining constant due to improved reservoir performance at Foster Creek and Christina Lake offsetting production;
|- |  | --------------------------------------------------------------------------------------------------------------------------------------------------------

| |  | Heavy oil proved reserves and proved plus probable reserves declining 15 percent and 21 percent, respectively. The decrease was due to the deferral of
drilling at Pelican Lake, the impact of low crude oil prices and the loss of undeveloped reserves at Elk Point due to poor economics;
|- |  | --------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------

| |  | Light and medium oil and NGLs proved reserves decreasing eight percent and proved plus probable reserves decreasing seven percent as production exceeded
additions;
|- |  | -------------------------------------------------------------------------------------------------------------------------------------------------------------------

| |  | Natural gas proved reserves declining nine percent and proved plus probable reserves decreasing 10 percent as additions and improved performance were more
than offset by reductions due to production; and
|- |  | -----------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------

| |  | Bitumen best estimate economic contingent resources remaining flat at 9.3 billion barrels and bitumen best estimate prospective resources decreasing slightly
to 7.4 billion barrels. Factors impacting the results include:
|- |  | ----------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------

| | ¡ |  | Reduced stratigraphic drilling yielding negligible contingent resources revisions; and
| | - |  | --------------------------------------------------------------------------------------

| | ¡ |  | Minor mapping changes plus small lease expiries slightly reducing prospective resources.
| | - |  | ----------------------------------------------------------------------------------------

The reserves and resources data that follows is presented as at December 31, 2015 using McDaniel & Associates Consultants Ltd.s
(McDaniels) January 1, 2016 forecast prices and inflation. Comparative information as at December 31, 2014 uses McDaniels January 1, 2015 forecast prices and inflation.

Reserves



|                     |  |                  |       |  |      |  |                    |  |  |      |  |                                      |      |  |  |  |                         |      |  |  |      |  |     |  |  |      |     |  |      |  |  |  |     |  |  |  |       | 
|-------------------- |  | ---------------- | ----- |  | ---- |  | ------------------ |  |  | ---- |  | ------------------------------------ | ---- |  |  |  | ----------------------- | ---- |  |  | ---- |  | --- |  |  | ---- | --- |  | ---- |  |  |  | --- |  |  |  | ----- | 
|As at December 31,   |  | Bitumen
(MMbbls) |       |  |      |  | Heavy Oil
(MMbbls) |  |  |      |  | Light and Medium
Oil & NGLs (MMbbls) |      |  |  |  | Natural Gas
& CBM (Bcf) |     
|(before royalties)   |  | 2015             |       |  | 2014 |  |                    |  |  | 2015 |  |                                      | 2014 |  |  |  |                         | 2015 |  |  | 2014 |  |     |  |  | 2015 |     |  | 2014 | 
|                     |  |                  |       |  |      |  |                    |  |  |      | 
|Proved               |  |                  | 2,183 |  |      |  | 1,970              |  |  |      |  |                                      | 133  |  |  |  | 156                     |      |  |  |      |  | 110 |  |  |      | 120 |  |      |  |  |  | 721 |  |  |  | 796   | 
|Probable             |  |                  | 1,115 |  |      |  | 1,330              |  |  |      |  |                                      | 87   |  |  |  | 123                     |      |  |  |      |  | 44  |  |  |      | 46  |  |      |  |  |  | 232 |  |  |  | 260   | 
|Proved plus Probable |  |                  | 3,298 |  |      |  | 3,300              |  |  |      |  |                                      | 220  |  |  |  | 279                     |      |  |  |      |  | 154 |  |  |      | 166 |  |      |  |  |  | 953 |  |  |  | 1,056 | 
|                     |  |                  |       |  |      |  |                    |  |  |      |  |                                      |      |  |  |  |                         |      |  |  |      |  |     |  |  |      |     |  |      |  |  |  |     |  |  |  |       | 



|                    |  |    |  |                                          
|------------------- |  | -- |  | -----------------------------------------
|Cenovus Energy Inc. |  | 28 |  | 2015 Managements Discussion and Analysis



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##### Table of Contents

Reconciliation of Proved Reserves



|                                                                                                                                       |  |                  |       |  |  |  |                    |  |       |  |  |                                   |  |  |      |  |                         |  |  |  |       | 
|-------------------------------------------------------------------------------------------------------------------------------------- |  | ---------------- | ----- |  |  |  | ------------------ |  | ----- |  |  | --------------------------------- |  |  | ---- |  | ----------------------- |  |  |  | ----- | 
|(before royalties)                                                                                                                     |  | Bitumen
(MMbbls) |       |  |  |  | Heavy Oil (MMbbls) |  |       |  |  | Light &Medium Oil & NGLs
(MMbbls) |  |  |      |  | Natural Gas
& CBM (Bcf) | 
|                                                                                                                                       |  |                  |       |  |  |  |                   
|December 31, 2014                                                                                                                      |  |                  | 1,970 |  |  |  |                    |  | 156   |  |  |                                   |  |  | 120  |  |                         |  |  |  | 796   | 
|Extensions and Improved Recovery                                                                                                       |  |                  | 188   |  |  |  |                    |  | -     |  |  |                                   |  |  | 1    |  |                         |  |  |  | 8     | 
|Technical Revisions                                                                                                                    |  |                  | 76    |  |  |  |                    |  | (10)  |  |  |                                   |  |  | 1    |  |                         |  |  |  | 79    | 
|Economic Factors                                                                                                                       |  |                  | -     |  |  |  |                    |  | -     |  |  |                                   |  |  | (1)  |  |                         |  |  |  | (1)   | 
|Production (1)                                                                                                                         |  |                  | (51)  |  |  |  |                    |  | (13)  |  |  |                                   |  |  | (11) |  |                         |  |  |  | (161) | 
|December 31, 2015                                                                                                                      |  |                  | 2,183 |  |  |  |                    |  | 133   |  |  |                                   |  |  | 110  |  |                         |  |  |  | 721   | 
|Year Over Year Change                                                                                                                  |  |                  | 213   |  |  |  |                    |  | (23)  |  |  |                                   |  |  | (10) |  |                         |  |  |  | (75)  | 
|                                                                                                                                       |  |                  | 11%   |  |  |  |                    |  | (15)% |  |  |                                   |  |  | (8)% |  |                         |  |  |  | (9)%  | 
|                                                                                                                                      
|(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)                                                                                                                     |  | Bitumen
(MMbbls) |       |  |  |  | Heavy Oil (MMbbls) |  |       |  |  | Light &Medium Oil & NGLs
(MMbbls) |  |  |      |  | Natural Gas
& CBM
(Bcf) | 
|                                                                                                                                       |  |                  |       |  |  |  |                   
|December 31, 2014                                                                                                                      |  |                  | 1,330 |  |  |  |                    |  | 123   |  |  |                                   |  |  | 46   |  |                         |  |  |  | 260   | 
|Extensions and Improved Recovery                                                                                                       |  |                  | -     |  |  |  |                    |  | -     |  |  |                                   |  |  | 1    |  |                         |  |  |  | 7     | 
|Technical Revisions                                                                                                                    |  |                  | (215) |  |  |  |                    |  | (36)  |  |  |                                   |  |  | (4)  |  |                         |  |  |  | (36)  | 
|Economic Factors                                                                                                                       |  |                  | -     |  |  |  |                    |  | -     |  |  |                                   |  |  | 1    |  |                         |  |  |  | 1     | 
|December 31, 2015                                                                                                                      |  |                  | 1,115 |  |  |  |                    |  | 87    |  |  |                                   |  |  | 44   |  |                         |  |  |  | 232   | 
|Year Over Year Change                                                                                                                  |  |                  | (215) |  |  |  |                    |  | (36)  |  |  |                                   |  |  | (2)  |  |                         |  |  |  | (28)  | 
|                                                                                                                                       |  |                  | (16)% |  |  |  |                    |  | (29)% |  |  |                                   |  |  | (4)% |  |                         |  |  |  | (11)% | 

Economic Contingent Resources and Prospective Resources



|                                        |  |         |     |  |      |  |     | 
|--------------------------------------- |  | ------- | --- |  | ---- |  | --- | 
|As at December 31,                      |  | Bitumen |    
|(billions of barrels, before royalties) |  | 2015    |     |  | 2014 | 
|                                        |  |        
|Economic Contingent Resources (1)       |  |         |     |  |      |  |     | 
|Best Estimate                           |  |         | 9.3 |  |      |  | 9.3 | 
|Prospective Resources (1) (2)           |  |         |     |  |      |  |     | 
|Best Estimate                           |  |         | 7.4 |  |      |  | 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 uncertainty that any portion of the prospective resources will be discovered. If discovered, there is no certainty that it will be commercially viable to produce any portion of the prospective resources.
Prospective resources are not screened for economic viability.
|--- | -----------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------

Additional information with respect to the evaluation and reporting
of our reserves in accordance with National Instrument 51-101, Standards of Disclosure for Oil and Gas Activities (NI 51-101), and material risks and uncertainties associated with estimates of reserves and contingent and
prospective resources is contained in our AIF for the year ended December 31, 2015. Further information with respect to contingent and prospective resources including project descriptions, significant factors relevant to the resource estimates,
and contingencies which prevent the classification of contingent resources as reserves is contained in our supplemental Statement of Contingent and Prospective Resources for the year ended December 31, 2015 (Resources Statement).
Both our AIF and Resources Statement are available on SEDAR at sedar.com, EDGAR at sec.gov and on our website at cenovus.com.

LIQUIDITY AND CAPITAL RESOURCES





|                                                                                   |  |      |       |   |  |  |      |  |        |   |  |      |  |  |        |  
|---------------------------------------------------------------------------------- |  | ---- | ----- | - |  |  | ---- |  | ------ | - |  | ---- |  |  | ------ | -
|($ millions)                                                                       |  | 2015 |       |   |  |  | 2014 |  |        |   |  | 2013 | 
|Net Cash From (Used In)                                                            |  |      |       |   |  |  |      |  |        |   |  |      |  |  |        |  
|Operating Activities                                                               |  |      | 1,474 |   |  |  |      |  | 3,526  |   |  |      |  |  | 3,539  |  
|Investing Activities                                                               |  |      | 888   |   |  |  |      |  | (4,350 | ) |  |      |  |  | (1,519 | )
|Net Cash Provided (Used) Before Financing Activities                               |  |      | 2,362 |   |  |  |      |  | (824   | ) |  |      |  |  | 2,020  |  
|Financing Activities                                                               |  |      | 894   |   |  |  |      |  | (797   | ) |  |      |  |  | (726   | )
|Foreign Exchange Gain (Loss) on Cash and Cash Equivalents Held in Foreign Currency |  |      | (34   | ) |  |  |      |  | 52     |   |  |      |  |  | (2     | )
|Increase (Decrease) in Cash and Cash Equivalents                                   |  |      | 3,222 |   |  |  |      |  | (1,569 | ) |  |      |  |  | 1,292  |  
|                                                                                   |  |      |       |   | 
|As at December 31,                                                                 |  | 2015 |       |   |  |  | 2014 |  |        |   |  | 2013 | 
|                                                                                   |  |      |       |   | 
|Cash and Cash Equivalents                                                          |  |      | 4,105 |   |  |  |      |  | 883    |   |  |      |  |  | 2,452  |  
|Committed and Undrawn Credit Facilities                                            |  |      | 4,000 |   |  |  |      |  | 3,000  |   |  |      |  |  | 3,000  |  



|                    |  |    |  |                                          
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|Cenovus Energy Inc. |  | 29 |  | 2015 Managements Discussion and Analysis



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##### Table of Contents

Operating Activities

Cash from operating activities decreased in 2015 mainly due to lower Cash Flow, as discussed in the Financial Results section of this MD&A. Excluding
risk management assets and liabilities, working capital was $4,337 million at December 31, 2015 compared with $772 million at December 31, 2014. Working capital increased due to cash proceeds received on the sale of our royalty
interest and mineral fee title lands business in July of 2015 and the common share issuance in the first quarter of 2015.

We anticipate that we will
continue to meet our payment obligations as they come due.

Investing Activities

Cash from investing activities in 2015 was primarily due to the divestiture of our royalty interest and mineral fee title lands business in 2015. In 2014,
cash used by investing activities related to the repayment of the US$1.4 billion Partnership Contribution Payable. Lower capital expenditures in 2015 also contributed to the increase in cash from investing activities.

Financing Activities

Cash provided by financing activities increased in 2015 primarily due to net proceeds from our common share issuance and cash savings from our DRIP. We
issued 67.5 million common shares at a price of $22.25 per share for net proceeds of $1.4 billion in the first quarter of 2015. We plan to use the net proceeds to partially fund our capital expenditure program for 2016 and for general corporate
purposes.

In 2015, we paid dividends of $0.8524 per share or $710 million, of which $528 million was paid in cash and $182 million was
reinvested in common shares through our DRIP (2014  $1.0648 per share or $805 million paid in cash). The declaration of dividends is at the sole discretion of the Board and is considered quarterly.

Our long-term debt at December 31, 2015 was $6,525 million (December 31, 2014  $5,458 million) with no principal payments due until
October 2019 (US$1.3 billion). The principal amount of long-term debt outstanding in U.S. dollars has remained unchanged since August 2012. The $1,067 million increase in long-term debt is due to weakening of the Canadian dollar relative to the
U.S. dollar.

As at December 31, 2015, we were in compliance with all of the terms of our debt agreements.

Available Sources of Liquidity

We expect cash flow from our crude oil, natural gas and refining operations to fund a portion of our cash requirements. Any potential shortfalls may be
required to be funded through prudent use of our balance sheet capacity, management of our asset portfolio and other corporate and financial opportunities that may be available to us.

The following sources of liquidity are available at December 31, 2015:



|                                   |  |        |       |  |  |  |      |  |                | 
|---------------------------------- |  | ------ | ----- |  |  |  | ---- |  | -------------- | 
|($ millions)                       |  | Amount |       |  |  |  | Term | 
|                                   |  |        |      
|Cash and Cash Equivalents          |  |        | 4,105 |  |  |  |      |  | Not applicable | 
|Committed Credit Facility          |  |        | 1,000 |  |  |  |      |  | November 2017  | 
|Committed Credit Facility          |  |        | 3,000 |  |  |  |      |  | November 2019  | 
|U.S. Base Shelf Prospectus (1)     |  | US$    | 2,000 |  |  |  |      |  | July 2016      | 
|Canadian Base Shelf Prospectus (1) |  |        | 1,500 |  |  |  |      |  | July 2016      | 



|(1) | Availability is subject to market conditions.
|--- | ---------------------------------------------

Committed Credit
Facility

In 2015, Cenovus renegotiated its existing $3.0 billion committed credit facility, extending the maturity date to
November 30, 2019. In addition, a new $1.0 billion tranche was established under the same facility, maturing on November 30, 2017. As at December 31, 2015, we had $4.0 billion available on our committed credit facility.

Under the committed credit facility, Cenovus is required to maintain a debt to capitalization ratio not to exceed 65 percent; we are well below this
limit.

U.S. and Canadian Base Shelf Prospectuses

On June 24, 2014, we filed a U.S. base shelf prospectus for unsecured notes in the amount of US$2.0 billion, which replaced the U.S. base shelf
prospectus dated June 6, 2012, as amended May 9, 2013. The U.S. base shelf prospectus allows for the issuance of debt securities in U.S. dollars or other currencies from time to time in one or more offerings. Terms of the notes, including,
but not limited to, interest at either fixed or floating rates and maturity dates will be determined at the date of issue.

On June 25, 2014, we
filed a Canadian base shelf prospectus for unsecured medium term notes in the amount of $1.5 billion, which replaced the Canadian base shelf prospectus dated May 24, 2012. The Canadian base shelf prospectus allows for the issuance of medium
term notes in Canadian dollars or other currencies from time to time in one or more offerings. Terms of the notes, including, but not limited to, interest at either fixed or floating rates and maturity dates will be determined at the date of issue.



|                    |  |    |  |                                          
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|Cenovus Energy Inc. |  | 30 |  | 2015 Managements Discussion and Analysis



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##### Table of Contents

As at December 31, 2015, no notes were issued under the existing U.S. or Canadian base shelf prospectuses.

It is our intention to file a new prospectus prior to the maturity of the existing prospectuses.

Financial Metrics

We monitor our capital structure and financing requirements using, among other things, non-GAAP financial metrics consisting of Debt to Capitalization and
Debt to Adjusted EBITDA. We define our non-GAAP measure of Debt as short-term borrowings and the current and long-term portions of long-term debt. We define Capitalization as Debt plus Shareholders Equity. We define Adjusted EBITDA as earnings
before finance costs, interest income, income tax expense, DD&A, goodwill and asset impairments, unrealized gains (losses) on risk management, foreign exchange gains (losses), gains (losses) on divestiture of assets and other income (loss), net,
calculated on a trailing twelve-month basis. These metrics are used to steward our overall debt position and as measures of our overall financial strength.

Over the long-term, we target a Debt to Capitalization ratio of between 30 percent to 40 percent and a Debt to Adjusted EBITDA of between 1.0 times
to 2.0 times. At different points within the economic cycle, we expect these ratios may periodically be outside of the target range.

Debt to
Capitalization remained consistent as higher debt balances from the weakening of the Canadian dollar relative to the U.S. dollar were offset by the increase in Shareholders Equity as a result of the common share issuance. Debt to Adjusted
EBITDA increased from higher debt balances due to foreign exchange and lower Adjusted EBITDA primarily due to a decline in Cash Flow as a result of low commodity prices.

Debt to Capitalization and Net Debt to Capitalization are calculated as follows:



|                           |  |      |        |  |  |  |      |  |        |  |  |      |  |  |        | 
|-------------------------- |  | ---- | ------ |  |  |  | ---- |  | ------ |  |  | ---- |  |  | ------ | 
|As at December 31,         |  | 2015 |        |  |  |  | 2014 |  |        |  |  | 2013 | 
|                           |  |      |        |  | 
|Debt                       |  |      | 6,525  |  |  |  |      |  | 5,458  |  |  |      |  |  | 4,997  | 
|Shareholders Equity       |  |      | 12,391 |  |  |  |      |  | 10,186 |  |  |      |  |  | 9,946  | 
|Capitalization             |  |      | 18,916 |  |  |  |      |  | 15,644 |  |  |      |  |  | 14,943 | 
|                           |  |      |        |  | 
|Debt to Capitalization     |  |      | 34%    |  |  |  |      |  | 35%    |  |  |      |  |  | 33%    | 
|                           |  |      |        |  | 
|Net Debt (1)               |  |      | 2,420  |  |  |  |      |  | 4,575  |  |  |      |  |  | 4,070  | 
|Shareholders Equity       |  |      | 12,391 |  |  |  |      |  | 10,186 |  |  |      |  |  | 9,946  | 
|Capitalization             |  |      | 14,811 |  |  |  |      |  | 14,761 |  |  |      |  |  | 14,016 | 
|                           |  |      |        |  | 
|Net Debt to Capitalization |  |      | 16%    |  |  |  |      |  | 31%    |  |  |      |  |  | 29%    | 



|(1) | Net Debt is defined as Debt and the current and long-term portions of the Partnership Contribution Payable, net of cash and cash equivalents.
|--- | ---------------------------------------------------------------------------------------------------------------------------------------------

The following is a reconciliation of Adjusted EBITDA, and the calculations of Debt to Adjusted EBITDA and Net Debt to Adjusted
EBITDA:



|                                          |  |      |         |  |  |  |      |  |       |  |  |      |  |  |       | 
|----------------------------------------- |  | ---- | ------- |  |  |  | ---- |  | ----- |  |  | ---- |  |  | ----- | 
|As at December 31,                        |  | 2015 |         |  |  |  | 2014 |  |       |  |  | 2013 | 
|                                          |  |      |         |  | 
|Debt                                      |  |      | 6,525   |  |  |  |      |  | 5,458 |  |  |      |  |  | 4,997 | 
|Net Debt (1)                              |  |      | 2,420   |  |  |  |      |  | 4,575 |  |  |      |  |  | 4,070 | 
|                                          |  |      |         |  | 
|Adjusted EBITDA                           |  |      |         |  |  |  |      |  |       |  |  |      |  |  |       | 
|Net Earnings                              |  |      | 618     |  |  |  |      |  | 744   |  |  |      |  |  | 662   | 
|Add (Deduct):                             |  |      |         |  |  |  |      |  |       |  |  |      |  |  |       | 
|Finance Costs                             |  |      | 482     |  |  |  |      |  | 445   |  |  |      |  |  | 529   | 
|Interest Income                           |  |      | (28)    |  |  |  |      |  | (33)  |  |  |      |  |  | (96)  | 
|Income Tax Expense                        |  |      | (81)    |  |  |  |      |  | 451   |  |  |      |  |  | 432   | 
|DD&A                                      |  |      | 2,114   |  |  |  |      |  | 1,946 |  |  |      |  |  | 1,833 | 
|Goodwill Impairment                       |  |      | -       |  |  |  |      |  | 497   |  |  |      |  |  | -     | 
|E&E Impairment                            |  |      | 138     |  |  |  |      |  | 86    |  |  |      |  |  | 50    | 
|Unrealized (Gain) Loss on Risk Management |  |      | 195     |  |  |  |      |  | (596) |  |  |      |  |  | 415   | 
|Foreign Exchange (Gain) Loss, Net         |  |      | 1,036   |  |  |  |      |  | 411   |  |  |      |  |  | 208   | 
|(Gain) Loss on Divestiture of Assets      |  |      | (2,392) |  |  |  |      |  | (156) |  |  |      |  |  | 1     | 
|Other (Income) Loss, Net                  |  |      | 2       |  |  |  |      |  | (4)   |  |  |      |  |  | 2     | 
|                                          |  |      | 2,084   |  |  |  |      |  | 3,791 |  |  |      |  |  | 4,036 | 
|                                          |  |      |         |  | 
|Debt to Adjusted EBITDA                   |  |      | 3.1x    |  |  |  |      |  | 1.4x  |  |  |      |  |  | 1.2x  | 
|                                          |  |      |         |  | 
|Net Debt to Adjusted EBITDA               |  |      | 1.2x    |  |  |  |      |  | 1.2x  |  |  |      |  |  | 1.0x  | 



|(1) | Net Debt is defined as Debt and the current and long-term portions of the Partnership Contribution Payable, net of cash and cash equivalents.
|--- | ---------------------------------------------------------------------------------------------------------------------------------------------

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



|                    |  |    |  |                                          
|------------------- |  | -- |  | -----------------------------------------
|Cenovus Energy Inc. |  | 31 |  | 2015 Managements Discussion and Analysis



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##### Table of Contents

Share Capital and Stock-Based Compensation Plans

As at December 31, 2015, there were approximately 833 million common shares outstanding (December 31, 2014  757 million common shares). Cenovus
issued 76.2 million common shares in 2015, including 8.7 million shares issued under the DRIP and 67.5 million shares issued related to the common share issuance in the first quarter of 2015.

The DRIP permits shareholders to reinvest their dividends into additional common shares. At the discretion of Cenovus, the additional common shares may be
issued from treasury or purchased on the market. In the first half of 2015, participants in our DRIP were issued shares from treasury at a three percent discount to the average market price, as defined in the DRIP; this resulted in cash savings of
$177 million. For the second half of the year, common shares acquired by the DRIP were purchased on the open market. Refer to cenovus.com for more details.

As part of our long-term incentive program, Cenovus has an employee Stock Option Plan as well as Performance Share Unit (PSU) Plan, a
Restricted Share Unit (RSU) Plan and two Deferred Share Unit (DSU) Plans. Refer to Note 27 of the Consolidated Financial Statements for more details on our Stock Option Plan and our PSU, RSU and DSU Plans.



|                                     |  |                               |         |  |  |  |                               |  |        | 
|------------------------------------ |  | ----------------------------- | ------- |  |  |  | ----------------------------- |  | ------ | 
|As at January 31, 2016               |  | Units
Outstanding
(thousands) |         |  |  |  | Units
Exercisable
(thousands) | 
|                                     |  |                               |        
|Common Shares                        |  |                               | 833,290 |  |  |  |                               |  | N/A    | 
|Stock Options                        |  |                               | 43,660  |  |  |  |                               |  | 25,892 | 
|Other Stock-Based Compensation Plans |  |                               | 10,257  |  |  |  |                               |  | 1,488  | 

Contractual Obligations and Commitments

We have entered into various commitments in the normal course of operations primarily related to demand charges on firm transportation agreements and
operating leases on buildings. In addition, we have commitments related to our risk management program and an obligation to fund our defined benefit pension and other post-employment benefit plans.

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



|                                   |  |                       |       |  |  |  |      |  |       |  |  |      |  |  |       |  |      |  |  |  |       |      |  |  |  |  |            |  |  |  |  |       |        |  |  |  |  |  |        | 
|---------------------------------- |  | --------------------- | ----- |  |  |  | ---- |  | ----- |  |  | ---- |  |  | ----- |  | ---- |  |  |  | ----- | ---- |  |  |  |  | ---------- |  |  |  |  | ----- | ------ |  |  |  |  |  | ------ | 
|                                   |  | Expected Payment Date |      
|($ millions)                       |  | 2016                  |       |  |  |  | 2017 |  |       |  |  | 2018 |  |  |       |  | 2019 |  |  |  |       | 2020 |  |  |  |  | Thereafter |  |  |  |  | Total |       
|                                   |  |                       |       |  |  |  |      |  |       |  |  |      | 
|Operating                          |  |                       |       |  |  |  |      |  |       |  |  |      |  |  |       |  |      |  |  |  |       |      |  |  |  |  |            |  |  |  |  |       |        |  |  |  |  |  |        | 
|Transportation and Storage (1)     |  |                       | 702   |  |  |  |      |  | 715   |  |  |      |  |  | 780   |  |      |  |  |  | 774   |      |  |  |  |  | 901        |  |  |  |  |       | 23,537 |  |  |  |  |  | 27,409 | 
|Operating Leases (Building Leases) |  |                       | 116   |  |  |  |      |  | 120   |  |  |      |  |  | 156   |  |      |  |  |  | 153   |      |  |  |  |  | 151        |  |  |  |  |       | 2,647  |  |  |  |  |  | 3,343  | 
|Product Purchases                  |  |                       | 84    |  |  |  |      |  | 3     |  |  |      |  |  | -     |  |      |  |  |  | -     |      |  |  |  |  | -          |  |  |  |  |       | -      |  |  |  |  |  | 87     | 
|Other Long-term Commitments        |  |                       | 45    |  |  |  |      |  | 31    |  |  |      |  |  | 24    |  |      |  |  |  | 26    |      |  |  |  |  | 15         |  |  |  |  |       | 125    |  |  |  |  |  | 266    | 
|Interest on Long-term Debt         |  |                       | 349   |  |  |  |      |  | 349   |  |  |      |  |  | 349   |  |      |  |  |  | 349   |      |  |  |  |  | 247        |  |  |  |  |       | 4,193  |  |  |  |  |  | 5,836  | 
|Decommissioning Liabilities        |  |                       | 34    |  |  |  |      |  | 28    |  |  |      |  |  | 28    |  |      |  |  |  | 30    |      |  |  |  |  | 36         |  |  |  |  |       | 6,509  |  |  |  |  |  | 6,665  | 
|Total Operating                    |  |                       | 1,330 |  |  |  |      |  | 1,246 |  |  |      |  |  | 1,337 |  |      |  |  |  | 1,332 |      |  |  |  |  | 1,350      |  |  |  |  |       | 37,011 |  |  |  |  |  | 43,606 | 
|Investing                          |  |                       |       |  |  |  |      |  |       |  |  |      |  |  |       |  |      |  |  |  |       |      |  |  |  |  |            |  |  |  |  |       |        |  |  |  |  |  |        | 
|Capital Commitments                |  |                       | 61    |  |  |  |      |  | 14    |  |  |      |  |  | 4     |  |      |  |  |  | -     |      |  |  |  |  | -          |  |  |  |  |       | -      |  |  |  |  |  | 79     | 
|Total Investing                    |  |                       | 61    |  |  |  |      |  | 14    |  |  |      |  |  | 4     |  |      |  |  |  | -     |      |  |  |  |  | -          |  |  |  |  |       | -      |  |  |  |  |  | 79     | 
|Financing                          |  |                       |       |  |  |  |      |  |       |  |  |      |  |  |       |  |      |  |  |  |       |      |  |  |  |  |            |  |  |  |  |       |        |  |  |  |  |  |        | 
|Long-term Debt (principal only)    |  |                       | -     |  |  |  |      |  | -     |  |  |      |  |  | -     |  |      |  |  |  | 1,799 |      |  |  |  |  | -          |  |  |  |  |       | 4,775  |  |  |  |  |  | 6,574  | 
|Total Financing                    |  |                       | -     |  |  |  |      |  | -     |  |  |      |  |  | -     |  |      |  |  |  | 1,799 |      |  |  |  |  | -          |  |  |  |  |       | 4,775  |  |  |  |  |  | 6,574  | 
|Total Payments(2)                  |  |                       | 1,391 |  |  |  |      |  | 1,260 |  |  |      |  |  | 1,341 |  |      |  |  |  | 3,131 |      |  |  |  |  | 1,350      |  |  |  |  |       | 41,786 |  |  |  |  |  | 50,259 | 
|                                   |  |                       |       |  |  |  |      |  |       |  |  |      | 
|Fixed Price Product Sales          |  |                       | 55    |  |  |  |      |  | 3     |  |  |      |  |  | -     |  |      |  |  |  | -     |      |  |  |  |  | -          |  |  |  |  |       | -      |  |  |  |  |  | 58     | 



|(1) | Certain transportation commitments included are subject to regulatory approval.
|--- | -------------------------------------------------------------------------------

|(2) | Contracts on behalf of FCCL Partnership (FCCL) and WRB are reflected at our 50 percent interest.
|--- | --------------------------------------------------------------------------------------------------

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

Commitments for various firm pipeline transportation agreements were $27 billion, consistent with 2014. Reduced obligations from changes to
TransCanadas proposed Energy East pipeline were offset by increases to our U.S. dollar commitments due to the weakening of the Canadian dollar relative to the U.S. dollar, and higher costs and tolls on existing commitments.



|                    |  |    |  |                                          
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|Cenovus Energy Inc. |  | 32 |  | 2015 Managements Discussion and Analysis



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##### Table of Contents

We continue to focus on near- and mid-term strategies to broaden market access for our crude oil production,
as illustrated by our purchase of a crude-by-rail terminal and exporting crude oil from the U.S. Gulf Coast. We continue to support proposed new pipeline projects that would connect us to new markets in the U.S. and globally, moving our crude oil
production to market by rail, assessing options to maximize the value of our crude oil by offering a wider range of products, including existing dilbit blends, under-blended bitumen or dry bitumen, and potential expansions of our refining capacity
as our production grows.

As at December 31, 2015, Cenovus remained a party to long-term, fixed price, physical contracts for natural gas with a
current delivery of approximately 29 MMcf per day, with varying terms and volumes through 2017. The total volume to be delivered within the terms of these contracts is 11 Bcf of natural gas, at a weighted average price of $4.94 per Mcf.

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

Legal Proceedings

We are involved in a limited number of legal claims associated with the normal course of operations and we believe we have made adequate provisions for
such claims. There are no individually or collectively significant claims.

Related Party Transactions

Cenovus did not enter into any related party transactions during the years ended December 31, 2015 or 2014, except for our key management
compensation. A summary of key management compensation can be found in the notes to the Consolidated Financial Statements.

RISK MANAGEMENT



Cenovus is exposed to a number of risks
through the pursuit of our strategic objectives. Some of these risks impact the oil and gas industry as a whole and others are unique to our operations. Our Enterprise Risk Management (ERM) program drives the identification, measurement,
prioritization, and management of risk across Cenovus.

Risk Governance



|                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                           |  |     
|------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------ |  | ----
|The ERM Policy, approved by our Board, outlines our risk management principles and expectations, as well as the roles and
responsibilities of all staff. Building on the ERM Policy, we have established Risk Management Practices, a Risk Management Framework and Risk Assessment Tools. Our Risk Management Framework contains the key attributes recommended by the
International Standards Organization (ISO) in its ISO 31000 Risk Management Principles and Guidelines. The results of our ERM program are documented in an Annual Risk Report presented to the Board as well as
through quarterly updates.  Risk
Assessment  All risks are assessed for their potential
impact on the achievement of Cenovuss strategic objectives as well as their likelihood of occurring. Risks are analyzed through the use of a Risk Matrix and other standardized risk assessment tools. |  | LOGO

Using a Risk Matrix, each risk is classified on a continuum ranging from Low to Extreme. Risks are
first evaluated on an inherent basis, without considering the presence of controls or mitigating measures. Risks are then re-evaluated based on their residual risk ranking, reflecting the exposure that remains after implemented mitigation and
control measures are considered.

Management determines if additional risk treatment is required based on the residual risk ranking. There are
prescribed actions for escalating and communicating risk to the right decision makers.

Significant Risk Factors

The following discussion describes the financial, operations and regulatory risks relating to Cenovus and our operations. A description of
the risk factors and uncertainties can be found in the Advisory and a full discussion of the material risk factors affecting Cenovus can be found in our AIF for the year ended December 31, 2015.

Financial Risk

Financial risk is the risk of loss or lost opportunity resulting from financial management and market conditions. From time to time, Management may enter
into contracts to mitigate risk associated with fluctuations of commodity prices, interest rates and foreign exchange rates.



|                    |  |    |  |                                          
|------------------- |  | -- |  | -----------------------------------------
|Cenovus Energy Inc. |  | 33 |  | 2015 Managements Discussion and Analysis



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##### Table of Contents

Commodity Prices

Fluctuations in commodity prices and refined product prices impacts our financial condition, results of operations, cash flows, growth, access to capital
and cost of borrowing.

Crude oil and natural gas prices are impacted by a number of factors including global and regional supply and demand and
economic conditions, the actions of OPEC, government regulation, political stability, transportation constraints, weather conditions and availability of alternative fuels, all of which are beyond our control and can result in a high degree of price
volatility. Changing prices will affect the revenues generated by the sale of our production. Our financial performance is also affected by price differentials since our upstream production differs in quality and location from underlying benchmark
commodity prices quoted on financial exchanges.

Commodity prices began to decline in the fourth quarter of 2014 and have remained low, resulting in
an impairment to the carrying value of some of our assets. If crude oil and natural gas prices continue to decline significantly and remain at low levels for an extended period of time, future capital spending could be reduced causing projects to be
impaired, delayed or cancelled, and production could be curtailed or suspended, among other impacts.

Refined product prices are affected by several
factors including global supply and demand for refined products, weather conditions, and planned and unplanned refinery maintenance, all of which are beyond our control and can result in a high degree of price volatility. The financial performance
of our refining operations is also impacted by margin volatility due to fluctuations in the supply and demand for refined products, crude oil costs and seasonal factors when production changes to match seasonal demand.

We partially mitigate our exposure to commodity price risk through the integration of our business, financial instruments, physical contracts and market
access commitments. Financial instruments undertaken within our refining business by the operator, Phillips 66, are primarily for purchased product. For details of our financial instruments, including classification, assumptions made in the
calculation of fair value and additional discussion on exposure of risks and the management of those risks, see Notes 3 and 32 to the Consolidated Financial Statements.

Impact of Financial Risk Management Activities



|                                          |  |          |      |   |            |  |      |       |  |  |      |   |          |  |  |            |     |   |       |  |      |   |  |  |      |  
|----------------------------------------- |  | -------- | ---- | - | ---------- |  | ---- | ----- |  |  | ---- | - | -------- |  |  | ---------- | --- | - | ----- |  | ---- | - |  |  | ---- | -
|                                          |  | 2015     |      |   |            |  | 2014 |      
|($ millions)                              |  | Realized |      |   | Unrealized |  |      | Total |  |  |      |   | Realized |  |  | Unrealized |     |   | Total | 
|Crude Oil                                 |  |          | (571 | ) |            |  | 123  |       |  |  | (448 | ) |          |  |  |            | (37 | ) |       |  | (536 | ) |  |  | (573 | )
|Natural Gas                               |  |          | (59  | ) |            |  | 55   |       |  |  | (4   | ) |          |  |  |            | (7  | ) |       |  | (55  | ) |  |  | (62  | )
|Refining                                  |  |          | (36  | ) |            |  | 10   |       |  |  | (26  | ) |          |  |  |            | (26 | ) |       |  | (11  | ) |  |  | (37  | )
|Power                                     |  |          | 10   |   |            |  | 5    |       |  |  | 15   |   |          |  |  |            | 4   |   |       |  | 6    |   |  |  | 10   |  
|Interest Rate                             |  |          | -    |   |            |  | 2    |       |  |  | 2    |   |          |  |  |            | -   |   |       |  | -    |   |  |  | -    |  
|(Gain) Loss on Risk Management            |  |          | (656 | ) |            |  | 195  |       |  |  | (461 | ) |          |  |  |            | (66 | ) |       |  | (596 | ) |  |  | (662 | )
|Income Tax Expense (Recovery)             |  |          | 175  |   |            |  | (54  | )     |  |  | 121  |   |          |  |  |            | 20  |   |       |  | 152  |   |  |  | 172  |  
|(Gain) Loss on Risk Management, After Tax |  |          | (481 | ) |            |  | 141  |       |  |  | (340 | ) |          |  |  |            | (46 | ) |       |  | (444 | ) |  |  | (490 | )

In 2015, we recorded realized gains on crude oil and natural gas risk management activities, consistent with our contract
prices exceeding the average benchmark price. We recorded unrealized losses on our crude oil and natural gas financial instruments primarily due to the realization of settled positions partially offset by changes in market prices.

Commodity Price Sensitivities  Risk Management Positions

The following table summarizes the sensitivities of the fair value of our risk management positions to fluctuations in commodity prices with all other
variables held constant. Management believes the price fluctuations identified in the table below are a reasonable measure of volatility. Fluctuations in commodity prices could have resulted in unrealized gains (losses) for the year on open risk
management positions as at December 31, 2015 as follows:



|                             |  |                                                                  |  |          |  |         
|---------------------------- |  | ---------------------------------------------------------------- |  | -------- |  | --------
|Commodity                    |  | Sensitivity Range                                                |  | Increase |  | Decrease
|                            
|                             |  |                                                                  | 
|Crude Oil Commodity Price    |  | ± US$10 per bbl Applied to Brent and WTI Hedges                  |  | (243)    |  | 245     
|Crude Oil Differential Price |  | ± US$5 per bbl Applied to Differential Hedges Tied to Production |  | 80       |  | (80)    
|Condensate Commodity Price   |  | ± US$10 per bbl Applied to Condensate Hedges                     |  | 23       |  | (23)    
|Power Commodity Price        |  | ± $25 per MWHr Applied to Power Hedge                            |  | 19       |  | (19)    
|Interest Rate Swaps          |  | ± 50 Basis Points                                                |  | 38       |  | (46)    
|                            

Risks Associated with Derivative Financial Instruments

Financial instruments expose Cenovus to the risk that a counterparty will default on its contractual obligations. This risk is partially mitigated through
credit exposure limits, frequent assessment of counterparty credit ratings and netting arrangements, as outlined in our Credit Policy.

Financial
instruments also expose Cenovus to the risk of a loss from adverse changes in the market value of financial instruments or if were unable to fulfill our delivery obligations related to the underlying physical



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transaction. Financial instruments may limit the benefit to Cenovus if commodity price increases. These risks are minimized through hedging limits that are reviewed annually by the Board, as
required by our Market Risk Mitigation Policy.

Liquidity

Liquidity risk is the risk we will not be able to meet all our financial obligations as they come due or be unable to liquidate assets in a timely manner
at a reasonable price. In declining economic times, such as the low commodity price environment in which we are currently operating, or due to unforeseen events, our liquidity risk could become heightened.

Liquidity risk is further impacted by the amount and timing of financial and operating commitments, future capital expenditures, debt repayments as well
as available sources of liquidity, which may be impacted by our credit ratings. If we were unable to meet our financial obligations as they became due or be unable to liquidate assets in a timely manner at a reasonable price, this could have a
material adverse effect on our financial condition, results of operations, cash flows, access to capital, ability to comply with various financial and operating covenants, credit ratings and reputation.

We manage our liquidity risk through the active management of cash and debt by ensuring that we have access to multiple sources of capital including, but
not limited to, cash and cash equivalents, cash from operating activities, undrawn credit facilities and availability under our shelf prospectuses. At December 31, 2015, we had cash and cash equivalents of $4.1 billion. No amounts were drawn on
our $4.0 billion committed credit facility. In addition, we had $1.5 billion in unused capacity under our Canadian base shelf prospectus and US$2.0 billion in unused capacity under our U.S. base shelf prospectus, the availability of which is
dependent on market conditions and our credit ratings. We intend to file a new prospectus prior to the maturity of the existing prospectuses.

Foreign Exchange Rates

Our revenues are subject to foreign exchange exposure as the sales prices of our crude oil,
natural gas and refined products are determined by reference to U.S. benchmark prices. A decrease in the value of the Canadian dollar compared with the U.S. dollar has a positive impact on our reported results. Likewise, as the Canadian dollar
strengthens, our reported results are lower. In addition to our revenues being denominated in U.S. dollars, we have chosen to borrow U.S. dollar long-term debt. In periods of a weakening Canadian dollar, our U.S. dollar debt gives rise to unrealized
foreign exchange losses when translated to Canadian dollars. Exchange rate fluctuations could have a material adverse effect on our financial condition, results of operations and cash flows.

Operational Risk

Operational risks are those risks that affect our ability to continue operations in the ordinary course of business. Our operations are subject to risks
generally affecting the oil and gas and refining industries. To partially mitigate our risk, we have a system of standards, practices and procedures called the Cenovus Operations Management System (COMS) to identify, assess and mitigate
safety, operational and environmental risk across our operations. In addition to leveraging COMS, we attempt to partially mitigate operational risks by maintaining a comprehensive insurance program in respect of our assets and operations.

Market Access and Transportation Restrictions

Cenovuss production is transported through pipelines and by rail and its refineries are reliant on pipelines to receive feedstock. Disruptions in,
or restricted availability of pipeline service or rail shipments, could adversely affect our crude oil and natural gas sales, projected production growth, refining operations and cash flows. Insufficient transportation capacity for our production
will impact our ability to efficiently access end markets. This may negatively impact our financial performance by way of higher transportation costs, wider price differentials, lower sales prices at specific locations or for specific grades of
crude oil, and in extreme situations, production curtailment.

Operational Outages and Major Environmental or Safety
Incidents

Our crude oil and natural gas production activities are subject to inherent operational risks such as encountering unexpected
formations or pressures, blowouts, equipment failures and other accidents, interdependence of component systems, sour gas releases, uncontrollable flows of crude oil, natural gas or well fluids, adverse weather conditions, pollution and other
environmental risks. Our refining and marketing activities are subject to risks including slowdowns due to equipment failure or transportation disruptions, weather, fires, explosions, railcar incidents or derailments, unavailability of feedstock,
and poor price and quality of feedstock. Cenovuss operations could also be interrupted by natural disasters or other events beyond our control.

Failure to manage these risks effectively could result in potential fatalities, serious injury, asset damage or environmental impacts, any of which could
have a material adverse effect on our reputation, financial condition, results of operations and cash flows. Cenovus does not insure against all potential occurrences and disruptions and our insurance may be insufficient to cover any such
occurrences or disruptions.

Project Execution

There are risks associated with the execution and operations of our upstream and refining growth and development projects. Successful project execution
will be highly dependent upon the availability and cost of materials,



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equipment and skilled labour, our ability to finance growth and general economic conditions. Project execution will also be impacted by our ability to obtain the necessary environmental and
regulatory approvals, and the effect of changing government regulations and public expectations in relation to the impact of oil sands development on the environment. The commissioning and integration of new facilities within our existing asset base
could also cause delays in achieving targets and objectives. Failure to manage these risks could have a material adverse effect on our financial condition, results of operations and cash flows.

