40-F

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

    ☑      ANNUAL REPORT PURSUANT TO SECTION 13(a) or 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

For the fiscal year ended: December 31, 2017    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)

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:

☑ Annual information form        ☑ 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:

1,228,789,845

Indicate by check mark whether the Registrant by filing the information contained in this Form is also thereby furnishing the information to the Commission pursuant to Rule 12g3-2(b) under the Securities Act of 1934 (the “Exchange Act”). If “Yes” is marked, indicate the file number assigned to the Registrant in connection with such Rule.

Yes ☐    82-             No ☑

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 ☑    No ☐

Indicate by check mark whether the registrant is an emerging growth company as defined in Rule 12b-2 of the Exchange Act.

Emerging growth company ☐

If an emerging growth company that prepares its financial statements in accordance with U.S. GAAP, indicate by check mark if the registrant has elected not to use the extended transition period for complying with any new or revised financial accounting standards† provided pursuant to Section 13(a) of the Exchange Act. ☐

† The term “new or revised financial accounting standard” refers to any update issued by the Financial Accounting Standards Board to its Accounting Standards Codification after April 5, 2012.

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. 333-220700).

Principal Documents

The following documents, filed as Exhibits 99.1, 99.2, 99.3 and 99.4 to this annual report on Form 40-F, are hereby incorporated by reference in this annual report on Form 40-F:

(a) Annual Information Form of Cenovus Energy Inc. for the fiscal year ended December 31, 2017.

(b) Management’s Discussion and Analysis of Cenovus Energy Inc. for the fiscal year ended December 31, 2017.

(c) Consolidated Financial Statements of Cenovus Energy Inc. for the fiscal year ended December 31, 2017.

(d) Supplementary Information – Oil and Gas Activities (unaudited) for the fiscal year ended December 31, 2017.

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ADDITIONAL DISCLOSURE

Certifications and Disclosure Regarding Controls and Procedures.

(a) Certifications. See Exhibits 99.5 99.6, 99.7 and 99.8 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, 2017, 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, 2017, filed as Exhibit 99.3 to 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, 2017, filed as Exhibit 99.3 to this annual report on Form 40-F.

(e) Changes in Internal Control Over Financial Reporting. During the fiscal year ended December 31, 2017, 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.

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During fiscal year 2017, the board of directors approved amendments to the Code including housekeeping amendments as well as more substantive amendments, which include additional wording to ensure staff understand the need to be familiar with the policies and practices that support the Code, specifically adding “environment” commitments to the Code, removing wording that permitted company contributions to political parties, adding reference to The Lobbyist Act (Saskatchewan) and adding wording to reflect that the registrant’s financial statements are prepared in accordance with International Financial Reporting Standards.

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, 2017, filed as Exhibit 99.1 to 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, 2017, filed as Exhibit 99.1 to this annual report on Form 40-F. All fees have been pre-approved by the Audit Committee and therefore 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, 2017, filed as Exhibit 99.2 to 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: Steven F. Leer, Claude Mongeau, Wayne G. Thomson and Colin Taylor.

Mine Safety Disclosure.

Not applicable.

4

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.

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 15, 2018	CENOVUS ENERGY INC.
	By:	/s/ Ivor M. Ruste
		Name:	Ivor M. Ruste
		Title:	Executive Vice-President &
			Chief Financial Officer

EXHIBIT INDEX

Exhibits	Documents
99.1	Annual Information Form of Cenovus Energy Inc. for the fiscal year ended December 31, 2017.
99.2	Management’s Discussion and Analysis of Cenovus Energy Inc. for the fiscal year ended December 31, 2017.
99.3	Consolidated Annual Financial Statements of Cenovus Energy Inc. for the fiscal year ended December 31, 2017.
99.4	Supplementary Information – Oil and Gas Activities (unaudited) for the fiscal year ended December 31, 2017.
99.5	Certification of Chief Executive Officer pursuant to Rule 13a-14(a) or 15d-14(a) of the Securities Exchange Act of 1934
99.6	Certification of Chief Financial Officer pursuant to Rule 13a-14(a) or 15d-14(a) of the Securities Exchange Act of 1934
99.7	Certification of Chief Executive Officer pursuant to 18 U.S.C. Section 1350
99.8	Certification of Chief Financial Officer pursuant to 18 U.S.C. Section 1350
99.9	Consent of PricewaterhouseCoopers LLP
99.10	Consent of McDaniel & Associates Consultants Ltd.
99.11	Consent of GLJ Petroleum Consultants Ltd.
99.12	Amended Code of Business Conduct & Ethics

EX-99.1

Exhibit 99.1

Cenovus Energy Inc.

Annual Information Form

For the Year Ended December 31, 2017

February 14, 2018

TABLE OF CONTENTS
FORWARD-LOOKING INFORMATION	1
CORPORATE STRUCTURE	3
GENERAL DEVELOPMENT OF THE BUSINESS	3
DESCRIPTION OF THE BUSINESS	7
Oil Sands	7
Deep Basin	9
Refining and Marketing	10
Conventional (Discontinued Operations)	11
Competitive and Environmental Considerations	11
Corporate Responsibility Policies	11
Employees	12
Foreign Operations	12
RESERVES DATA AND OTHER OIL AND GAS INFORMATION	13
Disclosure of Reserves Data	14
Development of Proved and Probable Undeveloped Reserves	19
Significant Factors or Uncertainties Affecting Reserves Data	20
Other Oil and Gas Information	20
DIRECTORS AND EXECUTIVE OFFICERS	23
AUDIT COMMITTEE	28
DESCRIPTION OF CAPITAL STRUCTURE	30
DIVIDENDS	32
MARKET FOR SECURITIES	32
RISK FACTORS	32
LEGAL PROCEEDINGS AND REGULATORY ACTIONS	32
INTEREST OF MANAGEMENT AND OTHERS IN MATERIAL TRANSACTIONS	33
MATERIAL CONTRACTS	33
INTERESTS OF EXPERTS	33
TRANSFER AGENTS AND REGISTRARS	34
ADDITIONAL INFORMATION	34
ABBREVIATIONS AND CONVERSIONS	34

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
APPENDIX D -	Netback Reconciliations	D1

Cenovus Energy Inc.   2017 Annual Information Form

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 and operations; projected future value; projections for 2018 and future years; forecast operating and financial results, including forecast sales prices and costs; planned capital expenditures, including the amount, timing and financing thereof; annual capital investment forecasts and plans with respect thereto; techniques expected to be used to recover reserves and forecasts of the timing thereof; future abandonment and reclamation costs and the timing of payments in relation thereto; expected recovery of income taxes; potential impacts of various identified risk factors; 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 trends and expected impacts to Cenovus; and future use and development of technology, including expected effects on environmental impact. 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 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 other 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

Cenovus Energy Inc. 1   2017 Annual Information Form

technology and its application to Cenovus’s business including potential cyber-attacks; 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, and including to address any gaps caused by constraints in the pipeline system; availability of, and Cenovus’s ability 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, 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, refer to “Risk Management and Risk Factors” in the Corporation’s annual 2017 Management’s Discussion and Analysis (“MD&A”), which section of the MD&A is incorporated by reference into this AIF, and to the risk factors described in other documents Cenovus files from time to time with securities regulatory authorities, available on SEDAR at sedar.com, on EDGAR at 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.

Cenovus Energy Inc. 2   2017 Annual Information Form

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 Energy Inc. amalgamated with its wholly owned subsidiary,

Cenovus Marketing Holdings Ltd., through a plan of arrangement approved by the Court of Queen’s Bench of Alberta. On July 31, 2015, Cenovus Energy Inc. amalgamated with its wholly owned subsidiary, 9281584 Canada Limited (formerly 1528419 Alberta Ltd.), by way of a vertical short-form amalgamation.

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, 2017 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
FCCL Partnership (“FCCL”)(2)	100	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) On May 17, 2017, Cenovus acquired from ConocoPhillips Company and certain of its subsidiaries (collectively, “ConocoPhillips”) a 50 percent interest in FCCL Partnership (“FCCL”). This acquisition increased Cenovus’s interest in FCCL to 100 percent.

(3) Cenovus non-operating 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, 2017 and (ii) less than 10 percent of the Corporation’s consolidated revenues for the year ended December 31, 2017. In aggregate, Cenovus’s subsidiaries and partnerships not listed above 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, 2017.

GENERAL DEVELOPMENT OF THE BUSINESS

OVERVIEW

Cenovus is an integrated oil company headquartered in Calgary, Alberta. Cenovus is in the business of developing, producing and marketing crude oil, natural gas and NGLs in Canada, and also conducts marketing activities and owns refining interests 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 British Columbia and Alberta. As at December 31, 2017, Cenovus had a land base of approximately 6.5 million net acres. On January 5, 2018, Cenovus completed the sale of its crude oil and natural gas assets in the Suffield, Alberta area, which represented approximately 0.9 million net acres, resulting in the Corporation’s land base being reduced to 5.6 million net acres. The estimated

proved reserves life index based on working interest production as at December 31, 2017 was approximately 32 years, excluding the Suffield assets.

On May 17, 2017, Cenovus acquired ConocoPhillips’ 50 percent interest in the FCCL Partnership (“FCCL”), and the majority of ConocoPhillips’ western Canadian conventional assets in Alberta and British Columbia (the “Acquisition”). The Acquisition increased Cenovus’s interest in FCCL to 100 percent. In order to finance the Acquisition, Cenovus incurred additional debt and issued additional common shares. Since closing the Acquisition, the Corporation is focused on deleveraging its balance sheet and generating increased cash flows.

Cenovus Energy Inc. 3   2017 Annual Information Form

BUSINESS SEGMENTS

The Corporation’s reportable segments are as follows:

Oil Sands

Cenovus’s Oil Sands segment includes the development and production of bitumen and natural gas in northeast Alberta. Cenovus’s bitumen assets include Foster Creek, Christina Lake and Narrows Lake as well as other projects in the early stages of development. Cenovus’s interest in certain of its operated oil sands properties, notably Foster Creek, Christina Lake and Narrows Lake, increased from 50 percent to 100 percent on May 17, 2017.

Deep Basin

The Deep Basin segment includes approximately three million net acres of land primarily in the Elmworth-Wapiti, Kaybob-Edson, and Clearwater operating areas, rich in natural gas and NGLs. The assets are located in Alberta and British Columbia and include interests in numerous natural gas processing facilities (collectively, the “Deep Basin Assets”). The Deep Basin Assets were acquired on May 17, 2017.

Refining and Marketing

Cenovus’s Refining and Marketing segment includes transporting and selling crude oil, natural gas and NGLs and joint ownership of 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

This segment primarily includes unrealized gains and losses recorded on derivative financial instruments and gains and losses on divestiture of assets, as well as other Cenovus-wide costs for general and administrative (“G&A”), 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.

Conventional (Discontinued Operations)

Cenovus’s Conventional segment has been reported as a discontinued operation as the majority of the Conventional assets were sold in 2017 and the remainder in early 2018.

This segment included the development and production of conventional crude oil⁽¹⁾, natural gas⁽²⁾ and NGLs in Alberta and Saskatchewan, including heavy oil⁽³⁾ assets at Pelican Lake, the carbon dioxide (“CO₂”) enhanced oil recovery (“EOR”) project at Weyburn and tight oil opportunities.

(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 (“NI 51-101”).

(2) For the purpose of this AIF, references to “natural gas” means “conventional natural gas and shale gas” as defined in NI 51-101.

(3) For the purpose of this AIF, references to “heavy oil” means “heavy crude oil” as defined in NI 51-101.

Cenovus Energy Inc. 4   2017 Annual Information Form

THREE YEAR HISTORY

The following describes significant events that have influenced the development of Cenovus’s business during the last three financial years:

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, permit approval was received on the Wood River Refinery debottlenecking project.