Cost Management

Our operating
costs could escalate and become uncompetitive due to labour costs, equipment limitations, commodity prices, higher steam-to-oil ratios in our oil sands operations, additional government or environmental regulations and general inflationary
pressures. Operating costs associated with our crude oil production are largely fixed in the short-term and, as a result, are largely dependent on levels of production. Our inability to manage costs may impact project returns and future development
decisions, which could have a material adverse effect on our financial condition, results of operations and cash flows.

Reserves Replacement

If we fail to acquire, develop or find additional crude oil and natural gas reserves, our reserves and production will decline materially from their
current levels. Our financial condition, results of operations and cash flows are highly dependent upon successfully producing from current reserves and acquiring, discovering or developing additional reserves.

Leadership and Talent

Our success in executing our business strategy is dependent upon Management and their leadership capabilities, as well as, the quality and competency of
our employees. If we fail to retain critical talent or are unsuccessful in attracting and retaining new talent, with the necessary leadership traits, skills and technical competencies, it could have a materially adverse effect on Cenovuss
results of operations, pace of growth and financial condition.

Regulatory Risk

Regulatory risk is the risk of loss or lost opportunity resulting from the introduction of, or changes in, regulatory requirements or the failure to
secure regulatory approval for a crude oil or natural gas development project. The implementation of new regulations or the modification of existing regulations could impact our existing and planned projects as well as result in compliance costs,
adversely impacting our financial condition, results of operations and cash flows.

Regulatory Approvals

Our operations are subject to regulation and intervention by governments in areas such as energy policies, environmental and safety policies, land tenure,
taxes, royalties, government fees, the export of crude oil, natural gas and other products, production rates, expropriation or cancellation of contract rights, acquisition of exploration and production rights, and control over the development and
abandonment of fields. Changes to government regulation could impact Cenovuss existing and planned projects or increase capital investment or operating expenses, adversely impacting our financial condition, results of operations and cash
flows.

Royalty Regimes

The governments of Alberta and Saskatchewan receive royalties on the production of crude oil and natural gas from lands where they own the mineral rights.
The Government of Alberta released its royalty review report on January 29, 2015. The report recommends no changes to existing oil sands royalty rates but recommended further government-industry consultation on administrative aspects of the oil
sands royalty regime. The royalty review report recommended a modernization of Albertas conventional oil and gas royalty regime but did not provide details. The changes proposed to conventional oil and gas royalties will require further
consultation between industry and government to fully understand their impacts. These changes to the Alberta provincial royalty structure could have a significant impact on Cenovuss financial condition, results of operations and cash flows. An
increase in the royalty rates applicable in one or both provinces could make, in the respective province, future capital expenditures or existing operations uneconomic.

Environmental Regulations

Environmental regulations impose, among other things, restrictions, liabilities and obligations in connection with the generation, handling, use, storage,
transportation, treatment and disposal of hazardous substances and waste and in connection with spills, releases and emissions of various substances in the environment. They also impose restrictions, liabilities and obligations in connection with
the management of fresh or potable water sources that are being used, or whose use is contemplated, in connection with oil and gas operations. The complexities of changes in environmental regulations make it difficult to predict the potential future
impact to Cenovus.

Compliance with environmental regulations can require significant expenditures, including clean-up costs and damages arising from
contaminated properties. We anticipate that future capital expenditures and operating expenses could continue to increase as a result of the implementation of new environmental regulations.



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Failure to comply with environmental regulations may result in the imposition of fines, penalties and
environmental protection orders. The costs of complying with environmental regulations in the future may have a material adverse effect on our financial condition, results of operations and cash flows. Non-compliance with environmental regulations
could have an adverse impact on Cenovuss reputation. There is also a risk that Cenovus could face litigation initiated by third parties relating to climate change or other environmental regulations.

Species at Risk Act

The Canadian federal legislation, Species at Risk Act, and provincial counterparts regarding threatened or endangered species may influence development in
areas identified as critical habitat for species of concern (e.g. woodland caribou). In Alberta, the Alberta Caribou Action and Range Planning Project has been established to develop range plans and action plans with a view to achieving the
maintenance and recovery of Albertas 15 caribou populations. The federal and/or provincial implementation of measures to protect species at risk such as woodland caribou and their critical habitat in areas of Cenovuss current or future
operations may limit our pace and amount of development and, in some cases, may result in an inability to operate in affected areas.

Climate Change

Various federal, provincial and state governments have announced intentions to regulate greenhouse gas
(GHG) emissions and other air pollutants. In November, 2015, the Government of Alberta announced its climate leadership plan (the CLP) highlighting four key strategies that the government will implement to address climate
change: (1) the complete phase-out of coal-fired sources of electricity by 2030; (2) an Alberta economy-wide price on GHG emissions of $30/tonne; (3) capping oil sands emissions to a province-wide total of 100 megatonnes per year,
with certain exceptions for cogeneration power sources and new upgrading capacity; and (4) reducing methane emissions from oil and gas activities by 45 percent by 2025.

We are also subject to the Specified Gas Emitters Regulation (the SGER), which imposes GHG emissions intensity limits and reduction
requirements for owners of facilities that emit 100,000 tonnes per year or more of GHG. Recent amendments to the SGER have increased the maximum emission intensity reduction requirement for facility owners from 12 percent to 15 percent in 2016 and
20 percent starting in 2017. One of the options for complying with the SGER is for facility owners to purchase technology fund credits. The SGER amendments have increased the price for such credits from $15/tonne to $20/tonne for 2016 and $30/tonne
beginning in 2017.

If comprehensive GHG regulation is enacted in Alberta or any jurisdiction in which we operate, including legislation to implement
the CLP, and as a result of the amendments to the SGER, we may incur increased compliance costs, loss of markets, permitting delays, substantial costs to generate or purchase emission credits or allowances, all of which may increase operating
expenses and reduce demand for crude oil, natural gas and certain refined products.

Beyond existing legal requirements, the extent and magnitude of
any adverse impacts of these additional programs cannot be reliably or accurately estimated at this time because specific legislative and regulatory requirements have not been finalized and uncertainty exists with respect to the additional measures
being considered and the time frames for compliance.

Water Licenses

To operate our SAGD facilities we rely on water, which is obtained under licenses issued through the Alberta Water Act. Currently, we are not required to
pay for the water we use under these licenses. If a change under these licenses reduces the amount of water available for our use, our production could decline or operating expenses could increase, both of which may have a material adverse effect on
our business and financial performance. There can be no assurance that the licenses to withdraw water will not be rescinded or that additional conditions will not be added to these licenses. There can be no assurance that we will not have to pay a
fee for the use of water in the future or that any such fees will be reasonable. In addition, the expansion of our projects rely on securing licenses for additional water withdrawal, and there can be no assurance that these licenses will be granted
on terms favourable to us or at all, or that such additional water will in fact be available to divert under such licenses.

Albertas Land-Use Framework

The Government of Alberta approved the Lower Athabasca Regional Plan (LARP), which identifies legally binding management frameworks for air,
land and water that will incorporate cumulative limits and triggers as well as identifying areas related to conservation, tourism and recreation. Uncertainty exists with respect to future development applications in the areas covered by the LARP,
including the potential for development restrictions and mineral rights cancellation. This may have a material adverse effect on our financial condition, results of operations and cash flows. Additional regional plans are in the process of being
developed by the Government of Alberta and no assurances can be given that such plans, if approved and implemented, will not materially impact our operations or future operations.



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CRITICAL ACCOUNTING JUDGMENTS, ESTIMATES AND ACCOUNTING
POLICIES





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

Critical Judgments in Applying Accounting Policies

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

Joint Arrangements

Cenovus holds a 50 percent ownership interest in two jointly controlled entities, FCCL and WRB. The classification of these joint arrangements as either a
joint operation or a joint venture requires judgment. It was determined that Cenovus has the rights to the assets and obligations for the liabilities of FCCL and WRB. As a result, these joint arrangements are classified as joint operations and our
share of the assets, liabilities, revenues and expenses are recorded in the Consolidated Financial Statements.

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

| |  | 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 Cenovuss accounting policy for E&E expenditures requires judgment in determining whether it is likely
that future economic benefit exists when activities have not reached a stage where technical feasibility and commercial viability can be reasonably determined. Factors such as drilling results, future capital programs, future operating expenses, as
well as estimated reserves and resources are considered. In addition, Management uses judgment to determine when E&E assets are reclassified to PP&E. In making this determination, various factors are considered, including the existence of
reserves, and whether the appropriate approvals have been received from regulatory bodies and Cenovuss internal approval process.

Identification of CGUs

CGUs are defined as the lowest level of integrated assets for which there are separately
identifiable cash flows that are largely independent of cash flows from other assets or groups of assets. The classification of assets and allocation of corporate assets into CGUs requires significant judgment and interpretations. Factors considered
in the classification include the integration between assets, shared infrastructures, the existence of common sales points, geography, geologic structure, and the manner in which Management monitors and makes decisions about its operations. The
recoverability of Cenovuss upstream, refining, crude-by-rail and corporate assets are assessed at the CGU level. As such, the determination of a CGU could have a significant impact on impairment losses.

Key Sources of Estimation Uncertainty

Critical accounting estimates are those estimates that require Management to make particularly subjective or complex judgments about matters that are
inherently uncertain. Estimates and underlying assumptions are reviewed on an ongoing basis and any revisions to accounting estimates are recorded in the period in which the estimates are revised. The following are the key assumptions about the
future and other key sources of estimation



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at the end of the reporting period that changes to could result in a material adjustment to the carrying amount of assets and liabilities within the next financial year.

Crude Oil and Natural Gas Reserves

There are a number of inherent uncertainties associated with estimating crude oil and natural gas reserves. Reserves estimates are dependent upon
variables including the recoverable quantities of hydrocarbons, the cost of the development of the required infrastructure to recover the hydrocarbons, production costs, estimated selling price of the hydrocarbons produced, royalty payments and
taxes. Changes in these variables could significantly impact the reserves estimates which would affect the impairment test and DD&A expense of our crude oil and natural gas assets in the Oil Sands and Conventional segments. Cenovuss crude
oil and natural gas reserves are evaluated annually and reported to Cenovus by IQREs. Refer to the Outlook section of this MD&A for more details on future commodity prices.

Impairment of Assets

Impairment calculations require the use of estimates and assumptions, which are subject to change as new information becomes available. For our upstream
assets, these estimates include forward commodity prices, expected production volumes, quantity of reserves and resources, discount rates, future development and operating expenses, and income tax rates. Recoverable amounts for the our refining
assets and crude-by-rail terminal use assumptions such as throughput, forward commodity prices, operating expenses, transportation capacity, supply and demand conditions, and income tax rates. Changes in assumptions used in determining the
recoverable amount could affect the carrying value of the related assets.

Refer to the Outlook section of this MD&A for more details on future
commodity prices and to the reportable segments section of this MD&A for more details on impairments.

As at December 31, 2015, the
recoverable amounts of Cenovuss upstream CGUs were determined based on fair value less costs of disposal. Key assumptions in the determination of cash flows from reserves include crude oil and natural gas prices, and the discount rate. All
reserves have been evaluated at December 31, 2015 by IQREs.

Crude Oil and Natural Gas Prices

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



|                 |  |      |       |  |      |  |       |      |  |  |       |  |  |      |       |  |                                 |  |       |  |  |  |      | 
|---------------- |  | ---- | ----- |  | ---- |  | ----- | ---- |  |  | ----- |  |  | ---- | ----- |  | ------------------------------- |  | ----- |  |  |  | ---- | 
|                 |  | 2016 |       |  | 2017 |  |       | 2018 |  |  | 2019  |  |  | 2020 |       |  | Average
Annual %
Change to
2026 | 
|                 | 
|                 |  |      |       |  |      | 
|WTI (US$/barrel) |  |      | 45.00 |  |      |  | 53.60 |      |  |  | 62.40 |  |  |      | 69.00 |  |                                 |  | 73.10 |  |  |  | 3.8% | 
|WCS ($/barrel)   |  |      | 46.40 |  |      |  | 54.40 |      |  |  | 59.70 |  |  |      | 66.30 |  |                                 |  | 68.20 |  |  |  | 3.9% | 
|AECO ($/Mcf)(1)  |  |      | 2.70  |  |      |  | 3.20  |      |  |  | 3.55  |  |  |      | 3.85  |  |                                 |  | 3.95  |  |  |  | 4.0% | 
|                 | 



|(1) | Assumes gas heating value of one million British Thermal Units per thousand cubic feet.
|--- | ---------------------------------------------------------------------------------------

Discount and Inflation Rates

Evaluations of discounted future cash flows are initiated using the discount rate of 10 percent and inflation is estimated at two percent, which is common
industry practice and used by Cenovuss IQREs in preparing their reserves reports. Based on the individual characteristics of the asset, other economic and operating factors are also considered, which may increase or decrease the implied
discount rate.

Decommissioning Costs

Provisions are recorded for the future decommissioning and restoration of our upstream crude oil and natural gas assets, refining assets and crude-by-rail
terminal at the end of their economic lives. Management uses judgement to assess the existence and to estimate the future liability. The actual cost of decommissioning and restoration is uncertain and cost estimates may change in response to
numerous factors including changes in legal requirements, technological advances, inflation and the timing of expected decommissioning and restoration. In addition, Management determines the appropriate discount rate at the end of each reporting
period. This discount rate, which is credit adjusted, is used to determine the present value of the estimated future cash outflows required to settle the obligation and may change in response to numerous market factors. Refer to Note 22 of the
Consolidated Financial Statements for more details on changes to decommissioning costs.

Income Tax Provisions

Tax regulations and legislation and the interpretations thereof in the various jurisdictions in which Cenovus operates are subject to
change. There are usually a number of tax matters under review; therefore, income taxes are subject to measurement uncertainty.

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



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Financial Statements of future periods. Refer to the Corporate and Eliminations section of this MD&A for more details on changes to estimates related to income taxes.

Changes in Accounting Policies

There were no new or amended accounting standards or interpretations adopted during 2015.

Future Accounting Pronouncements

A number of new accounting standards, amendments to accounting standards and interpretations are effective for annual periods beginning on or after
January 1, 2016 and have not been applied in preparing the Consolidated Financial Statements for the year ended December 31, 2015. The standards applicable to Cenovus are as follows and will be adopted on their respective effective dates:

Leases

On January 13, 2016, the IASB issued IFRS 16, Leases (IFRS 16), which requires entities to recognize lease assets and
lease obligations on the balance sheet. For lessees, IFRS 16 removes the classification of leases as either operating leases or finance leases, effectively treating all leases as finance leases. Certain short-term leases (less than 12 months) and
leases of low-value assets are exempt from the requirements, and may continue to be treated as operating leases.

Lessors will continue with a dual
lease classification model. Classification will determine how and when a lessor will recognize lease revenue, and what assets would be recorded.

IFRS
16 is effective for years beginning on or after January 1, 2019, with early adoption permitted if IFRS 15 Revenue From Contracts With Customers has been adopted. The standard may be applied retrospectively or using a modified
retrospective approach. The Company is currently evaluating the impact of adopting IFRS 16 on the Consolidated Financial Statements.

Revenue Recognition

On May 28, 2014, the IASB issued IFRS 15, Revenue From Contracts With
Customers (IFRS 15) replacing International Accounting Standard 11, Construction Contracts, International Accounting Standard 18, Revenue and several revenue-related interpretations. IFRS
15 establishes a single revenue recognition framework that applies to contracts with customers. The standard requires an entity to recognize revenue to reflect the transfer of goods and services for the amount it expects to receive, when control is
transferred to the purchaser. Disclosure requirements have also been expanded.

IFRS 15 is effective for annual periods beginning on or after
January 1, 2018. Early adoption is permitted. The standard may be applied retrospectively or using a modified retrospective approach. We are currently evaluating the impact of adopting IFRS 15 on the Consolidated Financial Statements.

Financial Instruments

On July 24, 2014, the IASB issued the final version of IFRS 9, Financial Instruments (IFRS 9) to replace IAS 39,
Financial Instruments: Recognition and Measurement (IAS 39).

IFRS 9 introduces a single approach to determine whether
a financial asset is measured at amortized cost or fair value and replaces the multiple rules in IAS 39. The approach is based on how an entity manages its financial instruments in the context of its business model and the contractual cash flow
characteristics of the financial assets. For financial liabilities, IFRS 9 retains most of the IAS 39 requirements; however, where the fair value option is applied to financial liabilities, the change in fair value resulting from an entitys
own credit risk is recorded in other comprehensive income rather than net earnings, unless this creates an accounting mismatch. In addition, a new expected credit loss model for calculating impairment on financial assets replaces the incurred loss
impairment model used in IAS 39. The new model will result in more timely recognition of expected credit losses. IFRS 9 also includes a simplified hedge accounting model, aligning hedge accounting more closely with risk management. We do not
currently apply hedge accounting.

IFRS 9 is effective for years beginning on or after January 1, 2018. Early adoption is permitted if IFRS 9 is
adopted in its entirety at the beginning of a fiscal period. We are currently evaluating the impact of adopting IFRS 9 on the Consolidated Financial Statements.

CONTROL ENVIRONMENT





Management, including our President & Chief Executive Officer and Executive Vice-President & Chief Financial Officer, has assessed the
design and effectiveness of internal control over financial reporting (ICFR) and disclosure controls and procedures (DC&P) as at December 31, 2015. In making its assessment, Management used the Committee of
Sponsoring Organizations of the Treadway Commission framework in Internal Control  Integrated Framework (2013) to evaluate the design and effectiveness of internal control over financial reporting. Based on our evaluation, Management has
concluded that both ICFR and DC&P were effective as at December 31, 2015.



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The effectiveness of our ICFR was audited by PricewaterhouseCoopers LLP, an independent firm of chartered
professional accountants, as stated in their Report of Independent Registered Public Accounting Firm, which is included in our audited Consolidated Financial Statements for the year ended December 31, 2015. There have been no changes to ICFR
during the year ended December 31, 2015 that have materially affected, or are reasonably likely to materially affect, ICFR.

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

CORPORATE RESPONSIBILITY





We are committed to operating in a responsible manner and integrating our corporate responsibility principles in the way we conduct our business. Our
Corporate Responsibility (CR) policy guides our activities in the areas of: Leadership; Corporate Governance and Business Practices; People; Environmental Performance; Stakeholder and Aboriginal Engagement; and Community Involvement and
Investment.

We published our 2014 CR report in June 2015, detailing our efforts to accelerate our environmental performance, protect the health and
safety of our staff, invest in and engage with the communities where we operate and maintain the highest standards of corporate governance. Our CR report also lists external recognition we received for our commitment to corporate responsibility and
our efforts to balance economic, governance, social and environmental performance. Our CR policy and CR report are available on our website at cenovus.com.

OUTLOOK





We expect 2016 will be another challenging
year for our industry. Maintaining our financial resilience remains a top priority. Our revised 2016 guidance reflects reduced capital spending plans, consistent with our expectation that commodity prices will continue to be low for a prolonged
period of time.

The following outlook commentary is focused on the next 12 months.

Commodity Prices Underlying our Financial Results

Our crude oil pricing outlook is influenced by the following:

|  |  |                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                              |  |     
|- |  | ---------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------- |  | ----
| |  | We expect the general outlook for crude oil prices will be tied primarily to the supply response to the current price environment and the pace of growth of the global
economy. Overall, we expect crude oil price volatility and a modest price improvement in 2016. Slower global supply growth, combined with annual increases in demand growth, should support prices in the second half of the year, constrained by the
need to draw down surplus crude oil inventories and anticipated re-entry of Iranian crude oil into markets. We continue to anticipate slower supply growth from North American producers as a result of the significant reductions in capital spending.
The low crude oil price environment also serves to help boost global economic momentum. |  | LOGO

We believe there is a risk that OPEC will attempt to gain market share by increasing rig counts or
increasing OPEC production, which will depress crude oil prices, and that economic uncertainty in China may slow emerging market demand;

| |  | We expect the Brent-WTI differential to remain narrow now that the U.S. has lifted restrictions on exporting crude oil to overseas markets. Overall, the
differential will likely be set by transportation costs. The Brent-WTI differential is expected to remain volatile due to mismatches in demand, global imports and refinery turnarounds; and
|- |  | -----------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------

| |  | We also expect that the WTI-WCS differential will remain wide due to additional Canadian supply growth and declining U.S. light tight oil supply. However,
substantially wider differentials are unlikely due to excess rail capacity and further expansions on existing pipeline systems.
|- |  | ------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------



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|Cenovus Energy Inc. |  | 41 |  | 2015 Managements Discussion and Analysis



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LOGO


LOGO  (1)
Refer to the foreign exchange rate sensitivities found within our current guidance available at cenovus.com.






Refining crack spreads in 2016, as
forecasted at January 29, 2016, are expected to strengthen late in the second quarter due to higher seasonal demand for refined products and then decline in the second half of the year.

Natural gas production is anticipated to increase marginally in 2016 due to low levels of drilling activity. However, warmer weather is expected to reduce
residential and commercial demand, while coal-to-gas substitution in the power sector is expected to continue. As a result, natural gas prices are anticipated to remain weak through the first half of 2016.

The average foreign exchange forward price expected over the next 12 months is US$0.711/C$. We expect that the Canadian dollar, compared with the U.S.
dollar, will remain relatively weak in the near term due to weak commodity prices and Canadian economic uncertainty. Overall, a weak Canadian dollar should have a positive impact on our revenues and Operating Cash Flow.

Our exposure to the light/heavy price differentials is composed of both a global light/heavy component as well as Canadian congestion. While we expect to
see volatility in crude oil prices, we mitigate our exposure to light/heavy price differentials through the following:

|  |  |                                                                                                                                                                                                                                                                                                      |  |                                                                                                                                                                                                                                                               
|- |  | ---------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------- |  | --------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------
|● |  | Integration  having heavy oil refining capacity capable of processing Canadian heavy oil. From a value perspective, our refining business positions us to capture
value from both the WTI-WCS differential for Canadian crude oil and the Brent-WTI differential from the sale of refined products; |  | Protection Against Canadian
Congestion  LOGO 
(1)      Expected gross production capacity.
(2)      Excludes additional 18,000 bbls/d heavy oil capacity expected as a result of the Wood
River debottlenecking project (expected in the second half of 2016).
|● |  | Financial hedge transactions  limiting the impact of fluctuations in upstream crude oil prices by entering into financial transactions that fix the WTI-WCS
differential;                                                                                                                           | 
|● |  | Marketing arrangements  limiting the impact of fluctuations in upstream crude oil prices by entering into physical supply transactions with fixed price components
directly with refiners; and                                                                                                      | 
|● |  | Transportation commitments and arrangements  supporting transportation projects that move crude oil from our production areas to consuming markets and also to
tidewater markets.                                                                                                                   | 
|  |  |                                                                                                                                                                                                                                                                                                      | 
|  |  |                                                                                                                                                                                                                                                                                                      | 
|  |  |                                                                                                                                                                                                                                                                                                      | 
|  |  |                                                                                                                                                                                                                                                                                                      | 
|  |  |                                                                                                                                                                                                                                                                                                      | 

Key Priorities for 2016

Maintain Financial Resilience

Maintaining our financial resilience continues to be a top priority. At December 31, 2015, we had $4.1 billion of cash on hand and $4.0 billion of undrawn
capacity under our committed credit facility. Our debt has a weighted average maturity of approximately 16 years, with no debt maturing until the fourth quarter of 2019. We also have Canadian and U.S. base shelf prospectuses, the availability of
which is dependent on market conditions and our credit ratings. Although we have a strong balance sheet, we plan to undertake additional measures in 2016 to remain financially resilient, including reductions in capital, operating and general and
administrative costs, as we anticipate commodity prices to remain low in the upcoming year.

Attack Cost Structures

We will continue to focus on reducing our cost structure. In 2015, we captured savings of approximately $540 million, relative to our
budget, from capital, operating and general and administrative cost reductions. We believe approximately 60 percent of these cost savings are sustainable over the long term and were reflected in our original 2016 budget.



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We believe we are positioned to achieve additional sustainable cost reductions going forward. We anticipate
capital investment in 2016 of $1.2 billion to $1.3 billion, a reduction of $200 million to $300 million from our original budget announced in December 2015. We are targeting $100 million to $200 million of further savings in operating, general and
administrative and compensation costs. We must ensure that, over the long term, we maintain an efficient and sustainable cost structure, and maximize the strengths of our functional business model.

Disciplined and Value-added Growth

We are committed to exercising capital discipline. We will consider expanding existing projects and developing emerging opportunities only when we believe
we will generate attractive potential returns for shareholders. Although we have some of the needed fiscal and regulatory clarity at the provincial level, additional certainty around federal fiscal and regulatory regimes, commodity prices and our
ability to sustain cost reductions is required. We will only commit to project reactivation if it does not undermine the strength of our balance sheet.

ADVISORY



Oil and Gas
Information

The estimates of reserves and resources data and related information were prepared effective December 31, 2015 by
independent qualified reserves evaluators, based on the Canadian Oil and Gas Evaluation Handbook and in compliance with the requirements of National Instrument 51-101 Standards of Disclosure for Oil and Gas Activities. Estimates are presented
using McDaniel & Associates Consultants Ltd. January 1, 2016 price forecast. For additional information about our reserves, resources and other oil and gas information, see Reserves Data and Other Oil and Gas Information in
our AIF for the year ended December 31, 2015 and our Resources Statement.

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
2015 reserves evaluation, which comply with NI 51-101 requirements.

Prospective resources are those
quantities of bitumen estimated, as of a given date, to be potentially recoverable from undiscovered accumulations by application of future development projects. Prospective resources have both an associated chance of discovery and a chance of
development. Prospective resources are further subdivided in accordance with the level of certainty associated with 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.

Barrels of Oil Equivalent  Natural gas volumes have been converted to barrels of oil equivalent (BOE) on the basis of six Mcf to one barrel (bbl).
BOE may be misleading, particularly if used in isolation. A conversion ratio of one bbl to six Mcf is based on an energy equivalency conversion method primarily applicable at the burner tip and does not represent value equivalency at the wellhead.
Given that the value ratio based on the current price of crude oil compared with natural gas is significantly different from the energy equivalency conversion ratio of 6:1, utilizing a conversion on a 6:1 basis is not an accurate reflection of
value.

Additional information with respect to the significant factors relevant to the resources estimates, the specific contingencies which prevent
the classification of the contingent resources as reserves, pricing and additional



|                    |  |    |  |                                          
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|Cenovus Energy Inc. |  | 43 |  | 2015 Managements Discussion and Analysis



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reserves and other oil and gas information, including the material risks and uncertainties associated with reserves and resources estimates, is contained in our AIF and Form 40-F for the year
ended December 31, 2015, and our Resources Statement, both available on SEDAR at sedar.com, EDGAR at sec.gov and on our website at cenovus.com.

Forward-looking Information

This document contains certain forward-looking statements and other information
(collectively forward-looking information) about our current expectations, estimates and projections, made in light of our experience and perception of historical trends. Forward-looking information in this document is identified by
words such as anticipate, believe, expect, estimate, plan, forecast or F, future, target, position, project,
capacity, could, should, focus, goal, outlook, proposed, potential, may, schedule, on track, strategy,
forward, opportunity or similar expressions and includes suggestions of future outcomes, including statements about: our strategy and related milestones and schedules; projected future value; projections for 2016 and future
years; forecast operating and financial results; targets for our Debt to Capitalization and Debt to EBITDA ratios; planned capital expenditures, including the timing and financing thereof; expected future production, including the timing, stability
or growth thereof; expected reserves and resources; broadening market access; expected capacities, including for projects, transportation and refining; improving cost structures, forecast cost savings and sustainability thereof; dividend plans and
strategy anticipated timelines for future regulatory, partner or internal approvals; future impact of regulatory measures; forecast commodity prices and expected impact to Cenovus; future use and development of technology, including expected effects
on our environmental impact; and projected shareholder return. Readers are cautioned not to place undue reliance on forward-looking information as our actual results may differ materially from those expressed or implied.

Developing forward-looking information involves reliance on a number of assumptions and consideration of certain risks and uncertainties, some of which
are specific to Cenovus and others that apply to the industry generally. The factors or assumptions on which the forward-looking information is based include: assumptions inherent in our current guidance, available at cenovus.com; our projected
capital investment levels, the flexibility of our capital spending plans and the associated source of funding; estimates of quantities of oil, bitumen, natural gas and liquids from properties and other sources not currently classified as proved; our
ability to obtain necessary regulatory and partner approvals; the successful and timely implementation of capital projects or stages thereof; our ability to generate sufficient cash flow to meet our current and future obligations; and other risks
and uncertainties described from time to time in the filings we make with securities regulatory authorities.

2016 guidance, as updated on February
11, 2016, assumes: Brent of US$52.75/bbl, WTI of US$49.00/bbl; WCS of US$34.50/bbl; NYMEX of US$2.50/MMBtu; AECO of $2.50/GJ; Chicago 3-2-1 crack spread of US$12.00/bbl; and an exchange rate of $0.75 US$/C$.

The risk factors and uncertainties that could cause our actual results to differ materially, include: volatility of and assumptions regarding oil and
natural gas prices; the effectiveness of our risk management program, including the impact of derivative financial instruments, the success of our hedging strategies and the sufficiency of our liquidity position; the accuracy of cost estimates;
commodity prices, currency and interest rates; product supply and demand; market competition, including from alternative energy sources; risks inherent in our marketing operations, including credit risks; exposure to counterparties and partners,
including ability and willingness of such parties to satisfy contractual obligations in a timely manner; risks inherent in operation of our crude-by-rail terminal, including health, safety and environmental risks; maintaining desirable ratios of
debt to adjusted EBITDA and net debt to adjusted EBITDA as well as debt to capitalization and net debt to capitalization; our ability to access various sources of debt and equity capital, generally, and on terms acceptable to us; our ability to
finance growth and sustaining capital expenditures; changes in credit ratings applicable to us or any of our securities; changes to our dividend plans or strategy, including the dividend reinvestment plan; accuracy of our reserves, resources and
future production estimates; our ability to replace and expand oil and gas reserves; our ability to maintain our relationships with our partners and to successfully manage and operate our integrated business; reliability of our assets, including in
order to meet production targets; potential disruption or unexpected technical difficulties in developing new products and manufacturing processes; the occurrence of unexpected events such as fires, severe weather conditions, explosions, blow-outs,
equipment failures, transportation incidents and other accidents or similar events; refining and marketing margins; inflationary pressures on operating costs, including labour, natural gas and other energy sources used in oil sands processes;
potential failure of products to achieve acceptance in the market; unexpected cost increases or technical difficulties in constructing or modifying manufacturing or refining facilities; unexpected difficulties in producing, transporting or refining
of crude oil into petroleum and chemical products; risks associated with technology and its application to our business; the timing and the costs of well and pipeline construction; our ability to secure adequate product transportation, including
sufficient pipeline, crude-by-rail, marine or other alternate transportation, including to address any gaps caused by constraints in the pipeline system; availability of, and our ability to attract and retain, critical talent; changes in the
regulatory framework in any of the locations in which we operate, including changes to the regulatory approval process and land-use designations, royalty, tax, environmental, greenhouse gas, carbon and other laws or regulations, or changes to the
interpretation of such laws and regulations, as adopted or proposed, the impact thereof and the costs associated with compliance; the expected impact and timing of various accounting pronouncements, rule changes and standards on our business, our
financial results and our consolidated financial statements; changes in the general economic, market and business conditions; the political and economic conditions in the countries in which we operate; the occurrence of unexpected events such as
war, terrorist threats and the instability resulting therefrom; and risks associated with existing and potential future lawsuits and regulatory actions against us.

Readers are cautioned that the foregoing lists are not exhaustive and are made as at the date hereof. For a full discussion of our material risk factors,
see Risk Factors in our AIF or Form 40-F for the period ended December 31, 2015, available on SEDAR at sedar.com, EDGAR at sec.gov and on our website at cenovus.com.



|                    |  |    |  |                                          
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##### Table of Contents

ABBREVIATIONS

The following abbreviations have been used in this document:



|          |  |                                   |  |       |  |                                 
|--------- |  | --------------------------------- |  | ----- |  | --------------------------------
|Crude Oil |  | Natural Gas                      
|          |  |                                   | 
|bbl       |  | barrel                            |  | Mcf   |  | thousand cubic feet             
|bbls/d    |  | barrels per day                   |  | MMcf  |  | million cubic feet              
|Mbbls/d   |  | thousand barrels per day          |  | Bcf   |  | billion cubic feet              
|MMbbls    |  | million barrels                   |  | MMBtu |  | million British thermal units   
|BOE       |  | barrel of oil equivalent          |  | GJ    |  | gigajoule                       
|BOE/d     |  | barrel of oil equivalent per day  |  | AECO  |  | Alberta Energy Company          
|MBOE      |  | thousand barrel of oil equivalent |  | NYMEX |  | New York Mercantile Exchange    
|MMBOE     |  | million barrel of oil equivalent  |  |       |  |                                 
|WTI       |  | West Texas Intermediate           |  |       |  |                                 
|WCS       |  | Western Canadian Select           |  |       |  |                                 
|CDB       |  | Christina Dilbit Blend            |  | TM    |  | trademark of Cenovus Energy Inc.



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|Cenovus Energy Inc. |  | 45 |  | 2015 Managements Discussion and Analysis



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##### Table of Contents

LOGO

Cenovus Energy Inc.

Consolidated Financial Statements

For the Year Ended December 31, 2015

(Canadian Dollars)



---

##### Table of Contents

CONSOLIDATED FINANCIAL STATEMENTS

For the year ended December 31, 2015

TABLE OF CONTENTS







|                                                                           |  |  |    | 
|-------------------------------------------------------------------------- |  |  | -- | 
|REPORT OF MANAGEMENT                                                       |  |  | 3  | 
|REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM                    |  |  | 4  | 
|CONSOLIDATED STATEMENTS OF EARNINGS                                        |  |  | 5  | 
|CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME                            |  |  | 5  | 
|CONSOLIDATED BALANCE SHEETS                                                |  |  | 6  | 
|CONSOLIDATED STATEMENTS OF SHAREHOLDERS EQUITY                            |  |  | 7  | 
|CONSOLIDATED STATEMENTS OF CASH FLOWS                                      |  |  | 8  | 
|NOTES TO CONSOLIDATED FINANCIAL STATEMENTS                                 |  |  | 9  | 
|1. DESCRIPTION OF BUSINESS AND SEGMENTED DISCLOSURES                       |  |  | 9  | 
|2. BASIS OF PREPARATION AND STATEMENT OF COMPLIANCE                        |  |  | 13 | 
|3. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES                              |  |  | 13 | 
|4. CRITICAL ACCOUNTING JUDGMENTS AND KEY SOURCES OF ESTIMATION UNCERTAINTY |  |  | 21 | 
|5. FINANCE COSTS                                                           |  |  | 23 | 
|6. INTEREST INCOME                                                         |  |  | 23 | 
|7. FOREIGN EXCHANGE (GAIN) LOSS, NET                                       |  |  | 23 | 
|8. DIVESTITURES                                                            |  |  | 24 | 
|9. IMPAIRMENTS                                                             |  |  | 24 | 
|10. INCOME TAXES                                                           |  |  | 26 | 
|11. PER SHARE AMOUNTS                                                      |  |  | 29 | 
|12. CASH AND CASH EQUIVALENTS                                              |  |  | 29 | 
|13. ACCOUNTS RECEIVABLE AND ACCRUED
REVENUES                               |  |  | 29 | 
|14. INVENTORIES                                                            |  |  | 30 | 
|15. EXPLORATION AND EVALUATION
ASSETS                                      |  |  | 30 | 
|16. PROPERTY, PLANT AND EQUIPMENT,
NET                                     |  |  | 31 | 
|17. ACQUISITION                                                            |  |  | 32 | 
|18. OTHER ASSETS                                                           |  |  | 32 | 
|19. GOODWILL                                                               |  |  | 32 | 
|20. ACCOUNTS PAYABLE AND ACCRUED
LIABILITIES                               |  |  | 32 | 
|21. LONG-TERM DEBT                                                         |  |  | 32 | 
|22. DECOMMISSIONING LIABILITIES                                            |  |  | 34 | 
|23. OTHER LIABILITIES                                                      |  |  | 34 | 
|24. PENSIONS AND OTHER POST-EMPLOYMENT BENEFITS                            |  |  | 35 | 
|25. SHARE CAPITAL                                                          |  |  | 38 | 
|26. ACCUMULATED OTHER COMPREHENSIVE INCOME (LOSS)                          |  |  | 39 | 
|27. STOCK-BASED COMPENSATION
PLANS                                         |  |  | 39 | 
|28. EMPLOYEE SALARIES AND BENEFIT
EXPENSES                                 |  |  | 43 | 
|29. RELATED PARTY TRANSACTIONS                                             |  |  | 43 | 
|30. CAPITAL STRUCTURE                                                      |  |  | 44 | 
|31. FINANCIAL INSTRUMENTS                                                  |  |  | 45 | 
|32. RISK MANAGEMENT                                                        |  |  | 47 | 
|33. SUPPLEMENTARY CASH FLOW
INFORMATION                                    |  |  | 50 | 
|34. COMMITMENTS AND CONTINGENCIES                                          |  |  | 50 | 



|                    |  |   |  |                                  
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|Cenovus Energy Inc. |  | 2 |  | Consolidated Financial Statements



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##### Table of Contents

Report of Management

Managements Responsibility for the Consolidated Financial Statements

The accompanying Consolidated Financial Statements of Cenovus Energy Inc. are the responsibility of Management. The Consolidated Financial Statements have
been prepared by Management in Canadian dollars in accordance with International Financial Reporting Standards as issued by the International Accounting Standards Board and include certain estimates that reflect Managements best judgments.

The Board of Directors has approved the information contained in the Consolidated Financial Statements. The Board of Directors fulfills its
responsibility regarding the financial statements mainly through its Audit Committee which is made up of four independent directors. The Audit Committee has a written mandate that complies with the current requirements of Canadian securities
legislation and the United States Sarbanes  Oxley Act of 2002and voluntarily complies, in principle, with the Audit Committee guidelines of the New York Stock Exchange. The Audit Committee meets with Management and the independent
auditors on at least a quarterly basis to review and approve interim Consolidated Financial Statements and Managements Discussion and Analysis prior to their public release as well as annually to review the annual Consolidated Financial
Statements and Managements Discussion and Analysis and recommend their approval to the Board of Directors.

Managements Assessment of Internal Control over Financial Reporting

Management is also responsible for establishing and maintaining adequate internal control over financial reporting. The internal control system was
designed to provide reasonable assurance to Management regarding the preparation and presentation of the Consolidated Financial Statements.

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

Management has assessed the design and effectiveness of internal control over financial reporting as at December 31, 2015. In making its assessment,
Management has used the Committee of Sponsoring Organizations of the Treadway Commission (COSO) framework in Internal Control  Integrated Framework (2013) to evaluate the design and effectiveness of internal control over
financial reporting. Based on our evaluation, Management has concluded that internal control over financial reporting was effective as at December 31, 2015.

PricewaterhouseCoopers LLP, an independent firm of Chartered Professional Accountants, was appointed to audit and provide independent opinions on both the
Consolidated Financial Statements and internal control over financial reporting as at December 31, 2015, as stated in their Report of Independent Registered Public Accounting Firm dated February 10, 2016. PricewaterhouseCoopers LLP has provided
such opinions.





|                        |  |                           
|----------------------- |  | --------------------------
|/s/ Brian C. Ferguson   |  | /s/ Ivor M. Ruste         
|                        | 
|Brian C. Ferguson       |  | Ivor M. Ruste             
|President &             |  | Executive Vice-President &
|Chief Executive Officer |  | Chief Financial Officer   
|Cenovus Energy Inc.     |  | Cenovus Energy Inc.       
|                        | 
|February 10, 2016       |  |                           



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|Cenovus Energy Inc. |  | 3 |  | Consolidated Financial Statements



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##### Table of Contents

Report of Independent Registered Public Accounting Firm

To the Shareholders of Cenovus Energy Inc.

We have audited the accompanying Consolidated Balance Sheets of Cenovus Energy Inc. as of December 31, 2015 and December 31, 2014 and the
Consolidated Statements of Earnings, Comprehensive Income, Shareholders Equity and Cash Flows for each of the years in the three-year period ended December 31, 2015. We also have audited Cenovus Energy Inc.s internal control over
financial reporting as of December 31, 2015, based on criteria established in Internal Control  Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO). Management
is responsible for these Consolidated Financial Statements, for maintaining effective internal control over financial reporting, and for its assessment of the effectiveness of internal control over financial reporting, included in the accompanying
Report of Management. Our responsibility is to express an opinion on these Consolidated Financial Statements and an opinion on Cenovus Energy Inc.s internal control over financial reporting based on our integrated audits.

We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we
plan and perform the audit to obtain reasonable assurance about whether the Consolidated Financial Statements are free of material misstatement and whether effective internal control over financial reporting was maintained in all material respects.
Our audits of the Consolidated Financial Statements included examining, on a test basis, evidence supporting the amounts and disclosures in the Consolidated Financial Statements, assessing the accounting principles used and significant estimates
made by management, and evaluating the overall Consolidated Financial Statement presentation. Our audit of internal control over financial reporting included obtaining an understanding of internal control over financial reporting, assessing the risk
that a material weakness exists, and testing and evaluating the design and operating effectiveness of internal control based on the assessed risk. Our audits also included performing such other procedures as we considered necessary in the
circumstances. We believe that our audits provide a reasonable basis for our opinions.

A companys internal control over financial reporting is
a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. A companys
internal control over financial reporting includes those policies and procedures that: (i) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the
company; (ii) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the company
are being made only in accordance with authorizations of management and directors of the company; and (iii) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the
companys assets that could have a material effect on the financial statements. Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of
effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.

In our opinion, the Consolidated Financial Statements referred to above present fairly, in all material respects, the financial position of Cenovus Energy
Inc. as of December 31, 2015 and December 31, 2014 and the results of its operations and its cash flows for each of the years in the three-year period ended December 31, 2015 in conformity with International Financial Reporting
Standards as issued by the International Accounting Standards Board. Also, in our opinion, Cenovus Energy Inc. maintained, in all material respects, effective internal control over financial reporting as of December 31, 2015, based on criteria
established in Internal Control  Integrated Framework (2013) issued by COSO.