· 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 gross overriding royalties on Cenovus’s Pelican Lake property in northern Alberta and its EOR project at 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 G&A costs compared with its original 2015 budget. The cost reductions were achieved across the Corporation and included 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 staff, including full- and part-time employees as well as contract workers. As at December 31, 2015,

the Corporation had approximately 24 percent fewer employee and contractor workforce than it had at December 31, 2014.

· Completed Christina Lake optimization. In the fourth quarter, the Christina Lake optimization program began steam circulation, adding 22,000 barrels per day gross production capacity, 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

· Reduced spending. Cenovus achieved its 2016 target of reducing planned capital, operating and G&A spending by $500 million compared with its original 2016 budget.

· Workforce reductions. In the second quarter, Cenovus further reduced its workforce by approximately 440 staff.

· First production from Foster Creek phase G. In the third quarter, Foster Creek phase G achieved first oil production. Phase G added 30,000 barrels per day of gross production capacity.

· Wood River debottlenecking project completed. In the third quarter, the Wood River debottlenecking project was successfully completed.

· First production from Christina Lake phase F. In the fourth quarter, Christina Lake phase F achieved first oil production. Phase F added 50,000 barrels per day of gross production capacity. The phase F expansion includes a 100 gross megawatt cogeneration plant.

2017

· Resumed Christina Lake phase G expansion. Cenovus resumed the phase G expansion, which has an approved design capacity of 50,000 gross barrels per day. First oil from phase G is expected in the second half of 2019.

· Common share issuance. In the second quarter, Cenovus issued 187.5 million common shares at a price of $16.00 per share for gross proceeds of approximately $3 billion, with net proceeds used to fund a portion of the cash consideration for the Acquisition. As part of the consideration for the Acquisition, Cenovus also issued 208 million common shares to ConocoPhillips.

Cenovus Energy Inc. 5   2017 Annual Information Form

· Increased FCCL interest to 100 percent and acquired Deep Basin Assets. In the second quarter, Cenovus acquired ConocoPhillips’ 50 percent interest in FCCL and the majority of ConocoPhillips’ Deep Basin Assets in Alberta and British Columbia for consideration of approximately US$10.6 billion in cash, before closing adjustments, and 208 million Cenovus shares. The Acquisition gave Cenovus a 100 percent interest in and full control of the FCCL Partnership assets, and provided a second core operating area with approximately three million net acres of land, exploration and production assets and related infrastructure.

· Senior notes offering. In the second quarter of 2017, Cenovus completed an offering of US$2.9 billion senior unsecured notes at a weighted average cost of 4.9%, the net proceeds of which contributed to the funding of the Acquisition.

· Divested legacy Conventional assets. In the third quarter Cenovus sold its Pelican Lake heavy oil operations, including the adjacent Grand Rapids project, for cash proceeds of $975 million. In the fourth quarter, Cenovus sold its Palliser crude oil and natural gas assets for cash proceeds of $1.3 billion and sold its Weyburn carbon-dioxide enhanced oil recovery operation in Saskatchewan for cash proceeds of $940 million. As part of the Corporation’s plan to deleverage its balance sheet, net proceeds from the divestitures were used to retire the $3.6 billion bridge credit facility that had been put in place in connection with the Acquisition.

· Changed President & Chief Executive Officer. In the fourth quarter, Alex Pourbaix was appointed Cenovus’s President & Chief Executive Officer and a member of the Board of Directors, replacing Brian Ferguson.

2018

· Sale of Suffield assets. In the first quarter of 2018 (January 5, 2018), Cenovus completed the sale of its Suffield crude oil and natural gas operations for cash proceeds of $512 million.

· 2018 capital and operating budget. In the fourth quarter of 2017, Cenovus announced its 2018 capital and operating budget, including its intention to continue focusing on cost reductions and plans to further reduce its workforce by approximately 15 percent. In addition, the Corporation announced it is marketing a package of non-core assets in the Deep Basin with a view of further streamlining its asset portfolio and reducing leverage.

· Leadership Team changes. In the fourth quarter of 2017, Cenovus announced changes to its Leadership Team, to be implemented in the first and second quarters of 2018.

Cenovus Energy Inc. 6   2017 Annual Information Form

DESCRIPTION OF THE BUSINESS

OIL SANDS

Cenovus’s Oil Sands segment includes 100 percent ownership of the Foster Creek and Christina Lake assets, both of which are producing. In addition, the Corporation has several emerging projects in the early stages of development, including 100 percent owned projects at Narrows Lake and Telephone Lake. The Oil Sands segment also includes Cenovus’s 100 percent owned Athabasca natural gas property, from which a portion of the natural gas production is used as fuel at the adjacent Foster Creek operations.

Prior to closing the Acquisition on May 17, 2017, the Foster Creek, Christina Lake and Narrows Lake assets were jointly (50 percent) owned through FCCL with ConocoPhillips, an unrelated U.S. public company.

As at December 31, 2017, Cenovus held bitumen rights of approximately 1.9 million gross acres (1.8 million net acres) within the Athabasca and Cold Lake areas, as well as the exclusive rights to lease an additional 536,000 gross acres on the Cold Lake Air Weapons Range.

Development Approach

Cenovus uses steam-assisted gravity drainage (“SAGD”) technology to recover bitumen. The Corporation does not employ mining techniques for extraction and none of its reserves are suitable for extraction using mining techniques. SAGD involves injecting steam into the reservoir to enable bitumen to be pumped to the surface. Cenovus applies a manufacturing-like, phased approach to developing its oil sands assets. This approach incorporates learnings from previous phases into future growth plans, helping the Corporation to minimize costs.

Technology

Cenovus continues to focus on technologies which are targeted to improve business performance and materially increase shareholder value amid continuing price uncertainty, a low carbon future, increased environmental protection pressure and regulatory changes. Technology development is a critical necessity to stay competitive and to sustain stakeholder and community support.

Foster Creek

As of May 17, 2017, the closing date of the Acquisition, Cenovus has a 100 percent working interest in Foster Creek. 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 G at Foster Creek averaged 124,752 net barrels per day in 2017 (70,244 net barrels per day in 2016). Phase G was completed in the third quarter of 2016.

Cenovus operates a 98 gross megawatt natural gas-fired cogeneration facility in conjunction with 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

As of May 17, 2017, the closing date of the Acquisition, Cenovus has a 100 percent working interest in Christina Lake. It is located approximately 120 kilometers south of Fort McMurray and has a reservoir depth up to 375 meters below the surface. Christina Lake produces from the McMurray formation using SAGD technology.

Production from phases A through F at Christina Lake averaged 167,727 net barrels per day in 2017 (79,449 net barrels per day in 2016). Phase F was completed in the fourth quarter of 2016. This expansion included a 100 gross megawatt natural gas-fired cogeneration facility. 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. Cenovus resumed work on the phase G expansion in 2017, which was deferred in late 2014 due to the low commodity price environment. Phase G has an approved design capacity of 50,000 gross barrels per day and first oil from the expansion is expected in the second half of 2019.

Narrows Lake

As of May 17, 2017, the closing date of the Acquisition, Cenovus has a 100 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 demonstration application of solvent aided process in conjunction with SAGD.

In 2012, Cenovus received regulatory approval for phases A, B and C for 130,000 gross barrels per day of production capacity. Initial work on phase A, a 45,000 gross barrels per day phase, with potential to increase to 65,000 gross barrels per day with the addition of solvent depending on ultimate solvent performance, commenced in the third quarter of 2013. Due to the low commodity price environment, Cenovus has deferred new construction spending on phase A. It is expected that the future development of Narrows Lake will benefit from the existing infrastructure and resources at Christina Lake, which is expected to lower overall costs.

Cenovus Energy Inc. 7   2017 Annual Information Form

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.

Cenovus received approval from the Alberta Energy Regulatory (“AER”) in late 2014 for a SAGD project with initial production capacity of 90,000 barrels per day.

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 12.1 million cubic feet per day in 2017 (2016 - 13 million cubic feet per day). The Alberta Department of Energy has provided a 10 year royalty credit which can equal up to 50 percent of lost cash flows to help offset the impact of the shut-in wells. This royalty credit fluctuates with the price of natural gas.

Capital Investment

Oil Sands capital investment reflects Cenovus’s 50 percent ownership of FCCL prior to May 17, 2017, and 100 percent ownership after that date. In 2017, the Corporation’s Oil Sands capital investment was $973 million, primarily related to sustaining existing production, construction of Christina Lake phase G expansion and stratigraphic test wells.

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

· Capital at Narrows Lake was focused on stratigraphic test wells to further progress the project and equipment preservation related to the suspension of construction.

· Capital at Telephone Lake was focused on seismic and stratigraphic test well programs.

2018 capital spending is forecast to be between $1,040 and $1,155 million and is expected to continue to be focused on sustaining current production levels from existing oil sands facilities and construction at Christina Lake phase G.

Cenovus Energy Inc. 8   2017 Annual Information Form

DEEP BASIN

On May 17, 2017, Cenovus acquired the majority of ConocoPhillips’ western Canadian conventional crude oil and natural gas assets including undeveloped land, exploration and production assets, and related infrastructure in Alberta and British Columbia. Cenovus’s Deep Basin Assets include approximately three million net acres of land primarily in the Elmworth-Wapiti, Kaybob-Edson, and Clearwater operating areas, with an average 70 percent working interest. In addition, the Deep Basin Assets include interests in numerous natural gas processing plants with an estimated net processing capacity of 1.4 Bcf per day. The Deep Basin Assets are expected to provide short-cycle development opportunities with high return potential that complement Cenovus’s long-term oil sands development. Deep Basin production is expected to provide an economic hedge for the natural gas required as a fuel source at both the Corporation’s oil sands and refining operations, as well as NGLs that could potentially be used as inputs for future solvent aided oil sands projects.

Cenovus’s priority continues to be the safe and efficient integration of the Deep Basin Assets. The Corporation is committed to ensuring strong stakeholder and community relations as it establishes itself as a new operator in the Deep Basin area.

The Corporation is currently marketing a package of non-core assets in the Deep Basin to further streamline its asset portfolio and reduce leverage.

Elmworth-Wapiti

Cenovus is one of the largest operators and producers in the Elmworth-Wapiti area, located in northwest Alberta and northeast British Columbia. As of December 31, 2017, Cenovus held leasehold rights of 1.2 million net acres in this area.

The Elmworth-Wapiti area provides production potential from more than 10 formations, with the most prospective being the Montney, Falher and Dunvegan. It is a mature area that was historically developed with conventional vertical well technology. Cenovus has shifted to horizontal drilling in its development programs with a view to unlock the vast resource potential in the tight sand plays.

The primary processing facility in the area is the Cenovus-operated Elmworth plant. The Corporation holds significant working interests in five other major natural gas processing facilities in the region. In 2017, Cenovus’s net production in Elmworth-Wapiti averaged 27,868 barrels of oil equivalent per day.

Kaybob-Edson

As of December 31, 2017, Cenovus held leasehold rights of 700,000 net acres in the Kaybob-Edson area, which is situated in west-central Alberta. Target development is in the Triassic and Lower Cretaceous formations where successful industry drilling has proven the resource potential of the offsetting Cenovus acreage. In the Kaybob-Edson area, natural gas processing is primarily controlled by midstream operators and other oil and gas companies.

Cenovus has secured longer term contracts to manage both existing base and new-development volumes. Additionally, Cenovus operates natural gas processing facilities in the area, including the Peco and Wolf plants. Net production in Kaybob-Edson averaged 24,819 barrels of oil equivalent per day in 2017.

Clearwater

The Clearwater area is situated in west-central Alberta, south of Kaybob-Edson. As of December 31, 2017, Cenovus held leasehold rights of 800,000 net acres. Cenovus’s assets in the Clearwater area are characterized by multi-horizon, Cretaceous and Jurassic reservoirs at depths ranging from 1,900 meters to 3,000 meters, all with high NGL content for a predominantly gas prone area. This is a mature area historically developed with conventional vertical well technology, providing Cenovus with a series of low risk horizontal drilling development programs. Cenovus operates natural gas processing facilities in the area, including the Sand Creek and Alder plants. Average net production was 20,805 barrels of oil equivalent per day in 2017.

Capital Investment

In 2017, capital investment of $225 million focused on developing all three operating areas including drilling 24 net horizontal wells and participating in drilling four non-operated net horizontal wells targeting liquids-rich natural gas in 2017. Twenty net wells were completed and 14 net wells started production. The Elmworth-Wapiti operating area focused on drilling nine net horizontal production wells within the Falher and Montney plays with five net completions. The Kaybob-Edson operating area focused on drilling seven net horizontal production wells within the Spirit River group and five net completions. The Clearwater operating area focused on drilling 12 net horizontal production wells within the Spirit River group and 10 net completions.

In 2018, Deep Basin capital investment is forecast to be between $175 million and $195 million.

Cenovus Energy Inc. 9   2017 Annual Information Form

REFINING AND MARKETING

Cenovus’s Refining and Marketing segment includes its U.S. refining non-operator ownership interests and operations involved in coordination of Cenovus’s marketing and transportation initiatives to optimize the value received for its products.

Refining

The refining interests allow Cenovus to capture the value from crude oil production through to refined products, such as diesel, gasoline and jet fuel, to partially mitigate volatility associated with regional North American light/heavy crude oil price differential fluctuations.

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, an unrelated U.S. public company, 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 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)	2017	2016
Crude Oil Capacity (Mbbls/d)	460	460
Crude Oil Runs (Mbbls/d)	442	444
Heavy Oil	202	233
Light & Medium Oil	240	211
Crude Utilization (%)	96	97
Refined Products (Mbbls/d)
Gasoline	238	236
Distillates	149	146
Other	83	90
Total	470	471

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

Wood River Refinery

Wood River Refinery ranks in the top 10 percent of 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. 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 various markets.

Wood River Refinery’s stated crude oil processing capacity for 2017 was 314,000 gross barrels per day, and was unchanged from 2016. Since completing coker construction and start-up of the coker and refinery expansion project, Wood River Refinery increased its total Canadian heavy crude oil processing capacity to 220,000 gross barrels per day. In 2017, approximately 60 percent of the crude oil processed at Wood River Refinery consisted of Canadian heavy crude oil, including a significant proportion of high acid crudes.

Borger Refinery

Borger Refinery is located in Borger, Texas, approximately 80 kilometers north of Amarillo, Texas. 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.

Borger Refinery’s stated oil processing capacity for 2017 was 146,000 gross barrels per day, including 35,000 gross barrels per day of heavy crude oil. Borger Refinery also has an NGL fractionation facility with stated capacity of 45,000 gross barrels per day. The stated processing capacity is unchanged from 2016.

Marketing

Cenovus’s marketing activities are focused on optimizing netbacks of its production and asset base across crude oil, condensate, natural gas, and NGLs.

As part of managing market risk arising from optimization activities, Cenovus enters into financial transactions. Details of these transactions in 2017 are provided in the notes to the Corporation’s annual audited Consolidated Financial Statements for the year ended December 31, 2017.

Transportation

Cenovus continues to focus on near, mid, and long-term strategies to optimize netbacks for its production. As at December 31, 2017, Cenovus has entered into various transportation and storage commitments totaling $18.3 billion, $8.8 billion of which relate to pipelines that are in approval or construction phases but are not yet in service. The Corporation’s portfolio of transportation commitments includes feeder pipelines from its

Cenovus Energy Inc. 10   2017 Annual Information Form

production areas to the major Alberta trade centres and major pipelines to markets downstream of these centres. Other transportation commitments are primarily related to diluent supply, railcar transportation as well as tankage and terminalling of both crude oil blend and condensate volumes. Cenovus’s transportation portfolio also includes a crude-by-rail terminal located at Bruderheim, Alberta.

CONVENTIONAL (DISCONTINUED OPERATIONS)

Cenovus’s Conventional segment has been reported as a discontinued operation. In late 2017 and early 2018, Cenovus divested its legacy assets in the Conventional segment for gross cash proceeds totaling approximately $3.7 billion.

In the third quarter, the Pelican Lake heavy oil assets, including the adjacent Grand Rapids project, were sold for gross cash proceeds of $975 million. In the fourth quarter, the Palliser crude oil and natural gas assets in southeastern Alberta were sold for gross cash proceeds of $1.3 million and the Weyburn CO₂ EOR project was sold for gross cash proceeds of $940 million. On January 5, 2018, a transaction to dispose of the Suffield crude oil and natural gas assets closed for gross cash proceeds of $512 million.

Capital Investment

In 2017, the Corporation’s Conventional capital investment was $206 million, primarily related to sustaining capital, the purchase of CO₂ at Weyburn, and tight oil drilling opportunities in southern Alberta. The drilling program was wound down early in the third quarter due to the pending sale of these assets.

COMPETITIVE AND ENVIRONMENTAL CONSIDERATIONS

All aspects of the oil and gas industry are highly competitive. For further information on the competitive conditions affecting Cenovus, refer to the section entitled “Risk Management and Risk Factors – Operational Considerations” in the Corporation’s annual 2017 MD&A, which section of the MD&A is incorporated by reference into this AIF.

Cenovus’s operations are subject to laws and regulations concerning environmental and public safety protection, including those relating to the handling, offering to transport and transport of hazardous materials. These laws and regulations generally require the Corporation to prevent adverse impacts, and 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. For a discussion of the risks associated with this uncertainty, see the section entitled “Risk Management and Risk Factors – Significant Risk Factors” in the Corporation’s annual 2017 MD&A, which section of the MD&A is incorporated by reference into this AIF.

CORPORATE RESPONSIBILITY POLICIES

Cenovus has established policies and practices relating to the conduct of business in a safe, healthy, ethical, legal and environmentally, socially and fiscally responsible manner. Cenovus’s commitment in these areas is reflected in two key policies, Cenovus’s Code of Business Conduct & Ethics (the “Code”) and Corporate Responsibility Policy (the “CR Policy”). These policies apply to directors and all employees, as well as contractors and suppliers who conduct activities for, or on behalf of, Cenovus. Individuals subject to both policies are accountable for applying them to their own conduct and work. Each employee and director is also asked to regularly review the policies to confirm they understand their individual responsibilities and that they conform to the requirements of both policies.

The Code addresses the identification and management of ethical situations and provides guidance in making ethical business decisions. The Code specifically references the following matters: (a) compliance with laws and regulations; (b) corporate opportunities; (c) conflict of interests; (d) fraud and other similar irregular activities; (e) confidentiality and disclosure; (f) safety, environmental and corporate responsibility; (g) acceptable uses of Cenovus’s systems and assets; (h) inducements and gifts; (i) political and lobbying activities; (j) fair dealing; (k) acquisition and supply of goods and services; (l) books and records accuracy; (m) accounting, auditing or disclosure concerns; and (n) human rights and harassment.

The CR Policy addresses Cenovus business conduct to help ensure the Corporation’s activities are undertaken in a responsible, transparent and respectful manner and in compliance with all applicable laws, regulations and industry standards in the jurisdictions in which Cenovus operates. The CR Policy specifically references the following matters: (a) leadership; (b) corporate governance and business practices; (c) people; (d) environmental performance; (e) stakeholder and Aboriginal engagement; and (f) community involvement and investment.

With respect to the environment specifically, the CR Policy provides that Cenovus recognizes the importance of: integrating an environmental perspective into Cenovus’s business activities; applying risk management throughout its operations to mitigate environmental impact; and pursuing improvements in environmental performance through technology investment and other means.

With respect to social aspects, the CR Policy provides that Cenovus recognizes the importance of: conducting its business with respect and care for the people and communities affected by its activities, noting the company’s commitment to safety and support for the principles of the Universal Declaration of Human Rights; engaging stakeholders, including Aboriginal communities, in a manner based on honesty, trust and respect; and developing and maintaining positive relationships

Cenovus Energy Inc. 11   2017 Annual Information Form

with the communities within which the company operates by, among other means, striving to provide economic and social development opportunities and community investment programs that facilitate capacity-building opportunities.

In addition to the Code and CR Policy, Cenovus has established other policies and practices that in some instances relate to environmental and or social aspects of Cenovus’s business. Stakeholders, employees and contractors are encouraged to report any business conduct concerns, including violations of legislation and or any Cenovus policy, through the company’s anonymous Integrity Helpline. Employees

and contractors may also report any such concerns to their supervisor, a human resources business partner, or a member of an investigations committee.

The aforementioned policies are accessible on the Corporation’s website at cenovus.com, as is Cenovus’s Corporate Responsibility Report (“CR Report”). The CR Report is published annually to detail the company’s management efforts and performance across the above noted areas within Cenovus’s CR Policy, as well as other environment, social and governance topics that are important to its stakeholders.

EMPLOYEES

The following table summarizes Cenovus’s full-time equivalent (“FTE”) employees as at December 31, 2017:

	FTE Employees
Upstream		1,901
Downstream		79
Corporate		902
Total		2,882

Cenovus also engages a number of contractors and service providers. Refer to the section entitled “Risk Management and Risk Factors” in the Corporation’s annual 2017 MD&A, which section of the MD&A is incorporated by reference into this AIF, for further information on employee and other workforce related risks 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 the section entitled “Risk Management and Risk Factors” in the Corporation’s annual 2017 MD&A, which section of the MD&A is incorporated by reference into this AIF, for information on foreign exchange rate matters affecting Cenovus.

Cenovus Energy Inc. 12   2017 Annual Information Form

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 NI 51-101.

The Corporation’s reserves are located in Alberta and British Columbia, 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, conventional natural gas, shale gas and NGLs proved and probable reserves. McDaniel evaluated approximately 92 percent of Cenovus’s proved reserves, all located in Alberta, and GLJ evaluated approximately eight percent of the Corporation’s proved reserves, located in Alberta and British Columbia.

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 the 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 reserves 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 the section entitled “Risk Management and Risk Factors” in the Corporation’s annual 2017 MD&A, which section of the MD&A is incorporated by reference into this AIF, for additional information.

The reserves data and other oil and gas information contained in this AIF is dated February 14, 2018, with an effective date of December 31, 2017. McDaniel’s preparation date of the information is January 12, 2018 and GLJ’s preparation date is January 12, 2018.

Cenovus Energy Inc. 13   2017 Annual Information Form

DISCLOSURE OF RESERVES DATA

The reserves data presented summarizes the Corporation’s bitumen, heavy oil, light and medium oil, NGLs conventional natural gas and shale gas, and total 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, G&A expenses or the impact of any hedging activities. Estimates of FNR have been presented on a before and after income tax basis.

Summary of Company Interest Oil and Gas Reserves as at December 31, 2017

(Forecast prices and inflation)

Before Royalties(1)(2)	Bitumen(3) (MMbbls)		NGLs(4) (MMbbls)		Conventional Natural Gas (Bcf)		Shale Gas (Bcf)		Total   (MMBOE)
Proved Reserves
Developed Producing		731		81		1,568		63		1,084
Developed Non-Producing		106		1		27		3		112
Undeveloped		3,928		34		232		217		4,036
Proved Reserves		4,765		116		1,827		283		5,232
Probable Reserves		1,645		74		860		285		1,910
Proved plus Probable Reserves		6,410		190		2,687		568		7,142
After Royalties(2)(5)	Bitumen(3) (MMbbls)		NGLs(4) (MMbbls)		Conventional Natural Gas (Bcf)		Shale Gas (Bcf)		Total   (MMBOE)
Proved Reserves
Developed Producing		569		66		1,460		62		888
Developed Non-Producing		81		1		25		2		87
Undeveloped		2,939		29		213		199		3,038
Proved Reserves		3,589		96		1,698		263		4,013
Probable Reserves		1,203		62		784		253		1,436
Proved plus Probable Reserves		4,792		158		2,482		516		5,449

(1) Before royalties excludes royalty interest reserves.