/s/ PricewaterhouseCoopers LLP

PricewaterhouseCoopers LLP

Chartered Professional Accountants

Calgary, Alberta,
Canada

February 10, 2016



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|Cenovus Energy Inc. |  | 4 |  | Consolidated Financial Statements



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##### Table of Contents

CONSOLIDATED STATEMENTS OF EARNINGS

For the years ended December 31,

($ millions, except per share amounts)



|                                                                                              |  |       |      |  |  |  |      |  |        |   |  |      |  |  |        |   |      |  |  |  |        |  
|--------------------------------------------------------------------------------------------- |  | ----- | ---- |  |  |  | ---- |  | ------ | - |  | ---- |  |  | ------ | - | ---- |  |  |  | ------ | -
|                                                                                              |  | Notes |      |  |  |  | 2015 |  |        |   |  | 2014 |  |  |        |   | 2013 | 
|                                                                                              |  |       |      |  |  |  |     
|Revenues                                                                                      |  |       | 1    |  |  |  |      |  |        |   |  |      |  |  |        |   |      |  |  |  |        |  
|Gross Sales                                                                                   |  |       |      |  |  |  |      |  | 13,207 |   |  |      |  |  | 20,107 |   |      |  |  |  | 18,993 |  
|Less: Royalties                                                                               |  |       |      |  |  |  |      |  | 143    |   |  |      |  |  | 465    |   |      |  |  |  | 336    |  
|                                                                                              |  |       |      |  |  |  |      |  | 13,064 |   |  |      |  |  | 19,642 |   |      |  |  |  | 18,657 |  
|Expenses                                                                                      |  |       | 1    |  |  |  |      |  |        |   |  |      |  |  |        |   |      |  |  |  |        |  
|Purchased Product                                                                             |  |       |      |  |  |  |      |  | 7,374  |   |  |      |  |  | 10,955 |   |      |  |  |  | 10,399 |  
|Transportation and Blending                                                                   |  |       |      |  |  |  |      |  | 2,043  |   |  |      |  |  | 2,477  |   |      |  |  |  | 2,074  |  
|Operating                                                                                     |  |       |      |  |  |  |      |  | 1,839  |   |  |      |  |  | 2,045  |   |      |  |  |  | 1,782  |  
|Production and Mineral Taxes                                                                  |  |       |      |  |  |  |      |  | 18     |   |  |      |  |  | 46     |   |      |  |  |  | 35     |  
|(Gain) Loss on Risk Management                                                                |  |       | 31   |  |  |  |      |  | (461   | ) |  |      |  |  | (662   | ) |      |  |  |  | 293    |  
|Depreciation, Depletion and Amortization                                                      |  |       | 9,16 |  |  |  |      |  | 2,114  |   |  |      |  |  | 1,946  |   |      |  |  |  | 1,833  |  
|Goodwill Impairment                                                                           |  |       | 9    |  |  |  |      |  | -      |   |  |      |  |  | 497    |   |      |  |  |  | -      |  
|Exploration Expense                                                                           |  |       | 9,15 |  |  |  |      |  | 138    |   |  |      |  |  | 86     |   |      |  |  |  | 114    |  
|General and Administrative                                                                    |  |       |      |  |  |  |      |  | 335    |   |  |      |  |  | 379    |   |      |  |  |  | 365    |  
|Finance Costs                                                                                 |  |       | 5    |  |  |  |      |  | 482    |   |  |      |  |  | 445    |   |      |  |  |  | 529    |  
|Interest Income                                                                               |  |       | 6    |  |  |  |      |  | (28    | ) |  |      |  |  | (33    | ) |      |  |  |  | (96    | )
|Foreign Exchange (Gain) Loss, Net                                                             |  |       | 7    |  |  |  |      |  | 1,036  |   |  |      |  |  | 411    |   |      |  |  |  | 208    |  
|Research Costs                                                                                |  |       |      |  |  |  |      |  | 27     |   |  |      |  |  | 15     |   |      |  |  |  | 24     |  
|(Gain) Loss on Divestiture of Assets                                                          |  |       | 8    |  |  |  |      |  | (2,392 | ) |  |      |  |  | (156   | ) |      |  |  |  | 1      |  
|Other (Income) Loss, Net                                                                      |  |       |      |  |  |  |      |  | 2      |   |  |      |  |  | (4     | ) |      |  |  |  | 2      |  
|Earnings Before Income Tax                                                                    |  |       |      |  |  |  |      |  | 537    |   |  |      |  |  | 1,195  |   |      |  |  |  | 1,094  |  
|Income Tax Expense (Recovery)                                                                 |  |       | 10   |  |  |  |      |  | (81    | ) |  |      |  |  | 451    |   |      |  |  |  | 432    |  
|Net Earnings                                                                                  |  |       |      |  |  |  |      |  | 618    |   |  |      |  |  | 744    |   |      |  |  |  | 662    |  
|                                                                                              |  |       |      |  |  |  |     
|Net Earnings Per Share                                                                        |  |       | 11   |  |  |  |      |  |        |   |  |      |  |  |        |   |      |  |  |  |        |  
|Basic                                                                                         |  |       |      |  |  |  |      |  | $0.75  |   |  |      |  |  | $0.98  |   |      |  |  |  | $0.88  |  
|Diluted                                                                                       |  |       |      |  |  |  |      |  | $0.75  |   |  |      |  |  | $0.98  |   |      |  |  |  | $0.87  |  
|                                                                                              | 
|See accompanying Notes to Consolidated Financial
Statements.                                  | 
|                                                                                             
|CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME
For the years ended December 31,
($ millions) | 
|                                                                                              |  |       |      |  |  |  | 2015 |  |        |   |  | 2014 |  |  |        |   | 2013 | 
|                                                                                              |  |       |      |  |  |  |     
|Net Earnings                                                                                  |  |       |      |  |  |  |      |  | 618    |   |  |      |  |  | 744    |   |      |  |  |  | 662    |  
|Other Comprehensive Income (Loss), Net of Tax                                                 |  |       | 26   |  |  |  |      |  |        |   |  |      |  |  |        |   |      |  |  |  |        |  
|Items That Will Not be Reclassified to Profit or Loss:                                        |  |       |      |  |  |  |      |  |        |   |  |      |  |  |        |   |      |  |  |  |        |  
|Actuarial Gain (Loss) Relating to Pension and Other Post-Retirement Benefits                  |  |       |      |  |  |  |      |  | 20     |   |  |      |  |  | (18    | ) |      |  |  |  | 14     |  
|Items That May be Reclassified to Profit or Loss:                                             |  |       |      |  |  |  |      |  |        |   |  |      |  |  |        |   |      |  |  |  |        |  
|Change in Value of Available for Sale Financial Assets                                        |  |       |      |  |  |  |      |  | 6      |   |  |      |  |  | -      |   |      |  |  |  | 10     |  
|Foreign Currency Translation Adjustment                                                       |  |       |      |  |  |  |      |  | 587    |   |  |      |  |  | 215    |   |      |  |  |  | 117    |  
|Total Other Comprehensive Income, Net of Tax                                                  |  |       |      |  |  |  |      |  | 613    |   |  |      |  |  | 197    |   |      |  |  |  | 141    |  
|Comprehensive Income                                                                          |  |       |      |  |  |  |      |  | 1,231  |   |  |      |  |  | 941    |   |      |  |  |  | 803    |  





See accompanying Notes to Consolidated Financial Statements.



|                    |  |   |  |                                  
|------------------- |  | - |  | ---------------------------------
|Cenovus Energy Inc. |  | 5 |  | Consolidated Financial Statements



---

##### Table of Contents

CONSOLIDATED BALANCE SHEETS

As at December 31,

($ millions)



|                                           |  |       |       |  |  |  |      |  |        |  |  |      |  |  |        | 
|------------------------------------------ |  | ----- | ----- |  |  |  | ---- |  | ------ |  |  | ---- |  |  | ------ | 
|                                           |  | Notes |       |  |  |  | 2015 |  |        |  |  | 2014 | 
|                                           |  |       |       |  | 
|Assets                                     |  |       |       |  |  |  |      |  |        |  |  |      |  |  |        | 
|Current Assets                             |  |       |       |  |  |  |      |  |        |  |  |      |  |  |        | 
|Cash and Cash Equivalents                  |  |       | 12    |  |  |  |      |  | 4,105  |  |  |      |  |  | 883    | 
|Accounts Receivable and Accrued Revenues   |  |       | 13    |  |  |  |      |  | 1,251  |  |  |      |  |  | 1,582  | 
|Income Tax Receivable                      |  |       |       |  |  |  |      |  | 6      |  |  |      |  |  | 28     | 
|Inventories                                |  |       | 14    |  |  |  |      |  | 810    |  |  |      |  |  | 1,224  | 
|Risk Management                            |  |       | 31,32 |  |  |  |      |  | 301    |  |  |      |  |  | 478    | 
|Current Assets                             |  |       |       |  |  |  |      |  | 6,473  |  |  |      |  |  | 4,195  | 
|Exploration and Evaluation Assets          |  |       | 1,15  |  |  |  |      |  | 1,575  |  |  |      |  |  | 1,625  | 
|Property, Plant and Equipment, Net         |  |       | 1,16  |  |  |  |      |  | 17,335 |  |  |      |  |  | 18,563 | 
|Income Tax Receivable                      |  |       |       |  |  |  |      |  | 90     |  |  |      |  |  | -      | 
|Other Assets                               |  |       | 18    |  |  |  |      |  | 76     |  |  |      |  |  | 70     | 
|Goodwill                                   |  |       | 1,19  |  |  |  |      |  | 242    |  |  |      |  |  | 242    | 
|Total Assets                               |  |       |       |  |  |  |      |  | 25,791 |  |  |      |  |  | 24,695 | 
|                                           |  |       |       |  | 
|Liabilities and Shareholders Equity       |  |       |       |  |  |  |      |  |        |  |  |      |  |  |        | 
|Current Liabilities                        |  |       |       |  |  |  |      |  |        |  |  |      |  |  |        | 
|Accounts Payable and Accrued Liabilities   |  |       | 20    |  |  |  |      |  | 1,702  |  |  |      |  |  | 2,588  | 
|Income Tax Payable                         |  |       |       |  |  |  |      |  | 133    |  |  |      |  |  | 357    | 
|Risk Management                            |  |       | 31,32 |  |  |  |      |  | 23     |  |  |      |  |  | 12     | 
|Current Liabilities                        |  |       |       |  |  |  |      |  | 1,858  |  |  |      |  |  | 2,957  | 
|Long-Term Debt                             |  |       | 21    |  |  |  |      |  | 6,525  |  |  |      |  |  | 5,458  | 
|Risk Management                            |  |       | 31,32 |  |  |  |      |  | 7      |  |  |      |  |  | 4      | 
|Decommissioning Liabilities                |  |       | 22    |  |  |  |      |  | 2,052  |  |  |      |  |  | 2,616  | 
|Other Liabilities                          |  |       | 23    |  |  |  |      |  | 142    |  |  |      |  |  | 172    | 
|Deferred Income Taxes                      |  |       | 10    |  |  |  |      |  | 2,816  |  |  |      |  |  | 3,302  | 
|Total Liabilities                          |  |       |       |  |  |  |      |  | 13,400 |  |  |      |  |  | 14,509 | 
|Shareholders Equity                       |  |       |       |  |  |  |      |  | 12,391 |  |  |      |  |  | 10,186 | 
|Total Liabilities and Shareholders Equity |  |       |       |  |  |  |      |  | 25,791 |  |  |      |  |  | 24,695 | 
|                                           |  |       |       |  | 
|Commitments and Contingencies              |  |       | 34    |  |  |  |      |  |        |  |  |      |  |  |        | 





See accompanying Notes to Consolidated Financial Statements.

Approved by the Board of Directors





|                       |  |                    
|---------------------- |  | -------------------
|/s/ Michael A. Grandin |  | /s/ Colin Taylor   
|                       | 
|Michael A. Grandin     |  | Colin Taylor       
|Director               |  | Director           
|Cenovus Energy Inc.    |  | Cenovus Energy Inc.



|                    |  |   |  |                                  
|------------------- |  | - |  | ---------------------------------
|Cenovus Energy Inc. |  | 6 |  | Consolidated Financial Statements



---

##### Table of Contents



CONSOLIDATED STATEMENTS OF SHAREHOLDERS EQUITY

($ millions)



|                                                            |  |               |          |   |  |  |                 |  |          |   |  |                   |  |  |       |   |          |  |  |  |          |       |  |  |  |  |        |  
|----------------------------------------------------------- |  | ------------- | -------- | - |  |  | --------------- |  | -------- | - |  | ----------------- |  |  | ----- | - | -------- |  |  |  | -------- | ----- |  |  |  |  | ------ | -
|                                                            |  | Share
Capital |          |   |  |  | Paid in
Surplus |  |          |   |  | Retained
Earnings |  |  |       |   | AOCI (1) |  |  |  |          | Total | 
|                                                            |  |               | (Note 25 | ) |  |  |                 |  | (Note 25 | ) |  |                   |  |  |       |   |          |  |  |  | (Note 26 | )     |  |  |  |  |        |  
|                                                            |  |               |          |   |  |  |                 |  |         
|Balance as at December 31, 2012                             |  |               | 3,829    |   |  |  |                 |  | 4,154    |   |  |                   |  |  | 1,730 |   |          |  |  |  | 69       |       |  |  |  |  | 9,782  |  
|Net Earnings                                                |  |               | -        |   |  |  |                 |  | -        |   |  |                   |  |  | 662   |   |          |  |  |  | -        |       |  |  |  |  | 662    |  
|Other Comprehensive Income (Loss)                           |  |               | -        |   |  |  |                 |  | -        |   |  |                   |  |  | -     |   |          |  |  |  | 141      |       |  |  |  |  | 141    |  
|Total Comprehensive Income (Loss)                           |  |               | -        |   |  |  |                 |  | -        |   |  |                   |  |  | 662   |   |          |  |  |  | 141      |       |  |  |  |  | 803    |  
|Common Shares Issued Under Stock Option Plans               |  |               | 31       |   |  |  |                 |  | -        |   |  |                   |  |  | -     |   |          |  |  |  | -        |       |  |  |  |  | 31     |  
|Common Shares Cancelled                                     |  |               | (3       | ) |  |  |                 |  | 3        |   |  |                   |  |  | -     |   |          |  |  |  | -        |       |  |  |  |  | -      |  
|Stock-Based Compensation Expense                            |  |               | -        |   |  |  |                 |  | 62       |   |  |                   |  |  | -     |   |          |  |  |  | -        |       |  |  |  |  | 62     |  
|Dividends on Common Shares                                  |  |               | -        |   |  |  |                 |  | -        |   |  |                   |  |  | (732  | ) |          |  |  |  | -        |       |  |  |  |  | (732   | )
|Balance as at December 31, 2013                             |  |               | 3,857    |   |  |  |                 |  | 4,219    |   |  |                   |  |  | 1,660 |   |          |  |  |  | 210      |       |  |  |  |  | 9,946  |  
|Net Earnings                                                |  |               | -        |   |  |  |                 |  | -        |   |  |                   |  |  | 744   |   |          |  |  |  | -        |       |  |  |  |  | 744    |  
|Other Comprehensive Income (Loss)                           |  |               | -        |   |  |  |                 |  | -        |   |  |                   |  |  | -     |   |          |  |  |  | 197      |       |  |  |  |  | 197    |  
|Total Comprehensive Income (Loss)                           |  |               | -        |   |  |  |                 |  | -        |   |  |                   |  |  | 744   |   |          |  |  |  | 197      |       |  |  |  |  | 941    |  
|Common Shares Issued Under Stock Option Plans               |  |               | 32       |   |  |  |                 |  | -        |   |  |                   |  |  | -     |   |          |  |  |  | -        |       |  |  |  |  | 32     |  
|Stock-Based Compensation Expense                            |  |               | -        |   |  |  |                 |  | 72       |   |  |                   |  |  | -     |   |          |  |  |  | -        |       |  |  |  |  | 72     |  
|Dividends on Common Shares                                  |  |               | -        |   |  |  |                 |  | -        |   |  |                   |  |  | (805  | ) |          |  |  |  | -        |       |  |  |  |  | (805   | )
|Balance as at December 31, 2014                             |  |               | 3,889    |   |  |  |                 |  | 4,291    |   |  |                   |  |  | 1,599 |   |          |  |  |  | 407      |       |  |  |  |  | 10,186 |  
|Net Earnings                                                |  |               | -        |   |  |  |                 |  | -        |   |  |                   |  |  | 618   |   |          |  |  |  | -        |       |  |  |  |  | 618    |  
|Other Comprehensive Income (Loss)                           |  |               | -        |   |  |  |                 |  | -        |   |  |                   |  |  | -     |   |          |  |  |  | 613      |       |  |  |  |  | 613    |  
|Total Comprehensive Income (Loss)                           |  |               | -        |   |  |  |                 |  | -        |   |  |                   |  |  | 618   |   |          |  |  |  | 613      |       |  |  |  |  | 1,231  |  
|Common Shares Issued for Cash                               |  |               | 1,463    |   |  |  |                 |  | -        |   |  |                   |  |  | -     |   |          |  |  |  | -        |       |  |  |  |  | 1,463  |  
|Common Shares Issued Pursuant to Dividend Reinvestment Plan |  |               | 182      |   |  |  |                 |  | -        |   |  |                   |  |  | -     |   |          |  |  |  | -        |       |  |  |  |  | 182    |  
|Common Shares Issued Under Stock Option Plans               |  |               | -        |   |  |  |                 |  | -        |   |  |                   |  |  | -     |   |          |  |  |  | -        |       |  |  |  |  | -      |  
|Stock-Based Compensation Expense                            |  |               | -        |   |  |  |                 |  | 39       |   |  |                   |  |  | -     |   |          |  |  |  | -        |       |  |  |  |  | 39     |  
|Dividends on Common Shares                                  |  |               | -        |   |  |  |                 |  | -        |   |  |                   |  |  | (710  | ) |          |  |  |  | -        |       |  |  |  |  | (710   | )
|Balance as at December 31, 2015                             |  |               | 5,534    |   |  |  |                 |  | 4,330    |   |  |                   |  |  | 1,507 |   |          |  |  |  | 1,020    |       |  |  |  |  | 12,391 |  
|                                                            |  |               |          |   |  |  |                 |  |          |   |  |                   |  |  |       |   |          |  |  |  |          |       |  |  |  |  |        |  



|(1) | Accumulated Other Comprehensive Income (Loss).
|--- | ----------------------------------------------

See accompanying Notes to Consolidated Financial Statements.



|                    |  |   |  |                                  
|------------------- |  | - |  | ---------------------------------
|Cenovus Energy Inc. |  | 7 |  | Consolidated Financial Statements



---

##### Table of Contents



CONSOLIDATED STATEMENTS OF CASH FLOWS

For the years ended December 31,

($ millions)



|                                                                                   |  |       |      |  |      |  |        |   |  |      |  |  |        |   |      |  |  |  |        |  
|---------------------------------------------------------------------------------- |  | ----- | ---- |  | ---- |  | ------ | - |  | ---- |  |  | ------ | - | ---- |  |  |  | ------ | -
|                                                                                   |  | Notes |      |  | 2015 |  |        |   |  | 2014 |  |  |        |   | 2013 | 
|                                                                                   |  |       |      |  |      | 
|Operating Activities                                                               |  |       |      |  |      |  |        |   |  |      |  |  |        |   |      |  |  |  |        |  
|Net Earnings                                                                       |  |       |      |  |      |  | 618    |   |  |      |  |  | 744    |   |      |  |  |  | 662    |  
|Depreciation, Depletion and Amortization                                           |  |       | 9,16 |  |      |  | 2,114  |   |  |      |  |  | 1,946  |   |      |  |  |  | 1,833  |  
|Goodwill Impairment                                                                |  |       | 9    |  |      |  | -      |   |  |      |  |  | 497    |   |      |  |  |  | -      |  
|Exploration Expense                                                                |  |       | 9,15 |  |      |  | 138    |   |  |      |  |  | 86     |   |      |  |  |  | 50     |  
|Deferred Income Taxes                                                              |  |       | 10   |  |      |  | (655   | ) |  |      |  |  | 359    |   |      |  |  |  | 244    |  
|Unrealized (Gain) Loss on Risk Management                                          |  |       | 31   |  |      |  | 195    |   |  |      |  |  | (596   | ) |      |  |  |  | 415    |  
|Unrealized Foreign Exchange (Gain) Loss                                            |  |       | 7    |  |      |  | 1,097  |   |  |      |  |  | 411    |   |      |  |  |  | 40     |  
|(Gain) Loss on Divestiture of Assets                                               |  |       | 8    |  |      |  | (2,392 | ) |  |      |  |  | (156   | ) |      |  |  |  | 1      |  
|Current Tax on Divestiture of Assets                                               |  |       | 8    |  |      |  | 391    |   |  |      |  |  | -      |   |      |  |  |  | -      |  
|Unwinding of Discount on Decommissioning Liabilities                               |  |       | 5,22 |  |      |  | 126    |   |  |      |  |  | 120    |   |      |  |  |  | 97     |  
|Other                                                                              |  |       |      |  |      |  | 59     |   |  |      |  |  | 68     |   |      |  |  |  | 267    |  
|Net Change in Other Assets and Liabilities                                         |  |       |      |  |      |  | (107   | ) |  |      |  |  | (135   | ) |      |  |  |  | (120   | )
|Net Change in Non-Cash Working Capital                                             |  |       |      |  |      |  | (110   | ) |  |      |  |  | 182    |   |      |  |  |  | 50     |  
|Cash From Operating Activities                                                     |  |       |      |  |      |  | 1,474  |   |  |      |  |  | 3,526  |   |      |  |  |  | 3,539  |  
|                                                                                   |  |       |      |  |      | 
|Investing Activities                                                               |  |       |      |  |      |  |        |   |  |      |  |  |        |   |      |  |  |  |        |  
|Capital Expenditures  Exploration and Evaluation Assets                           |  |       | 15   |  |      |  | (138   | ) |  |      |  |  | (279   | ) |      |  |  |  | (331   | )
|Capital Expenditures  Property, Plant and Equipment                               |  |       | 16   |  |      |  | (1,576 | ) |  |      |  |  | (2,779 | ) |      |  |  |  | (2,938 | )
|Acquisition                                                                        |  |       | 17   |  |      |  | (84    | ) |  |      |  |  | -      |   |      |  |  |  | -      |  
|Proceeds From Divestiture of Assets                                                |  |       | 8    |  |      |  | 3,344  |   |  |      |  |  | 276    |   |      |  |  |  | 258    |  
|Current Tax on Divestiture of Assets                                               |  |       | 8    |  |      |  | (391   | ) |  |      |  |  | -      |   |      |  |  |  | -      |  
|Net Change in Investments and Other                                                |  |       |      |  |      |  | 3      |   |  |      |  |  | (1,583 | ) |      |  |  |  | 1,486  |  
|Net Change in Non-Cash Working Capital                                             |  |       |      |  |      |  | (270   | ) |  |      |  |  | 15     |   |      |  |  |  | 6      |  
|Cash From (Used in) Investing Activities                                           |  |       |      |  |      |  | 888    |   |  |      |  |  | (4,350 | ) |      |  |  |  | (1,519 | )
|                                                                                   |  |       |      |  |      |  |        |   |  |      |  |  |        |   |      |  |  |  |        |  
|Net Cash Provided (Used) Before Financing Activities                               |  |       |      |  |      |  | 2,362  |   |  |      |  |  | (824   | ) |      |  |  |  | 2,020  |  
|                                                                                   |  |       |      |  |      | 
|Financing Activities                                                               |  |       |      |  |      |  |        |   |  |      |  |  |        |   |      |  |  |  |        |  
|Net Issuance (Repayment) of Short-Term Borrowings                                  |  |       |      |  |      |  | (25    | ) |  |      |  |  | (18    | ) |      |  |  |  | (8     | )
|Issuance of U.S. Unsecured Notes                                                   |  |       | 21   |  |      |  | -      |   |  |      |  |  | -      |   |      |  |  |  | 814    |  
|Repayment of U.S. Unsecured Notes                                                  |  |       | 21   |  |      |  | -      |   |  |      |  |  | -      |   |      |  |  |  | (825   | )
|Common Shares Issued, Net of Issuance Costs                                        |  |       | 25   |  |      |  | 1,449  |   |  |      |  |  | -      |   |      |  |  |  | -      |  
|Common Shares Issued Under Stock Option Plans                                      |  |       |      |  |      |  | -      |   |  |      |  |  | 28     |   |      |  |  |  | 28     |  
|Dividends Paid on Common Shares                                                    |  |       | 11   |  |      |  | (528   | ) |  |      |  |  | (805   | ) |      |  |  |  | (732   | )
|Other                                                                              |  |       |      |  |      |  | (2     | ) |  |      |  |  | (2     | ) |      |  |  |  | (3     | )
|Cash From (Used in) Financing Activities                                           |  |       |      |  |      |  | 894    |   |  |      |  |  | (797   | ) |      |  |  |  | (726   | )
|                                                                                   |  |       |      |  |      | 
|Foreign Exchange Gain (Loss) on Cash and Cash Equivalents Held in Foreign Currency |  |       |      |  |      |  | (34    | ) |  |      |  |  | 52     |   |      |  |  |  | (2     | )
|Increase (Decrease) in Cash and Cash Equivalents                                   |  |       |      |  |      |  | 3,222  |   |  |      |  |  | (1,569 | ) |      |  |  |  | 1,292  |  
|Cash and Cash Equivalents, Beginning of Year                                       |  |       |      |  |      |  | 883    |   |  |      |  |  | 2,452  |   |      |  |  |  | 1,160  |  
|Cash and Cash Equivalents, End of Year                                             |  |       |      |  |      |  | 4,105  |   |  |      |  |  | 883    |   |      |  |  |  | 2,452  |  
|                                                                                   |  |       |      |  |      | 
|Supplementary Cash Flow Information                                                |  |       | 33   |  |      |  |        |   |  |      |  |  |        |   |      |  |  |  |        |  
|                                                                                   |  |       |      |  |      |  |        |   |  |      |  |  |        |   |      |  |  |  |        |  

See accompanying Notes to Consolidated Financial Statements.



|                    |  |   |  |                                  
|------------------- |  | - |  | ---------------------------------
|Cenovus Energy Inc. |  | 8 |  | Consolidated Financial Statements



---

##### Table of Contents

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

All amounts in $ millions, unless otherwise indicated

For the year ended December 31, 2015

1. DESCRIPTION OF BUSINESS AND SEGMENTED DISCLOSURES



Cenovus Energy Inc. and
its subsidiaries, (together Cenovus or the Company) are in the business of developing, producing and marketing crude oil, natural gas liquids (NGLs) and natural gas in Canada with marketing activities and refining
operations in the United States (U.S.).

Cenovus is incorporated under the Canada Business Corporations Act and its shares are
listed on the Toronto (TSX) and New York (NYSE) stock exchanges. The executive and registered office is located at 2600, 500 Centre Street S.E., Calgary, Alberta, Canada, T2G 1A6. Information on the Companys basis of
preparation for these Consolidated Financial Statements is found in Note 2.

Management has determined the operating segments based on information
regularly reviewed for the purposes of decision making, allocating resources and assessing operational performance by Cenovuss chief operating decision makers. The Company evaluates the financial performance of its operating segments primarily
based on operating cash flow. The Companys reportable segments are:



| |  |  | Oil Sands, which includes the development and production of bitumen and natural gas in northeast Alberta. Cenovuss
bitumen assets include Foster Creek, Christina Lake and Narrows Lake as well as projects in the early stages of development, such as Grand Rapids and Telephone Lake. Certain of the Companys operated oil sands properties, notably Foster Creek,
Christina Lake and Narrows Lake, are jointly owned with ConocoPhillips, an unrelated U.S. public company.
| | - |  | ---------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------



| |  |  | Conventional, which includes the development and production of conventional crude oil, NGLs and natural gas in Alberta and
Saskatchewan, including the heavy oil assets at Pelican Lake, the carbon dioxide enhanced oil recovery project at Weyburn and emerging tight oil opportunities.
| | - |  | ------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------



| |  |  | Refining and Marketing, which is responsible for transporting, selling and refining crude oil into petroleum and chemical
products. Cenovus jointly owns two refineries in the U.S. with the operator Phillips 66, an unrelated U.S. public company. In addition, Cenovus owns and operates a crude-by-rail terminal in Alberta. This segment coordinates Cenovuss marketing
and transportation initiatives to optimize product mix, delivery points, transportation commitments and customer diversification. The marketing of crude oil and natural gas sourced from Canada, including physical product sales that settle in the
U.S., is considered to be undertaken by a Canadian business. U.S. sourced crude oil and natural gas purchases and sales are attributed to the U.S.
| | - |  | --------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------



| |  |  | Corporate and Eliminations, which primarily includes unrealized gains and losses recorded on derivative financial
instruments, gains and losses on divestiture of assets, as well as other Cenovus-wide costs for general and administrative, financing activities and research costs. As financial instruments are settled, the realized gains and losses are recorded in
the operating segment to which the derivative instrument relates. Eliminations relate to sales and operating revenues, and purchased product between segments, recorded at transfer prices based on current market prices, and to unrealized intersegment
profits in inventory. The Corporate and Eliminations segment is attributed to Canada, with the exception of unrealized risk management gains and losses, which have been attributed to the country in which the transacting entity resides.
| | - |  | --------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------

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



|                    |  |   |  |                                  
|------------------- |  | - |  | ---------------------------------
|Cenovus Energy Inc. |  | 9 |  | Consolidated Financial Statements



---

##### Table of Contents

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

All amounts in $ millions, unless otherwise indicated

For the year ended December 31, 2015



A) Results of Operations  Segment and Operational Information



|                                         |  |           |       |   |  |  |              |  |       |   |  |                        |  |  |       |   |                            |  |  |  |        |              |  |  |  |  |       |   |  |  |  |      |       |   |  |  |      |  |        |   |  |      |  |  |        |   |  |  |  |  |        |  
|---------------------------------------- |  | --------- | ----- | - |  |  | ------------ |  | ----- | - |  | ---------------------- |  |  | ----- | - | -------------------------- |  |  |  | ------ | ------------ |  |  |  |  | ----- | - |  |  |  | ---- | ----- | - |  |  | ---- |  | ------ | - |  | ---- |  |  | ------ | - |  |  |  |  | ------ | -
|                                         |  | Oil Sands |       |   |  |  | Conventional |  |       |   |  | Refining and Marketing | 
|For the years ended December 31,         |  | 2015      |       |   |  |  | 2014         |  |       |   |  | 2013                   |  |  |       |   | 2015                       |  |  |  |        | 2014         |  |  |  |  | 2013  |   |  |  |  | 2015 |       |   |  |  | 2014 |  |        |   |  | 2013 | 
|                                         |  |           |       |   |  |  |              |  |       |   |  |                        |  |  |       |   |                           
|Revenues                                 |  |           |       |   |  |  |              |  |       |   |  |                        |  |  |       |   |                            |  |  |  |        |              |  |  |  |  |       |   |  |  |  |      |       |   |  |  |      |  |        |   |  |      |  |  |        |   |  |  |  |  |        |  
|Gross Sales                              |  |           | 3,030 |   |  |  |              |  | 5,036 |   |  |                        |  |  | 3,912 |   |                            |  |  |  | 1,709  |              |  |  |  |  | 3,225 |   |  |  |  |      | 2,980 |   |  |  |      |  | 8,805  |   |  |      |  |  | 12,658 |   |  |  |  |  | 12,706 |  
|Less: Royalties                          |  |           | 29    |   |  |  |              |  | 236   |   |  |                        |  |  | 132   |   |                            |  |  |  | 114    |              |  |  |  |  | 229   |   |  |  |  |      | 204   |   |  |  |      |  | -      |   |  |      |  |  | -      |   |  |  |  |  | -      |  
|                                         |  |           | 3,001 |   |  |  |              |  | 4,800 |   |  |                        |  |  | 3,780 |   |                            |  |  |  | 1,595  |              |  |  |  |  | 2,996 |   |  |  |  |      | 2,776 |   |  |  |      |  | 8,805  |   |  |      |  |  | 12,658 |   |  |  |  |  | 12,706 |  
|Expenses                                 |  |           |       |   |  |  |              |  |       |   |  |                        |  |  |       |   |                            |  |  |  |        |              |  |  |  |  |       |   |  |  |  |      |       |   |  |  |      |  |        |   |  |      |  |  |        |   |  |  |  |  |        |  
|Purchased Product                        |  |           | -     |   |  |  |              |  | -     |   |  |                        |  |  | -     |   |                            |  |  |  | -      |              |  |  |  |  | -     |   |  |  |  |      | -     |   |  |  |      |  | 7,709  |   |  |      |  |  | 11,767 |   |  |  |  |  | 11,004 |  
|Transportation and Blending              |  |           | 1,815 |   |  |  |              |  | 2,131 |   |  |                        |  |  | 1,749 |   |                            |  |  |  | 230    |              |  |  |  |  | 346   |   |  |  |  |      | 325   |   |  |  |      |  | -      |   |  |      |  |  | -      |   |  |  |  |  | -      |  
|Operating                                |  |           | 531   |   |  |  |              |  | 639   |   |  |                        |  |  | 548   |   |                            |  |  |  | 561    |              |  |  |  |  | 709   |   |  |  |  |      | 701   |   |  |  |      |  | 754    |   |  |      |  |  | 703    |   |  |  |  |  | 538    |  
|Production and Mineral Taxes             |  |           | -     |   |  |  |              |  | -     |   |  |                        |  |  | -     |   |                            |  |  |  | 18     |              |  |  |  |  | 46    |   |  |  |  |      | 35    |   |  |  |      |  | -      |   |  |      |  |  | -      |   |  |  |  |  | -      |  
|(Gain) Loss on Risk Management           |  |           | (404  | ) |  |  |              |  | (38   | ) |  |                        |  |  | (37   | ) |                            |  |  |  | (209   | )            |  |  |  |  | (1    | ) |  |  |  |      | (104  | ) |  |  |      |  | (43    | ) |  |      |  |  | (27    | ) |  |  |  |  | 19     |  
|Operating Cash Flow                      |  |           | 1,059 |   |  |  |              |  | 2,068 |   |  |                        |  |  | 1,520 |   |                            |  |  |  | 995    |              |  |  |  |  | 1,896 |   |  |  |  |      | 1,819 |   |  |  |      |  | 385    |   |  |      |  |  | 215    |   |  |  |  |  | 1,145  |  
|Depreciation, Depletion and Amortization |  |           | 697   |   |  |  |              |  | 625   |   |  |                        |  |  | 446   |   |                            |  |  |  | 1,148  |              |  |  |  |  | 1,082 |   |  |  |  |      | 1,170 |   |  |  |      |  | 191    |   |  |      |  |  | 156    |   |  |  |  |  | 138    |  
|Goodwill Impairment                      |  |           | -     |   |  |  |              |  | -     |   |  |                        |  |  | -     |   |                            |  |  |  | -      |              |  |  |  |  | 497   |   |  |  |  |      | -     |   |  |  |      |  | -      |   |  |      |  |  | -      |   |  |  |  |  | -      |  
|Exploration Expense                      |  |           | 67    |   |  |  |              |  | 4     |   |  |                        |  |  | -     |   |                            |  |  |  | 71     |              |  |  |  |  | 82    |   |  |  |  |      | 114   |   |  |  |      |  | -      |   |  |      |  |  | -      |   |  |  |  |  | -      |  
|Segment Income (Loss)                    |  |           | 295   |   |  |  |              |  | 1,439 |   |  |                        |  |  | 1,074 |   |                            |  |  |  | (224   | )            |  |  |  |  | 235   |   |  |  |  |      | 535   |   |  |  |      |  | 194    |   |  |      |  |  | 59     |   |  |  |  |  | 1,007  |  
|                                         |  |           |       |   |  |  |              |  |      
|                                         |  |           |       |   |  |  |              |  |       |   |  |                        |  |  |       |   | Corporate and Eliminations |  |  |  |        | Consolidated | 
|For the years ended December 31,         |  |           |       |   |  |  |              |  |       |   |  |                        |  |  |       |   | 2015                       |  |  |  |        | 2014         |  |  |  |  | 2013  |   |  |  |  | 2015 |       |   |  |  | 2014 |  |        |   |  | 2013 | 
|                                         |  |           |       |   |  |  |              |  |       |   |  |                        |  |  |       |   |                           
|Revenues                                 |  |           |       |   |  |  |              |  |       |   |  |                        |  |  |       |   |                            |  |  |  |        |              |  |  |  |  |       |   |  |  |  |      |       |   |  |  |      |  |        |   |  |      |  |  |        |   |  |  |  |  |        |  
|Gross Sales                              |  |           |       |   |  |  |              |  |       |   |  |                        |  |  |       |   |                            |  |  |  | (337   | )            |  |  |  |  | (812  | ) |  |  |  |      | (605  | ) |  |  |      |  | 13,207 |   |  |      |  |  | 20,107 |   |  |  |  |  | 18,993 |  
|Less: Royalties                          |  |           |       |   |  |  |              |  |       |   |  |                        |  |  |       |   |                            |  |  |  | -      |              |  |  |  |  | -     |   |  |  |  |      | -     |   |  |  |      |  | 143    |   |  |      |  |  | 465    |   |  |  |  |  | 336    |  
|                                         |  |           |       |   |  |  |              |  |       |   |  |                        |  |  |       |   |                            |  |  |  | (337   | )            |  |  |  |  | (812  | ) |  |  |  |      | (605  | ) |  |  |      |  | 13,064 |   |  |      |  |  | 19,642 |   |  |  |  |  | 18,657 |  
|Expenses                                 |  |           |       |   |  |  |              |  |       |   |  |                        |  |  |       |   |                            |  |  |  |        |              |  |  |  |  |       |   |  |  |  |      |       |   |  |  |      |  |        |   |  |      |  |  |        |   |  |  |  |  |        |  
|Purchased Product                        |  |           |       |   |  |  |              |  |       |   |  |                        |  |  |       |   |                            |  |  |  | (335   | )            |  |  |  |  | (812  | ) |  |  |  |      | (605  | ) |  |  |      |  | 7,374  |   |  |      |  |  | 10,955 |   |  |  |  |  | 10,399 |  
|Transportation and Blending              |  |           |       |   |  |  |              |  |       |   |  |                        |  |  |       |   |                            |  |  |  | (2     | )            |  |  |  |  | -     |   |  |  |  |      | -     |   |  |  |      |  | 2,043  |   |  |      |  |  | 2,477  |   |  |  |  |  | 2,074  |  
|Operating                                |  |           |       |   |  |  |              |  |       |   |  |                        |  |  |       |   |                            |  |  |  | (7     | )            |  |  |  |  | (6    | ) |  |  |  |      | (5    | ) |  |  |      |  | 1,839  |   |  |      |  |  | 2,045  |   |  |  |  |  | 1,782  |  
|Production and Mineral Taxes             |  |           |       |   |  |  |              |  |       |   |  |                        |  |  |       |   |                            |  |  |  | -      |              |  |  |  |  | -     |   |  |  |  |      | -     |   |  |  |      |  | 18     |   |  |      |  |  | 46     |   |  |  |  |  | 35     |  
|(Gain) Loss on Risk Management           |  |           |       |   |  |  |              |  |       |   |  |                        |  |  |       |   |                            |  |  |  | 195    |              |  |  |  |  | (596  | ) |  |  |  |      | 415   |   |  |  |      |  | (461   | ) |  |      |  |  | (662   | ) |  |  |  |  | 293    |  
|Depreciation, Depletion and Amortization |  |           |       |   |  |  |              |  |       |   |  |                        |  |  |       |   |                            |  |  |  | 78     |              |  |  |  |  | 83    |   |  |  |  |      | 79    |   |  |  |      |  | 2,114  |   |  |      |  |  | 1,946  |   |  |  |  |  | 1,833  |  
|Goodwill Impairment                      |  |           |       |   |  |  |              |  |       |   |  |                        |  |  |       |   |                            |  |  |  | -      |              |  |  |  |  | -     |   |  |  |  |      | -     |   |  |  |      |  | -      |   |  |      |  |  | 497    |   |  |  |  |  | -      |  
|Exploration Expense                      |  |           |       |   |  |  |              |  |       |   |  |                        |  |  |       |   |                            |  |  |  | -      |              |  |  |  |  | -     |   |  |  |  |      | -     |   |  |  |      |  | 138    |   |  |      |  |  | 86     |   |  |  |  |  | 114    |  
|Segment Income (Loss)                    |  |           |       |   |  |  |              |  |       |   |  |                        |  |  |       |   |                            |  |  |  | (266   | )            |  |  |  |  | 519   |   |  |  |  |      | (489  | ) |  |  |      |  | (1     | ) |  |      |  |  | 2,252  |   |  |  |  |  | 2,127  |  
|General and Administrative               |  |           |       |   |  |  |              |  |       |   |  |                        |  |  |       |   |                            |  |  |  | 335    |              |  |  |  |  | 379   |   |  |  |  |      | 365   |   |  |  |      |  | 335    |   |  |      |  |  | 379    |   |  |  |  |  | 365    |  
|Finance Costs                            |  |           |       |   |  |  |              |  |       |   |  |                        |  |  |       |   |                            |  |  |  | 482    |              |  |  |  |  | 445   |   |  |  |  |      | 529   |   |  |  |      |  | 482    |   |  |      |  |  | 445    |   |  |  |  |  | 529    |  
|Interest Income                          |  |           |       |   |  |  |              |  |       |   |  |                        |  |  |       |   |                            |  |  |  | (28    | )            |  |  |  |  | (33   | ) |  |  |  |      | (96   | ) |  |  |      |  | (28    | ) |  |      |  |  | (33    | ) |  |  |  |  | (96    | )
|Foreign Exchange (Gain) Loss, Net        |  |           |       |   |  |  |              |  |       |   |  |                        |  |  |       |   |                            |  |  |  | 1,036  |              |  |  |  |  | 411   |   |  |  |  |      | 208   |   |  |  |      |  | 1,036  |   |  |      |  |  | 411    |   |  |  |  |  | 208    |  
|Research Costs                           |  |           |       |   |  |  |              |  |       |   |  |                        |  |  |       |   |                            |  |  |  | 27     |              |  |  |  |  | 15    |   |  |  |  |      | 24    |   |  |  |      |  | 27     |   |  |      |  |  | 15     |   |  |  |  |  | 24     |  
|(Gain) Loss on Divestiture of Assets     |  |           |       |   |  |  |              |  |       |   |  |                        |  |  |       |   |                            |  |  |  | (2,392 | )            |  |  |  |  | (156  | ) |  |  |  |      | 1     |   |  |  |      |  | (2,392 | ) |  |      |  |  | (156   | ) |  |  |  |  | 1      |  
|Other (Income) Loss, Net                 |  |           |       |   |  |  |              |  |       |   |  |                        |  |  |       |   |                            |  |  |  | 2      |              |  |  |  |  | (4    | ) |  |  |  |      | 2     |   |  |  |      |  | 2      |   |  |      |  |  | (4     | ) |  |  |  |  | 2      |  
|                                         |  |           |       |   |  |  |              |  |       |   |  |                        |  |  |       |   |                            |  |  |  | (538   | )            |  |  |  |  | 1,057 |   |  |  |  |      | 1,033 |   |  |  |      |  | (538   | ) |  |      |  |  | 1,057  |   |  |  |  |  | 1,033  |  
|Earnings Before Income Tax               |  |           |       |   |  |  |              |  |       |   |  |                        |  |  |       |   |                            |  |  |  |        |              |  |  |  |  |       |   |  |  |  |      |       |   |  |  |      |  | 537    |   |  |      |  |  | 1,195  |   |  |  |  |  | 1,094  |  
|Income Tax Expense (Recovery)            |  |           |       |   |  |  |              |  |       |   |  |                        |  |  |       |   |                            |  |  |  |        |              |  |  |  |  |       |   |  |  |  |      |       |   |  |  |      |  | (81    | ) |  |      |  |  | 451    |   |  |  |  |  | 432    |  
|Net Earnings                             |  |           |       |   |  |  |              |  |       |   |  |                        |  |  |       |   |                            |  |  |  |        |              |  |  |  |  |       |   |  |  |  |      |       |   |  |  |      |  | 618    |   |  |      |  |  | 744    |   |  |  |  |  | 662    |  



|                    |  |    |  |                                  
|------------------- |  | -- |  | ---------------------------------
|Cenovus Energy Inc. |  | 10 |  | Consolidated Financial Statements