(2) Includes reserves associated with the Suffield asset sold January 5, 2018, representing before royalties 69 MMBOE and 82 MMBOE on a proved and proved plus probable basis, respectively.

(3) Includes non-material heavy oil representing less than 1% of total bitumen on a proved plus probable basis.

(4) Includes non-material light and medium oil representing 10% of total NGLs on a proved plus probable basis.

(5) Includes royalty interest reserves.

Summary of Net Present Value of Future Net Revenue as at December 31, 2017

(Forecast prices and inflation)

	Discounted at %/year ($ millions)										Unit Value   Discounted at   10%(2)
Before Income Taxes(1)	0%		5%		10%		15%		20%		$/BOE
Proved Reserves
Developed Producing		17,222		16,886		14,800		13,007		11,574		16.66
Developed Non-Producing		2,863		2,137		1,647		1,305		1,058		18.99
Undeveloped		114,532		49,376		24,933		14,108		8,650		8.21
Proved Reserves		134,617		68,399		41,380		28,420		21,282		10.31
Probable Reserves		57,861		20,640		9,362		5,228		3,390		6.52
Proved plus Probable Reserves		192,478		89,039		50,742		33,648		24,672		9.31

	Discounted at %/year ($ millions)
After Income Taxes(1)(3)	0%		5%		10%		15%		20%
Proved Reserves
Developed Producing		13,132		13,239		11,727		10,344		9,214
Developed Non-Producing		2,141		1,601		1,237		982		798
Undeveloped		84,124		36,176		18,121		10,161		6,172
Proved Reserves		99,397		51,016		31,085		21,487		16,184
Probable Reserves		42,021		15,124		6,932		3,915		2,564
Proved plus Probable Reserves		141,418		66,140		38,017		25,402		18,748

(1) Includes non-material FNR associated with the Suffield assets sold January 5, 2018.

(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 and provincial 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 MD&A for the year ended December 31, 2017.

Cenovus Energy Inc. 14   2017 Annual Information Form

Total Future Net Revenue (undiscounted) as at December 31, 2017

(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		325,331		80,488		72,950		30,195		7,082		134,617		35,220		99,397
Proved  plus  Probable  Reserves		460,838		115,928		98,788		45,608		8,037		192,478		51,060		141,418

(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, 2017

(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(2)		38,654		10.77
	Light and Medium Oil(3)		86		4.94
	Conventional Natural Gas(4)		1,922		5.72
	Shale Gas(4)		718		10.22
	Total		41,380		10.31
Proved plus	Bitumen(2)		46,401		9.68
Probable Reserves	Light and Medium Oil(3)		172		6.42
	Conventional Natural Gas(4)		2,824		5.76
	Shale Gas(4)		1,345		9.61
	Total		50,742		9.31

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

  (2) Includes non-material heavy oil.

  (3) Includes solution gas and other byproducts.

  (4) Includes byproducts, but excludes solution gas.

Cenovus Energy Inc. 15   2017 Annual Information Form

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 heavy oil with bitumen and light and medium oil with NGLs, as the reserves of heavy oil and light and medium oil are not material.

· In accordance with NI 51-101, 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.

· BOE estimates may not sum due to rounding.

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 Cenovus 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 Cenovus’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 crude 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 are disclosed later in this AIF.

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.

Cenovus Energy Inc. 16   2017 Annual Information Form

Pricing Assumptions

The forecast of prices, inflation and exchange rate provided in the table below is computed using the average of forecasts (“IQRE Average Forecast”) by McDaniel, GLJ and Sproule Associates Limited (“Sproule”) and is used to estimate FNR associated with the reserves disclosed herein. The IQRE Average Forecast is dated January 1, 2018. The inflation forecast was applied uniformly to prices beyond the forecast interval, and to all future costs. For historical prices realized during 2017, see “Production History” in this AIF.

	Oil and Liquids								Natural Gas
Year	WTI Cushing Oklahoma (US$/bbl)		Edmonton Par Price 40  API (C$/bbl)		Western Canadian Select (C$/bbl)		Edmonton C5+ (C$/bbl)		AECO Gas Price (C$/MMBtu)		Inflation Rate (%/year)		Exchange   Rate   (US$/C$)
2018		57.50		68.60		50.61		72.41		2.43		0.0		0.790
2019		60.90		72.02		56.59		74.90		2.77		2.0		0.800
2020		64.13		74.48		60.86		77.07		3.19		2.0		0.817
2021		68.33		78.60		64.56		81.07		3.48		2.0		0.828
2022		71.19		80.84		66.63		83.32		3.67		2.0		0.840
2023		73.15		82.83		68.49		85.35		3.76		2.0		0.843
2024		75.16		85.17		70.63		87.75		3.85		2.0		0.843
2025		77.17		87.53		72.79		90.13		3.93		2.0		0.843
2026		79.01		89.66		74.72		92.32		4.02		2.0		0.843
2027		80.60		91.49		76.31		94.21		4.10		2.0		0.843
2028		82.20		93.31		77.84		96.11		4.19		2.0		0.843
2029+		+2%/yr		+2%/yr		+2%/yr		+2%/yr		+2%/yr		2.0		0.843

Future Development Costs

The following table outlines undiscounted future development costs deducted in the estimation of FNR for the years indicated:

Reserves Category ($ millions)	2018		2019		2020		2021		2022		Remainder		Total
Proved Reserves		737		1,030		880		1,118		1,523		24,907		30,195
Proved plus Probable Reserves		845		1,019		1,019		1,272		1,768		39,685		45,608

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.

Cenovus Energy Inc. 17   2017 Annual Information Form

Reserves Reconciliation

The following tables provide a reconciliation of Cenovus’s Company Interest Before Royalties reserves for bitumen, heavy oil, light and medium oil, NGLs, conventional natural gas and shale gas for year ended December 31, 2017, presented using forecast prices and inflation. All reserves are located in Canada.

Proved	Bitumen (MMbbls)			Heavy Oil (MMbbls)			Light & Medium Oil (MMbbls)			NGLs (MMbbls)			Conventional Natural Gas(1) (Bcf)			Shale Gas (Bcf)			Total   (MMBOE)
As at December 31, 2016		2,343			114			99			2			652			-		2,667
Extensions and Improved Recovery		141			-			-			1			35			-		148
Discoveries		-			2			-			-			-			-		2
Technical Revisions		28			2			-			-			86			-		43
Economic Factors		-			-			-			-			-			-		-
Acquisitions		2,345			-			14			108			1,557			289		2,775
Dispositions		-			(95	)		(90	)		(2	)		(266	)		-		(231)
Production		(107	)		(8	)		(10	)		(6	)		(237	)		(6	)	(172)
As at December 31, 2017		4,750			15			13			103			1,827			283		5,232
Probable	Bitumen (MMbbls)			Heavy Oil (MMbbls)			Light & Medium Oil (MMbbls)			NGLs (MMbbls)			Conventional Natural Gas(1) (Bcf)			Shale Gas (Bcf)			Total    (MMBOE)
As at December 31, 2016		976			75			43			1			212			-		1,130
Extensions and Improved Recovery		(141	)		-			-			3			21			15		(132)
Discoveries		-			7			-			-			-			-		7
Technical Revisions		(10	)		-			-			-			(3	)		-		(10)
Economic Factors		-			-			-			-			-			-		-
Acquisitions		887			-			6			65			748			270		1,128
Dispositions		(79	)		(70	)		(43	)		(1	)		(118	)		-		(213)
Production		-			-			-			-			-			-		-
As at December 31, 2017		1,633			12			6			68			860			285		1,910
Proved plus Probable	Bitumen (MMbbls)			Heavy Oil (MMbbls)			Light & Medium Oil (MMbbls)			NGLs (MMbbls)			Conventional Natural Gas(1) (Bcf)			Shale Gas (Bcf)			Total    (MMBOE)
As at December 31, 2016		3,319			189			142			3			864			-		3,797
Extensions and Improved Recovery		-			-			-			4			56			15		16
Discoveries		-			9			-			-			-			-		9
Technical Revisions		18			2			-			-			83			-		33
Economic Factors		-			-			-			-			-			-		-
Acquisitions		3,232			-			20			173			2,305			559		3,903
Dispositions		(79	)		(165	)		(133	)		(3	)		(384	)		-		(444)
Production		(107	)		(8	)		(10	)		(6	)		(237	)		(6	)	(172)
As at December 31, 2017		6,383			27			19			171			2,687			568		7,142

(1) Includes CBM as at December 31, 2016. No CBM remains at December 31, 2017 due to dispositions.

(2) 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 103 percent, primarily due to the acquisition of the remaining 50 percent working interest in FCCL, and also as a result of AER approved area expansions and improved reservoir performance at Foster Creek and Narrows Lake.

Proved plus probable bitumen reserves grew 92 percent due to the acquisition of the remaining 50 percent working interest in FCCL, partially offset by the Grand Rapids disposition.

Heavy oil proved and proved plus probable reserves decreased by approximately 87 percent and 86 percent, respectively, due to the Pelican Lake divestiture, partially offset by the discovery at Marten Hills.

Light and medium oil proved and proved plus probable reserves both decreased by 87 percent. The decrease is primarily attributed to the divestiture of both the Palliser and Weyburn assets, partially offset by the acquisition of the Deep Basin Assets.

The Deep Basin Assets acquisition increased Cenovus’s proved and proved plus probable NGL reserves by 101 MMbbls and 168 MMbbls, respectively.

Proved conventional natural gas reserves increased by 1,175 Bcf as the Deep Basin Assets acquisition and positive technical revisions were partially offset by the Palliser disposition. Proved plus probable conventional natural gas reserves grew 1,823 Bcf.

Cenovus’s Deep Basin Assets acquisition added proved and proved plus probable Shale Gas reserves of 283 Bcf and 568 Bcf, respectively.

Cenovus Energy Inc. 18   2017 Annual Information Form

Undeveloped Reserves

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, proved undeveloped reserves are scheduled to be developed within the next one to 50 years.

The asset transactions of 2017 shifted the portfolio mix of reported product types. The undeveloped tables presented here reflect the product type groups reported above, specifically, bitumen includes heavy oil, NGLs includes light and medium oil and conventional natural gas includes CBM, for the years 2015, 2016, 2017 and for the period prior to 2015. The 2017 dispositions and the early 2018 disposition of the Suffield property ensure that heavy oil, light and medium oil and CBM reserves are no longer material to the Company.

Company Interest Proved Undeveloped – Before Royalties
	Bitumen (MMbbls)				NGLs (MMbbls)				Conventional Natural Gas (Bcf)				Shale Gas (Bcf)				Total (MMBOE)
	First Attributed		Total at Year-End		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		2,137		1,772		70		21		304		4		-		-		2,258		1,794
2015		238		1,890		1		19		1		4		-		-		239		1,910
2016		185		2,020		-		15		-		5		-		-		185		2,036
2017		2,051		3,928		34		34		232		232		217		217		2,159		4,036
Company Interest Probable Undeveloped – Before Royalties
	Bitumen (MMbbls)				NGLs (MMbbls)				Conventional Natural Gas (Bcf)				Shale Gas (Bcf)				Total (MMBOE)
	First Attributed		Total at Year-End		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		2,020		1,369		43		15		61		11		-		-		2,073		1,386
2015		1		1,126		1		14		2		8		-		-		2		1,141
2016		10		981		-		15		-		9		-		-		10		998
2017		771		1,550		47		47		379		379		261		261		925		1,704

DEVELOPMENT OF PROVED AND PROBABLE UNDEVELOPED RESERVES

Bitumen

At the end of 2017, Cenovus had proved undeveloped bitumen reserves of 3,926 million barrels Before Royalties, or approximately 83 percent of the Corporation’s proved bitumen reserves. Of Cenovus’s 1,633 million barrels of probable bitumen reserves, 1,543 million barrels, or approximately 94 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 stratigraphic wells per section with 3D seismic, or 16 stratigraphic wells per section with no seismic. Additionally, all requisite legal and regulatory approvals must have been obtained, operator 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 located outside of an approved development plan area, but within an approved project 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 Foster Creek and Christina Lake 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. Development and capital spending on the proved and probable undeveloped reserves at Narrows Lake continues with the project scheduled to be on stream between 2020 and 2025. The forecast production of Cenovus’s proved bitumen reserves extends approximately 50 years, based on existing facilities. Production of the current proved developed portion is estimated to take approximately 15 years.

Cenovus Energy Inc. 19   2017 Annual Information Form

Conventional Natural Gas, Shale Gas and NGLs

Cenovus’s Deep Basin Assets proved undeveloped and proved plus probable undeveloped reserves are approximately two percent and four percent of the Corporation’s proved and proved plus probable reserves, respectively. Cenovus plans to develop the Deep Basin Assets proved undeveloped reserves over the next five years and proved plus probable undeveloped reserves over the next eight years.

SIGNIFICANT FACTORS OR UNCERTAINTIES AFFECTING RESERVES DATA

The evaluation of reserves is a continuous process 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 the section entitled “Risk Management and Risk Factors” in the Corporation’s annual 2017 MD&A, which section of the MD&A is incorporated by reference into this AIF.

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, 2017:

	Oil				Gas				Total
Producing Wells(1)	Gross		Net		Gross		Net		Gross		Net
Oil Sands(2)		587		587		220		220		807		807
Deep Basin(3)		747		415		4,143		2,908		4,890		3,323
Conventional (Discontinued Operations)		612		607		10,463		10,440		11,075		11,047
Total		1,946		1,609		14,826		13,568		16,772		15,177
(1)    Includes wells containing multiple completions as follows: 9,734 gross gas wells (9,713 net wells) and 469 gross oil wells (468 net wells).
(2)    All producing Oil Sands wells are located in Alberta.
(3)    Includes 4,469 gross producing wells (2,992 net producing wells) located in Alberta; 421 gross producing wells (331 net producing wells) located in British Columbia.
	Oil				Gas				Total
Non-Producing Wells(1)	Gross		Net		Gross		Net		Gross		Net
Oil Sands(2)		162		162		259		240		421		402
Deep Basin(3)		238		168		646		516		884		684
Conventional (Discontinued Operations)		354		346		359		348		713		694
Total		754		676		1,264		1,104		2,018		1,780

(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.

(2) All non-producing Oil Sands wells are located in Alberta.

(3) Includes 860 gross non-producing wells (664 net non-producing wells) located in Alberta; 24 gross non-producing wells (20 net non-producing wells) located in British Columbia.

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

Exploration and Development Activity

The following tables summarize Cenovus’s gross participation and net interest in wells drilled in 2017⁽¹⁾:

	Oil Sands				Deep Basin				Conventional				Total
Development Wells Drilled	Gross		Net		Gross		Net		Gross		Net		Gross		Net
Oil		286		187		-		-		24		24		310		211
Gas		-		-		38		28		-		-		38		28
Dry & Abandoned		-		-		-		-		-		-		-		-
Total Canada		286		187		38		28		24		24		348		239

(1) Cenovus did not have any participation or interest in any exploration wells in 2017.

During the year ended December 31, 2017, Oil Sands drilled 220 gross stratigraphic test wells (123 net wells) and Conventional drilled 26 gross stratigraphic test wells (26 net wells). Deep Basin drilled no stratigraphic test wells.

During the year ended December 31, 2017, no service wells were drilled within Oil Sands, Conventional or Deep Basin.

SAGD well pairs are counted as a single oil 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 the production of Deep Basin properties.

Cenovus Energy Inc. 20   2017 Annual Information Form

Properties With No Attributed Reserves

Cenovus has approximately 6.3 million gross acres (5.1 million net acres) of properties in Canada to which no reserves have been specifically attributed. For lands in which Cenovus holds multiple leases under the same surface area, both gross and net areas have been counted for each lease. There are currently no work commitments on these properties.

Cenovus has rights to explore, develop, and exploit approximately 74,880 net acres that could potentially expire by December 31, 2018, which relate entirely to Crown and freehold land.

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 the section entitled “Risk Management and Risk Factors” in the Corporation’s annual 2017 MD&A, which section of the MD&A is incorporated by reference into 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 of approximately $2,139 million (approximately $712 million, discounted at 10 percent) at December 31, 2017, of which the Corporation expects to pay between $200 million and $250 million in the next three financial years on a portion of the 10,154 net wells. The foregoing excludes abandonment and reclamation costs for the Suffield assets that were sold pursuant to a transaction that closed on January 5, 2018.

Of the undiscounted future abandonment and reclamation costs to be incurred over the life of Cenovus’s proved reserves, approximately $7 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 2018, Cenovus currently expects to incur losses for income tax purposes and recover income taxes paid in prior years. Tax may be payable by the Corporation in 2019.

Costs Incurred

($ millions)	2017
Acquisitions
Unproved	3,372
Proved	15,016
Total Acquisitions	18,388
Exploration Costs	147
Development Costs	1,257
Total Costs Incurred	19,792

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, 2017.

Cenovus Energy Inc. 21   2017 Annual Information Form

Production Estimates

The following table summarizes the estimated 2018 average daily volume of Company Working Interest Before Royalties reflected in the reserves reports for all properties held on December 31, 2017 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.

2018 Estimated Production  Forecast Prices and Costs	Proved	Proved plus   Probable
Bitumen (bbls/d)(1)	388,360	406,718
Heavy Oil (bbls/d)	6,645	6,889
Light & Medium Oil (bbls/d)	5,317	5,788
Conventional Natural Gas (MMcf/d)	584	655
Shale Gas (MMcf/d)	37	39
NGLs (bbls/d)	26,989	29,413
Total (BOE/d)	530,781	564,489

 (1) Includes Foster Creek production of 167,801 barrels per day for proved and 173,630 barrels per day for proved plus probable, and Christina Lake production of 220,559 barrels per day for proved and 233,088 barrels per day for proved plus probable.

Production History and Per-Unit Results – Before Royalties

	2017	Q4	Q3	Q2	Q1
Bitumen
Total Production (bbls/d)	292,479	361,363	362,494	261,812	181,501
Foster Creek	124,752	154,784	154,363	107,859	80,866
Christina Lake	167,727	206,579	208,131	153,953	100,635
Sales Price ($/bbl)	41.49	46.08	40.02	39.73	38.08
Royalties ($/bbl)	2.22	3.63	1.60	1.52	1.78
Transportation and blending ($/bbl)	6.33	6.55	6.11	6.68	5.81
Operating expenses ($/bbl)	8.40	8.39	7.58	9.19	8.97
Netback(1)	24.54	27.51	24.73	22.34	21.52
Heavy Oil
Total Production (bbls/d)	21,478	6,675	25,549	26,593	27,277
Sales Price ($/bbl)	48.46	58.93	48.01	46.67	47.77
Royalties ($/bbl)	6.41	3.10	7.04	6.15	7.03
Transportation and blending ($/bbl)	4.44	4.49	5.45	4.48	3.40
Operating expenses ($/bbl)	14.85	20.64	15.50	14.56	12.86
Production and mineral taxes ($/bbl)	0.02	0.05	0.01	0.01	0.02
Netback(1)	22.74	30.65	20.01	21.47	24.46
Light & Medium Oil
Total Production (bbls/d)	28,746	26,101	33,441	30,292	25,089
Sales Price ($/bbl)	56.71	62.61	52.03	57.01	56.84
Royalties ($/bbl)	11.50	12.91	9.71	11.32	12.75
Transportation and blending ($/bbl)	2.74	2.56	2.40	3.33	2.70
Operating expenses ($/bbl)	16.24	16.83	15.92	15.68	16.77
Production and mineral taxes ($/bbl)	1.62	1.74	1.24	1.66	1.95
Netback(1)	24.61	28.57	22.76	25.02	22.67
Conventional Natural Gas(2)
Total Production (bbls/d)	659	795	851	620	363
Sales Price ($/bbl)	2.25	1.92	1.84	2.82	2.99
Royalties ($/bbl)	0.10	0.08	0.07	0.12	0.14
Transportation and blending ($/bbl)	0.20	0.25	0.22	0.16	0.12
Operating expenses ($/bbl)	1.36	1.38	1.36	1.33	1.34
Production and mineral taxes ($/bbl)	0.01	-	0.01	0.01	0.02
Netback(1)	0.58	0.21	0.18	1.20	1.37
NGLs
Total Production (bbls/d)	18,001	28,018	27,571	14,967	1,047
Sales Price ($/bbl)	33.73	38.66	31.10	28.27	48.35
Royalties ($/bbl)	3.44	4.38	2.86	2.54	6.42
Transportation and blending ($/bbl)	2.47	2.80	2.76	1.46	-
Operating expenses ($/bbl)	7.24	6.57	8.71	6.30	-
Netback(1)	20.58	24.91	16.77	17.97	41.93

(1) Netback is a non-GAAP measure commonly used in the oil and gas industry to assist in measuring operating performance on a per-unit basis. Netback is defined as gross sales less royalties, transportation and blending, operating expenses and production and mineral taxes divided by sales volumes. Netbacks do not reflect non-cash write-downs of product inventory until the inventory is sold. This calculation is consistent with the definition found in the Canadian Oil and Gas Evaluation Handbook. The crude oil sales price, transportation and blending costs, and sales volumes exclude the impact of purchased condensate. Netback does not have a standardized meaning as prescribed by IFRS and therefore is considered a non-GAAP measure. As such, it may not be comparable to similar measures presented by other issuers. This measure has been described and presented in this AIF in order to provide shareholders and potential investors with additional information regarding Cenovus’s liquidity and its ability to generate funds to finance its operations, and to comply with the requirements of NI 51-101. This measure should not be considered in isolation or as a substitute for measures prepared in accordance with IFRS. For further information, refer to Cenovus’s most recent MD&A available at cenovus.com. For the reconciliation of the financial components of Netback to the GAAP measure and the sales volumes used in the calculations, see “Netback Reconciliations” in Appendix D.

(2) Conventional Natural Gas includes CBM and shale gas. Shale gas represents 2.69% of total Conventional Natural Gas.

Cenovus Energy Inc. 22   2017 Annual Information Form

Capital Expenditures, Acquisitions and Divestitures

In 2017, Cenovus had an active program to divest its legacy Conventional assets in order to increase its focus on key assets within the long-range business plan, as well as generate proceeds to deleverage its balance sheet.

In the third quarter of 2017, Cenovus sold its Pelican Lake heavy oil assets, including the adjacent Grand Rapids project, for gross cash proceeds of $975 million. In the fourth quarter of 2017, Cenovus sold its Palliser crude oil and natural gas operations in southern Alberta for gross cash proceeds of $1.3 billion and its Weyburn carbon-dioxide enhanced oil recovery operation in Saskatchewan for gross cash proceeds of $940 million. In the first quarter of 2018, Cenovus also sold its Suffield crude oil and natural gas assets for gross cash proceeds of $512 million.

The following table summarizes Cenovus’s net capital investment for 2017 and 2016:

Net Capital Investment ($ millions)	2017		2016
Capital Investment
Oil Sands
Foster Creek	455		263
Christina Lake	426		282
Total	881		545
Other Oil Sands	92		59
	973		604
Deep Basin(1)	225		-
Refining and Marketing	180		220
Conventional (Discontinued Operations)	206		171
Corporate	77		31
Capital Investment	1,661		1,026
Acquisitions(2)	18,388		11
Divestitures(2)	(3,210	)	(8)
Net Acquisition and Divestiture Activity	15,178		3
Net Capital Investment(3)	16,839		1,029

1) The Deep Basin Assets were acquired on May 17, 2017.

2) In connection with the Acquisition, Cenovus was deemed to have disposed of its pre-existing interest in FCCL and reacquired it at fair value as required by IFRS 3, which is not reflected in the table above. The carrying value of the pre-existing interest was $9,081 million and the fair value was $11,604 million at May 17, 2017.