---

##### Table of Contents

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

All amounts in $ millions, unless otherwise indicated

For the year ended December 31, 2015



B) Financial Results by Upstream Product



|                                 |  |                |       |   |  |  |              |  |       |   |  |       |  |  |       |   |      |  |  |  |       |      |  |  |  |  |       |   |  |  |  |      |       |   |  |  |      |  |       |   |  |      |  |  |       |   |  |  |  |  |       |  
|-------------------------------- |  | -------------- | ----- | - |  |  | ------------ |  | ----- | - |  | ----- |  |  | ----- | - | ---- |  |  |  | ----- | ---- |  |  |  |  | ----- | - |  |  |  | ---- | ----- | - |  |  | ---- |  | ----- | - |  | ---- |  |  | ----- | - |  |  |  |  | ----- | -
|                                 |  | Crude Oil (1)  |      
|                                 |  | Oil Sands      |       |   |  |  | Conventional |  |       |   |  | Total | 
|For the years ended December 31, |  | 2015           |       |   |  |  | 2014         |  |       |   |  | 2013  |  |  |       |   | 2015 |  |  |  |       | 2014 |  |  |  |  | 2013  |   |  |  |  | 2015 |       |   |  |  | 2014 |  |       |   |  | 2013 | 
|                                 |  |                |       |   |  |  |              |  |       |   |  |       |  |  |       |   |     
|Revenues                         |  |                |       |   |  |  |              |  |       |   |  |       |  |  |       |   |      |  |  |  |       |      |  |  |  |  |       |   |  |  |  |      |       |   |  |  |      |  |       |   |  |      |  |  |       |   |  |  |  |  |       |  
|Gross Sales                      |  |                | 3,000 |   |  |  |              |  | 4,963 |   |  |       |  |  | 3,850 |   |      |  |  |  | 1,239 |      |  |  |  |  | 2,456 |   |  |  |  |      | 2,373 |   |  |  |      |  | 4,239 |   |  |      |  |  | 7,419 |   |  |  |  |  | 6,223 |  
|Less: Royalties                  |  |                | 29    |   |  |  |              |  | 233   |   |  |       |  |  | 131   |   |      |  |  |  | 103   |      |  |  |  |  | 217   |   |  |  |  |      | 196   |   |  |  |      |  | 132   |   |  |      |  |  | 450   |   |  |  |  |  | 327   |  
|                                 |  |                | 2,971 |   |  |  |              |  | 4,730 |   |  |       |  |  | 3,719 |   |      |  |  |  | 1,136 |      |  |  |  |  | 2,239 |   |  |  |  |      | 2,177 |   |  |  |      |  | 4,107 |   |  |      |  |  | 6,969 |   |  |  |  |  | 5,896 |  
|Expenses                         |  |                |       |   |  |  |              |  |       |   |  |       |  |  |       |   |      |  |  |  |       |      |  |  |  |  |       |   |  |  |  |      |       |   |  |  |      |  |       |   |  |      |  |  |       |   |  |  |  |  |       |  
|Transportation and Blending      |  |                | 1,814 |   |  |  |              |  | 2,130 |   |  |       |  |  | 1,748 |   |      |  |  |  | 213   |      |  |  |  |  | 326   |   |  |  |  |      | 305   |   |  |  |      |  | 2,027 |   |  |      |  |  | 2,456 |   |  |  |  |  | 2,053 |  
|Operating                        |  |                | 511   |   |  |  |              |  | 615   |   |  |       |  |  | 527   |   |      |  |  |  | 381   |      |  |  |  |  | 505   |   |  |  |  |      | 489   |   |  |  |      |  | 892   |   |  |      |  |  | 1,120 |   |  |  |  |  | 1,016 |  
|Production and Mineral Taxes     |  |                | -     |   |  |  |              |  | -     |   |  |       |  |  | -     |   |      |  |  |  | 16    |      |  |  |  |  | 37    |   |  |  |  |      | 32    |   |  |  |      |  | 16    |   |  |      |  |  | 37    |   |  |  |  |  | 32    |  
|(Gain) Loss on Risk Management   |  |                | (400  | ) |  |  |              |  | (38   | ) |  |       |  |  | (33   | ) |      |  |  |  | (157  | )    |  |  |  |  | 4     |   |  |  |  |      | (43   | ) |  |  |      |  | (557  | ) |  |      |  |  | (34   | ) |  |  |  |  | (76   | )
|Operating Cash Flow              |  |                | 1,046 |   |  |  |              |  | 2,023 |   |  |       |  |  | 1,477 |   |      |  |  |  | 683   |      |  |  |  |  | 1,367 |   |  |  |  |      | 1,394 |   |  |  |      |  | 1,729 |   |  |      |  |  | 3,390 |   |  |  |  |  | 2,871 |  
|                                 |  |                |       |   |  |  |              |  |       |   |  |       |  |  |       |   |     
|(1) Includes NGLs.               |  |                |       |   |  |  |              |  |       |   |  |       |  |  |       |   |      |  |  |  |       |      |  |  |  |  |       |   |  |  |  |      |       |   |  |  |      |  |       |   |  |      |  |  |       |   |  |  |  |  |       |  
|                                 |  | Natural Gas    |      
|                                 |  | Oil Sands      |       |   |  |  | Conventional |  |       |   |  | Total | 
|For the years ended December 31, |  | 2015           |       |   |  |  | 2014         |  |       |   |  | 2013  |  |  |       |   | 2015 |  |  |  |       | 2014 |  |  |  |  | 2013  |   |  |  |  | 2015 |       |   |  |  | 2014 |  |       |   |  | 2013 | 
|                                 |  |                |       |   |  |  |              |  |       |   |  |       |  |  |       |   |     
|Revenues                         |  |                |       |   |  |  |              |  |       |   |  |       |  |  |       |   |      |  |  |  |       |      |  |  |  |  |       |   |  |  |  |      |       |   |  |  |      |  |       |   |  |      |  |  |       |   |  |  |  |  |       |  
|Gross Sales                      |  |                | 22    |   |  |  |              |  | 67    |   |  |       |  |  | 38    |   |      |  |  |  | 450   |      |  |  |  |  | 744   |   |  |  |  |      | 594   |   |  |  |      |  | 472   |   |  |      |  |  | 811   |   |  |  |  |  | 632   |  
|Less: Royalties                  |  |                | -     |   |  |  |              |  | 3     |   |  |       |  |  | 1     |   |      |  |  |  | 11    |      |  |  |  |  | 12    |   |  |  |  |      | 8     |   |  |  |      |  | 11    |   |  |      |  |  | 15    |   |  |  |  |  | 9     |  
|                                 |  |                | 22    |   |  |  |              |  | 64    |   |  |       |  |  | 37    |   |      |  |  |  | 439   |      |  |  |  |  | 732   |   |  |  |  |      | 586   |   |  |  |      |  | 461   |   |  |      |  |  | 796   |   |  |  |  |  | 623   |  
|Expenses                         |  |                |       |   |  |  |              |  |       |   |  |       |  |  |       |   |      |  |  |  |       |      |  |  |  |  |       |   |  |  |  |      |       |   |  |  |      |  |       |   |  |      |  |  |       |   |  |  |  |  |       |  
|Transportation and Blending      |  |                | 1     |   |  |  |              |  | 1     |   |  |       |  |  | 1     |   |      |  |  |  | 17    |      |  |  |  |  | 20    |   |  |  |  |      | 20    |   |  |  |      |  | 18    |   |  |      |  |  | 21    |   |  |  |  |  | 21    |  
|Operating                        |  |                | 15    |   |  |  |              |  | 17    |   |  |       |  |  | 18    |   |      |  |  |  | 175   |      |  |  |  |  | 198   |   |  |  |  |      | 208   |   |  |  |      |  | 190   |   |  |      |  |  | 215   |   |  |  |  |  | 226   |  
|Production and Mineral Taxes     |  |                | -     |   |  |  |              |  | -     |   |  |       |  |  | -     |   |      |  |  |  | 2     |      |  |  |  |  | 9     |   |  |  |  |      | 3     |   |  |  |      |  | 2     |   |  |      |  |  | 9     |   |  |  |  |  | 3     |  
|(Gain) Loss on Risk Management   |  |                | (4    | ) |  |  |              |  | -     |   |  |       |  |  | (4    | ) |      |  |  |  | (52   | )    |  |  |  |  | (5    | ) |  |  |  |      | (61   | ) |  |  |      |  | (56   | ) |  |      |  |  | (5    | ) |  |  |  |  | (65   | )
|Operating Cash Flow              |  |                | 10    |   |  |  |              |  | 46    |   |  |       |  |  | 22    |   |      |  |  |  | 297   |      |  |  |  |  | 510   |   |  |  |  |      | 416   |   |  |  |      |  | 307   |   |  |      |  |  | 556   |   |  |  |  |  | 438   |  
|                                 | 
|                                 |  | Other          |      
|                                 |  | Oil Sands      |       |   |  |  | Conventional |  |       |   |  | Total | 
|For the years ended December 31, |  | 2015           |       |   |  |  | 2014         |  |       |   |  | 2013  |  |  |       |   | 2015 |  |  |  |       | 2014 |  |  |  |  | 2013  |   |  |  |  | 2015 |       |   |  |  | 2014 |  |       |   |  | 2013 | 
|                                 |  |                |       |   |  |  |              |  |       |   |  |       |  |  |       |   |     
|Revenues                         |  |                |       |   |  |  |              |  |       |   |  |       |  |  |       |   |      |  |  |  |       |      |  |  |  |  |       |   |  |  |  |      |       |   |  |  |      |  |       |   |  |      |  |  |       |   |  |  |  |  |       |  
|Gross Sales                      |  |                | 8     |   |  |  |              |  | 6     |   |  |       |  |  | 24    |   |      |  |  |  | 20    |      |  |  |  |  | 25    |   |  |  |  |      | 13    |   |  |  |      |  | 28    |   |  |      |  |  | 31    |   |  |  |  |  | 37    |  
|Less: Royalties                  |  |                | -     |   |  |  |              |  | -     |   |  |       |  |  | -     |   |      |  |  |  | -     |      |  |  |  |  | -     |   |  |  |  |      | -     |   |  |  |      |  | -     |   |  |      |  |  | -     |   |  |  |  |  | -     |  
|                                 |  |                | 8     |   |  |  |              |  | 6     |   |  |       |  |  | 24    |   |      |  |  |  | 20    |      |  |  |  |  | 25    |   |  |  |  |      | 13    |   |  |  |      |  | 28    |   |  |      |  |  | 31    |   |  |  |  |  | 37    |  
|Expenses                         |  |                |       |   |  |  |              |  |       |   |  |       |  |  |       |   |      |  |  |  |       |      |  |  |  |  |       |   |  |  |  |      |       |   |  |  |      |  |       |   |  |      |  |  |       |   |  |  |  |  |       |  
|Transportation and Blending      |  |                | -     |   |  |  |              |  | -     |   |  |       |  |  | -     |   |      |  |  |  | -     |      |  |  |  |  | -     |   |  |  |  |      | -     |   |  |  |      |  | -     |   |  |      |  |  | -     |   |  |  |  |  | -     |  
|Operating                        |  |                | 5     |   |  |  |              |  | 7     |   |  |       |  |  | 3     |   |      |  |  |  | 5     |      |  |  |  |  | 6     |   |  |  |  |      | 4     |   |  |  |      |  | 10    |   |  |      |  |  | 13    |   |  |  |  |  | 7     |  
|Production and Mineral Taxes     |  |                | -     |   |  |  |              |  | -     |   |  |       |  |  | -     |   |      |  |  |  | -     |      |  |  |  |  | -     |   |  |  |  |      | -     |   |  |  |      |  | -     |   |  |      |  |  | -     |   |  |  |  |  | -     |  
|(Gain) Loss on Risk Management   |  |                | -     |   |  |  |              |  | -     |   |  |       |  |  | -     |   |      |  |  |  | -     |      |  |  |  |  | -     |   |  |  |  |      | -     |   |  |  |      |  | -     |   |  |      |  |  | -     |   |  |  |  |  | -     |  
|Operating Cash Flow              |  |                | 3     |   |  |  |              |  | (1    | ) |  |       |  |  | 21    |   |      |  |  |  | 15    |      |  |  |  |  | 19    |   |  |  |  |      | 9     |   |  |  |      |  | 18    |   |  |      |  |  | 18    |   |  |  |  |  | 30    |  
|                                 | 
|                                 |  | Total Upstream |      
|                                 |  | Oil Sands      |       |   |  |  | Conventional |  |       |   |  | Total | 
|For the years ended December 31, |  | 2015           |       |   |  |  | 2014         |  |       |   |  | 2013  |  |  |       |   | 2015 |  |  |  |       | 2014 |  |  |  |  | 2013  |   |  |  |  | 2015 |       |   |  |  | 2014 |  |       |   |  | 2013 | 
|                                 |  |                |       |   |  |  |              |  |       |   |  |       |  |  |       |   |     
|Revenues                         |  |                |       |   |  |  |              |  |       |   |  |       |  |  |       |   |      |  |  |  |       |      |  |  |  |  |       |   |  |  |  |      |       |   |  |  |      |  |       |   |  |      |  |  |       |   |  |  |  |  |       |  
|Gross Sales                      |  |                | 3,030 |   |  |  |              |  | 5,036 |   |  |       |  |  | 3,912 |   |      |  |  |  | 1,709 |      |  |  |  |  | 3,225 |   |  |  |  |      | 2,980 |   |  |  |      |  | 4,739 |   |  |      |  |  | 8,261 |   |  |  |  |  | 6,892 |  
|Less: Royalties                  |  |                | 29    |   |  |  |              |  | 236   |   |  |       |  |  | 132   |   |      |  |  |  | 114   |      |  |  |  |  | 229   |   |  |  |  |      | 204   |   |  |  |      |  | 143   |   |  |      |  |  | 465   |   |  |  |  |  | 336   |  
|                                 |  |                | 3,001 |   |  |  |              |  | 4,800 |   |  |       |  |  | 3,780 |   |      |  |  |  | 1,595 |      |  |  |  |  | 2,996 |   |  |  |  |      | 2,776 |   |  |  |      |  | 4,596 |   |  |      |  |  | 7,796 |   |  |  |  |  | 6,556 |  
|Expenses                         |  |                |       |   |  |  |              |  |       |   |  |       |  |  |       |   |      |  |  |  |       |      |  |  |  |  |       |   |  |  |  |      |       |   |  |  |      |  |       |   |  |      |  |  |       |   |  |  |  |  |       |  
|Transportation and Blending      |  |                | 1,815 |   |  |  |              |  | 2,131 |   |  |       |  |  | 1,749 |   |      |  |  |  | 230   |      |  |  |  |  | 346   |   |  |  |  |      | 325   |   |  |  |      |  | 2,045 |   |  |      |  |  | 2,477 |   |  |  |  |  | 2,074 |  
|Operating                        |  |                | 531   |   |  |  |              |  | 639   |   |  |       |  |  | 548   |   |      |  |  |  | 561   |      |  |  |  |  | 709   |   |  |  |  |      | 701   |   |  |  |      |  | 1,092 |   |  |      |  |  | 1,348 |   |  |  |  |  | 1,249 |  
|Production and Mineral Taxes     |  |                | -     |   |  |  |              |  | -     |   |  |       |  |  | -     |   |      |  |  |  | 18    |      |  |  |  |  | 46    |   |  |  |  |      | 35    |   |  |  |      |  | 18    |   |  |      |  |  | 46    |   |  |  |  |  | 35    |  
|(Gain) Loss on Risk Management   |  |                | (404  | ) |  |  |              |  | (38   | ) |  |       |  |  | (37   | ) |      |  |  |  | (209  | )    |  |  |  |  | (1    | ) |  |  |  |      | (104  | ) |  |  |      |  | (613  | ) |  |      |  |  | (39   | ) |  |  |  |  | (141  | )
|Operating Cash Flow              |  |                | 1,059 |   |  |  |              |  | 2,068 |   |  |       |  |  | 1,520 |   |      |  |  |  | 995   |      |  |  |  |  | 1,896 |   |  |  |  |      | 1,819 |   |  |  |      |  | 2,054 |   |  |      |  |  | 3,964 |   |  |  |  |  | 3,339 |  



|                    |  |    |  |                                  
|------------------- |  | -- |  | ---------------------------------
|Cenovus Energy Inc. |  | 11 |  | Consolidated Financial Statements



---

##### Table of Contents

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

All amounts in $ millions, unless otherwise indicated

For the year ended December 31, 2015



C) Geographic Information



|                                         |  |        |       |   |  |  |               |  |        |   |  |              |  |  |       |  |      |  |  |  |       |      |  |  |  |  |       |   |  |  |  |      |        |  |  |  |      |  |        |   |  |      |  |  |        |   |  |  |  |  |        | 
|---------------------------------------- |  | ------ | ----- | - |  |  | ------------- |  | ------ | - |  | ------------ |  |  | ----- |  | ---- |  |  |  | ----- | ---- |  |  |  |  | ----- | - |  |  |  | ---- | ------ |  |  |  | ---- |  | ------ | - |  | ---- |  |  | ------ | - |  |  |  |  | ------ | 
|                                         |  | Canada |       |   |  |  | United States |  |        |   |  | Consolidated | 
|For the years ended December 31,         |  | 2015   |       |   |  |  | 2014          |  |        |   |  | 2013         |  |  |       |  | 2015 |  |  |  |       | 2014 |  |  |  |  | 2013  |   |  |  |  | 2015 |        |  |  |  | 2014 |  |        |   |  | 2013 | 
|Revenues                                 |  |        |       |   |  |  |               |  |        |   |  |              |  |  |       |  |      |  |  |  |       |      |  |  |  |  |       |   |  |  |  |      |        |  |  |  |      |  |        |   |  |      |  |  |        |   |  |  |  |  |        | 
|Gross Sales                              |  |        | 6,407 |   |  |  |               |  | 10,604 |   |  |              |  |  | 8,943 |  |      |  |  |  | 6,800 |      |  |  |  |  | 9,503 |   |  |  |  |      | 10,050 |  |  |  |      |  | 13,207 |   |  |      |  |  | 20,107 |   |  |  |  |  | 18,993 | 
|Less: Royalties                          |  |        | 143   |   |  |  |               |  | 465    |   |  |              |  |  | 336   |  |      |  |  |  | -     |      |  |  |  |  | -     |   |  |  |  |      | -      |  |  |  |      |  | 143    |   |  |      |  |  | 465    |   |  |  |  |  | 336    | 
|                                         |  |        | 6,264 |   |  |  |               |  | 10,139 |   |  |              |  |  | 8,607 |  |      |  |  |  | 6,800 |      |  |  |  |  | 9,503 |   |  |  |  |      | 10,050 |  |  |  |      |  | 13,064 |   |  |      |  |  | 19,642 |   |  |  |  |  | 18,657 | 
|Expenses                                 |  |        |       |   |  |  |               |  |        |   |  |              |  |  |       |  |      |  |  |  |       |      |  |  |  |  |       |   |  |  |  |      |        |  |  |  |      |  |        |   |  |      |  |  |        |   |  |  |  |  |        | 
|Purchased Product                        |  |        | 1,607 |   |  |  |               |  | 2,310  |   |  |              |  |  | 2,022 |  |      |  |  |  | 5,767 |      |  |  |  |  | 8,645 |   |  |  |  |      | 8,377  |  |  |  |      |  | 7,374  |   |  |      |  |  | 10,955 |   |  |  |  |  | 10,399 | 
|Transportation and Blending              |  |        | 2,043 |   |  |  |               |  | 2,477  |   |  |              |  |  | 2,074 |  |      |  |  |  | -     |      |  |  |  |  | -     |   |  |  |  |      | -      |  |  |  |      |  | 2,043  |   |  |      |  |  | 2,477  |   |  |  |  |  | 2,074  | 
|Operating                                |  |        | 1,129 |   |  |  |               |  | 1,367  |   |  |              |  |  | 1,260 |  |      |  |  |  | 710   |      |  |  |  |  | 678   |   |  |  |  |      | 522    |  |  |  |      |  | 1,839  |   |  |      |  |  | 2,045  |   |  |  |  |  | 1,782  | 
|Production and Mineral Taxes             |  |        | 18    |   |  |  |               |  | 46     |   |  |              |  |  | 35    |  |      |  |  |  | -     |      |  |  |  |  | -     |   |  |  |  |      | -      |  |  |  |      |  | 18     |   |  |      |  |  | 46     |   |  |  |  |  | 35     | 
|(Gain) Loss on Risk Management           |  |        | (435  | ) |  |  |               |  | (625   | ) |  |              |  |  | 275   |  |      |  |  |  | (26   | )    |  |  |  |  | (37   | ) |  |  |  |      | 18     |  |  |  |      |  | (461   | ) |  |      |  |  | (662   | ) |  |  |  |  | 293    | 
|Depreciation, Depletion and Amortization |  |        | 1,925 |   |  |  |               |  | 1,790  |   |  |              |  |  | 1,695 |  |      |  |  |  | 189   |      |  |  |  |  | 156   |   |  |  |  |      | 138    |  |  |  |      |  | 2,114  |   |  |      |  |  | 1,946  |   |  |  |  |  | 1,833  | 
|Goodwill Impairment                      |  |        | -     |   |  |  |               |  | 497    |   |  |              |  |  | -     |  |      |  |  |  | -     |      |  |  |  |  | -     |   |  |  |  |      | -      |  |  |  |      |  | -      |   |  |      |  |  | 497    |   |  |  |  |  | -      | 
|Exploration Expense                      |  |        | 138   |   |  |  |               |  | 86     |   |  |              |  |  | 114   |  |      |  |  |  | -     |      |  |  |  |  | -     |   |  |  |  |      | -      |  |  |  |      |  | 138    |   |  |      |  |  | 86     |   |  |  |  |  | 114    | 
|Segment Income (Loss)                    |  |        | (161  | ) |  |  |               |  | 2,191  |   |  |              |  |  | 1,132 |  |      |  |  |  | 160   |      |  |  |  |  | 61    |   |  |  |  |      | 995    |  |  |  |      |  | (1     | ) |  |      |  |  | 2,252  |   |  |  |  |  | 2,127  | 

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 $870 million (2014
 $821 million; 2013  $926 million).

Major Customers

In connection with the marketing and sale of Cenovuss own and purchased crude oil, natural gas and refined products for the year ended
December 31, 2015, Cenovus had three customers (2014  three; 2013  three) that individually accounted for more than 10 percent of its consolidated gross sales. Sales to these customers, recognized as major international energy
companies with investment grade credit ratings, were approximately $4,647 million, $1,705 million and $1,545 million, respectively (2014  $7,210 million, $2,668 million and $2,316 million; 2013  $7,032 million, $2,711 million
and $1,799 million), which are included in all of the Companys segments.

D) Exploration and Evaluation Assets,
Property, Plant and Equipment, Goodwill and Total Assets

By Segment



|                           |  |         |       |  |  |  |          |  |       |  |  |          |  |  |        |  |              |  |  |  |        |      |  |  |  |  |      |  |  |  |  |      |     |  |  |  |      |  |        |  |  |  |  |  |        | 
|-------------------------- |  | ------- | ----- |  |  |  | -------- |  | ----- |  |  | -------- |  |  | ------ |  | ------------ |  |  |  | ------ | ---- |  |  |  |  | ---- |  |  |  |  | ---- | --- |  |  |  | ---- |  | ------ |  |  |  |  |  | ------ | 
|                           |  | E&E (1) |       |  |  |  | PP&E (2) |  |       |  |  | Goodwill |  |  |        |  | Total Assets | 
|As at December 31,         |  | 2015    |       |  |  |  | 2014     |  |       |  |  | 2015     |  |  |        |  | 2014         |  |  |  |        | 2015 |  |  |  |  | 2014 |  |  |  |  | 2015 |     |  |  |  | 2014 | 
|Oil Sands                  |  |         | 1,560 |  |  |  |          |  | 1,540 |  |  |          |  |  | 8,907  |  |              |  |  |  | 8,606  |      |  |  |  |  | 242  |  |  |  |  |      | 242 |  |  |  |      |  | 11,069 |  |  |  |  |  | 11,024 | 
|Conventional               |  |         | 15    |  |  |  |          |  | 85    |  |  |          |  |  | 3,720  |  |              |  |  |  | 6,038  |      |  |  |  |  | -    |  |  |  |  |      | -   |  |  |  |      |  | 3,830  |  |  |  |  |  | 6,211  | 
|Refining and Marketing     |  |         | -     |  |  |  |          |  | -     |  |  |          |  |  | 4,398  |  |              |  |  |  | 3,568  |      |  |  |  |  | -    |  |  |  |  |      | -   |  |  |  |      |  | 5,844  |  |  |  |  |  | 5,520  | 
|Corporate and Eliminations |  |         | -     |  |  |  |          |  | -     |  |  |          |  |  | 310    |  |              |  |  |  | 351    |      |  |  |  |  | -    |  |  |  |  |      | -   |  |  |  |      |  | 5,048  |  |  |  |  |  | 1,940  | 
|Consolidated               |  |         | 1,575 |  |  |  |          |  | 1,625 |  |  |          |  |  | 17,335 |  |              |  |  |  | 18,563 |      |  |  |  |  | 242  |  |  |  |  |      | 242 |  |  |  |      |  | 25,791 |  |  |  |  |  | 24,695 | 



|(1) | Exploration and evaluation (E&E) assets.
|--- | ------------------------------------------

|(2) | Property, plant and equipment (PP&E).
|--- | ---------------------------------------



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|Cenovus Energy Inc. |  | 12 |  | Consolidated Financial Statements



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##### Table of Contents

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

All amounts in $ millions, unless otherwise indicated

For the year ended December 31, 2015



By Geographic Region



|                   |  |      |       |  |  |  |      |  |       |  |  |          |  |  |        |  |              |  |  |  |        |      |  |  |  |  |      |  |  |  |  |      |     |  |  |  |      |  |        |  |  |  |  |  |        | 
|------------------ |  | ---- | ----- |  |  |  | ---- |  | ----- |  |  | -------- |  |  | ------ |  | ------------ |  |  |  | ------ | ---- |  |  |  |  | ---- |  |  |  |  | ---- | --- |  |  |  | ---- |  | ------ |  |  |  |  |  | ------ | 
|                   |  | E&E  |       |  |  |  | PP&E |  |       |  |  | Goodwill |  |  |        |  | Total Assets | 
|As at December 31, |  | 2015 |       |  |  |  | 2014 |  |       |  |  | 2015     |  |  |        |  | 2014         |  |  |  |        | 2015 |  |  |  |  | 2014 |  |  |  |  | 2015 |     |  |  |  | 2014 | 
|Canada             |  |      | 1,575 |  |  |  |      |  | 1,625 |  |  |          |  |  | 13,028 |  |              |  |  |  | 14,999 |      |  |  |  |  | 242  |  |  |  |  |      | 242 |  |  |  |      |  | 20,627 |  |  |  |  |  | 20,231 | 
|United States      |  |      | -     |  |  |  |      |  | -     |  |  |          |  |  | 4,307  |  |              |  |  |  | 3,564  |      |  |  |  |  | -    |  |  |  |  |      | -   |  |  |  |      |  | 5,164  |  |  |  |  |  | 4,464  | 
|Consolidated       |  |      | 1,575 |  |  |  |      |  | 1,625 |  |  |          |  |  | 17,335 |  |              |  |  |  | 18,563 |      |  |  |  |  | 242  |  |  |  |  |      | 242 |  |  |  |      |  | 25,791 |  |  |  |  |  | 24,695 | 

E) Capital Expenditures(1)



|                                 |  |      |       |  |  |  |      |  |       |  |  |      |  |  |       | 
|-------------------------------- |  | ---- | ----- |  |  |  | ---- |  | ----- |  |  | ---- |  |  | ----- | 
|For the years ended December 31, |  | 2015 |       |  |  |  | 2014 |  |       |  |  | 2013 | 
|Capital                          |  |      |       |  |  |  |      |  |       |  |  |      |  |  |       | 
|Oil Sands                        |  |      | 1,185 |  |  |  |      |  | 1,986 |  |  |      |  |  | 1,885 | 
|Conventional                     |  |      | 244   |  |  |  |      |  | 840   |  |  |      |  |  | 1,189 | 
|Refining and Marketing           |  |      | 248   |  |  |  |      |  | 163   |  |  |      |  |  | 107   | 
|Corporate                        |  |      | 37    |  |  |  |      |  | 62    |  |  |      |  |  | 81    | 
|                                 |  |      | 1,714 |  |  |  |      |  | 3,051 |  |  |      |  |  | 3,262 | 
|Acquisition Capital              |  |      |       |  |  |  |      |  |       |  |  |      |  |  |       | 
|Oil Sands                        |  |      | 3     |  |  |  |      |  | 15    |  |  |      |  |  | 27    | 
|Conventional                     |  |      | 1     |  |  |  |      |  | 3     |  |  |      |  |  | 5     | 
|Refining and Marketing           |  |      | 83    |  |  |  |      |  | -     |  |  |      |  |  | -     | 
|                                 |  |      | 1,801 |  |  |  |      |  | 3,069 |  |  |      |  |  | 3,294 | 

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

2. BASIS OF PREPARATION AND STATEMENT OF COMPLIANCE



In these Consolidated Financial Statements,
unless otherwise indicated, all dollars are expressed in Canadian dollars. All references to C$ or $ are to Canadian dollars and references to US$ are to U.S. dollars.

These Consolidated Financial Statements have been prepared in accordance with International Financial Reporting Standards (IFRS) as issued by
the International Accounting Standards Board (IASB) and interpretations of the International Financial Reporting Interpretations Committee (IFRIC). These Consolidated Financial Statements have been prepared in compliance with
IFRS.

These Consolidated Financial Statements have been prepared on a historical cost basis, except as detailed in the Companys accounting
policies disclosed in Note 3.

These Consolidated Financial Statements of Cenovus were approved by the Board of Directors on
February 10, 2016.

3. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES



A) Principles of
Consolidation

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

Interests in joint arrangements are classified as either joint operations or
joint ventures, depending on the rights and obligations of the parties to the arrangement. Joint operations arise when the Company has rights to the assets and obligations for the liabilities of the arrangement. Substantially all of the
Companys Oil Sands and Refining activities are conducted through two joint operations, FCCL Partnership (FCCL) and WRB Refining LP (WRB), and accordingly, the accounts reflect the Companys share of the assets,
liabilities, revenues and expenses.



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|Cenovus Energy Inc. |  | 13 |  | Consolidated Financial Statements



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##### Table of Contents

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

All amounts in $ millions, unless otherwise indicated

For the year ended December 31, 2015



B) Foreign Currency Translation

Functional and Presentation Currency

The Companys presentation currency is Canadian dollars. The accounts of the Companys foreign operations that have a functional currency
different from the Companys presentation currency are translated into the Companys presentation currency at period-end exchange rates for assets and liabilities, and using average rates over the period for revenues and expenses.
Translation gains and losses relating to the foreign operations are recognized in other comprehensive income (OCI) as cumulative translation adjustments.

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

Transactions and Balances

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

C) Revenue Recognition

Revenues associated with the sales of Cenovuss crude oil, natural gas, NGLs, and petroleum and refined products are recognized when the significant
risks and rewards of ownership have been transferred to the customer, the sales price and costs can be measured reliably and it is probable that the economic benefits will flow to the Company. This is generally met when title passes from the Company
to its customer. Revenues from crude oil and natural gas production represent the Companys share, net of royalty payments to governments and other mineral interest owners.

Revenue from fee-for-service hydrocarbon trans-loading services is recognized in the period the service is provided.

Purchases and sales of products that are entered into in contemplation of each other with the same counterparty are recorded on a net basis. Revenues
associated with the services provided as agent are recorded as the services are provided.

D) Transportation and Blending

The costs associated with the transportation of crude oil, natural gas and NGLs, including the cost of diluent used in blending, are
recognized when the product is sold.

E) Exploration Expense

Costs incurred prior to obtaining the legal right to explore (pre-exploration costs) are expensed in the period in which they are incurred as exploration
expense.

Costs incurred after the legal right to explore is obtained, are initially capitalized. If it is determined that the field/project/area is
not technically feasible and commercially viable or if the Company decides not to continue the exploration and evaluation activity, the unrecoverable accumulated costs are expensed as exploration expense.

F) Employee Benefit Plans

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

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

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



|                    |  |    |  |                                  
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|Cenovus Energy Inc. |  | 14 |  | Consolidated Financial Statements



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##### Table of Contents

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

All amounts in $ millions, unless otherwise indicated

For the year ended December 31, 2015



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



| |  |  | Service costs, including current service costs, past service costs, gains and losses on curtailments, and settlements, are recorded with pension benefit
costs.
| | - |  | ---------------------------------------------------------------------------------------------------------------------------------------------------------------



| |  |  | Net interest is calculated by applying the same discount rate used to measure the defined benefit obligation at the beginning of the annual period to the net
defined benefit asset or liability measured. Interest expense and interest income on net post-employment benefit liabilities and assets are recorded with pension benefit costs in operating, and general and administrative expenses, as well as
PP&E and E&E assets.
| | - |  | ------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------



| |  |  | Remeasurements, composed of actuarial gains and losses, the effect of changes to the asset ceiling (excluding interest) and the return on plan assets
(excluding interest income), are charged or credited to equity in OCI in the period in which they arise. Remeasurements are not reclassified to net earnings in subsequent periods.
| | - |  | -----------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------

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

G) Income Taxes

Income taxes comprise current and deferred taxes. Income taxes are provided for on a non-discounted basis at amounts expected to be paid using the tax
rates and laws that have been enacted or substantively enacted at the Consolidated Balance Sheet date.

Cenovus follows the liability method of
accounting for income taxes, where deferred income taxes are recorded for the effect of any temporary difference between the accounting and income tax basis of an asset or liability, using the substantively enacted income tax rates expected to apply
when the assets are realized or liabilities are settled. Deferred income tax balances are adjusted to reflect changes in income tax rates that are substantively enacted with the adjustment being recognized in net earnings in the period that the
change occurs, except when it relates to items charged or credited directly to equity or OCI, in which case the deferred income tax is also recorded in equity or OCI, respectively.

Deferred income tax is provided on temporary differences arising from investments in subsidiaries except in the case where the timing of the reversal of
the temporary difference is controlled by the Company and it is probable that the temporary difference will not reverse in the foreseeable future or when distributions can be made without incurring income taxes.

Deferred income tax assets are recognized only to the extent that it is probable that future taxable profit will be available against which the temporary
differences can be utilized. Deferred income tax assets and liabilities are only offset where they arise within the same entity and tax jurisdiction. Deferred income tax assets and liabilities are presented as non-current.

H) Net Earnings per Share Amounts

Basic net earnings per share is computed by dividing net earnings by the weighted average number of common shares outstanding during the period. Diluted
net earnings per share is calculated giving effect to the potential dilution that would occur if stock options or other contracts to issue common shares were exercised or converted to common shares. The treasury stock method is used to determine the
dilutive effect of stock options and other dilutive instruments. The treasury stock method assumes that proceeds received from the exercise of in-the-money stock options are used to repurchase common shares at the average market price. For those
contracts that may be settled in cash or in shares at the holders option, the more dilutive of cash settlement and share settlement is used in calculating diluted earnings per share.

I) Cash and Cash Equivalents

Cash and cash equivalents include short-term investments, such as money market deposits or similar type instruments, with a maturity of three months or
less.

J) Inventories

Product inventories are valued at the lower of cost and net realizable value on a first-in, first-out or weighted average cost basis. The cost of
inventory includes all costs incurred in the normal course of business to bring each product to its present location and condition. Net realizable value is the estimated selling price in the ordinary course of business less any expected selling
costs. If the carrying amount exceeds net realizable value, a write-down is recognized. The write-down may be reversed in a subsequent period if circumstances which caused it no longer exist and the inventory is still on hand.



|                    |  |    |  |                                  
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|Cenovus Energy Inc. |  | 15 |  | Consolidated Financial Statements



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##### Table of Contents

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

All amounts in $ millions, unless otherwise indicated

For the year ended December 31, 2015



K) Exploration and Evaluation Assets

Costs incurred after the legal right to explore an area has been obtained, and before technical feasibility and commercial viability of the
field/project/area have been established, are capitalized as E&E assets. These costs include license acquisition, geological and geophysical, drilling, sampling, decommissioning and other directly attributable internal costs. E&E assets are
not depreciated and are carried forward until technical feasibility and commercial viability of the field/project/area is established or the assets are determined to be impaired. E&E costs are subject to regular technical, commercial and
Management review to confirm the continued intent to develop the resources.

Once technical feasibility and commercial viability have been
established, the carrying value of the E&E asset is tested for impairment. The carrying value, net of any impairment loss, is then reclassified as PP&E.

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

L) Property, Plant and Equipment

General

PP&E is stated at cost less accumulated depreciation, depletion and amortization (DD&A), and net impairment losses. Expenditures
related to renewals or betterments that improve the productive capacity or extend the life of an asset are capitalized. Maintenance and repairs are expensed as incurred. Land is not depreciated.

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

Development and Production Assets

Development and production assets are capitalized on an area-by-area basis and include all costs associated with the development and production of the
crude oil and natural gas properties, as well as any E&E expenditures incurred in finding reserves of crude oil or natural gas transferred from E&E assets. Capitalized costs include directly attributable internal costs, decommissioning
liabilities and, for qualifying assets, borrowing costs directly associated with the acquisition of, the exploration for, and the development of crude oil and natural gas reserves.

Costs accumulated within each area are depleted using the unit-of-production method based on estimated proved reserves determined using forward prices and
costs. For the purpose of this calculation, natural gas is converted to crude oil on an energy equivalent basis. Costs subject to depletion include estimated future costs to be incurred in developing proved reserves.

Exchanges of development and production assets are measured at fair value unless the transaction lacks commercial substance or the fair value of neither
the asset received, nor the asset given up, can be reliably measured. When fair value is not used, the carrying amount of the asset given up is used as the cost of the asset acquired.

Other Upstream Assets

Other upstream assets include pipelines and information technology assets used to support the upstream business. These assets are depreciated on a
straight-line basis over their useful lives of three to 35 years.

Refining Assets

The initial acquisition costs of refining PP&E are capitalized when incurred. Costs include the cost of constructing or otherwise acquiring the
equipment or facilities, the cost of installing the asset and making it ready for its intended use, the associated decommissioning costs and, for qualifying assets, borrowing costs.

Refining assets are depreciated on a straight-line basis over the estimated service life of each component of the refinery. The major components are
depreciated as follows:



|                                |  |                |  | 
|------------------------------- |  | -------------- |  | 
|Land Improvements and Buildings |  | 25 to 40 years |  | 
|Office Equipment and Vehicles   |  | 3 to 20 years  |  | 
|Refining Equipment              |  | 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.



|                    |  |    |  |                                  
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|Cenovus Energy Inc. |  | 16 |  | Consolidated Financial Statements



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##### Table of Contents

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

All amounts in $ millions, unless otherwise indicated

For the year ended December 31, 2015



Other Assets

Costs associated with the crude-by-rail terminal, office furniture, fixtures, leasehold improvements, information technology and aircraft are carried at
cost and depreciated on a straight-line basis over the estimated service lives of the assets, which range from three to 40 years.

The residual
value, method of amortization and the useful lives of the assets are reviewed annually and adjusted on a prospective basis, if appropriate.

M) Impairment

Non-Financial Assets

PP&E and E&E assets are reviewed separately for indicators of impairment quarterly or when facts and circumstances suggest that the carrying
amount may exceed its recoverable amount. Goodwill is tested for impairment at least annually.

If indicators of impairment exist, the recoverable
amount of the cash-generating unit (CGU) is estimated as the greater of value-in-use (VIU) and fair value less costs of disposal (FVLCOD). VIU is estimated as the discounted present value of the future cash flows
expected to arise from the continuing use of a CGU or an asset. FVLCOD is determined by estimating the discounted after-tax future net cash flows. For Cenovuss upstream assets, FVLCOD is based on the discounted after-tax cash flows of reserves
and resources using forward prices and costs, consistent with Cenovuss independent qualified reserves evaluators, and may consider an evaluation of comparable asset transactions.

If the recoverable amount of the CGU is less than the carrying amount, an impairment loss is recognized. An impairment loss is allocated first to reduce
the carrying amount of any goodwill allocated to the CGU and then to reduce the carrying amounts of the other assets in the CGU. Goodwill impairments are not reversed.

E&E assets are allocated to a related CGU containing development and production assets for the purposes of testing for impairment. Goodwill is
allocated to the CGUs to which it contributes to the future cash flows.

Impairment losses on PP&E and E&E assets are recognized in the
Consolidated Statements of Earnings as additional DD&A and exploration expense, respectively.

Impairment losses recognized in prior periods,
other than goodwill impairments, are assessed at each reporting date for any indicators that the impairment losses may no longer exist or may have decreased. In the event that an impairment loss reverses, the carrying amount of the asset is
increased to the revised estimate of its recoverable amount, but only to the extent that the carrying amount does not exceed the amount that would have been determined had no impairment loss been recognized on the asset in prior periods. The amount
of the reversal is recognized in net earnings.

Financial Assets

At each reporting date, the Company assesses whether there are any indicators that its financial assets are impaired. An impairment loss is only
recognized if there is objective evidence of impairment, the loss event has an impact on future cash flows and the loss can be reliably estimated.

Evidence of impairment may include default or delinquency by a debtor or indicators that the debtor may enter bankruptcy. For equity securities, a
significant or prolonged decline in the fair value of the security below cost is evidence that the assets are impaired.

An impairment loss on a
financial asset carried at amortized cost is calculated as the difference between the amortized cost and the present value of the future cash flows discounted at the assets original effective interest rate. The carrying amount of the asset is
reduced through the use of an allowance account. Impairment losses on financial assets carried at amortized cost are reversed through net earnings in subsequent periods if the amount of the loss decreases.

N) Leases

Leases
in which substantially all of the risks and rewards of ownership are retained by the lessor are classified as operating leases. Operating lease payments are recognized as an expense on a straight-line basis over the lease term.

Leases where the Company assumes substantially all the risks and rewards of ownership are classified as finance leases within PP&E.



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|Cenovus Energy Inc. |  | 17 |  | Consolidated Financial Statements



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##### Table of Contents

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

All amounts in $ millions, unless otherwise indicated

For the year ended December 31, 2015



O) Business Combinations and Goodwill

Business combinations are accounted for using the acquisition method of accounting in which the identifiable assets acquired, liabilities assumed and any
non-controlling interest are recognized and measured at their fair value at the date of acquisition. Any excess of the purchase price plus any non-controlling interest over the fair value of the net assets acquired is recognized as goodwill. Any
deficiency of the purchase price over the fair value of the net assets acquired is credited to net earnings.

At acquisition, goodwill is allocated to
each of the CGUs to which it relates. Subsequent measurement of goodwill is at cost less any accumulated impairment losses.

P) Provisions

General

A provision is recognized if, as a result of a past event, the Company has a present obligation, legal
or constructive, that can be estimated reliably, and it is more likely than not that an outflow of economic benefits will be required to settle the obligation. Where applicable, provisions are determined by discounting the expected future cash flows
at a pre-tax credit-adjusted rate that reflects the current market assessments of the time value of money and the risks specific to the liability. The increase in the provision due to the passage of time is recognized as a finance cost in the
Consolidated Statements of Earnings.

Decommissioning Liabilities

Decommissioning liabilities include those legal or constructive obligations where the Company will be required to retire tangible long-lived assets such
as producing well sites, crude oil and natural gas processing facilities, refining facilities and the crude-by-rail terminal. The amount recognized is the present value of estimated future expenditures required to settle the obligation using a
credit-adjusted risk-free rate. A corresponding asset equal to the initial estimate of the liability is capitalized as part of the cost of the related long-lived asset. Changes in the estimated liability resulting from revisions to expected timing
or future decommissioning costs are recognized as a change in the decommissioning liability and the related long-lived asset. The amount capitalized in PP&E is depreciated over the useful life of the related asset.

Actual expenditures incurred are charged against the accumulated liability.

Q) Share Capital

Common shares are classified as equity. Transaction costs directly attributable to the issue of common shares are recognized as a deduction from equity,
net of any income taxes.

R) Stock-Based Compensation

Cenovus has a number of stock-based compensation plans which include stock options with associated net settlement rights (NSRs), stock options
with associated tandem stock appreciation rights (TSARs), performance share units (PSUs), restricted share units (RSUs) and deferred share units (DSUs). Stock-based compensation costs are recorded in
general and administrative expense, or E&E and PP&E when directly related to exploration or development activities.