3) Includes expenditures on: property, plant and equipment; exploration and evaluation assets; and assets held for sale.

DIRECTORS AND EXECUTIVE OFFICERS

DIRECTORS

The following individuals are directors of Cenovus as at December 31, 2017.

Name and   Residence	Director Since(1)	Principal Occupation During the Past Five Years
Susan F.   Dabarno(3,4,5)   Bracebridge, Ontario,   Canada	2017 Independent	Ms. Dabarno is a director of Manulife Financial Corporation. Ms. Dabarno has extensive wealth management and financial expertise and served as Executive Chair of Richardson Partners Financial Limited (“Richardson”), an independent wealth management services firm, from October 2009 to April 2010, and as President and Chief Executive Officer from June 2003 to October 2009. Prior to joining Richardson, she was President and Chief Operating Officer at Merrill Lynch Canada Inc.
Patrick D.   Daniel(4,7)   Calgary, Alberta,   Canada	2009 (Chair) Independent	Mr. Daniel has served as the Chair of Cenovus’s Board since April 2017. He is a director of Canadian Imperial Bank of Commerce; a director of 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. (“Enbridge”), a publicly traded energy delivery company, from April 2000 to October 2012. During his tenure with Enbridge, he also served as Chief Executive Officer from February 2012 to October 2012, as President & Chief Executive Officer from January 2001 to February 2012 and as President and Chief Operating Officer from September 2000 to January 2001.

Cenovus Energy Inc. 23   2017 Annual Information Form

Name and   Residence	Director Since(1)	Principal Occupation During the Past Five Years
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 Chairman of 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. During his tenure with Sherritt, he also served as Chairman from November 1995 to May 2004, Executive Chairman from May 2004 to December 2008, Chairman and Chief Executive Officer from January 2009 to December 2011 and Chairman 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.
Steven F. Leer(2,3,4)   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; non-executive Chairman of the Board 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 a director of USG from June 2005 to January 2012 and was lead director from January 2012 to November 2016. Mr. Leer also 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.
Richard J.   Marcogliese(4,5,6)   Alamo, California,   United States	2016 Independent	Mr. Marcogliese is the Principal of iRefine, LLC, a privately owned petroleum refining consulting company; Executive Advisor of Pilko & Associates L.P., a private chemical and energy advisory company; and is presently engaged as an Operations Advisor to NTR Partners III LLC, a private investment company. He served as Operations Advisor to the CEO of Philadelphia Energy Solutions, a partnership between The Carlyle Group and a subsidiary of Energy Transfer Partners, L.P. that operates an oil refining complex on the U.S. Eastern seaboard, from September 2012 to January 2016.
Claude   Mongeau(2,4,5)   Montreal, Quebec,   Canada	2016 Independent	Mr. Mongeau is a director of The Toronto-Dominion Bank and TELUS Corporation. Mr. Mongeau served as a director of Canadian National Railway Company (“CN”), a publicly traded railroad and transportation company, from October 2009 to July 2016 and as President and Chief Executive Officer from January 2010 to June 2016. During his tenure with CN, he also served as Executive Vice-President and Chief Financial Officer from October 2000 until December 2009, and held various increasingly senior positions from the time he joined in 1994. Mr. Mongeau also served as a director of SNC-Lavalin Group Inc. from August 2003 to May 2015 and Chairman of the Board of the Railway Association of Canada.

Cenovus Energy Inc. 24   2017 Annual Information Form

Name and   Residence	Director Since(1)	Principal Occupation During the Past Five Years
Alexander J.   Pourbaix(8)   Calgary, Alberta,   Canada	2017	Mr. Pourbaix has served as President & Chief Executive Officer of Cenovus since November 6, 2017 and is a director of Trican Well Service Ltd. Mr. Pourbaix served as Chief Operating Officer of TransCanada Corporation (“TransCanada”), a publicly traded energy infrastructure company, from October 2015 to April 2017. During his tenure with TransCanada, he also served as Executive Vice-President and President, Development from March 2014 to September 2015 and President, Energy & Oil Pipelines from July 2010 to February 2014, and held various increasingly senior positions from the time he joined TransCanada in 1994. Mr. Pourbaix was a member and past Board Chair for the Canadian Energy Pipeline Association.
Charles M.   Rampacek(3,4,6)   Fredericksburg, Texas,   United States	2009 Independent	Mr. Rampacek is a director of 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 served as a director of Flowserve Corporation, a publicly traded manufacturer of industrial equipment from March 1998 to May 2016. He 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(2,4,5)   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(2,4,5)   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 public Swedish oil and gas company; Chairman of Inventys Thermal Technologies Inc. (“Inventys”), a private carbon capture technology company; and Chairman and President of Enviro Valve Inc., a private company manufacturing proprietary pressure relief valves. Mr. Thomson served as Interim Executive Chairman of Inventys from May 2016 to February 2017, as Chief Executive Officer of Iskander Energy Corp., a private international oil and gas company, from November 2011 to August 2014 and as a director from November 2011 to March 2016.
Rhonda I.   Zygocki(3,4,6)   Friday Harbor,   Washington,   United States	2016 Independent	Ms. Zygocki served as Executive Vice President, Policy and Planning of Chevron Corporation (“Chevron”), an integrated energy company, from March 2011 until her retirement in February 2015 and prior thereto, during her 34 years with Chevron, she held a number of senior management and executive leadership positions in international operations, public affairs, strategic planning, policy, government affairs and health, environment and safety. She is a senior advisor with the Center for Strategic and International Studies and a former advisory board member of the Woodrow Wilson International Center of Scholars Canada Institute.

(1) Each of Messrs. Daniel, Delaney, Rampacek, Taylor and Thomson first became members of Cenovus’s Board pursuant to the Arrangement;

· Mr. Leer was elected as a director of Cenovus’s Board at the Annual and Special Meeting of Shareholders held on April 29, 2015,

· Ms. Zygocki and Mr. Marcogliese were elected as directors of Cenovus’s Board at the Annual Meeting of Shareholders held on April 27, 2016,

· Mr. Mongeau was appointed as a director of Cenovus’s Board as of December 1, 2016;

· Ms. Dabarno was elected as a director of Cenovus’s Board at the Annual Meeting of Shareholders held on April 26, 2017; and

· Mr. Pourbaix was appointed as President and Chief Executive Officer and a director of Cenovus’s Board as of November 6, 2017.

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

(8) As an officer and a non-independent director, Mr. Pourbaix is not a member of any of the committees of Cenovus’s Board.

Cenovus Energy Inc. 25   2017 Annual Information Form

EXECUTIVE OFFICERS

The following individuals served as executive officers of Cenovus as at December 31, 2017.

Name and Residence	Office Held and Principal Occupation During the Past Five Years
Alexander J. Pourbaix   Calgary, Alberta, Canada	President & Chief Executive Officer Mr. Pourbaix’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. Mr. Ruste will be retiring from Cenovus on April 30, 2018.
Harbir S. Chhina   Calgary, Alberta, Canada	Executive Vice-President & Chief Technology Officer Mr. Chhina became Executive Vice-President & Chief Technology Officer on April 25, 2017. From September 2015 to April 2017, Mr. Chhina was Executive Vice-President, Oil Sands Development; from December 2010 to August 2015, Mr. Chhina was Executive Vice-President, Oil Sands; and from November 2009 to November 2010, Mr. Chhina was Executive Vice-President, Enhanced Oil Development & New Resource Plays of Cenovus.
Keith Chiasson   Calgary, Alberta, Canada	Senior Vice-President, Downstream Mr. Chiasson became Senior Vice-President, Downstream on December 14, 2017. From May 15, 2017 to December 13, 2017, Mr. Chiasson was Vice-President, Oil Sands Production Operations; and from July 2016 to May 2017, Mr. Chiasson was Vice-President, Operations of Cenovus. From April 2016 to July 2016, Mr. Chiasson was Kearl Operations Manager at Imperial Oil Resources. From September 2013 to April 2016, Mr. Chiasson was U.S. Operations Manager for ExxonMobil. From January 2012 to September 2013, Mr. Chiasson was Planning and Business Analysis Manager for ExxonMobil Production Company.
Kieron McFadyen   Calgary, Alberta, Canada	(Former) Executive Vice-President & President, Upstream Oil & Gas Mr. McFadyen resigned from Cenovus as of January 15, 2018. Mr. McFadyen became Executive Vice-President & President, Upstream Oil & Gas of Cenovus on April 6, 2016. From January 2012 to April 2016, Mr. McFadyen was Group Vice-President, Non Operated Joint Ventures of Royal Dutch Shell plc, a multinational oil and gas company (“Royal Dutch Shell”), and from November 2006 to January 2012, he was Group and Executive Vice President (HSSE-SP) of Royal Dutch Shell.
Alan C. Reid   Calgary, Alberta, Canada	Executive Vice-President, Stakeholder Engagement, Safety & Legal and General Counsel Mr. Reid became Executive Vice-President, Stakeholder Engagement, Safety & Legal and General Counsel on December 14, 2017. From December 1, 2015 to December 13, 2017, Mr. Reid was Executive Vice-President, Environment, Corporate Affairs & Legal and General Counsel; from September 2015 to November 2015, Mr. Reid was Executive Vice-President, Environment, Corporate Affairs & Legal; from January 2014 to August 2015, Mr. Reid was Senior Vice-President, Christina Lake & Narrows Lake; from January 2012 to January 2014, Mr. Reid was Cenovus’s Senior Vice-President, Christina Lake; and from November 2009 to January 2012, Mr. Reid was Vice-President, Regulatory, Health & Safety of Cenovus.
Sarah J. Walters   Calgary, Alberta, Canada	Senior Vice-President, Corporate Services Ms. Walters became Senior Vice-President, Corporate Services on December 14, 2017. From January 1, 2017 until December 13, 2017, Ms. Walters was Vice-President, Human Resources; from September 2015 to December 2016, Ms. Walters was Vice-President, Organization & People; from March 2014 to August 2015, Ms. Walters was Vice-President HR Business Partners & Organizational Design; from July 2013 to February 2014, Ms. Walters was Vice-President, HR Business Partners; and from March 2013 to July 2013, Ms. Walters was Vice-President, HR Advisory of Cenovus. Prior to joining Cenovus in March 2013, Ms. Walters was Vice-President HR, International Operations West at Talisman Energy Inc.

Cenovus Energy Inc. 26   2017 Annual Information Form

Name and Residence

Office Held and Principal Occupation During the Past Five Years

J. Drew Zieglgansberger   Calgary, Alberta, Canada

Executive Vice-President, Upstream Mr. Zieglgansberger became Executive Vice-President, Upstream on January 16, 2018. From April 3, 2017 to January 15, 2018, Mr. Zieglgansberger was Executive Vice-President, Deep Basin; from September 2015 to April 2017, Mr. Zieglgansberger was Executive Vice-President, Oil Sands Manufacturing; from June 2015 to August 2015, Mr. Zieglgansberger was Executive Vice-President, Operations Shared Services; from June 2012 to May 2015, Mr. Zieglgansberger was Senior Vice-President, Operations Shared Services; from January 2012 to May 2012, Mr. Zieglgansberger was Senior Vice-President, Regulatory, Local Community & Military; and from December 2010 to January 2012, Mr. Zieglgansberger was Senior Vice-President, Christina Lake of Cenovus.

As of December 31, 2017, all of Cenovus’s directors and executive officers, as a group, beneficially owned or exercised control or direction over, directly or indirectly, 1,839,253 common shares of Cenovus (“Common Shares”) or approximately 0.15 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 (each, an “Order”) and that was issued while that director or executive officer 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 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 penalties 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.

Mr. Mongeau was, prior to August 10, 2009, a director of Nortel Networks Corporation and Nortel Networks Limited, each of which initiated creditor protection proceedings under the Companies’ Creditors Arrangement Act (Canada) on January 14, 2009. Certain U.S. subsidiaries filed voluntary petitions in the United States under Chapter 11 of the U.S. Bankruptcy Code, and certain Europe, Middle East and Africa subsidiaries made consequential filings in Europe and the Middle East.

Cenovus Energy Inc. 27   2017 Annual Information Form

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. 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.

Steven F. Leer

Mr. Leer holds a Bachelor of Electrical Engineering (University of the Pacific) and a Masters in Business Administration (Olin School of Business, Washington University). He was awarded an honorary doctorate by the University of the Pacific in May 1993. Mr. Leer is lead director of Norfolk Southern Corporation, a publicly traded North American rail transportation provider. He is the non-executive Chairman of the Board 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 lead director of USG from January 2012 to November 2016 and as a director of USG from June 2005 to January 2012, during which time he was a member and Chair of USG’s Governance Committee and a member of its Compensation and Organization Committee. 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 until April 2014. 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. Mr. Leer served as the Chairman of the Center for Energy and Economic Development, the National Coal Council, the National Mining Association and was on the board of the Mineral Information Institute. Mr. Leer is a former 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. He serves on the boards of the Center for Energy and Economic Development, the National Coal Council and the National Mining Association. In addition, he is a delegate to the Coal Industry Advisory Board of the International Energy Agency in Paris.

Claude Mongeau

Mr. Mongeau holds a Masters of Business Administration from McGill University and has received honorary doctorate degrees from St. Mary’s and Windsor University. He is a director of The Toronto-Dominion Bank and TELUS Corporation. Mr. Mongeau served as a director of Canadian National Railway Company (“CN”), a publicly traded railroad and transportation company, from October 2009 to

July 2016 and as President and Chief Executive Officer from January 2010 to June 2016. During his tenure with CN, he served as Executive Vice-President and Chief Financial Officer from October 2000 until December 2009 and from the time he joined CN in 1994 he held the titles of Vice-President, Strategic and Financial Planning and Assistant Vice-President, Corporate Development. Prior to joining CN, Mr. Mongeau was the Manager, Business Development for Imasco Inc. from 1993 to 1994, a partner with Groupe Secor Inc., a Montreal-based management consulting firm providing strategic advice to large Canadian corporations, from 1989 to 1993 and a consultant at Bain & Company from 1988 to 1989. Mr. Mongeau also served as a director of SNC Lavalin Group Inc. from August 2003 to May 2015 and as a director of Nortel Networks Corporation and Nortel Networks Limited from June 2006 to August 2009.

Mr. Mongeau was Chairman of the Board of the Railway Association of Canada. He was named one of Canada’s Top 40 under 40 in 1997 and selected as Canada’s CFO of the Year in 2005 by an independent committee of prominent Canadian business leaders.

Colin Taylor

(Audit Committee 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 as Chief Executive & Managing Partner of Deloitte LLP, Chartered Professional Accountants, and then acted as Senior Counsel until his retirement in May 2008. He also served as Advisory Partner to a number of public and private company clients of Deloitte & Touche LLP and has held a number of international management and governance responsibilities throughout his professional career.

Wayne G. Thomson

Mr. Thomson holds a Bachelor of Science of Mechanical Engineering (University of Manitoba) and is a professional engineer. He is a director of TVI Pacific Inc., a publicly traded international mining company; Chairman of Maha Energy Inc., a public Swedish oil and gas company; Chairman of Inventys Thermal Technologies Inc. (“Inventys”). He also serves as Chairman and President of Enviro Valve Inc., a private company manufacturing proprietary pressure relief valves, since 2005. Mr. Thomson served as interim Executive Chairman of Inventys from May 2016 to February 2017 and as

Cenovus Energy Inc. 28   2017 Annual Information Form

Chief Executive Officer of Iskander Energy Corp (“Iskander”) from November 2011 to August 2014 and as director of Iskander from November 2011 to March 2016.

The above list does not include Patrick D. Daniel who is, by standing invitation as Chair of the Board, 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, the Corporation’s auditor. 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 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, 2017 and 2016:

($ thousands)	2017	2016
Audit Fees(1)	2,852	2,863
Audit-Related Fees(2)	987	111
Tax Fees(3)	1	1
All Other Fees(4)	20	10
Total	3,860	2,985

(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. $70,000 previously reported as Tax Fees in 2016 has been reclassified as Audit Fees.

(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 prospectuses, systems development, controls testing and participation fees levied by the Canadian Public Accountability Board. Fees related to the acquisition of assets from ConocoPhillips or divestiture of Cenovus’s Conventional assets are also included in Audit-Related Fees.

(3) Tax Fees consist of the aggregate fees billed for audit related fees, tax compliance, tax advice and tax planning. $70,000 previously reported as Tax Fees in 2016 has been reclassified as Audit Fees.

(4) In 2016, All Other Fees are related to a readiness assessment to satisfy Extractive Sector Transparency Measures Act (“ESTMA”) reporting requirements. In 2017, All Other Fees relate to ESTMA Specified Procedures.

Cenovus Energy Inc. 29   2017 Annual Information Form

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, “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, 2017, there were approximately 1,228.8 million Common Shares and no Preferred Shares outstanding.

COMMON SHARES

The holders of Common Shares are entitled to: (i) receive dividends if, as and when declared by Cenovus’s Board; (ii) 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) 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. 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.

SHAREHOLDER RIGHTS PLAN

Cenovus has a shareholder rights plan (the “Shareholder Rights Plan”) which was adopted in 2009, and 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 acquiror, 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. Shareholders will be asked to reconfirm the plan at the 2018 annual meeting of shareholders.

DIVIDEND REINVESTMENT PLAN

Cenovus has a dividend reinvestment plan 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 volume weighted average price of the Common Shares (denominated in the currency in which the Common Shares trade on the applicable stock exchange) traded on the Toronto Stock Exchange (“TSX”) during the last five trading days preceding the relevant dividend payment date or purchased on the market.

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.

Cenovus Energy Inc. 30   2017 Annual Information Form

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, its access to sources of liquidity and capital, and potentially obligate it to post incremental collateral in the form of cash, letters of credit or other financial instruments. See the section entitled “Risk Management and Risk Factors” in the Corporation’s annual 2017 MD&A, which section of the MD&A is incorporated by reference into this AIF, for further information.

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

	S&P Global Ratings (“S&P”)		Moody’s Investors Service (“Moody’s”)		DBRS Limited (“DBRS”)		Fitch Ratings Inc. (“Fitch”)
Senior Unsecured Long-Term Rating Outlook/Trend		BBB Negative		Ba2 Stable		BBB Negative		BBB- Stable

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 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 “+” or “-” designation after a rating indicates the relative standing within the major rating categories. An 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 “Negative” outlook indicates that a rating may be lowered.

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 Ba2 by Moody’s is within the fifth highest of nine categories and is assigned to debt securities which are considered speculative-grade and subject to substantial credit risk. 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. A designation of Stable indicates a low likelihood of a rating change over the medium term.

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 by DBRS is within the fourth highest of 10 categories and is assigned to debt securities considered to be of adequate credit quality, with acceptable protection of principal and interest. Issuers in this category are fairly susceptible to adverse changes in financial and economic conditions. 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. Rating trends provide guidance in respect of DBRS’s 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 circumstances continue, or in some cases, unless challenges are addressed.

Fitch’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 BBB is within the fourth highest of 9 categories and is assigned to debt securities considered to be of good credit quality. BBB ratings indicate that expectations of credit risk are currently low. The capacity for payment of financial commitments is considered adequate but adverse business or economic conditions are more likely to impair this capacity. The modifiers “+” or “-” may be appended to a rating to denote relative status within major rating categories. A Fitch rating outlook indicates the direction a rating is likely to move over a one to two-year period, with rating outlooks falling into four categories: “Positive”, “Negative”, “Stable” or “Evolving”. Rating outlooks reflect financial or other trends that have not yet reached the level that would trigger a rating action, but which may do so if such trends continue. The majority of Fitch’s outlooks are Stable, which is consistent with the historical migration experience of ratings over a one to two year period. Positive or Negative outlooks do not imply that a rating change is inevitable and similarly, ratings with Stable

Cenovus Energy Inc. 31   2017 Annual Information Form

outlooks can be raised or lowered without prior revision of the outlook, if circumstances warrant such an action. Where the fundamental trend has strong, conflicting elements of both positive and negative, the rating outlook may be described as Evolving.

Throughout the last two years, Cenovus has made payments to each of S&P, Moody’s, DBRS and Fitch related to the rating of the Corporation’s debt. Additionally, Cenovus has purchased products and services from S&P, Moody’s, DBRS and Fitch.

DIVIDENDS

The declaration of dividends is at the sole discretion of Cenovus’s Board and is considered each quarter. The Board has approved a first quarter dividend of $0.05 per share payable on March 29, 2018 to holders of Common Shares of record as of March 15, 2018. Readers should also refer to the section entitled “Risk Management and Risk Factors” in the Corporation’s annual 2017 MD&A, which section of the MD&A is incorporated by reference into this AIF, for additional information.

Cenovus paid the following dividends over the last three years:

Dividends Paid
($ per share)	Year		Q4		Q3		Q2		Q1
2017		0.2000		0.0500		0.0500		0.0500		0.0500
2016		0.2000		0.0500		0.0500		0.0500		0.0500
2015		0.8524		0.1600		0.1600		0.2662		0.2662

MARKET FOR SECURITIES

All of the outstanding Common Shares are listed and posted for trading on the 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 2017:

	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		20.88		17.55		17.76		64,424		15.54		13.49		13.63		36,446
February		18.85		16.75		16.80		74,979		14.46		12.61		12.66		38,948
March		17.81		14.81		15.05		175,654		13.32		11.12		11.30		102,755
April		15.37		13.35		13.61		244,892		11.45		9.79		9.98		93,057
May		13.64		11.94		12.05		135,025		9.97		8.83		8.92		76,769
June		12.38		8.98		9.56		216,550		9.17		6.76		7.37		141,391
July		11.10		8.89		10.49		187,431		8.86		6.90		8.41		108,526
August		10.80		9.09		9.77		116,205		8.50		7.28		7.82		92,819
September		13.22		9.68		12.51		187,361		10.69		7.81		10.02		111,781
October		12.63		11.89		12.52		148,372		10.05		9.21		9.72		77,686
November		14.66		11.65		12.30		170,313		11.52		9.09		9.51		92,507
December		12.92		10.78		11.48		139,567		10.18		8.41		9.13		74,815

RISK FACTORS

A discussion of risk factors can be found in the section entitled “Risk Management and Risk Factors” in the Corporation’s annual 2017 MD&A, which section of the MD&A is incorporated by reference into this AIF.

LEGAL PROCEEDINGS AND REGULATORY ACTIONS

During the year ended December 31, 2017, 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, 2017, there were no penalties or sanctions imposed against Cenovus by a court relating to 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 securities legislation or with a securities regulatory authority.

Cenovus Energy Inc. 32   2017 Annual Information Form

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 within the three most recently completed financial years or any proposed transaction that has materially affected or is reasonably expected to materially affect Cenovus.

MATERIAL CONTRACTS

Other than as set forth below, during the year ended December 31, 2017, 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.

On March 29, 2017, Cenovus entered into a purchase and sale agreement (the “Acquisition Agreement”) with ConocoPhillips to acquire: (i) ConocoPhillips’ 50 percent interest (the “FCCL Interest”) (being the remaining 50 percent interest that Cenovus did not already own) in FCCL Partnership, the owner of the Foster Creek, Christina Lake and Narrows Lake oil sands projects in northeast Alberta (the “FCCL Assets”), and (ii) the majority of ConocoPhillips’ western Canadian conventional assets, including ConocoPhillips’ exploration and production assets and related infrastructure and agreements in the Elmworth-Wapiti, Kaybob-Edson and Clearwater operating areas and other operating areas, and all of ConocoPhillips’ interest in petroleum and natural gas rights and oil sands leases within a certain area of mutual interest northwest of Foster Creek (the “Deep Basin Assets”). The FCCL Interest and the Deep Basin Assets were acquired by Cenovus for total consideration of C$17.6 billion, comprised of C$15.0 billion cash, and 208 million Common Shares. Cenovus agreed to make quarterly payments to ConocoPhillips during the five years subsequent to the closing date of the Acquisition for quarters in which the average WCS crude oil price exceeds $52 per barrel during the quarter. The quarterly payment will be $6 million for each dollar that the WCS price exceeds $52 per barrel. There are no maximum payment terms. The calculation includes an adjustment mechanism related to certain significant production outages at Foster Creek and Christina Lake, which may reduce the amount of a contingent payment.