Net Settlement Rights

NSRs are accounted for as equity instruments, which are measured at fair value on the grant date using the Black-Scholes-Merton valuation model and are
not revalued at each reporting date. The fair value is recognized as stock-based compensation costs over the vesting period, with a corresponding increase recorded as paid in surplus in Shareholders Equity. On exercise, the cash consideration
received by the Company and the associated paid in surplus are recorded as share capital.

Tandem Stock Appreciation
Rights

TSARs are accounted for as liability instruments, which are measured at fair value at each period end using the
Black-Scholes-Merton valuation model. The fair value is recognized as stock-based compensation costs over the vesting period. When options are settled for cash, the liability is reduced by the cash settlement paid. When options are settled for
common shares, the cash consideration received by the Company and the previously recorded liability associated with the option are recorded as share capital.



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|Cenovus Energy Inc. |  | 18 |  | Consolidated Financial Statements



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##### Table of Contents

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

All amounts in $ millions, unless otherwise indicated

For the year ended December 31, 2015



Performance, Restricted and Deferred Share Units

PSUs, RSUs and DSUs are accounted for as liability instruments and are measured at fair value based on the market value of Cenovuss common shares at
each period end. The fair value is recognized as stock-based compensation costs over the vesting period. Fluctuations in the fair values are recognized as stock-based compensation costs in the period they occur.

S) Financial Instruments

The Companys financial assets include cash and cash equivalents, accounts receivable and accrued revenues, risk management assets, available for
sale financial assets and long-term receivables. The Companys financial liabilities include accounts payable and accrued liabilities, risk management liabilities, short-term borrowings and long-term debt.

Financial instruments are recognized when the Company becomes a party to the contractual provisions of the instrument. Financial assets and liabilities
are not offset unless the Company has the current legal right to offset and intends to settle on a net basis or settle the asset and liability simultaneously. A financial asset is derecognized when the rights to receive cash flows from the asset
have expired or have been transferred and the Company has transferred substantially all the risks and rewards of ownership. A financial liability is derecognized when the obligation is discharged, cancelled or expired. When an existing financial
liability is replaced by another from the same counterparty with substantially different terms, or the terms of an existing liability are substantially modified, this exchange or modification is treated as a derecognition of the original liability
and the recognition of a new liability. The difference in the carrying amounts of the liabilities is recognized in the Consolidated Statements of Earnings.

Financial instruments are classified as either fair value through profit and loss, loans and receivables, held-to-maturity
investments, available for sale financial assets or financial liabilities measured at amortized cost. The Company determines the classification of its financial assets at initial recognition. Financial instruments are
initially measured at fair value except in the case of financial liabilities measured at amortized cost, which are initially measured at fair value net of directly attributable transaction costs.

As required by IFRS, the Company characterizes its fair value measurements into a three-level hierarchy depending on the degree to which the inputs are
observable, as follows:



| |  |  | Level 1 inputs are quoted prices in active markets for identical assets and liabilities;
| | - |  | ----------------------------------------------------------------------------------------

| |  |  | Level 2 inputs are inputs, other than quoted prices included within Level 1, that are observable for the asset or liability either directly or indirectly; and
| | - |  | --------------------------------------------------------------------------------------------------------------------------------------------------------------

| |  |  | Level 3 inputs are unobservable inputs for the asset or liability.
| | - |  | ------------------------------------------------------------------

Fair Value through Profit or Loss

Financial assets and financial liabilities at fair value through profit or loss are either held-for-trading or have been
designated at fair value through profit or loss. In both cases, the financial assets and financial liabilities are measured at fair value with changes in fair value recognized in net earnings.

Risk management assets and liabilities are derivative financial instruments classified as held-for-trading unless designated for hedge
accounting. Derivative instruments that do not qualify as hedges, or are not designated as hedges, are recorded using mark-to-market accounting whereby instruments are recorded in the Consolidated 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.



|                    |  |    |  |                                  
|------------------- |  | -- |  | ---------------------------------
|Cenovus Energy Inc. |  | 19 |  | Consolidated Financial Statements



---

##### Table of Contents

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

All amounts in $ millions, unless otherwise indicated

For the year ended December 31, 2015



Available for Sale Financial Assets

Available for sale financial assets are measured at fair value, with changes in the fair value recognized in OCI. When an active market is
non-existent, fair value is determined using valuation techniques. When fair value cannot be reliably measured, such assets are carried at cost. Available for sale financial assets comprise investments in the equity of private companies that the
Company does not control or have significant influence over.

Financial Liabilities Measured at Amortized Cost

These financial liabilities are measured at amortized cost at the settlement date using the effective interest method of amortization.
Financial liabilities measured at amortized cost comprise accounts payable and accrued liabilities, short-term borrowings and long-term debt. Long-term debt transaction costs, premiums and discounts are capitalized within long-term debt or as a
prepayment and amortized using the effective interest method.

T) Reclassification

Certain information provided for prior years has been reclassified to conform to the presentation adopted in 2015. Employee stock-based compensation costs
previously included in operating expense have been reclassified to general and administrative expense. As a result, for the years ended December 31, 2014 and 2013, expenses of $21 million and $16 million, respectively, were reclassified.

U) Recent Accounting Pronouncements

New and Amended Accounting Standards and Interpretations Adopted

There were no new or amended accounting standards or interpretations adopted during the year ended December 31, 2015.

New Accounting Standards and Interpretations not yet Adopted

A number of new accounting standards, amendments to accounting standards and interpretations are effective for annual periods beginning on or after
January 1, 2016 and have not been applied in preparing the Consolidated Financial Statements for the year ended December 31, 2015. The standards applicable to the Company are as follows and will be adopted on their respective effective
dates:

Leases

On January 13, 2016, the IASB issued IFRS 16, Leases (IFRS 16), which requires entities to recognize lease assets and
lease obligations on the balance sheet. For lessees, IFRS 16 removes the classification of leases as either operating leases or finance leases, effectively treating all leases as finance leases. Certain short-term leases (less than 12 months) and
leases of low-value assets are exempt from the requirements, and may continue to be treated as operating leases.

Lessors will continue with a dual
lease classification model. Classification will determine how and when a lessor will recognize lease revenue, and what assets would be recorded.

IFRS
16 is effective for years beginning on or after January 1, 2019, with early adoption permitted if IFRS 15 Revenue From Contracts With Customers has been adopted. The standard may be applied retrospectively or using a modified
retrospective approach. The Company is currently evaluating the impact of adopting IFRS 16 on the Consolidated Financial Statements.

Revenue Recognition

On May 28, 2014, the IASB issued IFRS 15, Revenue From Contracts With
Customers (IFRS 15) replacing IAS 11, Construction Contracts, IAS 18, Revenue and several revenue-related interpretations. IFRS 15 establishes a single revenue recognition
framework that applies to contracts with customers. The standard requires an entity to recognize revenue to reflect the transfer of goods and services for the amount it expects to receive, when control is transferred to the purchaser. Disclosure
requirements have also been expanded.

IFRS 15 is effective for annual periods beginning on or after January 1, 2018. Early adoption is
permitted. The standard may be applied retrospectively or using a modified retrospective approach. The Company is currently evaluating the impact of adopting IFRS 15 on the Consolidated Financial Statements.

Financial Instruments

On July 24, 2014, the IASB issued the final version of IFRS 9, Financial Instruments (IFRS 9) to replace IAS 39,
Financial Instruments: Recognition and Measurement (IAS 39).

IFRS 9 introduces a single approach to determine whether
a financial asset is measured at amortized cost or fair value and replaces the multiple rules in IAS 39. The approach is based on how an entity manages its financial instruments in the context of its business model and the contractual cash flow
characteristics of the financial



|                    |  |    |  |                                  
|------------------- |  | -- |  | ---------------------------------
|Cenovus Energy Inc. |  | 20 |  | Consolidated Financial Statements



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##### Table of Contents

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

All amounts in $ millions, unless otherwise indicated

For the year ended December 31, 2015



assets. For financial liabilities, IFRS 9 retains most of the IAS 39 requirements; however, where the fair value option is applied to financial liabilities, the change in fair value resulting
from an entitys own credit risk is recorded in OCI rather than net earnings, unless this creates an accounting mismatch. In addition, a new expected credit loss model for calculating impairment on financial assets replaces the incurred loss
impairment model used in IAS 39. The new model will result in more timely recognition of expected credit losses. IFRS 9 also includes a simplified hedge accounting model, aligning hedge accounting more closely with risk management. Cenovus does
not currently apply hedge accounting.

IFRS 9 is effective for years beginning on or after January 1, 2018. Early adoption is permitted if IFRS 9
is adopted in its entirety at the beginning of a fiscal period. The Company is currently evaluating the impact of adopting IFRS 9 on the Consolidated Financial Statements.



4.   CRITICAL
ACCOUNTING JUDGMENTS AND KEY SOURCES OF ESTIMATION UNCERTAINTY





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

A) Critical Judgments in Applying Accounting Policies

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

Joint Arrangements

Cenovus holds a 50 percent ownership interest in two jointly controlled entities, FCCL and WRB. The classification of these joint arrangements as either a
joint operation or a joint venture requires judgment. It was determined that Cenovus has the rights to the assets and obligations for the liabilities of FCCL and WRB.

As a result, these joint arrangements are classified as joint operations and the Companys share of the assets, liabilities, revenues and expenses
are recorded in the Consolidated Financial Statements.

In determining the classification of its joint arrangements under IFRS 11, Joint
Arrangements, the Company considered the following:



| |  |  | 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.
| | - |  | ----------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------



|                    |  |    |  |                                  
|------------------- |  | -- |  | ---------------------------------
|Cenovus Energy Inc. |  | 21 |  | Consolidated Financial Statements



---

##### Table of Contents

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

All amounts in $ millions, unless otherwise indicated

For the year ended December 31, 2015



Exploration and Evaluation Assets

The application of the Companys accounting policy for E&E expenditures requires judgment in determining whether it is likely that future
economic benefit exists when activities have not reached a stage where technical feasibility and commercial viability can be reasonably determined. Factors such as drilling results, future capital programs, future operating expenses, as well as
estimated reserves and resources are considered. In addition, Management uses judgment to determine when E&E assets are reclassified to PP&E. In making this determination, various factors are considered, including the existence of reserves,
and whether the appropriate approvals have been received from regulatory bodies and the Companys internal approval process.

Identification of 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, crude-by-rail and corporate assets are assessed at the CGU level. As such, the determination of a CGU could have a significant impact on impairment losses.

B) Key Sources of Estimation Uncertainty

Critical accounting estimates are those estimates that require Management to make particularly subjective or complex judgments about matters that are
inherently uncertain. Estimates and underlying assumptions are reviewed on an ongoing basis and any revisions to accounting estimates are recorded in the period in which the estimates are revised. The following are the key assumptions about the
future and other key sources of estimation at the end of the reporting period that changes to could result in a material adjustment to the carrying amount of assets and liabilities within the next financial year.

Crude Oil and Natural Gas Reserves

There are a number of inherent uncertainties associated with estimating crude oil and natural gas reserves. Reserves estimates are dependent upon
variables including the recoverable quantities of hydrocarbons, the cost of the development of the required infrastructure to recover the hydrocarbons, production costs, estimated selling price of the hydrocarbons produced, royalty payments and
taxes. Changes in these variables could significantly impact the reserves estimates which would affect the impairment test and DD&A expense of the Companys crude oil and natural gas assets in the Oil Sands and Conventional segments. The
Companys crude oil and natural gas reserves are evaluated annually and reported to the Company by independent qualified reserves evaluators.

Impairment of Assets

Determining the recoverable amount of a CGU or an individual asset requires the use of
estimates and assumptions, which are subject to change as new information becomes available. For the Companys upstream assets, these estimates include forward commodity prices, expected production volumes, quantity of reserves and resources,
discount rates, future development and operating expenses, and income tax rates. Recoverable amounts for the Companys refining assets and crude-by-rail terminal use assumptions such as throughput, forward commodity prices, operating expenses,
transportation capacity, supply and demand conditions and income tax rates. Changes in assumptions used in determining the recoverable amount could affect the carrying value of the related assets.

Decommissioning Costs

Provisions are recorded for the future decommissioning and restoration of the Companys upstream crude oil and natural gas assets, refining assets
and crude-by-rail terminal at the end of their economic lives. Management uses judgement to assess the existence and to estimate the future liability. The actual cost of decommissioning and restoration is uncertain and cost estimates may change in
response to numerous factors including changes in legal requirements, technological advances, inflation and the timing of expected decommissioning and restoration. In addition, Management determines the appropriate discount rate at the end of each
reporting period. This discount rate, which is credit adjusted, is used to determine the present value of the estimated future cash outflows required to settle the obligation and may change in response to numerous market factors.



|                    |  |    |  |                                  
|------------------- |  | -- |  | ---------------------------------
|Cenovus Energy Inc. |  | 22 |  | Consolidated Financial Statements



---

##### Table of Contents

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

All amounts in $ millions, unless otherwise indicated

For the year ended December 31, 2015



Income Tax Provisions

Tax regulations and legislation and the interpretations thereof in the various jurisdictions in which Cenovus operates are subject to change. There are
usually a number of tax matters under review; therefore, income taxes are subject to measurement uncertainty.

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

5. FINANCE COSTS







|                                                               |  |      |     |  |  |  |      |  |     |  |  |      |  |  |     | 
|-------------------------------------------------------------- |  | ---- | --- |  |  |  | ---- |  | --- |  |  | ---- |  |  | --- | 
|For the years ended December 31,                               |  | 2015 |     |  |  |  | 2014 |  |     |  |  | 2013 | 
|                                                               |  |      |     |  | 
|Interest Expense  Short-Term Borrowings and Long-Term Debt    |  |      | 328 |  |  |  |      |  | 285 |  |  |      |  |  | 271 | 
|Premium on Redemption of Long-Term Debt                        |  |      | -   |  |  |  |      |  | -   |  |  |      |  |  | 33  | 
|Unwinding of Discount on Decommissioning Liabilities (Note 22) |  |      | 126 |  |  |  |      |  | 120 |  |  |      |  |  | 97  | 
|Other                                                          |  |      | 28  |  |  |  |      |  | 18  |  |  |      |  |  | 30  | 
|Interest Expense  Partnership Contribution Payable(1)         |  |      | -   |  |  |  |      |  | 22  |  |  |      |  |  | 98  | 
|                                                               |  |      | 482 |  |  |  |      |  | 445 |  |  |      |  |  | 529 | 



|(1) | In 2014, Cenovus repaid the remaining principal and accrued interest due under the Partnership Contribution Payable.
|--- | --------------------------------------------------------------------------------------------------------------------

6. INTEREST INCOME







|                                                         |  |      |     |   |  |  |      |  |     |   |  |      |  |  |     |  
|-------------------------------------------------------- |  | ---- | --- | - |  |  | ---- |  | --- | - |  | ---- |  |  | --- | -
|For the years ended December 31,                         |  | 2015 |     |   |  |  | 2014 |  |     |   |  | 2013 | 
|                                                         |  |      |     |   | 
|Interest Income  Partnership Contribution Receivable(1) |  |      | -   |   |  |  |      |  | -   |   |  |      |  |  | (82 | )
|Other                                                    |  |      | (28 | ) |  |  |      |  | (33 | ) |  |      |  |  | (14 | )
|                                                         |  |      | (28 | ) |  |  |      |  | (33 | ) |  |      |  |  | (96 | )



|(1) | In 2013, Cenovus received the remaining principal and accrued interest due under the Partnership Contribution Receivable.
|--- | -------------------------------------------------------------------------------------------------------------------------

7. FOREIGN EXCHANGE (GAIN) LOSS, NET







|                                                                   |  |      |       |   |  |  |      |  |     |   |  |      |  |  |      |  
|------------------------------------------------------------------ |  | ---- | ----- | - |  |  | ---- |  | --- | - |  | ---- |  |  | ---- | -
|For the years ended December 31,                                   |  | 2015 |       |   |  |  | 2014 |  |     |   |  | 2013 | 
|                                                                   |  |      |       |   | 
|Unrealized Foreign Exchange (Gain) Loss on Translation of:         |  |      |       |   |  |  |      |  |     |   |  |      |  |  |      |  
|U.S. Dollar Debt Issued From Canada                                |  |      | 1,064 |   |  |  |      |  | 458 |   |  |      |  |  | 357  |  
|U.S. Dollar Partnership Contribution Receivable Issued From Canada |  |      | -     |   |  |  |      |  | -   |   |  |      |  |  | (305 | )
|Other                                                              |  |      | 33    |   |  |  |      |  | (47 | ) |  |      |  |  | (12  | )
|Unrealized Foreign Exchange (Gain) Loss                            |  |      | 1,097 |   |  |  |      |  | 411 |   |  |      |  |  | 40   |  
|Realized Foreign Exchange (Gain) Loss                              |  |      | (61   | ) |  |  |      |  | -   |   |  |      |  |  | 168  |  
|                                                                   |  |      | 1,036 |   |  |  |      |  | 411 |   |  |      |  |  | 208  |  



|                    |  |    |  |                                  
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|Cenovus Energy Inc. |  | 23 |  | Consolidated Financial Statements



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##### Table of Contents

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

All amounts in $ millions, unless otherwise indicated

For the year ended December 31, 2015



8. DIVESTITURES





On July 29, 2015, the Company completed the sale of Heritage Royalty Limited Partnership (HRP), a wholly-owned subsidiary, to a third
party for gross cash proceeds of $3.3 billion, resulting in a gain of $2.4 billion. HRP is a royalty business consisting of approximately 4.8 million gross acres of royalty interest and mineral fee title lands in Alberta, Saskatchewan and
Manitoba. Cenovus entered into lease agreements with HRP on the fee lands from which it currently has working interest production.

In addition, HRP
has a Gross Overriding Royalty on production from Cenovuss Pelican Lake and Weyburn assets. These assets and results of operations were reported in the Conventional segment.

The divestiture gave rise to a taxable gain for which the Company has recognized current tax expense of $391 million. The majority of HRPs
assets had been acquired at a nominal cost and, as such, had minimal benefit from tax depreciation in prior years. For this reason, the current tax expense associated with the divestiture is specifically identifiable; therefore, it has been
classified as an investing activity in the Consolidated Statements of Cash Flows.

In the first quarter of 2015, the Company divested an office
building, recording a gain of $16 million.

In 2014, the Company completed the sale of certain Wainwright properties to an unrelated third party for
net proceeds of $234 million, resulting in a gain of $137 million. The Company also completed the sale of certain Bakken properties to an unrelated third party for net proceeds of $35 million, resulting in a gain of $16 million. Other
divestitures in 2014 included the sale of certain non-core properties, resulting in a gain of $4 million. These assets and results of operations were reported in the Conventional segment.

In 2013, the Company completed the sale of the Lower Shaunavon asset to an unrelated third party for net proceeds of $241 million, resulting in a loss of
$2 million. These assets and results of operations were reported in the Conventional segment. Other divestitures in 2013 included undeveloped land in northern Alberta, cancellation of some of the Companys non-core Oil Sands mineral rights
under the Lower Athabasca Regional Plan and a third-party land exchange.

9. IMPAIRMENTS





A) Cash-Generating Unit Impairments

As indicators of impairment were noted due to the significant decline in forward commodity prices, the Company has tested its upstream CGUs for
impairment.

Key Assumptions

As at December 31, 2015, the recoverable amounts of Cenovuss upstream CGUs were determined based on fair value less costs of disposal or an
evaluation of comparable asset transactions. Key assumptions in the determination of future cash flows from reserves include crude oil and natural gas prices, costs to develop and the discount rate. All reserves have been evaluated as at
December 31, 2015 by independent qualified reserves evaluators.

Crude Oil and Natural Gas Prices

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



|                     |  |      |       |  |      |  |       |      |  |  |       |  |  |      |       |  |                                 |  |       |  |  |  |      | 
|-------------------- |  | ---- | ----- |  | ---- |  | ----- | ---- |  |  | ----- |  |  | ---- | ----- |  | ------------------------------- |  | ----- |  |  |  | ---- | 
|                     |  | 2016 |       |  | 2017 |  |       | 2018 |  |  | 2019  |  |  | 2020 |       |  | Average
Annual % Change to 2026 | 
|                     | 
|                     |  |      |       |  |      | 
|WTI (US$/barrel)(1)  |  |      | 45.00 |  |      |  | 53.60 |      |  |  | 62.40 |  |  |      | 69.00 |  |                                 |  | 73.10 |  |  |  | 3.8% | 
|WCS (C$/barrel)(2)   |  |      | 46.40 |  |      |  | 54.40 |      |  |  | 59.70 |  |  |      | 66.30 |  |                                 |  | 68.20 |  |  |  | 3.9% | 
|AECO (C$/Mcf)(3) (4) |  |      | 2.70  |  |      |  | 3.20  |      |  |  | 3.55  |  |  |      | 3.85  |  |                                 |  | 3.95  |  |  |  | 4.0% | 
|                     |  |      |       |  |      |  |       |      |  |  |       |  |  |      |       |  |                                 |  |       |  |  |  |      | 

|(1) | West Texas Intermediate (WTI) crude oil.
|--- | ------------------------------------------

|(2) | Western Canadian Select (WCS) crude oil blend.
|--- | ------------------------------------------------

|(3) | Alberta Energy Company (AECO) natural gas.
|--- | --------------------------------------------

|(4) | Assumes gas heating value of one million British Thermal Units per thousand cubic feet.
|--- | ---------------------------------------------------------------------------------------



|                    |  |    |  |                                  
|------------------- |  | -- |  | ---------------------------------
|Cenovus Energy Inc. |  | 24 |  | Consolidated Financial Statements



---

##### Table of Contents

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

All amounts in $ millions, unless otherwise indicated

For the year ended December 31, 2015



Discount and Inflation Rates

Evaluations of discounted future cash flows are initiated using the discount rate of 10 percent and inflation is estimated at two percent, which is common
industry practice and used by Cenovuss independent qualified reserves evaluators in preparing their reserves reports. Based on the individual characteristics of the asset, other economic and operating factors are also considered, which may
increase or decrease the implied discount rate.

2015 Impairments

As at December 31, 2015, the Company determined that the carrying amount of the Northern Alberta CGU exceeded its recoverable amount, resulting in an
impairment loss of $184 million. The impairment was recorded as additional DD&A in the Conventional segment. The Northern Alberta CGU includes the Pelican Lake and Elk Point producing assets and other emerging assets in the exploration and
evaluation stage. Future cash flows for the CGU declined due to lower forward crude oil prices, a decline in reserves estimates and a slowing down of the development plan. This was partially offset by lower future development and operating costs.

The recoverable amount was determined using fair value less costs of disposal. The fair value for producing properties was calculated based on
discounted after-tax cash flows of proved and probable reserves using forward prices and cost estimates, consistent with Cenovuss independent qualified reserves evaluators (Level 3). Future cash flows were estimated using a two percent
inflation rate and discounted using a rate of 10 percent. As at December 31, 2015, the recoverable amount of the Northern Alberta CGU was estimated to be approximately $1.5 billion.

For the purpose of impairment testing, goodwill is allocated to the CGU to which it relates. There were no impairments of goodwill in the year ended
December 31, 2015.

Sensitivities

Changes to the assumed discount rate or forward price estimates over the life of the reserves independently would have the following impact on the 2015
impairment of the Northern Alberta CGU:



|                               |  |                                           |     |  |  |  |                                                   |  |     | 
|------------------------------ |  | ----------------------------------------- | --- |  |  |  | ------------------------------------------------- |  | --- | 
|                               |  | One Percent
Increase in the
Discount Rate |     |  |  |  | Five PercentDecrease in theForward PriceEstimates | 
|                               |  |                                           |    
|Increase to Impairment of PP&E |  |                                           | 157 |  |  |  |                                                   |  | 336 | 

2014 Impairments

As at December 31, 2014, the Company determined that the carrying amount of the Northern Alberta CGU exceeded its recoverable amount and the full
amount of the impairment was attributed to goodwill. An impairment loss of $497 million was recorded as goodwill impairment on the Consolidated Statements of Earnings. The operating results of the CGU are included in the Conventional segment. Future
cash flows for the CGU declined due to lower crude oil prices and a slowing down of the Pelican Lake development plan.

The recoverable amount was
determined using fair value less costs of disposal. The fair value for producing properties was calculated based on discounted after-tax cash flows of proved and probable reserves using forward prices and cost estimates, consistent with
Cenovuss independent qualified reserves evaluators (Level 3). The fair value of E&E assets was determined using market comparable transactions (Level 3). Future cash flows were estimated using a two percent inflation rate and discounted
using a rate of 11 percent. To assess reasonableness, an evaluation of fair value based on comparable asset transactions was also completed. As at December 31, 2014, the recoverable amount of the Northern Alberta CGU was estimated to be $2.3
billion.

2013 Impairments

There were no CGU impairments for the year ended December 31, 2013.

B) Asset Impairments

Exploration and Evaluation Assets

In 2015, $138 million of previously capitalized E&E costs were deemed not to be technically feasible and commercially viable, and were recorded as
exploration expense. This impairment loss included $67 million and $71 million within the Oil Sands and Conventional segments, respectively.



|                    |  |    |  |                                  
|------------------- |  | -- |  | ---------------------------------
|Cenovus Energy Inc. |  | 25 |  | Consolidated Financial Statements



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##### Table of Contents

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

All amounts in $ millions, unless otherwise indicated

For the year ended December 31, 2015



In 2014, $82 million of previously capitalized E&E costs were deemed not to be technically feasible
and commercially viable, and were recorded as exploration expense in the Conventional segment. In addition, $4 million of costs related to the expiry of leases in the Borealis CGU were recorded as exploration expense in the Oil Sands segment.

In 2013, $50 million of previously capitalized E&E costs were deemed not to be technically feasible and commercially viable and were recorded as
exploration expense in the Conventional segment.

Property, Plant and Equipment, Net

In addition to the impairments recorded at the CGU level, DD&A expense includes the following asset impairments:



|                                     |  |      |    |  |  |  |      |  |    |  |  |      |  |  |    | 
|------------------------------------ |  | ---- | -- |  |  |  | ---- |  | -- |  |  | ---- |  |  | -- | 
|For the years ended December 31,     |  | 2015 |    |  |  |  | 2014 |  |    |  |  | 2013 | 
|                                     |  |      |    |  | 
|Development and Production (Note 16) |  |      | 16 |  |  |  |      |  | 65 |  |  |      |  |  | 59 | 
|                                     |  |      | 16 |  |  |  |      |  | 65 |  |  |      |  |  | 59 | 

In 2015, the Company impaired a sulphur recovery facility for $16 million, which was recorded in the Oil Sands segment.
The Company did not have future plans for the assets and did not believe it would recover the carrying amount through a sale.

In 2014, the Company
impaired equipment for $52 million. The Company did not have future plans for the equipment and did not believe it would recover the carrying amount through a sale. The asset was written down to fair value less costs of disposal. Additionally, a
minor natural gas property was shut-in and abandonment commenced, resulting in an impairment of $13 million. These impairments were recorded in the Conventional segment.

In 2013, the Company impaired its Lower Shaunavon asset for $57 million prior to its divestiture. The impairment was recorded in the Conventional segment.

10. INCOME TAXES





The provision for income taxes is:



|                                     |  |      |      |   |  |  |      |  |     |   |  |      |  |  |     | 
|------------------------------------ |  | ---- | ---- | - |  |  | ---- |  | --- | - |  | ---- |  |  | --- | 
|For the years ended December 31,     |  | 2015 |      |   |  |  | 2014 |  |     |   |  | 2013 | 
|                                     |  |      |      |   | 
|Current Tax                          |  |      |      |   |  |  |      |  |     |   |  |      |  |  |     | 
|Canada                               |  |      | 586  |   |  |  |      |  | 94  |   |  |      |  |  | 143 | 
|United States                        |  |      | (12  | ) |  |  |      |  | (2  | ) |  |      |  |  | 45  | 
|Total Current Tax Expense (Recovery) |  |      | 574  |   |  |  |      |  | 92  |   |  |      |  |  | 188 | 
|Deferred Tax Expense (Recovery)      |  |      | (655 | ) |  |  |      |  | 359 |   |  |      |  |  | 244 | 
|                                     |  |      | (81  | ) |  |  |      |  | 451 |   |  |      |  |  | 432 | 

In 2015, the Company recorded a deferred tax recovery of $415 million arising from an adjustment to the tax basis of the
Companys refining assets. The increase in tax basis was a result of the Companys partner recognizing a taxable gain on its interest in WRB which, due to an election filed with the U.S. tax authorities, was added to the tax basis of
WRBs assets.

The Alberta government enacted a two percent increase in the corporate income tax rate effective July 1, 2015, increasing the
statutory tax rate for the year to 26.1 percent. As a result, the Companys deferred income tax liability increased by $161 million for the year ended December 31, 2015. The Canadian statutory tax rate as at December 31, 2015 was 27.0
percent. The U.S. statutory tax rate has decreased to 38.0 percent from 38.1 percent in 2014 and 38.5 percent in 2013.



|                    |  |    |  |                                  
|------------------- |  | -- |  | ---------------------------------
|Cenovus Energy Inc. |  | 26 |  | Consolidated Financial Statements



---

##### Table of Contents

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

All amounts in $ millions, unless otherwise indicated

For the year ended December 31, 2015



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



|                                                                                   |  |      |         |  |  |  |      |  |       |  |  |      |  |  |       | 
|---------------------------------------------------------------------------------- |  | ---- | ------- |  |  |  | ---- |  | ----- |  |  | ---- |  |  | ----- | 
|For the years ended December 31,                                                   |  | 2015 |         |  |  |  | 2014 |  |       |  |  | 2013 | 
|Earnings Before Income Tax                                                         |  |      | 537     |  |  |  |      |  | 1,195 |  |  |      |  |  | 1,094 | 
|Canadian Statutory Rate                                                            |  |      | 26.1%   |  |  |  |      |  | 25.2% |  |  |      |  |  | 25.2% | 
|Expected Income Tax                                                                |  |      | 140     |  |  |  |      |  | 301   |  |  |      |  |  | 276   | 
|Effect of Taxes Resulting From:                                                    |  |      |         |  |  |  |      |  |       |  |  |      |  |  |       | 
|Foreign Tax Rate Differential                                                      |  |      | (41)    |  |  |  |      |  | (43)  |  |  |      |  |  | 87    | 
|Non-Deductible Stock-Based Compensation                                            |  |      | 7       |  |  |  |      |  | 13    |  |  |      |  |  | 10    | 
|Non-Taxable Capital Losses                                                         |  |      | 137     |  |  |  |      |  | 74    |  |  |      |  |  | 6     | 
|Unrecognized Capital Losses Arising From Unrealized Foreign Exchange               |  |      | 135     |  |  |  |      |  | 50    |  |  |      |  |  | 25    | 
|Adjustments Arising From Prior Year Tax Filings                                    |  |      | (55)    |  |  |  |      |  | (16)  |  |  |      |  |  | (13)  | 
|Derecognition (Recognition) of Capital Losses                                      |  |      | (149)   |  |  |  |      |  | (9)   |  |  |      |  |  | 15    | 
|Recognition of U.S. Tax Basis                                                      |  |      | (415)   |  |  |  |      |  | -     |  |  |      |  |  | -     | 
|Change in Statutory Rate                                                           |  |      | 161     |  |  |  |      |  | -     |  |  |      |  |  | -     | 
|Foreign Exchange Gains (Losses) not Included in Net Earnings                       |  |      | -       |  |  |  |      |  | (13)  |  |  |      |  |  | 19    | 
|Goodwill Impairment                                                                |  |      | -       |  |  |  |      |  | 125   |  |  |      |  |  | -     | 
|Other                                                                              |  |      | (1)     |  |  |  |      |  | (31)  |  |  |      |  |  | 7     | 
|Total Tax                                                                          |  |      | (81)    |  |  |  |      |  | 451   |  |  |      |  |  | 432   | 
|Effective Tax Rate                                                                 |  |      | (15.1)% |  |  |  |      |  | 37.7% |  |  |      |  |  | 39.5% | 
|                                                                                   |  |      |         |  | 
|The analysis of deferred income tax liabilities and deferred income tax assets is: |  |      |         |  |  |  |      |  |       |  |  |      |  |  |       | 
|                                                                                   |  |      |         |  | 
|As at December 31,                                                                 |  |      |         |  |  |  | 2015 |  |       |  |  | 2014 | 
|                                                                                   |  |      |         |  | 
|Net Deferred Income Tax Liabilities                                                |  |      |         |  |  |  |      |  |       |  |  |      |  |  |       | 
|Deferred Tax Liabilities to be Settled Within 12 Months                            |  |      |         |  |  |  |      |  | 58    |  |  |      |  |  | 296   | 
|Deferred Tax Liabilities to be Settled After More Than 12 Months                   |  |      |         |  |  |  |      |  | 2,758 |  |  |      |  |  | 3,006 | 
|                                                                                   |  |      |         |  |  |  |      |  | 2,816 |  |  |      |  |  | 3,302 | 

For the purposes of the preceding table, deferred income tax liabilities are shown net of offsetting deferred income tax
assets where they occur in the same entity and jurisdiction. The deferred income tax liabilities to be settled within 12 months represents Managements estimate of the timing of the reversal of temporary differences and may not correlate to the
current income tax expense of the subsequent year.

The movement in deferred income tax liabilities and assets, without taking into consideration the
offsetting of balances within the same tax jurisdiction, is:



|                                |  |                               |       |   |  |  |                             |  |      |   |  |                 |  |  |     |   |       |  |  |  |      |       |  |  |  |  |       |  
|------------------------------- |  | ----------------------------- | ----- | - |  |  | --------------------------- |  | ---- | - |  | --------------- |  |  | --- | - | ----- |  |  |  | ---- | ----- |  |  |  |  | ----- | -
|Deferred Income Tax Liabilities |  | Property,
Plant and Equipment |       |   |  |  | Timing of
Partnership Items |  |      |   |  | Risk
Management |  |  |     |   | Other |  |  |  |      | Total | 
|As at December 31, 2013         |  |                               | 3,000 |   |  |  |                             |  | 88   |   |  |                 |  |  | 2   |   |       |  |  |  | 152  |       |  |  |  |  | 3,242 |  
|Charged/(Credited) to Earnings  |  |                               | 22    |   |  |  |                             |  | 79   |   |  |                 |  |  | 119 |   |       |  |  |  | (111 | )     |  |  |  |  | 109   |  
|Charged/(Credited) to OCI       |  |                               | 84    |   |  |  |                             |  | -    |   |  |                 |  |  | -   |   |       |  |  |  | -    |       |  |  |  |  | 84    |  
|As at December 31, 2014         |  |                               | 3,106 |   |  |  |                             |  | 167  |   |  |                 |  |  | 121 |   |       |  |  |  | 41   |       |  |  |  |  | 3,435 |  
|Charged/(Credited) to Earnings  |  |                               | (246  | ) |  |  |                             |  | (167 | ) |  |                 |  |  | (39 | ) |       |  |  |  | (24  | )     |  |  |  |  | (476  | )
|Charged/(Credited) to OCI       |  |                               | 192   |   |  |  |                             |  | -    |   |  |                 |  |  | -   |   |       |  |  |  | -    |       |  |  |  |  | 192   |  
|As at December 31, 2015         |  |                               | 3,052 |   |  |  |                             |  | -    |   |  |                 |  |  | 82  |   |       |  |  |  | 17   |       |  |  |  |  | 3,151 |  



|                    |  |    |  |                                  
|------------------- |  | -- |  | ---------------------------------
|Cenovus Energy Inc. |  | 27 |  | Consolidated Financial Statements



---

##### Table of Contents

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

All amounts in $ millions, unless otherwise indicated

For the year ended December 31, 2015



|                                                            |  |                   |  |  |  |                             |     |   |  |  |                 |  |     |   |  |       |  |  |      |   |       |  |  |  |       |  
|----------------------------------------------------------- |  | ----------------- |  |  |  | --------------------------- | --- | - |  |  | --------------- |  | --- | - |  | ----- |  |  | ---- | - | ----- |  |  |  | ----- | -
|Deferred Income Tax Assets                                  |  | Unused Tax
Losses |  |  |  | Timing of
Partnership Items |     |   |  |  | Risk
Management |  |     |   |  | Other |  |  |      |   | Total | 
|As at December 31, 2013                                     |  | (104)             |  |  |  |                             | -   |   |  |  |                 |  | (35 | ) |  |       |  |  | (241 | ) |       |  |  |  | (380  | )
|Charged/(Credited) to Earnings                              |  | 41                |  |  |  |                             | -   |   |  |  |                 |  | 31  |   |  |       |  |  | 178  |   |       |  |  |  | 250   |  
|Charged/(Credited) to OCI                                   |  | (9)               |  |  |  |                             | -   |   |  |  |                 |  | -   |   |  |       |  |  | 6    |   |       |  |  |  | (3    | )
|As at December 31, 2014                                     |  | (72)              |  |  |  |                             | -   |   |  |  |                 |  | (4  | ) |  |       |  |  | (57  | ) |       |  |  |  | (133  | )
|Charged/(Credited) to Earnings                              |  | (80)              |  |  |  |                             | (36 | ) |  |  |                 |  | (4  | ) |  |       |  |  | (59  | ) |       |  |  |  | (179  | )
|Charged/(Credited) to OCI                                   |  | (20)              |  |  |  |                             | -   |   |  |  |                 |  | -   |   |  |       |  |  | (3   | ) |       |  |  |  | (23   | )
|As at December 31, 2015                                     |  | (172)             |  |  |  |                             | (36 | ) |  |  |                 |  | (8  | ) |  |       |  |  | (119 | ) |       |  |  |  | (335  | )
|                                                            |  |                   |  |  |  |                             |     |   | 
|Net Deferred Income Tax Liabilities                         |  |                   |  |  |  |                             |     |   |  |  |                 |  |     |   |  |       |  |  |      |   | Total | 
|Net Deferred Income Tax Liabilities as at December 31, 2013 |  |                   |  |  |  |                             |     |   |  |  |                 |  |     |   |  |       |  |  |      |   |       |  |  |  | 2,862 |  
|Charged/(Credited) to Earnings                              |  |                   |  |  |  |                             |     |   |  |  |                 |  |     |   |  |       |  |  |      |   |       |  |  |  | 359   |  
|Charged/(Credited) to OCI                                   |  |                   |  |  |  |                             |     |   |  |  |                 |  |     |   |  |       |  |  |      |   |       |  |  |  | 81    |  
|Net Deferred Income Tax Liabilities as at December 31, 2014 |  |                   |  |  |  |                             |     |   |  |  |                 |  |     |   |  |       |  |  |      |   |       |  |  |  | 3,302 |  
|Charged/(Credited) to Earnings                              |  |                   |  |  |  |                             |     |   |  |  |                 |  |     |   |  |       |  |  |      |   |       |  |  |  | (655  | )
|Charged/(Credited) to OCI                                   |  |                   |  |  |  |                             |     |   |  |  |                 |  |     |   |  |       |  |  |      |   |       |  |  |  | 169   |  
|Net Deferred Income Tax Liabilities as at December 31, 2015 |  |                   |  |  |  |                             |     |   |  |  |                 |  |     |   |  |       |  |  |      |   |       |  |  |  | 2,816 |  

No deferred tax liability has been recognized as at December 31, 2015 on temporary differences associated with
investments in subsidiaries and joint arrangements where the Company can control the timing of the reversal of the temporary difference and the reversal is not probable in the foreseeable future. As at December 31, 2015, the Company had
temporary differences of $6,692 million (2014  $6,667 million) in respect of certain of these investments where, on dissolution or sale, a tax liability may exist.

The approximate amounts of tax pools available are:



|                   |  |      |       |  |  |  |      |  |       | 
|------------------ |  | ---- | ----- |  |  |  | ---- |  | ----- | 
|As at December 31, |  | 2015 |       |  |  |  | 2014 | 
|Canada             |  |      | 4,882 |  |  |  |      |  | 6,153 | 
|United States      |  |      | 2,119 |  |  |  |      |  | 958   | 
|                   |  |      | 7,001 |  |  |  |      |  | 7,111 | 

As at December 31, 2015, the above tax pools included $13 million (2014  $8 million) of Canadian non-capital
losses and $380 million (2014  $140 million) of U.S. federal net operating losses. These losses expire no earlier than 2031.

Also included in
the December 31, 2015 tax pools are Canadian net capital losses totaling $44 million (2014  $593 million), which are available for carry forward to reduce future capital gains. Of these losses, $41 million are unrecognized as a
deferred income tax asset as at December 31, 2015 (2014  $559 million). Recognition is dependent on future capital gains. The Company has not recognized $828 million of net capital losses associated with unrealized foreign exchange losses
on its U.S. denominated debt.



|                    |  |    |  |                                  
|------------------- |  | -- |  | ---------------------------------
|Cenovus Energy Inc. |  | 28 |  | Consolidated Financial Statements



---

##### Table of Contents

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

All amounts in $ millions, unless otherwise indicated

For the year ended December 31, 2015



11. PER SHARE AMOUNTS



A) Net Earnings
Per Share



|                                                     |  |      |       |  |  |  |      |  |       |  |  |      |  |  |       | 
|---------------------------------------------------- |  | ---- | ----- |  |  |  | ---- |  | ----- |  |  | ---- |  |  | ----- | 
|For the years ended December 31,                     |  | 2015 |       |  |  |  | 2014 |  |       |  |  | 2013 | 
|Net Earnings  Basic and Diluted ($ millions)        |  |      | 618   |  |  |  |      |  | 744   |  |  |      |  |  | 662   | 
|                                                     |  |      |       |  | 
|Basic  Weighted Average Number of Shares (millions) |  |      | 818.7 |  |  |  |      |  | 756.9 |  |  |      |  |  | 755.9 | 
|Dilutive Effect of Cenovus TSARs                     |  |      | -     |  |  |  |      |  | 0.7   |  |  |      |  |  | 1.6   | 
|Dilutive Effect of Cenovus NSRs                      |  |      | -     |  |  |  |      |  | -     |  |  |      |  |  | -     | 
|Diluted  Weighted Average Number of Shares          |  |      | 818.7 |  |  |  |      |  | 757.6 |  |  |      |  |  | 757.5 | 
|                                                     |  |      |       |  | 
|Net Earnings Per Share ($)                           |  |      |       |  |  |  |      |  |       |  |  |      |  |  |       | 
|Basic                                                |  |      | $0.75 |  |  |  |      |  | $0.98 |  |  |      |  |  | $0.88 | 
|Diluted                                              |  |      | $0.75 |  |  |  |      |  | $0.98 |  |  |      |  |  | $0.87 | 

B) Dividends Per Share

For the year ended December 31, 2015, the Company paid dividends of $710 million or $0.8524 per share (2014  $805 million, $1.0648
per share; 2013  $732 million, $0.968 per share), including cash dividends of $528 million. For 2014 and 2013, all dividends were paid in cash. The Cenovus Board of Directors declared a first quarter dividend of $0.05 per share,
payable on March 31, 2016, to common shareholders of record as of March 15, 2016.

12. CASH AND CASH EQUIVALENTS





|                       |  |      |       |  |  |  |      |  |     | 
|---------------------- |  | ---- | ----- |  |  |  | ---- |  | --- | 
|As at December 31,     |  | 2015 |       |  |  |  | 2014 | 
|Cash                   |  |      | 323   |  |  |  |      |  | 458 | 
|Short-Term Investments |  |      | 3,782 |  |  |  |      |  | 425 | 
|                       |  |      | 4,105 |  |  |  |      |  | 883 | 

13. ACCOUNTS RECEIVABLE AND ACCRUED REVENUES





|                             |  |      |       |  |  |  |      |  |       | 
|---------------------------- |  | ---- | ----- |  |  |  | ---- |  | ----- | 
|As at December 31,           |  | 2015 |       |  |  |  | 2014 | 
|Accruals                     |  |      | 1,037 |  |  |  |      |  | 1,417 | 
|Partner Advances             |  |      | 35    |  |  |  |      |  | 44    | 
|Prepaids and Deposits        |  |      | 71    |  |  |  |      |  | 56    | 
|Trade                        |  |      | 61    |  |  |  |      |  | 6     | 
|Joint Operations Receivables |  |      | 13    |  |  |  |      |  | 18    | 
|Other                        |  |      | 34    |  |  |  |      |  | 41    | 
|                             |  |      | 1,251 |  |  |  |      |  | 1,582 | 



|                    |  |    |  |                                  
|------------------- |  | -- |  | ---------------------------------
|Cenovus Energy Inc. |  | 29 |  | Consolidated Financial Statements



---

##### Table of Contents

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

All amounts in $ millions, unless otherwise indicated

For the year ended December 31, 2015



14. INVENTORIES





|                       |  |      |     |  |  |  |      |  |       | 
|---------------------- |  | ---- | --- |  |  |  | ---- |  | ----- | 
|As at December 31,     |  | 2015 |     |  |  |  | 2014 | 
|Product                |  |      |     |  |  |  |      |  |       | 
|Refining and Marketing |  |      | 591 |  |  |  |      |  | 972   | 
|Oil Sands              |  |      | 158 |  |  |  |      |  | 182   | 
|Conventional           |  |      | 11  |  |  |  |      |  | 28    | 
|Parts and Supplies     |  |      | 50  |  |  |  |      |  | 42    | 
|                       |  |      | 810 |  |  |  |      |  | 1,224 | 

During the year ended December 31, 2015, approximately $10,618 million of produced and purchased inventory was
recorded as an expense (2014  $15,065 million; 2013  $13,895 million).

As a result of a decline in commodity prices, Cenovus recorded a
write-down of its product inventory of $66 million from cost to net realizable value as at December 31, 2015 (2014  $131 million).

15. EXPLORATION AND EVALUATION ASSETS





|                                      |  |  |       |  
|------------------------------------- |  |  | ----- | -
|COST                                  |  |  |       |  
|As at December 31, 2013               |  |  | 1,473 |  
|Additions                             |  |  | 279   |  
|Transfers to PP&E (Note 16)           |  |  | (53   | )
|Exploration Expense (Note 9)          |  |  | (86   | )
|Divestitures                          |  |  | (2    | )
|Change in Decommissioning Liabilities |  |  | 14    |  
|As at December 31, 2014               |  |  | 1,625 |  
|Additions                             |  |  | 138   |  
|Acquisitions                          |  |  | 3     |  
|Transfers to PP&E (Note 16)           |  |  | (49   | )
|Exploration Expense (Note 9)          |  |  | (138  | )
|Change in Decommissioning Liabilities |  |  | (4    | )
|As at December 31, 2015               |  |  | 1,575 |  



|                    |  |    |  |                                  
|------------------- |  | -- |  | ---------------------------------
|Cenovus Energy Inc. |  | 30 |  | Consolidated Financial Statements



---

##### Table of Contents

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

All amounts in $ millions, unless otherwise indicated

For the year ended December 31, 2015



16. PROPERTY, PLANT AND EQUIPMENT, NET





|                                                     |  |                          |        |   |  |  |                |  |     |  |  |                    |  |  |       |   |          |  |  |  |       |       |  |  |  |  |        |  
|---------------------------------------------------- |  | ------------------------ | ------ | - |  |  | -------------- |  | --- |  |  | ------------------ |  |  | ----- | - | -------- |  |  |  | ----- | ----- |  |  |  |  | ------ | -
|                                                     |  | Upstream Assets          |        |   |  |  |                |  |     |  |  |                    |  |  |       |   |          | 
|                                                     |  | Development
& Production |        |   |  |  | Other
Upstream |  |     |  |  | Refining
Equipment |  |  |       |   | Other(1) |  |  |  |       | Total | 
|COST                                                 |  |                          |        |   |  |  |                |  |     |  |  |                    |  |  |       |   |          |  |  |  |       |       |  |  |  |  |        |  
|As at December 31, 2013                              |  |                          | 29,390 |   |  |  |                |  | 286 |  |  |                    |  |  | 3,654 |   |          |  |  |  | 849   |       |  |  |  |  | 34,179 |  
|Additions                                            |  |                          | 2,522  |   |  |  |                |  | 43  |  |  |                    |  |  | 162   |   |          |  |  |  | 63    |       |  |  |  |  | 2,790  |  
|Transfers From E&E Assets (Note 15)                  |  |                          | 53     |   |  |  |                |  | -   |  |  |                    |  |  | -     |   |          |  |  |  | -     |       |  |  |  |  | 53     |  
|Transfers to Assets Held for Sale                    |  |                          | (55    | ) |  |  |                |  | -   |  |  |                    |  |  | -     |   |          |  |  |  | -     |       |  |  |  |  | (55    | )
|Change in Decommissioning Liabilities                |  |                          | 264    |   |  |  |                |  | -   |  |  |                    |  |  | (3    | ) |          |  |  |  | -     |       |  |  |  |  | 261    |  
|Exchange Rate Movements and Other                    |  |                          | 1      |   |  |  |                |  | -   |  |  |                    |  |  | 338   |   |          |  |  |  | -     |       |  |  |  |  | 339    |  
|Divestitures                                         |  |                          | (474   | ) |  |  |                |  | -   |  |  |                    |  |  | -     |   |          |  |  |  | (2    | )     |  |  |  |  | (476   | )
|As at December 31, 2014                              |  |                          | 31,701 |   |  |  |                |  | 329 |  |  |                    |  |  | 4,151 |   |          |  |  |  | 910   |       |  |  |  |  | 37,091 |  
|Additions                                            |  |                          | 1,289  |   |  |  |                |  | 2   |  |  |                    |  |  | 240   |   |          |  |  |  | 45    |       |  |  |  |  | 1,576  |  
|Acquisition (Note 17)                                |  |                          | 1      |   |  |  |                |  | -   |  |  |                    |  |  | -     |   |          |  |  |  | 83    |       |  |  |  |  | 84     |  
|Transfers From E&E Assets (Note 15)                  |  |                          | 49     |   |  |  |                |  | -   |  |  |                    |  |  | -     |   |          |  |  |  | -     |       |  |  |  |  | 49     |  
|Change in Decommissioning Liabilities                |  |                          | (635   | ) |  |  |                |  | -   |  |  |                    |  |  | 1     |   |          |  |  |  | (1    | )     |  |  |  |  | (635   | )
|Exchange Rate Movements and Other                    |  |                          | (1     | ) |  |  |                |  | -   |  |  |                    |  |  | 814   |   |          |  |  |  | -     |       |  |  |  |  | 813    |  
|Divestitures (Note 8)                                |  |                          | (923   | ) |  |  |                |  | -   |  |  |                    |  |  | -     |   |          |  |  |  | -     |       |  |  |  |  | (923   | )
|As at December 31, 2015                              |  |                          | 31,481 |   |  |  |                |  | 331 |  |  |                    |  |  | 5,206 |   |          |  |  |  | 1,037 |       |  |  |  |  | 38,055 |  
|                                                     |  |                          |        |   |  |  |                |  |    
|ACCUMULATED DEPRECIATION, DEPLETION AND AMORTIZATION |  |                          |        |   |  |  |                |  |     |  |  |                    |  |  |       |   |          |  |  |  |       |       |  |  |  |  |        |  
|As at December 31, 2013                              |  |                          | 15,791 |   |  |  |                |  | 193 |  |  |                    |  |  | 386   |   |          |  |  |  | 475   |       |  |  |  |  | 16,845 |  
|Depreciation, Depletion and Amortization             |  |                          | 1,602  |   |  |  |                |  | 40  |  |  |                    |  |  | 156   |   |          |  |  |  | 83    |       |  |  |  |  | 1,881  |  
|Transfers to Assets Held for Sale                    |  |                          | (27    | ) |  |  |                |  | -   |  |  |                    |  |  | -     |   |          |  |  |  | -     |       |  |  |  |  | (27    | )
|Impairment Losses (Note 9)                           |  |                          | 65     |   |  |  |                |  | -   |  |  |                    |  |  | -     |   |          |  |  |  | -     |       |  |  |  |  | 65     |  
|Exchange Rate Movements and Other                    |  |                          | 38     |   |  |  |                |  | -   |  |  |                    |  |  | 42    |   |          |  |  |  | -     |       |  |  |  |  | 80     |  
|Divestitures                                         |  |                          | (316   | ) |  |  |                |  | -   |  |  |                    |  |  | -     |   |          |  |  |  | -     |       |  |  |  |  | (316   | )
|As at December 31, 2014                              |  |                          | 17,153 |   |  |  |                |  | 233 |  |  |                    |  |  | 584   |   |          |  |  |  | 558   |       |  |  |  |  | 18,528 |  
|Depreciation, Depletion and Amortization             |  |                          | 1,601  |   |  |  |                |  | 44  |  |  |                    |  |  | 189   |   |          |  |  |  | 80    |       |  |  |  |  | 1,914  |  
|Impairment Losses (Note 9)                           |  |                          | 200    |   |  |  |                |  | -   |  |  |                    |  |  | -     |   |          |  |  |  | -     |       |  |  |  |  | 200    |  
|Exchange Rate Movements and Other                    |  |                          | (1     | ) |  |  |                |  | -   |  |  |                    |  |  | 123   |   |          |  |  |  | 1     |       |  |  |  |  | 123    |  
|Divestitures (Note 8)                                |  |                          | (45    | ) |  |  |                |  | -   |  |  |                    |  |  | -     |   |          |  |  |  | -     |       |  |  |  |  | (45    | )
|As at December 31, 2015                              |  |                          | 18,908 |   |  |  |                |  | 277 |  |  |                    |  |  | 896   |   |          |  |  |  | 639   |       |  |  |  |  | 20,720 |  
|                                                     |  |                          |        |   |  |  |                |  |    
|CARRYING VALUE                                       |  |                          |        |   |  |  |                |  |     |  |  |                    |  |  |       |   |          |  |  |  |       |       |  |  |  |  |        |  
|As at December 31, 2013                              |  |                          | 13,599 |   |  |  |                |  | 93  |  |  |                    |  |  | 3,268 |   |          |  |  |  | 374   |       |  |  |  |  | 17,334 |  
|As at December 31, 2014                              |  |                          | 14,548 |   |  |  |                |  | 96  |  |  |                    |  |  | 3,567 |   |          |  |  |  | 352   |       |  |  |  |  | 18,563 |  
|As at December 31, 2015                              |  |                          | 12,573 |   |  |  |                |  | 54  |  |  |                    |  |  | 4,310 |   |          |  |  |  | 398   |       |  |  |  |  | 17,335 |  

(1) Includes crude-by-rail terminal, office furniture, fixtures, leasehold improvements, information technology and aircraft.

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



|                           |  |      |     |  |  |  |      |  |     | 
|-------------------------- |  | ---- | --- |  |  |  | ---- |  | --- | 
|As at December 31,         |  | 2015 |     |  |  |  | 2014 | 
|                           |  |      |    
|Development and Production |  |      | 537 |  |  |  |      |  | 478 | 
|Refining Equipment         |  |      | 265 |  |  |  |      |  | 159 | 
|                           |  |      | 802 |  |  |  |      |  | 637 | 



|                    |  |    |  |                                  
|------------------- |  | -- |  | ---------------------------------
|Cenovus Energy Inc. |  | 31 |  | Consolidated Financial Statements



---

##### Table of Contents

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

All amounts in $ millions, unless otherwise indicated

For the year ended December 31, 2015



17. ACQUISITION





On August 31, 2015, the Company completed the acquisition of a crude-by-rail terminal for cash consideration of $75 million, plus adjustments. The
transaction was accounted for using the acquisition method of accounting. In connection with the acquisition, the Company assumed an associated decommissioning liability of $4 million, working capital of $1 million and net transportation commitments
of $92 million. Transaction costs associated with the acquisition have been expensed. These assets and results of operations are reported in the Refining and Marketing segment.

18. OTHER ASSETS





|                      |  |      |    |  |  |  |      |  |    | 
|--------------------- |  | ---- | -- |  |  |  | ---- |  | -- | 
|As at December 31,    |  | 2015 |    |  |  |  | 2014 | 
|                      |  |      |   
|Investments           |  |      | 46 |  |  |  |      |  | 36 | 
|Long-Term Receivables |  |      | 1  |  |  |  |      |  | 7  | 
|Prepaids              |  |      | 7  |  |  |  |      |  | 7  | 
|Other                 |  |      | 22 |  |  |  |      |  | 20 | 
|                      |  |      | 76 |  |  |  |      |  | 70 | 

19. GOODWILL







|                                  |  |      |     |  |  |  |      |  |      |  
|--------------------------------- |  | ---- | --- |  |  |  | ---- |  | ---- | -
|As at December 31,                |  | 2015 |     |  |  |  | 2014 | 
|                                  |  |      |    
|Carrying Value, Beginning of Year |  |      | 242 |  |  |  |      |  | 739  |  
|Impairment Losses (Note 9)        |  |      | -   |  |  |  |      |  | (497 | )
|Carrying Value, End of Year       |  |      | 242 |  |  |  |      |  | 242  |  

All of the Companys goodwill arose in 2002 upon the formation of the predecessor corporation. As at
December 31, 2015 and 2014, the carrying amount of goodwill was associated with the Companys Primrose (Foster Creek) CGU.

20. ACCOUNTS PAYABLE AND ACCRUED LIABILITIES







|                              |  |      |       |  |  |  |      |  |       | 
|----------------------------- |  | ---- | ----- |  |  |  | ---- |  | ----- | 
|As at December 31,            |  | 2015 |       |  |  |  | 2014 | 
|                              |  |      |      
|Accruals                      |  |      | 1,366 |  |  |  |      |  | 2,057 | 
|Partner Advances              |  |      | 35    |  |  |  |      |  | 218   | 
|Trade                         |  |      | 68    |  |  |  |      |  | 51    | 
|Employee Long-Term Incentives |  |      | 47    |  |  |  |      |  | 91    | 
|Interest                      |  |      | 73    |  |  |  |      |  | 61    | 
|Other                         |  |      | 113   |  |  |  |      |  | 110   | 
|                              |  |      | 1,702 |  |  |  |      |  | 2,588 | 

21. LONG-TERM DEBT







|                                        |  |   |  |      |       |   |  |  |      |  |       |  
|--------------------------------------- |  | - |  | ---- | ----- | - |  |  | ---- |  | ----- | -
|As at December 31,                      |  |   |  | 2015 |       |   |  |  | 2014 | 
|                                        |  |   |  |     
|Revolving Term Debt(1)                  |  | A |  |      | -     |   |  |  |      |  | -     |  
|U.S. Dollar Denominated Unsecured Notes |  | B |  |      | 6,574 |   |  |  |      |  | 5,510 |  
|Total Debt Principal                    |  | C |  |      | 6,574 |   |  |  |      |  | 5,510 |  
|Debt Discounts and Transaction Costs    |  | D |  |      | (49   | ) |  |  |      |  | (52   | )
|                                        |  |   |  |      | 6,525 |   |  |  |      |  | 5,458 |  

(1)  Revolving term debt may include bankers acceptances, LIBOR loans, prime rate loans and U.S. base
rate loans.



|                    |  |    |  |                                  
|------------------- |  | -- |  | ---------------------------------
|Cenovus Energy Inc. |  | 32 |  | Consolidated Financial Statements



---

##### Table of Contents

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

All amounts in $ millions, unless otherwise indicated

For the year ended December 31, 2015



The weighted average interest rate on outstanding debt for the year ended December 31, 2015 was 5.3
percent (2014  5.0 percent).

A) Revolving Term Debt

As at December 31, 2015, Cenovus had in place a committed credit facility in the amount of $4.0 billion or the equivalent amount in U.S. dollars.
During the second quarter of 2015, Cenovus renegotiated its existing $3.0 billion committed credit facility, extending the maturity date to November 30, 2019. In addition, a new $1.0 billion tranche was established under the same facility,
maturing on November 30, 2017. The maturity dates are extendable from time to time, at the option of Cenovus and upon agreement from the lenders. Borrowings are available by way of Bankers Acceptances, LIBOR based loans, prime rate loans
or U.S. base rate loans. As at December 31, 2015, there were no amounts drawn on Cenovuss committed bank credit facility (December 31, 2014  $nil).

B) Unsecured Notes

Unsecured notes are composed of:



|                             |  |                      |       |  |  |  |      |  |       |  |  |      |  |  |       | 
|---------------------------- |  | -------------------- | ----- |  |  |  | ---- |  | ----- |  |  | ---- |  |  | ----- | 
|As at December 31,           |  | US$ Principal
Amount |       |  |  |  | 2015 |  |       |  |  | 2014 | 
|                             |  |                      |       |  | 
|5.70% due October 15, 2019   |  |                      | 1,300 |  |  |  |      |  | 1,799 |  |  |      |  |  | 1,508 | 
|3.00% due August 15, 2022    |  |                      | 500   |  |  |  |      |  | 692   |  |  |      |  |  | 580   | 
|3.80% due September 15, 2023 |  |                      | 450   |  |  |  |      |  | 623   |  |  |      |  |  | 522   | 
|6.75% due November 15, 2039  |  |                      | 1,400 |  |  |  |      |  | 1,938 |  |  |      |  |  | 1,624 | 
|4.45% due September 15, 2042 |  |                      | 750   |  |  |  |      |  | 1,038 |  |  |      |  |  | 870   | 
|5.20% due September 15, 2043 |  |                      | 350   |  |  |  |      |  | 484   |  |  |      |  |  | 406   | 
|                             |  |                      |       |  |  |  |      |  | 6,574 |  |  |      |  |  | 5,510 | 

On June 24, 2014, Cenovus filed a U.S. base shelf prospectus for unsecured notes in the amount of US$2.0 billion. The
U.S. base shelf prospectus allows for the issuance of debt securities in U.S. dollars or other currencies from time to time in one or more offerings. Terms of the notes, including, but not limited to, interest at either fixed or floating rates and
maturity dates will be determined at the date of issue. As at December 31, 2015, no notes have been issued under this U.S. base shelf prospectus. The U.S. base shelf prospectus expires in July 2016.

On June 25, 2014, Cenovus filed a Canadian base shelf prospectus for unsecured medium term notes in the amount of $1.5 billion. The Canadian base
shelf prospectus allows for the issuance of medium term notes in Canadian dollars or other currencies from time to time in one or more offerings. Terms of the notes, including, but not limited to, interest at either fixed or floating rates and
maturity dates will be determined at the date of issue. As at December 31, 2015, no medium term notes have been issued under this Canadian base shelf prospectus. The Canadian base shelf prospectus expires in July 2016.

As at December 31, 2015, the Company is in compliance with all of the terms of its debt agreements.

C) Mandatory Debt Payments



|           |  |                      |       |  |  |  |                     |  |   |  |  |                     |  |  |       | 
|---------- |  | -------------------- | ----- |  |  |  | ------------------- |  | - |  |  | ------------------- |  |  | ----- | 
|           |  | US$ Principal
Amount |       |  |  |  | C$ Principal
Amount |  |   |  |  | Total C$
Equivalent | 
|           |  |                      |       |  | 
|2016       |  |                      | -     |  |  |  |                     |  | - |  |  |                     |  |  | -     | 
|2017       |  |                      | -     |  |  |  |                     |  | - |  |  |                     |  |  | -     | 
|2018       |  |                      | -     |  |  |  |                     |  | - |  |  |                     |  |  | -     | 
|2019       |  |                      | 1,300 |  |  |  |                     |  | - |  |  |                     |  |  | 1,799 | 
|2020       |  |                      | -     |  |  |  |                     |  | - |  |  |                     |  |  | -     | 
|Thereafter |  |                      | 3,450 |  |  |  |                     |  | - |  |  |                     |  |  | 4,775 | 
|           |  |                      | 4,750 |  |  |  |                     |  | - |  |  |                     |  |  | 6,574 | 

D) Debt Discounts and Transaction Costs

Long-term debt transaction costs and discounts associated with the unsecured notes are recorded within long-term debt and are amortized using the
effective interest rate method. Transaction costs associated with the revolving term debt are recorded as a prepayment and are amortized over the remaining term of the committed credit facility. During 2015, additional transaction costs of $3
million were recorded (2014  $2 million).



|                    |  |    |  |                                  
|------------------- |  | -- |  | ---------------------------------
|Cenovus Energy Inc. |  | 33 |  | Consolidated Financial Statements



---

##### Table of Contents

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

All amounts in $ millions, unless otherwise indicated

For the year ended December 31, 2015



22. DECOMMISSIONING LIABILITIES



The decommissioning provision represents the
present value of the expected future costs associated with the retirement of upstream crude oil and natural gas assets, refining facilities and the crude-by-rail terminal. The aggregate carrying amount of the obligation is:



|                                                     |  |      |       |   |  |  |      |  |       |  
|---------------------------------------------------- |  | ---- | ----- | - |  |  | ---- |  | ----- | -
|As at December 31,                                   |  | 2015 |       |   |  |  | 2014 | 
|                                                     |  |      |      
|Decommissioning Liabilities, Beginning of Year       |  |      | 2,616 |   |  |  |      |  | 2,370 |  
|Liabilities Incurred                                 |  |      | 10    |   |  |  |      |  | 48    |  
|Liabilities Acquired                                 |  |      | 4     |   |  |  |      |  | -     |  
|Liabilities Settled                                  |  |      | (62   | ) |  |  |      |  | (93   | )
|Liabilities Divested                                 |  |      | -     |   |  |  |      |  | (60   | )
|Transfers and Reclassifications                      |  |      | -     |   |  |  |      |  | (9    | )
|Change in Estimated Future Cash Flows                |  |      | (70   | ) |  |  |      |  | 115   |  
|Change in Discount Rate                              |  |      | (579  | ) |  |  |      |  | 122   |  
|Unwinding of Discount on Decommissioning Liabilities |  |      | 126   |   |  |  |      |  | 120   |  
|Foreign Currency Translation                         |  |      | 7     |   |  |  |      |  | 3     |  
|Decommissioning Liabilities, End of Year             |  |      | 2,052 |   |  |  |      |  | 2,616 |  

The undiscounted amount of estimated future cash flows required to settle the obligation is $6,665 million
(December 31, 2014  $8,333 million), which has been discounted using a credit-adjusted risk-free rate of 6.4 percent (December 31, 2014  4.9 percent). An inflation rate of two percent (2014  two percent) was
used to calculate the decommissioning provision. Most of these obligations are not expected to be paid for several years, or decades, and are expected to be funded from general resources at that time. The Company expects to settle approximately $35
million to $70 million of decommissioning liabilities over the next year. Revisions in estimated future cash flows resulted from lower cost estimates, partially offset by accelerated timing of decommissioning liabilities over the estimated life of
the reserves.

Sensitivities

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



|                     |  |                                |       |  |  |  |                |  |       |  |  |                                |  |  |      |   |                |  |  |  |      |  
|-------------------- |  | ------------------------------ | ----- |  |  |  | -------------- |  | ----- |  |  | ------------------------------ |  |  | ---- | - | -------------- |  |  |  | ---- | -
|                     |  | 2015                           |       |  |  |  | 2014           | 
|As at December 31,   |  | Credit-Adjusted
Risk-Free Rate |       |  |  |  | Inflation Rate |  |       |  |  | Credit-Adjusted
Risk-Free Rate |  |  |      |   | Inflation Rate | 
|                     |  |                                |       |  |  |  |               
|One Percent Increase |  |                                | (247) |  |  |  |                |  | 319   |  |  |                                |  |  | (419 | ) |                |  |  |  | 574  |  
|One Percent Decrease |  |                                | 308   |  |  |  |                |  | (259) |  |  |                                |  |  | 562  |   |                |  |  |  | (433 | )

23. OTHER LIABILITIES





|                              |  |      |     |  |  |  |      |  |     | 
|----------------------------- |  | ---- | --- |  |  |  | ---- |  | --- | 
|As at December 31,            |  | 2015 |     |  |  |  | 2014 | 
|                              |  |      |    
|Employee Long-Term Incentives |  |      | 40  |  |  |  |      |  | 57  | 
|Pension and OPEB (Note 24)    |  |      | 66  |  |  |  |      |  | 84  | 
|Other                         |  |      | 36  |  |  |  |      |  | 31  | 
|                              |  |      | 142 |  |  |  |      |  | 172 | 



|                    |  |    |  |                                  
|------------------- |  | -- |  | ---------------------------------
|Cenovus Energy Inc. |  | 34 |  | Consolidated Financial Statements



---

##### Table of Contents

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

All amounts in $ millions, unless otherwise indicated

For the year ended December 31, 2015



24. PENSIONS AND OTHER POST-EMPLOYMENT BENEFITS



The Company provides
employees with a pension that includes either a defined contribution or defined benefit component and OPEB. Most of the employees participate in the defined contribution pension. Starting in 2012, employees who meet certain criteria may move from
the current defined contribution component to a defined benefit component for their future service.

The defined benefit pension provides pension
benefits at retirement based on years of service and final average earnings. Future enrollment is limited to eligible employees who meet certain criteria. The Companys OPEB provides certain retired employees with health care and dental
benefits until age 65 and life insurance benefits.

The Company is required to file an actuarial valuation of its registered defined benefit pension
with the provincial regulator at least every three years. The most recently filed valuation was dated December 31, 2014 and the next required actuarial valuation will be as at December 31, 2017.

A) Defined Benefit and OPEB Plan Obligation and Funded Status

Information related to defined benefit pension and OPEB plans, based on actuarial estimations, is:



|                                                          |  |                  |     |   |  |  |      |  |     |   |  |      |  |  |     |   |      |  |  |  |     |  
|--------------------------------------------------------- |  | ---------------- | --- | - |  |  | ---- |  | --- | - |  | ---- |  |  | --- | - | ---- |  |  |  | --- | -
|                                                          |  | Pension Benefits |     |   |  |  | OPEB | 
|As at December 31,                                        |  | 2015             |     |   |  |  | 2014 |  |     |   |  | 2015 |  |  |     |   | 2014 | 
|                                                          |  |                  |     |   |  |  |     
|Defined Benefit Obligation                                |  |                  |     |   |  |  |      |  |     |   |  |      |  |  |     |   |      |  |  |  |     |  
|Defined Benefit Obligation, Beginning of Year             |  |                  | 200 |   |  |  |      |  | 148 |   |  |      |  |  | 23  |   |      |  |  |  | 18  |  
|Current Service Costs                                     |  |                  | 19  |   |  |  |      |  | 15  |   |  |      |  |  | 3   |   |      |  |  |  | 2   |  
|Interest Costs(1)                                         |  |                  | 8   |   |  |  |      |  | 7   |   |  |      |  |  | 1   |   |      |  |  |  | 1   |  
|Benefits Paid                                             |  |                  | (6  | ) |  |  |      |  | (3  | ) |  |      |  |  | (1  | ) |      |  |  |  | -   |  
|Plan Participant Contributions                            |  |                  | 3   |   |  |  |      |  | 3   |   |  |      |  |  | -   |   |      |  |  |  | -   |  
|Past Service Costs  Curtailments                         |  |                  | (5  | ) |  |  |      |  | -   |   |  |      |  |  | -   |   |      |  |  |  | -   |  
|Settlements                                               |  |                  | (20 | ) |  |  |      |  | -   |   |  |      |  |  | -   |   |      |  |  |  | -   |  
|Remeasurements:                                           |  |                  |     |   |  |  |      |  |     |   |  |      |  |  |     |   |      |  |  |  |     |  
|(Gains) Losses from Experience Adjustments                |  |                  | (3  | ) |  |  |      |  | -   |   |  |      |  |  | -   |   |      |  |  |  | -   |  
|(Gains) Losses from Changes in Demographic Assumptions    |  |                  | -   |   |  |  |      |  | (1  | ) |  |      |  |  | -   |   |      |  |  |  | -   |  
|(Gains) Losses from Changes in Financial Assumptions      |  |                  | (28 | ) |  |  |      |  | 31  |   |  |      |  |  | -   |   |      |  |  |  | 2   |  
|Defined Benefit Obligation, End of Year                   |  |                  | 168 |   |  |  |      |  | 200 |   |  |      |  |  | 26  |   |      |  |  |  | 23  |  
|                                                          |  |                  |     |   |  |  |     
|Plan Assets                                               |  |                  |     |   |  |  |      |  |     |   |  |      |  |  |     |   |      |  |  |  |     |  
|Fair Value of Plan Assets, Beginning of Year              |  |                  | 139 |   |  |  |      |  | 115 |   |  |      |  |  | -   |   |      |  |  |  | -   |  
|Employer Contributions                                    |  |                  | 16  |   |  |  |      |  | 12  |   |  |      |  |  | -   |   |      |  |  |  | -   |  
|Plan Participant Contributions                            |  |                  | 3   |   |  |  |      |  | 3   |   |  |      |  |  | -   |   |      |  |  |  | -   |  
|Benefits Paid                                             |  |                  | (6  | ) |  |  |      |  | (3  | ) |  |      |  |  | -   |   |      |  |  |  | -   |  
|Settlements                                               |  |                  | (23 | ) |  |  |      |  | -   |   |  |      |  |  | -   |   |      |  |  |  | -   |  
|Interest Income (1)                                       |  |                  | 2   |   |  |  |      |  | 4   |   |  |      |  |  | -   |   |      |  |  |  | -   |  
|Remeasurements:                                           |  |                  |     |   |  |  |      |  |     |   |  |      |  |  |     |   |      |  |  |  |     |  
|Return on Plan Assets (Excluding Interest Income)         |  |                  | (3  | ) |  |  |      |  | 8   |   |  |      |  |  | -   |   |      |  |  |  | -   |  
|Fair Value of Plan Assets, End of Year                    |  |                  | 128 |   |  |  |      |  | 139 |   |  |      |  |  | -   |   |      |  |  |  | -   |  
|                                                          |  |                  |     |   |  |  |     
|Pension and Other Post-Employment Benefit (Liability)
(2) |  |                  | (40 | ) |  |  |      |  | (61 | ) |  |      |  |  | (26 | ) |      |  |  |  | (23 | )

(1)  Based on the discount rate of the defined benefit obligation at the beginning of the year.

(2)  Pension and OPEB liabilities are included in other liabilities on the Consolidated Balance Sheets.

The weighted average duration of the defined benefit pension and OPEB obligations are 15 years and 12 years, respectively.



|                    |  |    |  |                                  
|------------------- |  | -- |  | ---------------------------------
|Cenovus Energy Inc. |  | 35 |  | Consolidated Financial Statements



---

##### Table of Contents

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

All amounts in $ millions, unless otherwise indicated

For the year ended December 31, 2015



B) Pension and OPEB Costs



|                                                       |  |                  |     |   |  |  |      |  |    |   |  |      |  |  |     |   |      |  |  |  |   |      |  |  |  |  |      |  |  |  |  |  |    |  
|------------------------------------------------------ |  | ---------------- | --- | - |  |  | ---- |  | -- | - |  | ---- |  |  | --- | - | ---- |  |  |  | - | ---- |  |  |  |  | ---- |  |  |  |  |  | -- | -
|                                                       |  | Pension Benefits |     |   |  |  | OPEB | 
|For the years ended December 31,                       |  | 2015             |     |   |  |  | 2014 |  |    |   |  | 2013 |  |  |     |   | 2015 |  |  |  |   | 2014 |  |  |  |  | 2013 | 
|                                                       |  |                  |     |   |  |  |      |  |    |   | 
|Defined Benefit Plan Cost                              |  |                  |     |   |  |  |      |  |    |   |  |      |  |  |     |   |      |  |  |  |   |      |  |  |  |  |      |  |  |  |  |  |    |  
|Current Service Costs                                  |  |                  | 19  |   |  |  |      |  | 15 |   |  |      |  |  | 17  |   |      |  |  |  | 3 |      |  |  |  |  | 2    |  |  |  |  |  | 2  |  
|Past Service Costs  Curtailments                      |  |                  | (5  | ) |  |  |      |  | -  |   |  |      |  |  | -   |   |      |  |  |  | - |      |  |  |  |  | -    |  |  |  |  |  | -  |  
|Net Settlement Costs                                   |  |                  | 3   |   |  |  |      |  | -  |   |  |      |  |  | -   |   |      |  |  |  | - |      |  |  |  |  | -    |  |  |  |  |  | -  |  
|Net Interest Costs                                     |  |                  | 6   |   |  |  |      |  | 3  |   |  |      |  |  | 4   |   |      |  |  |  | 1 |      |  |  |  |  | 1    |  |  |  |  |  | 1  |  
|Remeasurements:                                        |  |                  |     |   |  |  |      |  |    |   |  |      |  |  |     |   |      |  |  |  |   |      |  |  |  |  |      |  |  |  |  |  |    |  
|Return on Plan Assets (Excluding Interest Income)      |  |                  | 3   |   |  |  |      |  | (8 | ) |  |      |  |  | (7  | ) |      |  |  |  | - |      |  |  |  |  | -    |  |  |  |  |  | -  |  
|(Gains) Losses from Experience Adjustments             |  |                  | (3  | ) |  |  |      |  | -  |   |  |      |  |  | 1   |   |      |  |  |  | - |      |  |  |  |  | -    |  |  |  |  |  | -  |  
|(Gains) Losses from Changes in Demographic Assumptions |  |                  | -   |   |  |  |      |  | (1 | ) |  |      |  |  | 12  |   |      |  |  |  | - |      |  |  |  |  | -    |  |  |  |  |  | (1 | )
|(Gains) Losses from Changes in Financial Assumptions   |  |                  | (28 | ) |  |  |      |  | 31 |   |  |      |  |  | (19 | ) |      |  |  |  | - |      |  |  |  |  | 2    |  |  |  |  |  | (4 | )
|Defined Benefit Plan Cost (Gain)                       |  |                  | (5  | ) |  |  |      |  | 40 |   |  |      |  |  | 8   |   |      |  |  |  | 4 |      |  |  |  |  | 5    |  |  |  |  |  | (2 | )
|Defined Contribution Plan Cost                         |  |                  | 29  |   |  |  |      |  | 30 |   |  |      |  |  | 27  |   |      |  |  |  | - |      |  |  |  |  | -    |  |  |  |  |  | -  |  
|Total Plan Cost                                        |  |                  | 24  |   |  |  |      |  | 70 |   |  |      |  |  | 35  |   |      |  |  |  | 4 |      |  |  |  |  | 5    |  |  |  |  |  | (2 | )

C) Investment Objectives and Fair Value of Plan Assets

The objective of the asset allocation is to manage the funded status of the plan at an appropriate level of risk, giving consideration to the security of
the assets and the potential volatility of market returns and the resulting effect on both contribution requirements and pension expense. The long-term return is expected to achieve or exceed the return from a composite benchmark comprised of
passive investments in appropriate market indices. The asset allocation structure is subject to diversification requirements and constraints which reduce risk by limiting exposure to individual equity investment and credit rating categories.

The allocation of assets between the various types of investment funds is monitored monthly and is re-balanced as necessary. The asset allocation
structure targets an investment of 60 to 70 percent in equity securities, 30 percent in debt instruments and the remainder invested in real estate and other.

The Company does not use derivative instruments to manage the risks of its plan assets. There has been no change in the process used by the Company to
manage these risks from prior periods.

The fair value of the plan assets is:



|                                |  |      |     |  |  |  |      |  |     | 
|------------------------------- |  | ---- | --- |  |  |  | ---- |  | --- | 
|As at December 31,              |  | 2015 |     |  |  |  | 2014 | 
|                                |  |      |    
|Equity Securities               |  |      |     |  |  |  |      |  |     | 
|Equity Funds and Balanced Funds |  |      | 73  |  |  |  |      |  | 75  | 
|Other                           |  |      | 3   |  |  |  |      |  | 9   | 
|Bond Funds                      |  |      | 31  |  |  |  |      |  | 36  | 
|Non-Invested Assets             |  |      | 17  |  |  |  |      |  | 15  | 
|Real Estate                     |  |      | 4   |  |  |  |      |  | 4   | 
|                                |  |      | 128 |  |  |  |      |  | 139 | 

Fair value of equity securities and bond funds are based on the trading price of the underlying funds. The fair value of
the non-invested assets is the discounted value of the expected future payments. The fair value of real estate is determined by accredited real estate appraisers.

Equity securities do not include any direct investments in Cenovus shares.



|                    |  |    |  |                                  
|------------------- |  | -- |  | ---------------------------------
|Cenovus Energy Inc. |  | 36 |  | Consolidated Financial Statements



---

##### Table of Contents

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

All amounts in $ millions, unless otherwise indicated

For the year ended December 31, 2015



D) Funding

The defined benefit pension is funded in accordance with federal and provincial government pension legislation, where applicable. Contributions are made
to trust funds administered by an independent trustee. The Companys contributions to the defined benefit pension plan are based on the most recent actuarial valuation as at December 31, 2014, and direction by the Management Pension
Committee and Human Resources and Compensation Committee of the Board of Directors.

Employees participating in the defined benefit pension are
required to contribute four percent of their pensionable earnings, up to an annual maximum, and the Company provides the balance of the funding necessary to ensure benefits will be fully provided for at retirement. The expected employer
contributions for the year ended December 31, 2016 are $15 million for the defined benefit pension plan and $nil for the OPEB. The OPEB is funded on an as required basis.

E) Actuarial Assumptions and Sensitivities

Actuarial Assumptions

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



|                                 |  |                  |       |  |  |  |      |  |       |  |  |      |  |  |       |  |      |  |  |  |       |      |  |  |  |  |       |  |  |  |  |  |       | 
|-------------------------------- |  | ---------------- | ----- |  |  |  | ---- |  | ----- |  |  | ---- |  |  | ----- |  | ---- |  |  |  | ----- | ---- |  |  |  |  | ----- |  |  |  |  |  | ----- | 
|                                 |  | Pension Benefits |       |  |  |  | OPEB | 
|For the years ended December 31, |  | 2015             |       |  |  |  | 2014 |  |       |  |  | 2013 |  |  |       |  | 2015 |  |  |  |       | 2014 |  |  |  |  | 2013  | 
|                                 |  |                  |       |  |  |  |      |  |       |  | 
|Discount Rate                    |  |                  | 4.00% |  |  |  |      |  | 3.75% |  |  |      |  |  | 4.75% |  |      |  |  |  | 3.75% |      |  |  |  |  | 3.75% |  |  |  |  |  | 4.75% | 
|Future Salary Growth Rate        |  |                  | 3.80% |  |  |  |      |  | 4.32% |  |  |      |  |  | 4.39% |  |      |  |  |  | 5.15% |      |  |  |  |  | 5.65% |  |  |  |  |  | 5.65% | 
|Average Longevity (Years)        |  |                  | 88.3  |  |  |  |      |  | 88.3  |  |  |      |  |  | 88.5  |  |      |  |  |  | 88.3  |      |  |  |  |  | 88.3  |  |  |  |  |  | 88.5  | 
|Health Care Cost Trend Rate      |  |                  | N/A   |  |  |  |      |  | N/A   |  |  |      |  |  | N/A   |  |      |  |  |  | 7.00% |      |  |  |  |  | 7.00% |  |  |  |  |  | 7.00% | 

The discount rates are determined with reference to market yields on high quality corporate debt instruments of similar
duration to the benefit obligations at the end of the reporting period.

Sensitivities

The sensitivity of the defined benefit and OPEB obligation to changes in relevant actuarial assumptions is shown below.



|                              |  |                               |     |   |  |  |                               |  |    |   |  |                               |  |  |     |   |                               |  |  |  |    |  
|----------------------------- |  | ----------------------------- | --- | - |  |  | ----------------------------- |  | -- | - |  | ----------------------------- |  |  | --- | - | ----------------------------- |  |  |  | -- | -
|                              |  | 2015                          |     |   |  |  | 2014                          | 
|As at December 31,            |  | One
Percentage Point Increase |     |   |  |  | One
Percentage Point Decrease |  |    |   |  | One
Percentage Point
Increase |  |  |     |   | One
Percentage Point
Decrease | 
|                              |  |                               |     |   |  |  |                              
|Discount Rate                 |  |                               | (27 | ) |  |  |                               |  | 35 |   |  |                               |  |  | (34 | ) |                               |  |  |  | 43 |  
|Future Salary Growth Rate     |  |                               | 3   |   |  |  |                               |  | (3 | ) |  |                               |  |  | 4   |   |                               |  |  |  | (4 | )
|Health Care Cost Trend Rate   |  |                               | 2   |   |  |  |                               |  | (2 | ) |  |                               |  |  | 2   |   |                               |  |  |  | (2 | )
|Future Mortality Rate (Years) |  |                               | 4   |   |  |  |                               |  | (4 | ) |  |                               |  |  | 4   |   |                               |  |  |  | (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.



|                    |  |    |  |                                  
|------------------- |  | -- |  | ---------------------------------
|Cenovus Energy Inc. |  | 37 |  | Consolidated Financial Statements



---

##### Table of Contents

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

All amounts in $ millions, unless otherwise indicated

For the year ended December 31, 2015



Interest Rate Risk

A decrease in corporate bond yields will increase the defined benefit plan obligation, although this will be partially offset by an increase in the return
on debt holdings.

Investment Risk

The present value of the defined benefit plan obligation is calculated using a discount rate determined by reference to high quality corporate bond
yields. If the return on plan assets is below this rate, a plan deficit will result. Due to the long-term nature of the plan liabilities, a higher portion of the plan assets are invested in equity securities than in debt instruments and real estate.

Salary Risk

The present value of the defined benefit plan obligation is calculated by reference to the future salaries of plan participants. As such, an increase in
the salary of the plan participants will increase the defined benefit obligation.

25. SHARE
CAPITAL



A) Authorized

Cenovus is authorized to issue an unlimited number of common shares and first and second preferred shares not exceeding, in aggregate, 20 percent of the
number of issued and outstanding common shares. The first and second preferred shares may be issued in one or more series with rights and conditions to be determined by the Companys Board of Directors prior to issuance and subject to the
Companys articles.

B) Issued and Outstanding



|                                                            |  |                                   |         |  |  |  |        |  |       |  |  |                                   |  |  |         |  |        |  |  |  |       | 
|----------------------------------------------------------- |  | --------------------------------- | ------- |  |  |  | ------ |  | ----- |  |  | --------------------------------- |  |  | ------- |  | ------ |  |  |  | ----- | 
|                                                            |  | 2015                              |         |  |  |  | 2014   | 
|As at December 31,                                          |  | Number ofCommonShares
(Thousands) |         |  |  |  | Amount |  |       |  |  | Number ofCommonShares
(Thousands) |  |  |         |  | Amount | 
|                                                            |  |                                   |         |  |  |  |       
|Outstanding, Beginning of Year                              |  |                                   | 757,103 |  |  |  |        |  | 3,889 |  |  |                                   |  |  | 756,046 |  |        |  |  |  | 3,857 | 
|Common Shares Issued, Net of Issuance Costs                 |  |                                   | 67,500  |  |  |  |        |  | 1,463 |  |  |                                   |  |  | -       |  |        |  |  |  | -     | 
|Common Shares Issued Pursuant to Dividend Reinvestment Plan |  |                                   | 8,687   |  |  |  |        |  | 182   |  |  |                                   |  |  | -       |  |        |  |  |  | -     | 
|Common Shares Issued Under Stock Option Plans               |  |                                   | -       |  |  |  |        |  | -     |  |  |                                   |  |  | 1,057   |  |        |  |  |  | 32    | 
|Outstanding, End of Year                                    |  |                                   | 833,290 |  |  |  |        |  | 5,534 |  |  |                                   |  |  | 757,103 |  |        |  |  |  | 3,889 | 

On March 3, 2015, Cenovus issued 67.5 million common shares at a price of $22.25 per common share. Share
issuance costs of $53 million were incurred.

The Company has a DRIP, whereby holders of common shares may reinvest all or a portion of the cash
dividends payable on their common shares in additional common shares. At the discretion of the Company, the additional common shares may be issued from treasury of the Company or purchased on the market. During the year ended December 31, 2015,
the Company issued 8.7 million common shares from treasury under the DRIP.

There were no preferred shares outstanding as at December 31,
2015 (2014  nil).

As at December 31, 2015, there were 12 million (2014  13 million) common shares available for future issuance
under the stock option plan.



|                    |  |    |  |                                  
|------------------- |  | -- |  | ---------------------------------
|Cenovus Energy Inc. |  | 38 |  | Consolidated Financial Statements



---

##### Table of Contents

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

All amounts in $ millions, unless otherwise indicated

For the year ended December 31, 2015



C) Paid in Surplus

Cenovuss paid in surplus reflects the Companys retained earnings prior to the split of Encana Corporation (Encana) under the plan
of arrangement into two independent energy companies, Encana and Cenovus. In addition, paid in surplus includes stock-based compensation expense related to the Companys NSRs discussed in Note 27A).



|                                 |  |                         |       |  |  |  |                                 |  |     |  |  |       |  |  |       | 
|-------------------------------- |  | ----------------------- | ----- |  |  |  | ------------------------------- |  | --- |  |  | ----- |  |  | ----- | 
|                                 |  | Pre-ArrangementEarnings |       |  |  |  | Stock-Based        Compensation |  |     |  |  | Total | 
|                                 |  |                         |       |  | 
|As at December 31, 2013          |  |                         | 4,086 |  |  |  |                                 |  | 133 |  |  |       |  |  | 4,219 | 
|Stock-Based Compensation Expense |  |                         | -     |  |  |  |                                 |  | 72  |  |  |       |  |  | 72    | 
|As at December 31, 2014          |  |                         | 4,086 |  |  |  |                                 |  | 205 |  |  |       |  |  | 4,291 | 
|Stock-Based Compensation Expense |  |                         | -     |  |  |  |                                 |  | 39  |  |  |       |  |  | 39    | 
|As at December 31, 2015          |  |                         | 4,086 |  |  |  |                                 |  | 244 |  |  |       |  |  | 4,330 | 

26. ACCUMULATED OTHER COMPREHENSIVE INCOME (LOSS)





|                                              |  |                      |     |   |  |  |                               |  |       |  |  |                                   |  |  |    |   |       |  |  |  |       |  
|--------------------------------------------- |  | -------------------- | --- | - |  |  | ----------------------------- |  | ----- |  |  | --------------------------------- |  |  | -- | - | ----- |  |  |  | ----- | -
|                                              |  | Defined Benefit Plan |     |   |  |  | ForeignCurrency   Translation |  |       |  |  | Available
for SaleFinancialAssets |  |  |    |   | Total | 
|                                              |  |                      |     |   |  |  |                              
|As at December 31, 2013                       |  |                      | (12 | ) |  |  |                               |  | 212   |  |  |                                   |  |  | 10 |   |       |  |  |  | 210   |  
|Other Comprehensive Income (Loss), Before Tax |  |                      | (24 | ) |  |  |                               |  | 215   |  |  |                                   |  |  | -  |   |       |  |  |  | 191   |  
|Income Tax                                    |  |                      | 6   |   |  |  |                               |  | -     |  |  |                                   |  |  | -  |   |       |  |  |  | 6     |  
|As at December 31, 2014                       |  |                      | (30 | ) |  |  |                               |  | 427   |  |  |                                   |  |  | 10 |   |       |  |  |  | 407   |  
|Other Comprehensive Income (Loss), Before Tax |  |                      | 28  |   |  |  |                               |  | 587   |  |  |                                   |  |  | 8  |   |       |  |  |  | 623   |  
|Income Tax                                    |  |                      | (8  | ) |  |  |                               |  | -     |  |  |                                   |  |  | (2 | ) |       |  |  |  | (10   | )
|As at December 31, 2015                       |  |                      | (10 | ) |  |  |                               |  | 1,014 |  |  |                                   |  |  | 16 |   |       |  |  |  | 1,020 |  

27. STOCK-BASED COMPENSATION PLANS



A) Employee Stock
Option Plan

Cenovus has an Employee Stock Option Plan that provides employees with the opportunity to exercise an option to purchase a
common share of the Company. Option exercise prices approximate the market price for the common shares on the date the options were issued. Options granted are exercisable at 30 percent of the number granted after one year, an additional 30 percent
of the number granted after two years and are fully exercisable after three years. Options expire after seven years.

Options issued by the Company
under the Employee Stock Option Plan prior to February 24, 2011 have associated tandem stock appreciation rights. In lieu of exercising the options, the tandem stock appreciation rights give the option holder the right to receive a cash payment
equal to the excess of the market price of Cenovuss common shares at the time of exercise over the exercise price of the option.

Options issued
by the Company on or after February 24, 2011 have associated net settlement rights. The net settlement rights, in lieu of exercising the option, give the option holder the right to receive the number of common shares that could be acquired with
the excess value of the market price of Cenovuss common shares at the time of exercise over the exercise price of the option.

The tandem stock
appreciation rights and net settlement rights vest and expire under the same terms and conditions as the underlying options. For the purpose of this financial statement note, options with associated tandem stock appreciation rights are referred to
as TSARs and options with associated net settlement rights are referred to as NSRs.

In addition, certain of the TSARs are
performance based (performance TSARs). All performance TSARs have vested, and, as such, terms and conditions are consistent with TSARs, which were not performance based.



|                    |  |    |  |                                  
|------------------- |  | -- |  | ---------------------------------
|Cenovus Energy Inc. |  | 39 |  | Consolidated Financial Statements



---

##### Table of Contents

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

All amounts in $ millions, unless otherwise indicated

For the year ended December 31, 2015



NSRs

The weighted average unit fair value of NSRs granted during the year ended December 31, 2015 was $3.58 before considering forfeitures, which are
considered in determining total cost for the period. The fair value of each NSR was estimated on its grant date using the Black-Scholes-Merton valuation model with weighted average assumptions as follows:



|                        |  |  |        | 
|----------------------- |  |  | ------ | 
|Risk-Free Interest Rate |  |  | 0.75%  | 
|Expected Dividend Yield |  |  | 3.60%  | 
|Expected Volatility (1) |  |  | 28.27% | 
|Expected Life (Years)   |  |  | 4.55   | 

(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, 2015        |  | Number ofNSRs
(Thousands) |        |   |  |  | Weighted
Average Exercise
Price($) | 
|                               |  |                           |       
|Outstanding, Beginning of Year |  |                           | 40,549 |   |  |  |                                    |  | 32.63 | 
|Granted                        |  |                           | 4,106  |   |  |  |                                    |  | 22.25 | 
|Exercised                      |  |                           | -      |   |  |  |                                    |  | -     | 
|Forfeited                      |  |                           | (2,541 | ) |  |  |                                    |  | 32.19 | 
|Outstanding, End of Year       |  |                           | 42,114 |   |  |  |                                    |  | 31.65 | 
|Exercisable, End of Year       |  |                           | 23,484 |   |  |  |                                    |  | 34.46 | 



|                                                    |  |                            |        |  |  |  |                                                    |  |      |  |  |                                    |  |  |       | 
|--------------------------------------------------- |  | -------------------------- | ------ |  |  |  | -------------------------------------------------- |  | ---- |  |  | ---------------------------------- |  |  | ----- | 
|                                                    |  | Outstanding NSRs           |       
|As at December 31, 2015
Range of Exercise Price ($) |  | Number of
NSRs (Thousands) |        |  |  |  | Weighted
Average Remaining Contractual
Life(Years) |  |      |  |  | Weighted
Average Exercise
Price($) | 
|                                                    |  |                            |        |  | 
|15.00 to 19.99                                      |  |                            | 6      |  |  |  |                                                    |  | 6.68 |  |  |                                    |  |  | 18.07 | 
|20.00 to 24.99                                      |  |                            | 4,075  |  |  |  |                                                    |  | 6.15 |  |  |                                    |  |  | 22.26 | 
|25.00 to 29.99                                      |  |                            | 14,281 |  |  |  |                                                    |  | 5.14 |  |  |                                    |  |  | 28.39 | 
|30.00 to 34.99                                      |  |                            | 12,642 |  |  |  |                                                    |  | 4.18 |  |  |                                    |  |  | 32.61 | 
|35.00 to 39.99                                      |  |                            | 11,110 |  |  |  |                                                    |  | 2.79 |  |  |                                    |  |  | 38.19 | 
|                                                    |  |                            | 42,114 |  |  |  |                                                    |  | 4.33 |  |  |                                    |  |  | 31.65 | 



|                                                    |  |                            |        |  |  |  |                                    |  |       | 
|--------------------------------------------------- |  | -------------------------- | ------ |  |  |  | ---------------------------------- |  | ----- | 
|                                                    |  | Exercisable NSRs           |       
|As at December 31, 2015
Range of Exercise Price ($) |  | Number of
NSRs (Thousands) |        |  |  |  | Weighted
Average Exercise
Price($) | 
|                                                    |  |                            |       
|15.00 to 19.99                                      |  |                            | -      |  |  |  |                                    |  | -     | 
|20.00 to 24.99                                      |  |                            | 40     |  |  |  |                                    |  | 22.99 | 
|25.00 to 29.99                                      |  |                            | 4,404  |  |  |  |                                    |  | 28.41 | 
|30.00 to 34.99                                      |  |                            | 7,930  |  |  |  |                                    |  | 32.64 | 
|35.00 to 39.99                                      |  |                            | 11,110 |  |  |  |                                    |  | 38.19 | 
|                                                    |  |                            | 23,484 |  |  |  |                                    |  | 34.46 | 



|                    |  |    |  |                                  
|------------------- |  | -- |  | ---------------------------------
|Cenovus Energy Inc. |  | 40 |  | Consolidated Financial Statements



---

##### Table of Contents

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

All amounts in $ millions, unless otherwise indicated

For the year ended December 31, 2015



TSARs

The Company has recorded a liability of $1 million as at December 31, 2015 (December 31, 2014  $8 million) in the Consolidated Balance Sheets
based on the fair value of each TSAR held by Cenovus employees. Fair value was estimated at the period-end date using the Black-Scholes-Merton valuation model with weighted average assumptions as follows:



|                             |  |  |        | 
|---------------------------- |  |  | ------ | 
|Risk-Free Interest Rate      |  |  | 0.75%  | 
|Expected Dividend Yield      |  |  | 4.14%  | 
|Expected Volatility (1)      |  |  | 29.24% | 
|Cenovuss Common Share Price |  |  | $17.50 | 

(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, 2015 was $nil (December 31, 2014 
$nil).

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



|                                                    |  |                                   |       |  |  |  |                                                    |  |       |   |  |                                    |  |  |       | 
|--------------------------------------------------- |  | --------------------------------- | ----- |  |  |  | -------------------------------------------------- |  | ----- | - |  | ---------------------------------- |  |  | ----- | 
|As at December 31, 2015                             |  |                                   |       |  |  |  | Number ofTSARs
(Thousands)                         |  |       |   |  | Weighted
Average Exercise Price($) | 
|Outstanding, Beginning of Year                      |  |                                   |       |  |  |  |                                                    |  | 3,862 |   |  |                                    |  |  | 26.72 | 
|Exercised for Cash Payment                          |  |                                   |       |  |  |  |                                                    |  | -     |   |  |                                    |  |  | -     | 
|Exercised as Options for Common Shares              |  |                                   |       |  |  |  |                                                    |  | -     |   |  |                                    |  |  | -     | 
|Forfeited                                           |  |                                   |       |  |  |  |                                                    |  | (144  | ) |  |                                    |  |  | 27.06 | 
|Expired                                             |  |                                   |       |  |  |  |                                                    |  | (73   | ) |  |                                    |  |  | 25.89 | 
|Outstanding, End of Year                            |  |                                   |       |  |  |  |                                                    |  | 3,645 |   |  |                                    |  |  | 26.72 | 
|Exercisable, End of Year                            |  |                                   |       |  |  |  |                                                    |  | 3,645 |   |  |                                    |  |  | 26.72 | 
|                                                    | 
|                                                    |  | Outstanding and Exercisable TSARs |      
|As at December 31, 2015
Range of Exercise Price ($) |  | Number of
TSARs (Thousands)       |       |  |  |  | Weighted
Average Remaining Contractual
Life(Years) |  |       |   |  | Weighted
Average Exercise Price($) | 
|20.00 to 29.99                                      |  |                                   | 3,497 |  |  |  |                                                    |  | 1.16  |   |  |                                    |  |  | 26.46 | 
|30.00 to 39.99                                      |  |                                   | 148   |  |  |  |                                                    |  | 1.98  |   |  |                                    |  |  | 32.88 | 
|                                                    |  |                                   | 3,645 |  |  |  |                                                    |  | 1.20  |   |  |                                    |  |  | 26.72 | 

The closing price of Cenovuss common shares on the TSX as at December 31, 2015 was $17.50.

B) Performance Share Units

Cenovus has granted PSUs to certain employees under its Performance Share Unit Plan for Employees. PSUs are whole share units and entitle employees to
receive, upon vesting, either a common share of Cenovus or a cash payment equal to the value of a Cenovus common share. For a portion of PSUs, the number of PSUs eligible for payment is determined over three years based on the units granted
multiplied by 30 percent after year one, 30 percent after year two and 40 percent after year three. All PSUs are eligible to vest based on the Company achieving key pre-determined performance measures. PSUs vest after three years.

The Company has recorded a liability of $49 million as at December 31, 2015 (2014  $109 million) in the Consolidated Balance Sheets for PSUs
based on the market value of Cenovuss common shares as at December 31, 2015. As PSUs are paid out upon vesting, the intrinsic value of vested PSUs was $nil as at December 31, 2015 and 2014.



|                    |  |    |  |                                  
|------------------- |  | -- |  | ---------------------------------
|Cenovus Energy Inc. |  | 41 |  | Consolidated Financial Statements



---

##### Table of Contents

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

All amounts in $ millions, unless otherwise indicated

For the year ended December 31, 2015



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



|                               |  |                            |        |  
|------------------------------ |  | -------------------------- | ------ | -
|As at December 31, 2015        |  | Number
of PSUs (Thousands) |       
|Outstanding, Beginning of Year |  |                            | 7,099  |  
|Granted                        |  |                            | 2,909  |  
|Vested and Paid Out            |  |                            | (2,176 | )
|Cancelled                      |  |                            | (1,681 | )
|Units in Lieu of Dividends     |  |                            | 276    |  
|Outstanding, End of Year       |  |                            | 6,427  |  

C) Restricted Share Units

Cenovus has granted RSUs to certain employees under its Restricted Share Unit Plan for Employees. RSUs are whole-share units and entitle employees to
receive, upon vesting, either a common share of Cenovus or a cash payment equal to the value of a Cenovus common share. RSUs vest after three years.

RSUs are accounted for as liability instruments and are measured at fair value based on the market value of Cenovuss common shares at each period
end. The fair value is recognized as stock-based compensation costs over the vesting period. Fluctuations in the fair value are recognized as stock-based compensation costs in the period they occur.

The Company has recorded a liability of $11 million as at December 31, 2015 (2014  $1 million) in the Consolidated Balance Sheets for RSUs
based on the market value of Cenovuss common shares as at December 31, 2015. As RSUs are paid out upon vesting, the intrinsic value of vested RSUs was $nil as at December 31, 2015 and 2014.

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



|                               |  |                           |       |  
|------------------------------ |  | ------------------------- | ----- | -
|As at December 31, 2015        |  | Number ofRSUs
(Thousands) |      
|Outstanding, Beginning of Year |  |                           | 93    |  
|Granted                        |  |                           | 2,345 |  
|Vested and Paid Out            |  |                           | (22   | )
|Cancelled                      |  |                           | (251  | )
|Units in Lieu of Dividends     |  |                           | 102   |  
|Outstanding, End of Year       |  |                           | 2,267 |  

D) Deferred Share Units

Under two Deferred Share Unit Plans, Cenovus directors, officers and employees may receive DSUs, which are equivalent in value to a common share of the
Company. Employees have the option to convert either zero, 25 or 50 percent of their annual bonus award into DSUs. DSUs vest immediately, are redeemed in accordance with the terms of the agreement and expire on December 15 of the calendar year
following the year of cessation of directorship or employment.

The Company has recorded a liability of $26 million as at December 31, 2015 (2014
 $31 million) in the Consolidated Balance Sheets for DSUs based on the market value of Cenovuss common shares as at December 31, 2015. The intrinsic value of vested DSUs equals the carrying value as DSUs vest at the time of
grant.



|                    |  |    |  |                                  
|------------------- |  | -- |  | ---------------------------------
|Cenovus Energy Inc. |  | 42 |  | Consolidated Financial Statements



---

##### Table of Contents

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

All amounts in $ millions, unless otherwise indicated

For the year ended December 31, 2015



The following table summarizes the information related to the DSUs held by Cenovus directors, officers
and employees:



|                               |  |                           |       |  
|------------------------------ |  | ------------------------- | ----- | -
|As at December 31, 2015        |  | Number ofDSUs
(Thousands) |      
|Outstanding, Beginning of Year |  |                           | 1,297 |  
|Granted to Directors           |  |                           | 68    |  
|Granted                        |  |                           | 68    |  
|Units in Lieu of Dividends     |  |                           | 60    |  
|Redeemed                       |  |                           | (5    | )
|Outstanding, End of Year       |  |                           | 1,488 |  

E) Total Stock-Based Compensation



|                                            |  |      |     |   |  |  |      |  |     |   |  |      |  |  |     |  
|------------------------------------------- |  | ---- | --- | - |  |  | ---- |  | --- | - |  | ---- |  |  | --- | -
|For the years ended December 31,            |  | 2015 |     |   |  |  | 2014 |  |     |   |  | 2013 | 
|NSRs                                        |  |      | 27  |   |  |  |      |  | 41  |   |  |      |  |  | 35  |  
|TSARs                                       |  |      | (5  | ) |  |  |      |  | (10 | ) |  |      |  |  | (16 | )
|PSUs                                        |  |      | (13 | ) |  |  |      |  | 34  |   |  |      |  |  | 32  |  
|RSUs                                        |  |      | 6   |   |  |  |      |  | -   |   |  |      |  |  | -   |  
|DSUs                                        |  |      | (5  | ) |  |  |      |  | (5  | ) |  |      |  |  | -   |  
|Stock-Based Compensation Expense (Recovery) |  |      | 10  |   |  |  |      |  | 60  |   |  |      |  |  | 51  |  
|Stock-Based Compensation Costs Capitalized  |  |      | 6   |   |  |  |      |  | 29  |   |  |      |  |  | 18  |  
|Total Stock-Based Compensation              |  |      | 16  |   |  |  |      |  | 89  |   |  |      |  |  | 69  |  

28. EMPLOYEE SALARIES AND BENEFIT EXPENSES





|                                                         |  |      |     |  |  |  |      |  |     |  |  |      |  |  |     | 
|-------------------------------------------------------- |  | ---- | --- |  |  |  | ---- |  | --- |  |  | ---- |  |  | --- | 
|For the years ended December 31,                         |  | 2015 |     |  |  |  | 2014 |  |     |  |  | 2013 | 
|Salaries, Bonuses and Other Short-Term
Employee Benefits |  |      | 534 |  |  |  |      |  | 550 |  |  |      |  |  | 494 | 
|Defined Contribution Pension Plan                        |  |      | 19  |  |  |  |      |  | 18  |  |  |      |  |  | 17  | 
|Defined Benefit Pension Plan and OPEB                    |  |      | 17  |  |  |  |      |  | 14  |  |  |      |  |  | 15  | 
|Stock-Based Compensation Expense (Note 27)               |  |      | 10  |  |  |  |      |  | 60  |  |  |      |  |  | 51  | 
|Termination Benefits                                     |  |      | 43  |  |  |  |      |  | -   |  |  |      |  |  | -   | 
|                                                         |  |      | 623 |  |  |  |      |  | 642 |  |  |      |  |  | 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,                |  | 2015 |    |  |  |  | 2014 |  |    |  |  | 2013 | 
|Salaries, Director Fees and Short-Term
Benefits |  |      | 30 |  |  |  |      |  | 29 |  |  |      |  |  | 31 | 
|Post-Employment Benefits                        |  |      | 5  |  |  |  |      |  | 4  |  |  |      |  |  | 4  | 
|Stock-Based Compensation                        |  |      | 5  |  |  |  |      |  | 20 |  |  |      |  |  | 24 | 
|                                                |  |      | 40 |  |  |  |      |  | 53 |  |  |      |  |  | 59 | 

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



|                    |  |    |  |                                  
|------------------- |  | -- |  | ---------------------------------
|Cenovus Energy Inc. |  | 43 |  | Consolidated Financial Statements



---

##### Table of Contents

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

All amounts in $ millions, unless otherwise indicated

For the year ended December 31, 2015



30. CAPITAL STRUCTURE



Cenovuss capital structure objectives
and targets have remained unchanged from previous periods. Cenovuss capital structure consists of Shareholders Equity plus Debt. Debt is defined as short-term borrowings and the current and long-term portions of long-term debt. Net debt
includes the Companys short-term borrowings, current and long-term portions of long-term debt, and the current and long-term portions of the Partnership Contribution Payable, net of cash and cash equivalents. Cenovuss objectives when
managing its capital structure are to maintain financial flexibility, preserve access to capital markets, ensure its ability to finance internally generated growth and to fund potential acquisitions while maintaining the ability to meet the
Companys financial obligations as they come due.

Cenovus monitors its capital structure and financing requirements using, among other things,
non-GAAP financial metrics consisting of Debt to Capitalization and Debt to Adjusted Earnings Before Interest, Taxes and DD&A (Adjusted EBITDA). These metrics are used to steward Cenovuss overall debt position as measures of
Cenovuss overall financial strength.

Over the long term, Cenovus targets a Debt to Capitalization ratio of between 30 and 40 percent and a Debt
to Adjusted EBITDA ratio of between 1.0 and 2.0 times. At different points within the economic cycle, Cenovus expects these ratios may periodically be outside of the target range.

A) Debt to Capitalization and Net Debt to Capitalization



|                                                       |  |  |  |      |        |   |  |  |      |  |        |   |  |      |  |  |         | 
|------------------------------------------------------ |  |  |  | ---- | ------ | - |  |  | ---- |  | ------ | - |  | ---- |  |  | ------- | 
|As at December 31,                                     |  |  |  | 2015 |        |   |  |  | 2014 |  |        |   |  | 2013 | 
|Debt                                                   |  |  |  |      | 6,525  |   |  |  |      |  | 5,458  |   |  |      |  |  | 4,997   | 
|Add (Deduct):                                          |  |  |  |      |        |   |  |  |      |  |        |   |  |      |  |  |         | 
|Cash and Cash Equivalents                              |  |  |  |      | (4,105 | ) |  |  |      |  | (883   | ) |  |      |  |  | (2,452) | 
|Current Portion of Partnership Contribution Payable(1) |  |  |  |      | -      |   |  |  |      |  | -      |   |  |      |  |  | 438     | 
|Partnership Contribution Payable(1)                    |  |  |  |      | -      |   |  |  |      |  | -      |   |  |      |  |  | 1,087   | 
|Net Debt                                               |  |  |  |      | 2,420  |   |  |  |      |  | 4,575  |   |  |      |  |  | 4,070   | 
|                                                       |  |  |  |      |        |  
|Debt                                                   |  |  |  |      | 6,525  |   |  |  |      |  | 5,458  |   |  |      |  |  | 4,997   | 
|Shareholders Equity                                   |  |  |  |      | 12,391 |   |  |  |      |  | 10,186 |   |  |      |  |  | 9,946   | 
|                                                       |  |  |  |      | 18,916 |   |  |  |      |  | 15,644 |   |  |      |  |  | 14,943  | 
|Debt to Capitalization                                 |  |  |  |      | 34%    |   |  |  |      |  | 35%    |   |  |      |  |  | 33%     | 
|                                                       |  |  |  |      |        |  
|Net Debt                                               |  |  |  |      | 2,420  |   |  |  |      |  | 4,575  |   |  |      |  |  | 4,070   | 
|Shareholders Equity                                   |  |  |  |      | 12,391 |   |  |  |      |  | 10,186 |   |  |      |  |  | 9,946   | 
|                                                       |  |  |  |      | 14,811 |   |  |  |      |  | 14,761 |   |  |      |  |  | 14,016  | 
|Net Debt to Capitalization                             |  |  |  |      | 16%    |   |  |  |      |  | 31%    |   |  |      |  |  | 29%     | 



|(1) | In 2014, Cenovus repaid the remaining principal and accrued interest due under the Partnership Contribution Payable.
|--- | --------------------------------------------------------------------------------------------------------------------



|                    |  |    |  |                                  
|------------------- |  | -- |  | ---------------------------------
|Cenovus Energy Inc. |  | 44 |  | Consolidated Financial Statements



---

##### Table of Contents

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

All amounts in $ millions, unless otherwise indicated

For the year ended December 31, 2015



B) Debt to Adjusted EBITDA and Net Debt to Adjusted EBITDA



|                                          |  |  |  |      |        |   |  |  |      |  |       |   |  |      |  |  |       |  
|----------------------------------------- |  |  |  | ---- | ------ | - |  |  | ---- |  | ----- | - |  | ---- |  |  | ----- | -
|As at December 31,                        |  |  |  | 2015 |        |   |  |  | 2014 |  |       |   |  | 2013 | 
|Debt                                      |  |  |  |      | 6,525  |   |  |  |      |  | 5,458 |   |  |      |  |  | 4,997 |  
|Net Debt                                  |  |  |  |      | 2,420  |   |  |  |      |  | 4,575 |   |  |      |  |  | 4,070 |  
|                                          |  |  |  |      |        |  
|Net Earnings                              |  |  |  |      | 618    |   |  |  |      |  | 744   |   |  |      |  |  | 662   |  
|Add (Deduct):                             |  |  |  |      |        |   |  |  |      |  |       |   |  |      |  |  |       |  
|Finance Costs                             |  |  |  |      | 482    |   |  |  |      |  | 445   |   |  |      |  |  | 529   |  
|Interest Income                           |  |  |  |      | (28    | ) |  |  |      |  | (33   | ) |  |      |  |  | (96   | )
|Income Tax Expense (Recovery)             |  |  |  |      | (81    | ) |  |  |      |  | 451   |   |  |      |  |  | 432   |  
|Depreciation, Depletion and Amortization  |  |  |  |      | 2,114  |   |  |  |      |  | 1,946 |   |  |      |  |  | 1,833 |  
|Goodwill Impairment                       |  |  |  |      | -      |   |  |  |      |  | 497   |   |  |      |  |  | -     |  
|E&E Impairment                            |  |  |  |      | 138    |   |  |  |      |  | 86    |   |  |      |  |  | 50    |  
|Unrealized (Gain) Loss on Risk Management |  |  |  |      | 195    |   |  |  |      |  | (596  | ) |  |      |  |  | 415   |  
|Foreign Exchange (Gain) Loss, Net         |  |  |  |      | 1,036  |   |  |  |      |  | 411   |   |  |      |  |  | 208   |  
|(Gain) Loss on Divestitures of Assets     |  |  |  |      | (2,392 | ) |  |  |      |  | (156  | ) |  |      |  |  | 1     |  
|Other (Income) Loss, Net                  |  |  |  |      | 2      |   |  |  |      |  | (4    | ) |  |      |  |  | 2     |  
|Adjusted EBITDA                           |  |  |  |      | 2,084  |   |  |  |      |  | 3,791 |   |  |      |  |  | 4,036 |  
|                                          |  |  |  |      |        |  
|Debt to Adjusted EBITDA                   |  |  |  |      | 3.1x   |   |  |  |      |  | 1.4x  |   |  |      |  |  | 1.2x  |  
|Net Debt to
Adjusted EBITDA               |  |  |  |      | 1.2x   |   |  |  |      |  | 1.2x  |   |  |      |  |  | 1.0x  |  

Cenovus will maintain a high level of capital discipline and manage its capital structure to ensure sufficient liquidity
through all stages of the economic cycle. To manage its capital structure, Cenovus may, among other actions, adjust capital and operating spending, adjust dividends paid to shareholders, purchase shares for cancellation pursuant to normal course
issuer bids, issue new shares, issue new debt, draw down on its credit facilities or repay existing debt.

As at December 31, 2015, Cenovus had
$4.0 billion available on its committed credit facility. In addition, Cenovus had in place a $1.5 billion Canadian base shelf prospectus and a US$2.0 billion U.S. base shelf prospectus, the availability of which are dependent on market conditions.

Under the committed credit facility, the Company is required to maintain a debt to capitalization ratio, not to exceed 65 percent. The Company is
well below this limit.

As at December 31, 2015, Cenovus is in compliance with all of the terms of its debt agreements.

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, risk management assets and liabilities, available for sale financial assets, long-term receivables,
short-term borrowings and long-term debt. Risk management assets and liabilities arise from the use of derivative financial instruments.

A) Fair Value of Non-Derivative Financial Instruments

The fair values of cash and cash equivalents, accounts
receivable and accrued revenues, accounts payable and accrued liabilities, and short-term borrowings approximate their carrying amount due to the short-term maturity of those instruments.

The fair values of long-term receivables approximate their carrying amount due to the specific non-tradeable nature of these instruments.

Long-term debt is carried at amortized cost. The estimated fair values of long-term borrowings have been determined based on period-end trading prices of
long-term borrowings on the secondary market (Level 2). As at December 31, 2015, the carrying value of Cenovuss long-term debt was $6,525 million and the fair value was $6,050 million (2014 carrying value  $5,458 million, fair
value  $5,726 million).



|                    |  |    |  |                                  
|------------------- |  | -- |  | ---------------------------------
|Cenovus Energy Inc. |  | 45 |  | Consolidated Financial Statements



---

##### Table of Contents

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

All amounts in $ millions, unless otherwise indicated

For the year ended December 31, 2015



Available for sale financial assets are carried at fair value on the Consolidated Balance Sheets in
other assets. Fair value is determined based on recent private placement transactions (Level 3) when available. The following table provides a reconciliation of changes in the fair value of available for sale financial assets:



|                                       |  |      |    |  |  |  |      |  |    |  
|-------------------------------------- |  | ---- | -- |  |  |  | ---- |  | -- | -
|As at December 31,                     |  | 2015 |    |  |  |  | 2014 | 
|Fair Value, Beginning of Year          |  |      | 32 |  |  |  |      |  | 32 |  
|Acquisition of Investments             |  |      | 2  |  |  |  |      |  | 4  |  
|Reclassification of Equity Investments |  |      | -  |  |  |  |      |  | (4 | )
|Change in Fair Value (1)               |  |      | 8  |  |  |  |      |  | -  |  
|Fair Value, End of Year                |  |      | 42 |  |  |  |      |  | 32 |  



|(1) | Unrealized gains and losses on available for sale financial assets are recorded in other comprehensive income.
|--- | --------------------------------------------------------------------------------------------------------------

B) Fair Value of Risk Management Assets and Liabilities

The Companys risk management assets and liabilities consist of crude oil, condensate, natural gas and power purchase contracts, as well as interest
rate swaps. Crude oil, condensate and natural gas contracts are recorded at their estimated fair value based on the difference between the contracted price and the period-end forward price for the same commodity, using quoted market prices or the
period-end forward price for the same commodity extrapolated to the end of the term of the contract (Level 2). The fair value of power purchase contracts are calculated internally based on observable and unobservable inputs such as forward power
prices in less active markets (Level 3). The unobservable inputs are obtained from third parties whenever possible and reviewed by the Company for reasonableness. The forward prices used in the determination of the fair value of the power purchase
contracts as at December 31, 2015 range from $30.00 to $41.00 per megawatt hour. The fair value of interest rate swaps are calculated using external valuation models which incorporate observable market data, including quoted market prices and
interest rate yield curves (Level 2).

Summary of Unrealized Risk Management Positions



|                   |  |                 |     |                 |  |  |           |  |    |  |  |     |  |  |      |  |       |  |  |  |     |           |  |  |  |  |     |  |  |  |  |  |     |  
|------------------ |  | --------------- | --- | --------------- |  |  | --------- |  | -- |  |  | --- |  |  | ---- |  | ----- |  |  |  | --- | --------- |  |  |  |  | --- |  |  |  |  |  | --- | -
|                   |  | 2015            |     |                 |  |  | 2014      | 
|                   |  | Risk Management |     | Risk Management | 
|As at December 31, |  | Asset           |     |                 |  |  | Liability |  |    |  |  | Net |  |  |      |  | Asset |  |  |  |     | Liability |  |  |  |  | Net | 
|Commodity
Prices   |  |                 |     |                 |  |  |           |  |    |  |  |     |  |  |      |  |       |  |  |  |     |           |  |  |  |  |     |  |  |  |  |  |     |  
|Crude Oil          |  |                 | 301 |                 |  |  |           |  | 15 |  |  |     |  |  | 286  |  |       |  |  |  | 423 |           |  |  |  |  | 7   |  |  |  |  |  | 416 |  
|Natural Gas        |  |                 | -   |                 |  |  |           |  | -  |  |  |     |  |  | -    |  |       |  |  |  | 55  |           |  |  |  |  | -   |  |  |  |  |  | 55  |  
|Power              |  |                 | -   |                 |  |  |           |  | 13 |  |  |     |  |  | (13) |  |       |  |  |  | -   |           |  |  |  |  | 9   |  |  |  |  |  | (9  | )
|                   |  |                 | 301 |                 |  |  |           |  | 28 |  |  |     |  |  | 273  |  |       |  |  |  | 478 |           |  |  |  |  | 16  |  |  |  |  |  | 462 |  
|Interest Rate      |  |                 | -   |                 |  |  |           |  | 2  |  |  |     |  |  | (2)  |  |       |  |  |  | -   |           |  |  |  |  | -   |  |  |  |  |  | -   |  
|Total Fair Value   |  |                 | 301 |                 |  |  |           |  | 30 |  |  |     |  |  | 271  |  |       |  |  |  | 478 |           |  |  |  |  | 16  |  |  |  |  |  | 462 |  

The following table presents the Companys fair value hierarchy for risk management assets and liabilities carried
at fair value:



|                                                                      |  |      |     |   |  |  |      |  |     |  
|--------------------------------------------------------------------- |  | ---- | --- | - |  |  | ---- |  | --- | -
|As at December 31,                                                    |  | 2015 |     |   |  |  | 2014 | 
|Prices Sourced
From Observable Data or Market Corroboration (Level 2) |  |      | 284 |   |  |  |      |  | 471 |  
|Prices Determined From Unobservable Inputs (Level 3)                  |  |      | (13 | ) |  |  |      |  | (9  | )
|                                                                      |  |      | 271 |   |  |  |      |  | 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.



|                    |  |    |  |                                  
|------------------- |  | -- |  | ---------------------------------
|Cenovus Energy Inc. |  | 46 |  | Consolidated Financial Statements



---

##### Table of Contents

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

All amounts in $ millions, unless otherwise indicated

For the year ended December 31, 2015



The following table provides a reconciliation of changes in the fair value of Cenovuss risk
management assets and liabilities:



|                                                                                                              |  |      |      |   |  |  |      |  |      |  
|------------------------------------------------------------------------------------------------------------- |  | ---- | ---- | - |  |  | ---- |  | ---- | -
|As at December 31,                                                                                            |  | 2015 |      |   |  |  | 2014 | 
|Fair Value of Contracts, Beginning of
Year                                                                    |  |      | 462  |   |  |  |      |  | (129 | )
|Fair Value of Contracts Realized During the Year(1)                                                           |  |      | (656 | ) |  |  |      |  | (66  | )
|Change in Fair Value of Contracts in Place at Beginning of Year and Contracts Entered Into During the Year(2) |  |      | 461  |   |  |  |      |  | 662  |  
|Unrealized Foreign Exchange Gain (Loss) on U.S. Dollar Contracts                                              |  |      | 4    |   |  |  |      |  | (5   | )
|Fair Value of Contracts, End of Year                                                                          |  |      | 271  |   |  |  |      |  | 462  |  



|(1) | Includes a realized loss of $10 million related to power contracts (2014 - $4 million gain).
|--- | --------------------------------------------------------------------------------------------

|(2) | Includes a decrease of $14 million related to power contracts (2014 - $10 million decrease).
|--- | --------------------------------------------------------------------------------------------

Financial assets and liabilities are only offset if Cenovus has the current legal right to offset and intends to settle on a
net basis or settle the asset and liability simultaneously. Cenovus offsets risk management assets and liabilities when the counterparty, commodity, currency and timing of settlement are the same. No additional unrealized risk management positions
are subject to an enforceable master netting arrangement or similar agreement that are not otherwise offset.

The following table provides a summary
of the Companys offsetting risk management positions:



|                                                 |  |                 |      |  |  |  |                 |  |     |   |  |     |  |  |     |  |       |  |  |  |     |           |  |  |  |  |     |   |  |  |  |  |     | 
|------------------------------------------------ |  | --------------- | ---- |  |  |  | --------------- |  | --- | - |  | --- |  |  | --- |  | ----- |  |  |  | --- | --------- |  |  |  |  | --- | - |  |  |  |  | --- | 
|                                                 |  | 2015            |      |  |  |  | 2014            | 
|                                                 |  | Risk Management |      |  |  |  | Risk Management | 
|As at December 31,                               |  | Asset           |      |  |  |  | Liability       |  |     |   |  | Net |  |  |     |  | Asset |  |  |  |     | Liability |  |  |  |  | Net |  
|Recognized Risk
Management Positions             |  |                 |      |  |  |  |                 |  |     |   |  |     |  |  |     |  |       |  |  |  |     |           |  |  |  |  |     |   |  |  |  |  |     | 
|Gross Amount                                     |  |                 | 317  |  |  |  |                 |  | 46  |   |  |     |  |  | 271 |  |       |  |  |  | 479 |           |  |  |  |  | 17  |   |  |  |  |  | 462 | 
|Amount Offset                                    |  |                 | (16) |  |  |  |                 |  | (16 | ) |  |     |  |  | -   |  |       |  |  |  | (1  | )         |  |  |  |  | (1  | ) |  |  |  |  | -   | 
|Net Amount per Consolidated Financial Statements |  |                 | 301  |  |  |  |                 |  | 30  |   |  |     |  |  | 271 |  |       |  |  |  | 478 |           |  |  |  |  | 16  |   |  |  |  |  | 462 | 

The derivative liabilities do not have credit risk-related contingent features. Due to credit practices that limit
transactions according to counterparties credit quality, the change in fair value through profit or loss attributable to changes in the credit risk of financial liabilities is immaterial.

Cenovus pledges cash collateral with respect to certain of these risk management contracts, which is not offset against the related financial liability.
The amount of cash collateral required will vary daily over the life of these risk management contracts as commodity prices change. Additional cash collateral is required if, on a net basis, risk management payables exceed risk management
receivables on a particular day. As at December 31, 2015, $26 million (2014  $12 million) was pledged as collateral, of which $5 million (2014  $7 million) could have been withdrawn.

C) Earnings Impact of (Gains) Losses From Risk Management Positions



|                                 |  |      |      |   |  |  |      |  |      |   |  |      |  |  |      |  
|-------------------------------- |  | ---- | ---- | - |  |  | ---- |  | ---- | - |  | ---- |  |  | ---- | -
|For the years ended December 31, |  | 2015 |      |   |  |  | 2014 |  |      |   |  | 2013 | 
|Realized (Gain) Loss(1)          |  |      | (656 | ) |  |  |      |  | (66  | ) |  |      |  |  | (122 | )
|Unrealized (Gain) Loss(2)        |  |      | 195  |   |  |  |      |  | (596 | ) |  |      |  |  | 415  |  
|(Gain) Loss on Risk Management   |  |      | (461 | ) |  |  |      |  | (662 | ) |  |      |  |  | 293  |  



|(1) | Realized gains and losses on risk management are recorded in the operating segment to which the derivative instrument relates.
|--- | ------------------------------------------------------------------------------------------------------------------------------

|(2) | Unrealized gains and losses on risk management are recorded in the Corporate and Eliminations segment.
|--- | ------------------------------------------------------------------------------------------------------

32. RISK MANAGEMENT



The Company is exposed to financial risks,
including market risk related to commodity prices, foreign exchange rates, interest rates as well as credit risk and liquidity risk.

A) Commodity Price Risk

Commodity price risk arises from the effect that fluctuations of forward commodity prices may
have on the fair value or future cash flows of financial assets and liabilities. To partially mitigate exposure to commodity price risk, the Company has entered into various financial derivative instruments.



|                    |  |    |  |                                  
|------------------- |  | -- |  | ---------------------------------
|Cenovus Energy Inc. |  | 47 |  | Consolidated Financial Statements



---

##### Table of Contents

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

All amounts in $ millions, unless otherwise indicated

For the year ended December 31, 2015



The use of these derivative instruments is governed under formal policies and is subject to limits
established by the Board of Directors. The Companys policy is not to use derivative instruments for speculative purposes.

Crude Oil  The Company has used fixed price swaps and costless collars to partially mitigate its exposure to the commodity price risk
on its crude oil sales. In addition, Cenovus has entered into a limited number of swaps and futures to help protect against widening light/heavy crude oil price differentials.

Condensate  The Company has used fixed price swaps to partially mitigate its exposure
to the commodity price risk on its condensate purchases.

Natural Gas  To
partially mitigate the natural gas commodity price risk, the Company may enter into swaps, which fix the AECO or the New York Mercantile Exchange (NYMEX) price. To help protect against widening natural gas price differentials in various
production areas, Cenovus may also enter into swaps to manage the price differentials between production areas and various sales points.

Power  The Company has in place a Canadian dollar denominated derivative contract, which commenced January 1, 2007 for a period of 11 years, to manage a portion of its electricity
consumption costs.

Net Fair Value of Risk Management Positions



|                              |  |                  |  |  |  |      |                         |  |  |  |               |  |                        |  |  |            |  |  |     |  
|----------------------------- |  | ---------------- |  |  |  | ---- | ----------------------- |  |  |  | ------------- |  | ---------------------- |  |  | ---------- |  |  | --- | -
|As at December 31, 2015       |  | Notional Volumes |  |  |  | Term |                         |  |  |  | Average Price |  |                        |  |  | Fair Value | 
|                              |  |                  |  |  |  |      |                        
|Crude Oil Contracts           |  |                  |  |  |  |      |                         |  |  |  |               |  |                        |  |  |            |  |  |     |  
|Fixed Price Contracts         |  |                  |  |  |  |      |                         |  |  |  |               |  |                        |  |  |            |  |  |     |  
|Brent Fixed Price             |  | 17,000 bbls/d    |  |  |  |      | January  June 2016     |  |  |  |               |  | $75.80/bbl             |  |  |            |  |  | 64  |  
|Brent Fixed Price             |  | 33,000 bbls/d    |  |  |  |      | January  June 2016     |  |  |  |               |  | US$47.59/bbl           |  |  |            |  |  | 65  |  
|Brent Fixed Price             |  | 10,000 bbls/d    |  |  |  |      | January  December 2016 |  |  |  |               |  | US$66.93/bbl           |  |  |            |  |  | 127 |  
|Brent Fixed Price             |  | 5,000 bbls/d     |  |  |  |      | July  December 2016    |  |  |  |               |  | $75.46/bbl             |  |  |            |  |  | 13  |  
|WCS Differential (1)          |  | 31,600 bbls/d    |  |  |  |      | January  December 2016 |  |  |  |               |  | US$(13.96)/bbl         |  |  |            |  |  | (9  | )
|Brent Collars                 |  | 10,000 bbls/d    |  |  |  |      | July  December 2016    |  |  |  |               |  | US$45.55 US$56.55/bbl |  |  |            |  |  | 11  |  
|Other Financial Positions (2) |  |                  |  |  |  |      |                         |  |  |  |               |  |                        |  |  |            |  |  | 17  |  
|Crude Oil Fair Value Position |  |                  |  |  |  |      |                         |  |  |  |               |  |                        |  |  |            |  |  | 288 |  
|                              |  |                  |  |  |  |      |                        
|Condensate Purchase Contracts |  |                  |  |  |  |      |                         |  |  |  |               |  |                        |  |  |            |  |  |     |  
|Mont Belvieu Fixed Price      |  | 3,000 bbls/d     |  |  |  |      | January  December 2016 |  |  |  |               |  | US$39.20/bbl           |  |  |            |  |  | (2  | )
|                              |  |                  |  |  |  |      |                        
|Power Purchase Contracts      |  |                  |  |  |  |      |                         |  |  |  |               |  |                        |  |  |            |  |  |     |  
|Power Fair Value Position     |  |                  |  |  |  |      |                         |  |  |  |               |  |                        |  |  |            |  |  | (13 | )
|                              |  |                  |  |  |  |      |                        
|Interest Rate Swaps           |  |                  |  |  |  |      |                         |  |  |  |               |  |                        |  |  |            |  |  | (2  | )

(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.

Price Sensitivities  Risk Management Positions

The following table summarizes the sensitivity of the fair value of Cenovuss risk management positions to fluctuations in commodity prices or
interest rates, with all other variables held constant. Management believes the price and interest rate fluctuations identified in the table below are a reasonable measure of volatility. The impact of fluctuating commodity prices and interest rates
on the Companys open risk management positions in place as at December 31, 2015 and 2014 could have resulted in unrealized gains (losses) impacting earnings before income tax as follows:



|                             |  |                                                                    |  |          |      |   |  |  |      |  |          |  |     |   |  |          |  |  |      |   |          |  |  |  |     |  
|---------------------------- |  | ------------------------------------------------------------------ |  | -------- | ---- | - |  |  | ---- |  | -------- |  | --- | - |  | -------- |  |  | ---- | - | -------- |  |  |  | --- | -
|                             |  |                                                                    |  | 2015     |      |   |  |  | 2014 | 
|                             |  | Sensitivity Range                                                  |  | Increase |      |   |  |  |      |  | Decrease |  |     |   |  | Increase |  |  |      |   | Decrease | 
|Crude Oil Commodity Price    |  | ±   US$10 per bbl
Applied to Brent and WTI Hedges                  |  |          | (243 | ) |  |  |      |  |          |  | 245 |   |  |          |  |  | (145 | ) |          |  |  |  | 146 |  
|Crude Oil Differential Price |  | ±   US$5 per bbl Applied to Differential Hedges
Tied to Production |  |          | 80   |   |  |  |      |  |          |  | (80 | ) |  |          |  |  | 5    |   |          |  |  |  | (5  | )
|Condensate Commodity Price   |  | ±   US$10 per bbl Applied to Condensate Hedges                     |  |          | 23   |   |  |  |      |  |          |  | (23 | ) |  |          |  |  | -    |   |          |  |  |  | -   |  
|Natural Gas Commodity Price  |  | ±   US$1 per Mcf Applied to NYMEX and AECO
Natural Gas Hedges      |  |          | -    |   |  |  |      |  |          |  | -   |   |  |          |  |  | (70  | ) |          |  |  |  | 70  |  
|Power Commodity Price        |  | ±   $25 per MWHr Applied to Power Hedge                            |  |          | 19   |   |  |  |      |  |          |  | (19 | ) |  |          |  |  | 19   |   |          |  |  |  | (19 | )
|Interest Rate Swaps          |  | ±   50 Basis
Points                                                |  |          | 38   |   |  |  |      |  |          |  | (46 | ) |  |          |  |  | -    |   |          |  |  |  | -   |  



|                    |  |    |  |                                  
|------------------- |  | -- |  | ---------------------------------
|Cenovus Energy Inc. |  | 48 |  | Consolidated Financial Statements



---

##### Table of Contents

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

All amounts in $ millions, unless otherwise indicated

For the year ended December 31, 2015



B) Foreign Exchange Risk

Foreign exchange risk arises from changes in foreign exchange rates that may affect the fair value or future cash flows of Cenovuss financial assets
or liabilities. As Cenovus operates in North America, fluctuations in the exchange rate between the U.S./Canadian dollar can have a significant effect on reported results.

As disclosed in Note 7, Cenovuss foreign exchange (gain) loss primarily includes unrealized foreign exchange gains and losses on the translation of
the U.S. dollar debt issued from Canada and the translation of the U.S. dollar Partnership Contribution Receivable issued from Canada. As at December 31, 2015, Cenovus had US$4,750 million in U.S. dollar debt issued from Canada (2014 
US$4,750 million) and US$nil related to the U.S. dollar Partnership Contribution Receivable (2014  US$nil). In respect of these financial instruments, the impact of changes in the U.S. to Canadian dollar exchange rate would have resulted in a
change to foreign exchange (gain) loss as follows:



|                                                            |  |      |  |  |  |      |  |  |  |     
|----------------------------------------------------------- |  | ---- |  |  |  | ---- |  |  |  | ----
|For the years ended December 31,                            |  | 2015 |  |  |  | 2014 |  |  |  | 2013
|                                                            |  |      |  |  | 
|$0.01 Increase in the U.S. to Canadian Dollar Exchange Rate |  | 48   |  |  |  | 48   |  |  |  | 48  
|$0.01 Decrease in the U.S. to Canadian Dollar Exchange Rate |  | (48) |  |  |  | (48) |  |  |  | (48)

C) Interest Rate Risk

Interest rate risk arises from changes in market interest rates that may affect earnings, cash flows and valuations. Cenovus has the flexibility to
partially mitigate its exposure to interest rate changes by maintaining a mix of both fixed and floating rate debt. In addition, to manage the Companys exposure to interest rate volatility, the Company may periodically enter into interest rate
swap contracts related to future debt issuances. As at December 31, 2015, the Company had a notional amount of US$300 million in forward swaps.

As at December 31, 2015, the increase or decrease in net earnings for a one percentage point change in interest rates on floating rate debt amounts
to $nil (2014  $nil, 2013  $nil). This assumes the amount of fixed and floating debt remains unchanged from the respective balance sheet dates.

D) Credit Risk

Credit risk arises from the potential that the Company may incur a loss if a counterparty to a financial instrument fails to meet its obligation in
accordance with agreed terms. This credit risk exposure is mitigated through the use of the credit policy approved by the Audit Committee of the Board of Directors governing the Companys credit portfolio and with credit practices that limit
transactions according to counterparties credit quality. Agreements are entered into with major financial institutions with investment grade credit ratings and with large commercial counterparties, most of which have investment grade credit
ratings. A substantial portion of Cenovuss accounts receivable are with customers in the oil and gas industry and are subject to normal industry credit risks. As at December 31, 2015 and 2014, substantially all of the Companys
accounts receivable were less than 60 days. As at December 31, 2015, 91 percent (2014  91 percent) of Cenovuss accounts receivable and financial derivative credit exposures are with investment grade counterparties. Cenovuss
exposure to its counterparties is within credit policy tolerances.

As at December 31, 2015, Cenovus had one counterparty (2014  two
counterparties) whose net settlement position individually account for more than 10 percent of the fair value of the outstanding in-the-money net financial and physical contracts by counterparty. The maximum credit risk exposure associated with
accounts receivable and accrued revenues, risk management assets, and long-term receivables is the total carrying value.

E)
Liquidity Risk

Liquidity risk is the risk that Cenovus will not be able to meet all of its financial obligations as they become due.
Liquidity risk also includes the risk of not being able to liquidate assets in a timely manner at a reasonable price. Cenovus manages its liquidity risk through the active management of cash and debt and by maintaining appropriate access to credit,
which may be impacted by the Companys credit ratings. As disclosed in Note 30, over the long term, Cenovus targets a Debt to Capitalization ratio between 30 and 40 percent and a Debt to Adjusted EBITDA of between 1.0 to 2.0 times to manage the
Companys overall debt position.

Cenovus manages its liquidity risk by ensuring that it has access to multiple sources of capital including:
cash and cash equivalents, cash from operating activities, undrawn credit facilities and availability under its shelf prospectuses. As at December 31, 2015, Cenovus had $4.1 billion in cash and cash equivalents, and $4.0 billion available on
its committed credit facility. In addition, Cenovus had in place a $1.5 billion Canadian base shelf prospectus and a US$2.0 billion U.S. base shelf prospectus, the availability of which are dependent on market conditions.



|                    |  |    |  |                                  
|------------------- |  | -- |  | ---------------------------------
|Cenovus Energy Inc. |  | 49 |  | Consolidated Financial Statements



---

##### Table of Contents

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

All amounts in $ millions, unless otherwise indicated

For the year ended December 31, 2015



Undiscounted cash outflows relating to financial liabilities are:



|                                         |  |                  |       |  |  |  |           |  |       |  |  |           |  |  |       |  |            |  |  |  |       |       |  |  |  |  |        | 
|---------------------------------------- |  | ---------------- | ----- |  |  |  | --------- |  | ----- |  |  | --------- |  |  | ----- |  | ---------- |  |  |  | ----- | ----- |  |  |  |  | ------ | 
|2015                                     |  | Less than 1 Year |       |  |  |  | 1-3 Years |  |       |  |  | 4-5 Years |  |  |       |  | Thereafter |  |  |  |       | Total | 
|Accounts Payable and Accrued
Liabilities |  |                  | 1,702 |  |  |  |           |  | -     |  |  |           |  |  | -     |  |            |  |  |  | -     |       |  |  |  |  | 1,702  | 
|Risk Management Liabilities (1)          |  |                  | 23    |  |  |  |           |  | 5     |  |  |           |  |  | 2     |  |            |  |  |  | -     |       |  |  |  |  | 30     | 
|Long-Term Debt (2)                       |  |                  | 349   |  |  |  |           |  | 2,847 |  |  |           |  |  | 493   |  |            |  |  |  | 8,721 |       |  |  |  |  | 12,410 | 
|Other (2)                                |  |                  | -     |  |  |  |           |  | 3     |  |  |           |  |  | 1     |  |            |  |  |  | 4     |       |  |  |  |  | 8      | 
|2014                                     |  | Less than 1 Year |       |  |  |  | 1-3 Years |  |       |  |  | 4-5 Years |  |  |       |  | Thereafter |  |  |  |       | Total | 
|Accounts Payable and Accrued
Liabilities |  |                  | 2,588 |  |  |  |           |  | -     |  |  |           |  |  | -     |  |            |  |  |  | -     |       |  |  |  |  | 2,588  | 
|Risk Management Liabilities (1)          |  |                  | 12    |  |  |  |           |  | 4     |  |  |           |  |  | -     |  |            |  |  |  | -     |       |  |  |  |  | 16     | 
|Long-Term Debt (2)                       |  |                  | 293   |  |  |  |           |  | 585   |  |  |           |  |  | 2,093 |  |            |  |  |  | 7,724 |       |  |  |  |  | 10,695 | 
|Other (2)                                |  |                  | -     |  |  |  |           |  | 3     |  |  |           |  |  | 1     |  |            |  |  |  | 4     |       |  |  |  |  | 8      | 

(1) Risk management liabilities subject to master netting agreements.

(2) Principal and interest, including current portion.

33. SUPPLEMENTARY CASH FLOW INFORMATION





|                                 |  |      |  |  |  |      |  |  |  |     
|-------------------------------- |  | ---- |  |  |  | ---- |  |  |  | ----
|For the years ended December 31, |  | 2015 |  |  |  | 2014 |  |  |  | 2013
|Interest Paid                    |  | 330  |  |  |  | 335  |  |  |  | 409 
|Interest Received                |  | 19   |  |  |  | 33   |  |  |  | 119 
|Income Taxes Paid                |  | 933  |  |  |  | 46   |  |  |  | 133 

34. COMMITMENTS AND CONTINGENCIES



A) Commitments

As part of normal operations, the Company has committed to certain amounts over the next five years and thereafter as follows:



|                                   |  |        |       |  |  |  |         |  |     |  |  |         |  |  |     |  |         |  |  |  |       |         |  |  |  |  |            |  |  |  |  |       |        |  |  |  |  |  |        | 
|---------------------------------- |  | ------ | ----- |  |  |  | ------- |  | --- |  |  | ------- |  |  | --- |  | ------- |  |  |  | ----- | ------- |  |  |  |  | ---------- |  |  |  |  | ----- | ------ |  |  |  |  |  | ------ | 
|2015                               |  | 1 Year |       |  |  |  | 2 Years |  |     |  |  | 3 Years |  |  |     |  | 4 Years |  |  |  |       | 5 Years |  |  |  |  | Thereafter |  |  |  |  | Total |       
|Transportation and Storage(1)      |  |        | 702   |  |  |  |         |  | 715 |  |  |         |  |  | 780 |  |         |  |  |  | 774   |         |  |  |  |  | 901        |  |  |  |  |       | 23,537 |  |  |  |  |  | 27,409 | 
|Operating Leases (Building Leases) |  |        | 116   |  |  |  |         |  | 120 |  |  |         |  |  | 156 |  |         |  |  |  | 153   |         |  |  |  |  | 151        |  |  |  |  |       | 2,647  |  |  |  |  |  | 3,343  | 
|Product Purchases                  |  |        | 84    |  |  |  |         |  | 3   |  |  |         |  |  | -   |  |         |  |  |  | -     |         |  |  |  |  | -          |  |  |  |  |       | -      |  |  |  |  |  | 87     | 
|Capital Commitments                |  |        | 61    |  |  |  |         |  | 14  |  |  |         |  |  | 4   |  |         |  |  |  | -     |         |  |  |  |  | -          |  |  |  |  |       | -      |  |  |  |  |  | 79     | 
|Other Long-Term Commitments        |  |        | 45    |  |  |  |         |  | 31  |  |  |         |  |  | 24  |  |         |  |  |  | 26    |         |  |  |  |  | 15         |  |  |  |  |       | 125    |  |  |  |  |  | 266    | 
|Total Payments(2)                  |  |        | 1,008 |  |  |  |         |  | 883 |  |  |         |  |  | 964 |  |         |  |  |  | 953   |         |  |  |  |  | 1,067      |  |  |  |  |       | 26,309 |  |  |  |  |  | 31,184 | 
|Fixed Price Product Sales          |  |        | 55    |  |  |  |         |  | 3   |  |  |         |  |  | -   |  |         |  |  |  | -     |         |  |  |  |  | -          |  |  |  |  |       | -      |  |  |  |  |  | 58     | 
|                                   |  |        |       |  |  |  |         |  |     |  |  |         | 
|2014                               |  | 1 Year |       |  |  |  | 2 Years |  |     |  |  | 3 Years |  |  |     |  | 4 Years |  |  |  |       | 5 Years |  |  |  |  | Thereafter |  |  |  |  | Total |       
|Transportation and Storage (1)     |  |        | 522   |  |  |  |         |  | 637 |  |  |         |  |  | 644 |  |         |  |  |  | 823   |         |  |  |  |  | 1,590      |  |  |  |  |       | 23,632 |  |  |  |  |  | 27,848 | 
|Operating Leases (Building Leases) |  |        | 124   |  |  |  |         |  | 122 |  |  |         |  |  | 120 |  |         |  |  |  | 162   |         |  |  |  |  | 160        |  |  |  |  |       | 2,796  |  |  |  |  |  | 3,484  | 
|Product Purchases                  |  |        | 101   |  |  |  |         |  | 7   |  |  |         |  |  | -   |  |         |  |  |  | -     |         |  |  |  |  | -          |  |  |  |  |       | -      |  |  |  |  |  | 108    | 
|Capital Commitments                |  |        | 90    |  |  |  |         |  | 55  |  |  |         |  |  | 11  |  |         |  |  |  | 2     |         |  |  |  |  | -          |  |  |  |  |       | 46     |  |  |  |  |  | 204    | 
|Other Long-Term Commitments        |  |        | 58    |  |  |  |         |  | 24  |  |  |         |  |  | 21  |  |         |  |  |  | 15    |         |  |  |  |  | 13         |  |  |  |  |       | 116    |  |  |  |  |  | 247    | 
|Total Payments(2)                  |  |        | 895   |  |  |  |         |  | 845 |  |  |         |  |  | 796 |  |         |  |  |  | 1,002 |         |  |  |  |  | 1,763      |  |  |  |  |       | 26,590 |  |  |  |  |  | 31,891 | 
|Fixed Price Product Sales          |  |        | 54    |  |  |  |         |  | 55  |  |  |         |  |  | 3   |  |         |  |  |  | -     |         |  |  |  |  | -          |  |  |  |  |       | -      |  |  |  |  |  | 112    | 

(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.

In 2015, net transportation commitments of $92 million were assumed upon the acquisition of the Companys crude-by-rail terminal.

As at December 31, 2015, there were outstanding letters of credit aggregating $64 million issued as security for performance under certain contracts
(2014  $74 million).



|                    |  |    |  |                                  
|------------------- |  | -- |  | ---------------------------------
|Cenovus Energy Inc. |  | 50 |  | Consolidated Financial Statements



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##### Table of Contents

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

All amounts in $ millions, unless otherwise indicated

For the year ended December 31, 2015



In addition to the above, Cenovuss commitments related to its risk management program are
disclosed in Note 32.

B) Contingencies

Legal Proceedings

Cenovus is involved in a limited number of legal claims associated with the normal course of operations. Cenovus believes it has made adequate provisions
for such legal claims. There are no individually or collectively significant claims.

Decommissioning Liabilities

Cenovus is responsible for the retirement of long-lived assets at the end of their useful lives. Cenovus has recorded a liability of
$2,052 million, based on current legislation and estimated costs, related to its crude oil and natural gas properties, refining facilities and midstream facilities. Actual costs may differ from those estimated due to changes in legislation and
changes in costs.

Income Tax Matters

The tax regulations and legislation and interpretations thereof in the various jurisdictions in which Cenovus operates are continually changing. As a
result, there are usually a number of tax matters under review. Management believes that the provision for taxes is adequate.



|                    |  |    |  |                                  
|------------------- |  | -- |  | ---------------------------------
|Cenovus Energy Inc. |  | 51 |  | Consolidated Financial Statements



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##### Table of Contents

LOGO





Cenovus Energy Inc.

Supplementary Information  Oil and Gas Activities (unaudited)

For the Year
Ended December 31, 2015

(Canadian Dollars)



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##### Table of Contents

DISCLOSURES ABOUT OIL AND GAS PRODUCING ACTIVITIES TOPIC 932 EXTRACTIVE
ACTIVITIES  OIL AND GAS (unaudited)

The following select disclosures of Cenovus Energy Inc.s (Cenovus
or the Company) reserves and other oil and gas information have been prepared in accordance with United States (U.S.) Financial Accounting Standards Board (FASB) Topic 932, Extractive Activities 
Oil & Gas and the U.S. disclosure requirements of the Securities and Exchange Commission (SEC).

All amounts pertaining to
Cenovuss audited Consolidated Financial Statements are prepared in accordance with International Financial Reporting Standards (IFRS) as issued by the International Accounting Standards Board (IASB). Unless otherwise
noted, all dollars are in millions of Canadian dollars. All references to C$ or $ are to Canadian dollars and references to US$ are to U.S. dollars.

RESERVES DATA

The SEC Modernization of Oil and Gas Reporting final rules require that proved reserves be estimated using existing economic conditions (constant
pricing). Cenovuss results have been calculated using the average of the first-day-of-the-month prices for the prior twelve month period. This same twelve month average price is also used in calculating the aggregate amount of (and changes in)
future cash inflows related to the standardized measure of discounted future net cash flows. Future fluctuations in prices, production rates, or changes in political or regulatory environments could cause Cenovuss share of future production
from Canadian reserves to be materially different from that presented.

The reserves estimates included in this supplemental information are estimates
only. There are numerous uncertainties inherent in estimating quantities of reserves, including many factors beyond the Companys control. In general, estimates of economically recoverable bitumen, crude oil and natural gas reserves and the
future net cash flows derived therefrom are based upon a number of variable factors and assumptions, including but not limited to: product prices; future operating and capital costs; historical production from the properties and the assumed effects
of regulation by governmental agencies, including with respect to royalty payments and taxes; initial production rates; production decline rates; and the availability, proximity and capacity of oil and gas gathering systems, pipelines and processing
facilities, all of which may vary considerably from actual results.

All such estimates are to some degree uncertain and classifications of reserves
are only attempts to define the degree of uncertainty involved. For those reasons, estimates of the economically recoverable bitumen, crude oil and natural gas reserves attributable to any particular group of properties, classification of such
reserves based on risk of recovery and estimates of future net revenues expected therefrom, prepared by different engineers or by the same engineers at different times, may vary substantially. Cenovuss actual production, revenues, royalty
payments, taxes and development and operating expenditures with respect to its reserves may vary from current estimates and such variances may be material.

Estimates with respect to reserves that may be developed and produced in the future are often based upon volumetric calculations and upon analogy to
similar types of reserves, rather than upon actual production history. Subsequent evaluation of the same reserves based upon production history will result in variations, which may be material, in the estimated reserves.

Canadian provincial royalties are determined based on a graduated percentage scale which varies with prices and production volumes. Canadian reserves, as
presented on a net basis, assume royalty rates in existence at the time the estimates were made.

Subsequent to December 31, 2015 no major
discovery or other favourable or unfavourable event is believed to have caused a material change in the proved reserves as of that date.

The reserves
data contained herein is dated February 9, 2016 with an effective date of December 31, 2015.



|                    |  |                                                               
|------------------- |  | --------------------------------------------------------------
|                    |  | 2                                                             
|Cenovus Energy Inc. |  | Supplementary Information  Oil and Gas Activities (unaudited)



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##### Table of Contents

OIL AND GAS RESERVE INFORMATION

All of Cenovuss reserves are located in Alberta and Saskatchewan, Canada.

Net Proved Reserves (Cenovus Share After Royalties)(1)(2)(3)

Average Fiscal-Year Prices



|                                |  |                     |       |   |                                            |  |     |                     |  |  |      |  
|------------------------------- |  | ------------------- | ----- | - | ------------------------------------------ |  | --- | ------------------- |  |  | ---- | -
|                                |  | Bitumen
(MMbbls)(4) |       |   | Crude Oil andNatural GasLiquids(MMbbls)(4) |  |     | Natural Gas(Bcf)(4) | 
|2014                            |  |                     |       |   |                                            |  |     |                     |  |  |      |  
|Beginning of year               |  |                     | 1,455 |   |                                            |  | 251 |                     |  |  | 795  |  
|Revisions and improved recovery |  |                     | 8     |   |                                            |  | (2  | )                   |  |  | 183  |  
|Extensions and discoveries      |  |                     | 83    |   |                                            |  | 22  |                     |  |  | 24   |  
|Purchase of reserves in place   |  |                     | -     |   |                                            |  | -   |                     |  |  | 2    |  
|Sale of reserves in place       |  |                     | -     |   |                                            |  | (10 | )                   |  |  | (5   | )
|Production                      |  |                     | (43   | ) |                                            |  | (25 | )                   |  |  | (179 | )
|End of year                     |  |                     | 1,503 |   |                                            |  | 236 |                     |  |  | 820  |  
|Developed                       |  |                     | 180   |   |                                            |  | 183 |                     |  |  | 817  |  
|Undeveloped                     |  |                     | 1,323 |   |                                            |  | 53  |                     |  |  | 3    |  
|Total                           |  |                     | 1,503 |   |                                            |  | 236 |                     |  |  | 820  |  
|                                |  |                     |      
|2015                            |  |                     |       |   |                                            |  |     |                     | 
|Beginning of year               |  |                     | 1,503 |   |                                            |  | 236 |                     |  |  | 820  |  
|Revisions and improved recovery |  |                     | 336   |   |                                            |  | (7  | )                   |  |  | (73  | )
|Extensions and discoveries      |  |                     | 164   |   |                                            |  | 1   |                     |  |  | 6    |  
|Purchase of reserves in place   |  |                     | -     |   |                                            |  | -   |                     |  |  | -    |  
|Sale of reserves in place       |  |                     | -     |   |                                            |  | (18 | )                   |  |  | (54  | )
|Production                      |  |                     | (50   | ) |                                            |  | (22 | )                   |  |  | (160 | )
|End of year                     |  |                     | 1,953 |   |                                            |  | 190 |                     |  |  | 539  |  
|Developed                       |  |                     | 282   |   |                                            |  | 157 |                     |  |  | 538  |  
|Undeveloped                     |  |                     | 1,671 |   |                                            |  | 33  |                     |  |  | 1    |  
|Total                           |  |                     | 1,953 |   |                                            |  | 190 |                     |  |  | 539  |  



|(1) | Definitions:
|--- | ------------

| | (a) | Net reserves are the remaining reserves attributable to Cenovus, after deduction of estimated royalties and including royalty interests. | 
| | --- | ------------------------------------------------------------------------------------------------------------------------------------------ | 

| | (b) | Proved oil and gas reserves are those quantities of oil and gas, which, by analysis of geoscience and engineering data, can be estimated with
reasonable certainty to be economically producible from a given date forward, from known reservoirs and under existing economic conditions, operating methods and government regulations, i.e., prices and costs as of the date the estimate is made. | 
| | --- | ----------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------- | 

| | (c) | Developed oil and gas reserves are reserves that can be expected to be recovered through existing wells with existing equipment and operating
methods in which the cost of the required equipment is relatively minor compared to the cost of a new well. | 
| | --- | ----------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------- | 

| | (d) | Undeveloped reserves are reserves of any category that are expected to be recovered from new wells on undrilled acreage, or from existing wells
where a relatively major expenditure is required for recompletion. | 
| | --- | -------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------- | 

|(2) | Estimates of total net proved bitumen, crude oil, natural gas liquids, or natural gas reserves are not filed by Cenovus with any U.S. federal
authority or agency other than the SEC. | 
|--- | ------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------- | 

|(3) | Natural gas liquids reserves are individually insignificant and have been included with crude oil reserves. | 
|--- | ----------------------------------------------------------------------------------------------------------- | 

|(4) | Millions of barrels is abbreviated as MMbbls; Billion cubic feet is abbreviated as Bcf. | 
|--- | --------------------------------------------------------------------------------------- | 



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|------------------- |  | --------------------------------------------------------------
|                    |  | 3                                                             
|Cenovus Energy Inc. |  | Supplementary Information  Oil and Gas Activities (unaudited)



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##### Table of Contents

STANDARDIZED MEASURE OF DISCOUNTED FUTURE NET CASH FLOWS AND CHANGES THEREIN

In calculating the standardized measure of discounted future net cash flows, the average of the first-day-of-the-month prices for the
prior twelve month period and cost assumptions were applied to Cenovuss annual future production from proved reserves to determine cash inflows. Future production and development costs do not include any cost inflation and assume the
continuation of existing economic, operating and regulatory conditions. Future income taxes are calculated by applying statutory income tax rates to future pre-tax cash flows after provision for the tax cost of the oil and natural gas properties
based upon existing laws and regulations. The discount was computed by application of a 10 percent discount factor to the future net cash flows. The calculation of the standardized measure of discounted future net cash flows is based upon the
discounted future net cash flows prepared by independent qualified reserves evaluators in relation to the reserves they respectively evaluated, and adjusted to the extent provided by contractual arrangements such as price risk management activities,
in existence at year end and to account for asset retirement obligations and future income taxes.

Cenovus cautions that the discounted future net
cash flows relating to proved oil and gas reserves are an indication of neither the fair market value of Cenovuss oil and gas properties, nor the future net cash flows expected to be generated from such properties. The discounted future net
cash flows do not include the fair market value of exploratory properties and probable or possible oil and gas reserves, nor is consideration given to the effect of anticipated future changes in crude oil and natural gas prices, development, asset
retirement and production costs and possible changes to tax and royalty regulations. The prescribed discount rate of 10 percent may not appropriately reflect future interest rates. The computation also excludes values attributable to Cenovuss
enhancing the netback price of the Companys proprietary production.

Computation of the standardized measure of discounted future net cash flows
relating to proved oil and gas reserves were based on the following average of the first-day-of-the-month benchmark prices for the twelve month period before the end of the year:



|     |  |                                  |       |  |                 |  |             |                       |  |  |       |  |                                |  |  |                    |      |  |  |  |      | 
|---- |  | -------------------------------- | ----- |  | --------------- |  | ----------- | --------------------- |  |  | ----- |  | ------------------------------ |  |  | ------------------ | ---- |  |  |  | ---- | 
|     |  | Crude Oil                        |       |  |                 |  | Natural Gas |                      
|     |  | WTI(1) CushingOklahoma
(US$/bbl) |       |  | WCS(2)
(C$/bbl) |  |             | Edmonton Par
(C$/bbl) |  |  |       |  | Henry HubLouisiana
(US$/MMBtu) |  |  | AECO(3)
(C$/MMBtu) |     
|2015 |  |                                  | 50.28 |  |                 |  | 46.78       |                       |  |  | 59.41 |  |                                |  |  |                    | 2.58 |  |  |  | 2.69 | 
|2014 |  |                                  | 95.55 |  |                 |  | 84.27       |                       |  |  | 97.60 |  |                                |  |  |                    | 4.34 |  |  |  | 4.63 | 



|(1) | WTI is an abbreviation for West Texas Intermediate.
|--- | ---------------------------------------------------

|(2) | WCS is an abbreviation for Western Canadian Select.
|--- | ---------------------------------------------------

|(3) | AECO is an abbreviation for Alberta Energy Company Operations.
|--- | --------------------------------------------------------------

Standardized Measure of Discounted Future Net Cash Flows Relating to Proved Oil and Gas Reserves



|                                                                                                            |  |      |         |   |      |  |         |  
|----------------------------------------------------------------------------------------------------------- |  | ---- | ------- | - | ---- |  | ------- | -
|($ millions)                                                                                                |  | 2015 |         |   | 2014 | 
|Future cash inflows                                                                                         |  |      | 73,219  |   |      |  | 122,882 |  
|Less future:                                                                                                |  |      |         |   |      |  |         |  
|Production costs                                                                                            |  |      | 34,339  |   |      |  | 41,292  |  
|Development costs                                                                                           |  |      | 14,626  |   |      |  | 15,643  |  
|Decommissioning liability payments                                                                          |  |      | 3,706   |   |      |  | 960     |  
|Income taxes                                                                                                |  |      | 4,432   |   |      |  | 14,935  |  
|Future net cash flows                                                                                       |  |      | 16,116  |   |      |  | 50,052  |  
|Less 10 percent annual discount for estimated timing of cash flows                                          |  |      | 10,090  |   |      |  | 31,065  |  
|Discounted future net cash flows                                                                            |  |      | 6,026   |   |      |  | 18,987  |  
|Changes in Standardized
Measure of Discounted Future Net Cash Flows Relating to Proved Oil and Gas Reserves | 
|($ millions)                                                                                                |  | 2015 |         |   | 2014 | 
|Balance, beginning of year                                                                                  |  |      | 18,987  |   |      |  | 13,992  |  
|Changes resulting from:                                                                                     |  |      |         |   |      |  |         |  
|Sales of oil and gas produced during the period                                                             |  |      | (2,054  | ) |      |  | (3,947  | )
|Extensions, discoveries and improved recovery, net of related costs                                         |  |      | 535     |   |      |  | 1,498   |  
|Purchases of proved reserves in place                                                                       |  |      | -       |   |      |  | 4       |  
|Sales of proved reserves in place                                                                           |  |      | (87     | ) |      |  | (134    | )
|Net change in prices and production costs                                                                   |  |      | (20,942 | ) |      |  | 6,414   |  
|Revisions to quantity estimates                                                                             |  |      | 1,021   |   |      |  | 361     |  
|Accretion of discount                                                                                       |  |      | 2,441   |   |      |  | 1,809   |  
|Previously estimated development costs incurred net of change in future development costs                   |  |      | 2,636   |   |      |  | 279     |  
|Asset Retirement Obligation                                                                                 |  |      | (313    | ) |      |  | (15     | )
|Other                                                                                                       |  |      | (186    | ) |      |  | 48      |  
|Net change in income taxes                                                                                  |  |      | 3,988   |   |      |  | (1,322  | )
|Balance, end of year                                                                                        |  |      | 6,026   |   |      |  | 18,987  |  



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|                    |  | 4                                                             
|Cenovus Energy Inc. |  | Supplementary Information  Oil and Gas Activities (unaudited)



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##### Table of Contents

OTHER FINANCIAL INFORMATION

Results of Operations



|                                                                                                                    |  |      |       |   |      |      
|------------------------------------------------------------------------------------------------------------------- |  | ---- | ----- | - | ---- | -----
|($ millions)                                                                                                        |  | 2015 |       |   | 2014
|Oil and gas sales to external customers, net of royalties, transportation and blending and realized risk management |  |      | 2,829 |   |      | 4,546
|Intersegment sales                                                                                                  |  |      | 335   |   |      | 812  
|                                                                                                                    |  |      | 3,164 |   |      | 5,358
|Less:                                                                                                               |  |      |       |   |      |      
|Operating costs, production and mineral taxes, and accretion of decommissioning
liabilities(1)                      |  |      | 1,235 |   |      | 1,512
|Depreciation, depletion and amortization                                                                            |  |      | 1,845 |   |      | 1,707
|Goodwill impairment                                                                                                 |  |      | -     |   |      | 497  
|Exploration expense                                                                                                 |  |      | 138   |   |      | 86   
|Operating income                                                                                                    |  |      | (54   | ) |      | 1,556
|Income taxes                                                                                                        |  |      | (14   | ) |      | 517  
|Results of operations                                                                                               |  |      | (40   | ) |      | 1,039

|(1) | Employee stock-based compensation costs previously included in operating expense have been reclassified to general and administrative expense. As a result,
for the year ended December 31, 2014, $17 million was reclassified.
|--- | -------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------

Capitalized Costs



|                                                                                                                                                     |  |      |        |  |      |       
|---------------------------------------------------------------------------------------------------------------------------------------------------- |  | ---- | ------ |  | ---- | ------
|($ millions)                                                                                                                                         |  | 2015 |        |  | 2014
|Proved oil and gas properties                                                                                                                        |  |      | 31,812 |  |      | 32,030
|Unproved oil and gas properties (2)                                                                                                                  |  |      | 1,575  |  |      | 1,625 
|Total capital cost                                                                                                                                   |  |      | 33,387 |  |      | 33,655
|Accumulated depreciation, depletion and amortization                                                                                                 |  |      | 19,185 |  |      | 17,386
|Net capitalized costs                                                                                                                                |  |      | 14,202 |  |      | 16,269
|(2)     Unproved oil and gas properties include exploration and evaluation assets for
which no proved reserves have been recognized.  Costs Incurred
|($ millions)                                                                                                                                         |  | 2015 |        |  | 2014
|Acquisitions                                                                                                                                         |  |      |        |  |      |       
|Unproved                                                                                                                                             |  |      | 4      |  |      | 16    
|Proved                                                                                                                                               |  |      | -      |  |      | 2     
|Total acquisitions                                                                                                                                   |  |      | 4      |  |      | 18    
|Exploration costs                                                                                                                                    |  |      | 66     |  |      | 159   
|Development costs                                                                                                                                    |  |      | 1,360  |  |      | 2,623 
|Total costs incurred                                                                                                                                 |  |      | 1,430  |  |      | 2,800 



|                    |  |                                                               
|------------------- |  | --------------------------------------------------------------
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|Cenovus Energy Inc. |  | Supplementary Information  Oil and Gas Activities (unaudited)



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##### Table of Contents

ADDITIONAL DISCLOSURE

Certifications and Disclosure Regarding Controls and Procedures.



|(a) | Certifications. See Exhibits 99.1, 99.2, 99.3 and 99.4 to this annual report on Form 40-F.
|--- | ------------------------------------------------------------------------------------------



|(b) | Disclosure Controls and Procedures. As of the end of the registrants fiscal year ended December 31, 2015, an evaluation of the
effectiveness of the registrants disclosure controls and procedures (as such term is defined in Rules 13a-15(e) and 15d-15(e) of the Securities Exchange Act of 1934, as amended (the Exchange Act)) was carried out by the
registrants management with the participation of the principal executive officer and principal financial officer. Based upon that evaluation, the registrants principal executive officer and principal financial officer have concluded that
as of the end of that fiscal year, the registrants disclosure controls and procedures are effective to ensure that information required to be disclosed by the registrant in reports that it files or submits under the Exchange Act is
(i) recorded, processed, summarized and reported within the time periods specified in the Securities and Exchange Commissions (the Commission) rules and forms and (ii) accumulated and communicated to the registrants
management, including its principal executive and principal financial officers, or persons performing similar functions, as appropriate to allow timely decisions regarding required disclosure.
|--- | --------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------

It should be noted that while the registrants principal executive officer and principal financial officer believe that
the registrants disclosure controls and procedures provide a reasonable level of assurance that they are effective, they do not expect that the registrants disclosure controls and procedures or internal control over financial reporting
will prevent all errors and fraud. A control system, no matter how well conceived or operated, can provide only reasonable, not absolute, assurance that the objectives of the control system are met.



|(c) | Managements Annual Report on Internal Control Over Financial Reporting. The required disclosure is included in the Report of
Management that accompanies the registrants Consolidated Financial Statements for the fiscal year ended December 31, 2015, filed as part of this annual report on Form 40-F.
|--- | -------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------



|(d) | Attestation Report of the Registered Public Accounting Firm. The required disclosure is included in the Report of Independent
Registered Public Accounting Firm that accompanies the registrants Consolidated Financial Statements for the fiscal year ended December 31, 2015, filed as part of this annual report on Form 40-F.
|--- | ------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------



|(e) | Changes in Internal Control Over Financial Reporting. During the fiscal year ended December 31, 2015, there was no change in the
registrants internal control over financial reporting that has materially affected, or is reasonably likely to materially affect, the registrants internal control over financial reporting.
|--- | -------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------

Notices Pursuant to Regulation BTR.

None.

Audit Committee
Financial Expert.

The registrants board of directors has determined that Colin Taylor, a member of the registrants audit
committee, qualifies as an audit committee financial expert (as such term is defined in paragraph (8) of General Instruction B to Form 40-F), and is independent as that term is defined in the rules of the New York
Stock Exchange.

Code of Ethics.

The registrant has adopted a code of ethics (as that term is defined in paragraph (9) of General Instruction B to Form 40-F),
entitled the Code of Business Conduct & Ethics, that applies to all of its employees, including its principal executive officer, principal financial officer, principal accounting officer or controller, and persons performing
similar functions.

The Code of Business Conduct & Ethics (the Code) is available for viewing on the
registrants website at www.cenovus.com, and is available in print to any person without charge, upon request. Requests for copies of the Code should be made by contacting the registrants Corporate Secretarial Department, Cenovus Energy
Inc., 2600, 500 Centre Street S.E., Calgary, Alberta, Canada T2G 1A6. Information on or connected to our website, even if referred to herein, does not constitute part of this annual report on Form 40-F.

Since the adoption of the Code, there have not been any waivers, including implicit waivers, granted from any provision of the Code.
There were no amendments to the Code in the fiscal year ended December 31, 2015.



3



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##### Table of Contents

Principal Accountant Fees and Services.

The required disclosure is included under the heading Audit Committee  External Auditor Service Fees in the
registrants Annual Information Form for the fiscal year ended December 31, 2015, filed as part of this annual report on Form 40-F.

Pre-Approval Policies and Procedures and Percentage of Services Approved by Audit Committee.

The required disclosure is included under the heading Audit Committee  Pre-Approval Policies and Procedures and Audit
Committee  External Auditor Service Fees in the registrants Annual Information Form for the fiscal year ended December 31, 2015, filed as part of this annual report on Form 40-F.
None of the services therein were approved by the Audit Committee pursuant to paragraph (c)(7)(i)(C) of Rule 2-01 of Regulation S-X.

Off-Balance Sheet
Arrangements.

The registrant does not have any off-balance sheet arrangements (as that term is defined in paragraph (11) of General
Instruction B to Form 40-F) that have or are reasonably likely to have a current or future effect on its financial condition, changes in financial condition, revenues or expenses, results of operations, liquidity, capital expenditures or capital
resources that is material to investors.

Tabular Disclosure of Contractual Obligations.

The required disclosure is included under the heading Liquidity and Capital Resources - Contractual Obligations and Commitments in
the registrants Managements Discussion and Analysis for the fiscal year ended December 31, 2015, filed as part of this annual report on Form 40-F.

Identification of the Audit Committee.

The registrant has a separately-designated standing audit committee established in accordance with Section 3(a)(58)(A) of the Exchange
Act. The members of the audit committee are: Patrick D. Daniel, Steven F. Leer, Valerie A.A. Nielsen and Colin Taylor.

Mine Safety Disclosure.

Not applicable.



4



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##### Table of Contents

UNDERTAKING AND CONSENT TO SERVICE OF PROCESS

A. Undertaking

The registrant
undertakes to make available, in person or by telephone, representatives to respond to inquiries made by the Commission staff, and to furnish promptly, when requested to do so by the Commission staff, information relating to: the securities
registered pursuant to Form 40-F; the securities in relation to which the obligation to file an annual report on Form 40-F arises; or transactions in said securities.

B. Consent to Service of Process



|(1) | The registrant has previously filed a Form F-X in connection with the class of securities in relation to which the obligation to file this report
arises.
|--- | ---------------------------------------------------------------------------------------------------------------------------------------------------------



|(2) | Any change to the name or address of the agent for service of process of the registrant shall be communicated promptly to the Commission by an
amendment to the Form F-X referencing the file number of the registrant.
|--- | -----------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------



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##### Table of Contents

SIGNATURES

Pursuant to the requirements of the Exchange Act, the Registrant certifies that it meets all of the requirements for filing
on Form 40-F and has duly caused this annual report to be signed on its behalf by the undersigned, thereto duly authorized.



|                          |  |  |  |                     |  |                   |  |                                                    |  | 
|------------------------- |  |  |  | ------------------- |  | ----------------- |  | -------------------------------------------------- |  | 
|Date:   February 11, 2016 |  |  |  | CENOVUS ENERGY INC. |  |                  
|                          |  |  |  |                    
|                          |  |  |  | By:                 |  | /s/ Ivor M. Ruste |  |                                                   
|                          |  |  |  |                     |  | Name:             |  | Ivor M. Ruste                                      |  | 
|                          |  |  |  |                     |  | Title:            |  | Executive Vice-President & Chief Financial
Officer |  | 



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##### Table of Contents

EXHIBIT INDEX



|         |  |                                                                                                                        
|-------- |  | -----------------------------------------------------------------------------------------------------------------------
|Exhibits |  | Documents                                                                                                              
|         | 
|99.1     |  | Certification of Chief Executive Officer pursuant to Rule 13a-14(a) or 15d-14(a) of the Securities Exchange Act of 1934
|         | 
|99.2     |  | Certification of Chief Financial Officer pursuant to Rule 13a-14(a) or 15d-14(a) of the Securities Exchange Act of 1934
|         | 
|99.3     |  | Certification of Chief Executive Officer pursuant to 18 U.S.C. Section 1350                                            
|         | 
|99.4     |  | Certification of Chief Financial Officer pursuant to 18 U.S.C. Section 1350                                            
|         | 
|99.5     |  | Consent of PricewaterhouseCoopers LLP                                                                                  
|         | 
|99.6     |  | Consent of McDaniel & Associates Consultants Ltd.                                                                      
|         | 
|99.7     |  | Consent of GLJ Petroleum Consultants Ltd.                                                                              
|         | 
|99.8     |  | Statement of Contingent and Prospective Resources