At closing of the Acquisition, Cenovus and ConocoPhillips entered into a registration rights agreement (“Registration Rights Agreement”) and an investor agreement (“Investor Agreement”), which, among other things, restricted ConocoPhillips from selling or hedging its Common Shares until November 17, 2017. In addition, the Registration Rights Agreement provides ConocoPhillips with certain rights to facilitate the sale of its Common Shares, including the right to require Cenovus to qualify the distribution of the Common Shares held by ConocoPhillips and the right to piggy-back on an offering of Common Shares by Cenovus. The Investor Agreement places certain restrictions on ConocoPhillips, including from nominating new members to Cenovus’s board of directors and by requiring ConocoPhillips to vote its Common Shares in accordance with management recommendations or abstain from voting. The Registration Rights Agreement and the Investor Agreement will terminate when ConocoPhillips owns 3.5 percent or less of the then outstanding Common Shares.

A copy of the Acquisition Agreement, which includes the forms of the Contingent Payment Agreement, Registration Rights Agreement and Investor Agreement, in redacted form, was filed on SEDAR on April 5, 2017, and a copy of the amendment to the Acquisition Agreement was filed on SEDAR on May 17, 2017, each of which may be viewed under Cenovus’s profile at sedar.com.

Particulars for each of the Arrangement Agreement and the Separation Agreement (previously filed material contracts that are still in effect) are described in the section entitled “Risk Management and Risk Factors” in the Corporation’s annual 2017 MD&A, and such section of the MD&A is incorporated by reference into this AIF.

INTERESTS OF EXPERTS

The Corporation’s independent auditors are PricewaterhouseCoopers LLP, Chartered Professional Accountants, who have issued an independent auditor’s report dated February 14, 2018 in respect of Cenovus’s Consolidated Financial Statements which comprise the Consolidated Balance Sheets as at December 31, 2017 and December 31, 2016 and the Consolidated Statements of Earnings, Comprehensive Income, Shareholders’ Equity and Cash Flows for the years ended December 31, 2017, 2016, and 2015 and Cenovus’s internal control over financial reporting as at December 31, 2017. 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 and McDaniel as independent qualified reserves evaluators. The principals of each of GLJ and McDaniel, in each case, as a group own beneficially, directly or indirectly, less than one percent of any class of the Corporation’s securities.

Cenovus Energy Inc. 33   2017 Annual Information Form

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

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, 2017. Additional information, 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 information 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 annual Consolidated Financial Statements and MD&A for the year ended December 31, 2017, 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, 2017 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.

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.

Cenovus Energy Inc. 34   2017 Annual Information Form

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, 2017. The reserves data are estimates of proved reserves and probable reserves and related future net revenue as at December 31, 2017, 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”) 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 shows the net present value of 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, 2017, 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 of       Reserves		Evaluated Net Present       Value of Future Net       Revenue       (before income taxes,       10% discount rate)       $ millions
McDaniel & Associates Consultants Ltd.	December 31, 2017		Canada	$46,542
GLJ Petroleum Consultants Ltd.	December 31, 2017		Canada	$4,200
				$50,742

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	/s/ Keith M. Braaten
P.A. Welch, P. Eng.	Keith M. Braaten, P. Eng
McDaniel & Associates Consultants Ltd.	GLJ Petroleum Consultants Ltd.
Calgary, Alberta, Canada	Calgary, Alberta, Canada
February 13, 2018

Cenovus Energy Inc. A1   2017 Annual Information Form

APPENDIX B

REPORT OF MANAGEMENT AND DIRECTORS

ON RESERVES DATA AND OTHER INFORMATION

Management 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 of 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;

(c) reviewed the reserves data with management and the independent qualified reserves evaluators; and

(d) 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/ Alexander J. Pourbaix	/s/ Ivor M. Ruste
Alexander J. Pourbaix	Ivor M. Ruste
President & Chief Executive Officer	Executive Vice-President &
	Chief Financial Officer
/s/ Patrick D. Daniel	/s/ Wayne G. Thomson
Patrick D. Daniel	Wayne G. Thomson
Director and Chair of the Board	Director and Chair of the Reserves Committee
February 14, 2018

Cenovus Energy Inc. B1   2017 Annual Information Form

APPENDIX C

AUDIT COMMITTEE MANDATE

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.

CONSTITUTION, COMPOSITION AND DEFINITIONS

1.              Reporting

The Committee shall report to the Board.

2.              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

Cenovus Energy Inc. C1   2017 Annual Information Form

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.

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.

3. 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.

4. Vacancies

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

5. 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.

6. 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.

7. 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 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.

Cenovus Energy Inc. C2   2017 Annual Information Form

8. 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.

9. 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.

10. Attendance at Meetings

The Chief Executive Officer, the 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.

11. 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.

RESPONSIBILITIES

In carrying out its mandate, the Committee is expected to:

12. Review Procedures

(a) 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.

(b) 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.

13. Annual Financial Statements

(a) 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:

(i) The annual financial statements and related notes including significant issues regarding accounting principles, practices and significant management estimates and judgments,

Cenovus Energy Inc. C3   2017 Annual Information Form

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.

(ii) Management’s Discussion and Analysis.

(iii) The use of off-balance sheet financing including management’s risk assessment and adequacy of disclosure.

(iv) The external auditors’ audit examination of the financial statements and their report thereon.

(v) Any significant changes required in the external auditors’ audit plan.

(vi) 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.

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

(b) Review and formally recommend approval to the Board of the Corporation’s:

(i) 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.

(ii) Management’s Discussion and Analysis.

(iii) Annual Information Form as to financial information.

(iv) 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.

14. Quarterly Financial Statements

(a) 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:

(i) Quarterly unaudited financial statements and related documents, including Management’s Discussion and Analysis.

(ii) Any significant changes to the Corporation’s accounting principles.

(b) Review quarterly unaudited financial statements prior to their distribution of any subsidiary of the Corporation with public securities.

15. Other Financial Filings and Public Documents

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 press 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.

16. Internal Control Environment

(a) 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.

Cenovus Energy Inc. C4   2017 Annual Information Form

(b) 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.

(c) 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.

(d) Review with the Chief Executive Officer, the 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.

(e) Review significant findings prepared by the external auditors and the internal auditing department together with management’s responses.

17. Risk Oversight

Review and evaluate the Corporation’s risk management framework and related processes including the supporting guidelines and practice documents.

18. Other Review Items

(a) 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.

(b) Review all related party transactions between the Corporation and any executive officers or directors, including affiliations of any executive officers or directors.

(c) 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.

(d) 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.

(e) 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.

(f) Ensure that the Corporation’s presentation of hydrocarbon reserves has been reviewed with the Reserves Committee of the Board.

(g) Review management’s processes in place to prevent and detect fraud.

(h) Review:

(i) 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

(ii) a summary of any significant investigations regarding such matters.

(i) Meet on a periodic basis separately with management.

Cenovus Energy Inc. C5   2017 Annual Information Form

19. External Auditors

(a) 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.

(b) 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.

(c) Review and discuss a report from the external auditors at least quarterly regarding:

(i) All critical accounting policies and practices to be used;

(ii) 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

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

(d) Obtain and review a report from the external auditors at least annually regarding:

(i) The external auditors’ internal quality-control procedures.

(ii) 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.

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

(e) 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.

(f) Review and evaluate annually:

(i) 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.

(ii) The terms of engagement of the external auditors together with their proposed fees.

(iii) External audit plans and results.

(iv) Any other related audit engagement matters.

(v) 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.

(vi) Review the Annual Report of the Canadian Public Accountability Board (“CPAB”) concerning audit quality in Canada and discuss implications for Cenovus.

(vii) Review any reports issued by CPAB regarding the audit of Cenovus.

Cenovus Energy Inc. C6   2017 Annual Information Form

(g) 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.

(h) Upon reviewing and discussing the information provided to the Committee in accordance with paragraphs 19.(c) through (f), 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.

(i) 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.

(j) Set clear hiring policies for the Corporation’s hiring of employees or former employees of the external auditors.

(k) Consider with management and the external auditors the rationale for employing audit firms other than the principal external auditors.

(l) Consider and review with the external auditors, management and the head of internal audit:

(i) Significant findings during the year and management’s responses and follow-up thereto.

(ii) 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.

(iii) Any significant disagreements between the external auditors or internal auditors and management.

(iv) Any changes required in the planned scope of their audit plan.

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

(vi) The internal audit department mandate.

(vii) Internal audit’s compliance with the Institute of Internal Auditors’ standards.

20. Internal Audit Group and Independence

(a) Meet on a periodic basis separately with the head of internal audit.

(b) Review and concur in the appointment, compensation, replacement, reassignment, or dismissal of the head of internal audit.

(c) Confirm and assure, annually, the independence of the internal audit group and the external auditors.

21. Approval of Audit and Non-Audit Services

(a) 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).

(b) 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.

(c) If the pre-approvals contemplated in paragraphs 21.(a) and (b) 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.

(d) 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

Cenovus Energy Inc. C7   2017 Annual Information Form

described in paragraphs 21.(a) through (c). The decision of any such subcommittee to grant pre-approval shall be presented to the full Committee at the next scheduled Committee meeting.

(e) Establish policies and procedures for the pre-approvals described in paragraphs 21.(a) and (b) 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.

22. Other Matters

(a) Review and concur in the appointment, replacement, reassignment, or dismissal of the Chief Financial Officer.

(b) Upon a majority vote of the Committee outside resources may be engaged where and if deemed advisable.

(c) Report Committee actions to the Board of Directors with such recommendations as the Committee may deem appropriate.

(d) 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.

(e) 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.

(f) 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.

(g) Review and reassess the adequacy of this Mandate annually and recommend any proposed changes to the Board for approval.

(h) 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.

(i) Perform such other functions as required by law, the Corporation’s by-laws or the Board of Directors.

(j) Consider any other matters referred to it by the Board of Directors.

Revised Effective: February 10, 2015

Cenovus Energy Inc. C8   2017 Annual Information Form

APPENDIX D

NETBACK RECONCILIATIONS

Netback is a non-GAAP measure commonly used in the oil and gas industry to assist in measuring operating performance on a per-unit basis. Netback is defined as gross sales less royalties, transportation and blending, operating expenses and production and mineral taxes divided by sales volumes. Netbacks do not reflect non-cash write-downs of product inventory until the inventory is sold. Netbacks reflect Cenovus’s margin on a per-barrel basis of unblended bitumen and crude oil. As such, the bitumen and crude oil sales price, transportation and blending costs, and sales volumes exclude the impact of purchased condensate. Condensate is blended with the bitumen and heavy oil to reduce its thickness in order to transport it to market. Our Netback calculation is aligned with the definition found in the Canadian Oil and Gas Evaluation Handbook.

The following tables provide a reconciliation of the financial components comprising Netbacks (in millions of dollars) to the nearest GAAP measure found in the annual and interim consolidated financial statements.

Year Ended December 31, 2017

($ millions)

	Per Consolidated Financial Statements
	Oil Sands(1)		Deep Basin(1)		Conventional(2)		Total Upstream
Revenues
Gross Sales		7,362		555		1,309		9,226
Less: Royalties		230		41		174		445
		7,132		514		1,135		8,781
Expenses
Transportation and Blending		3,704		56		167		3,927
Operating		934		250		426		1,610
Production and Mineral Taxes		-		1		18		19
Netback		2,494		207		524		3,225
(Gain) Loss on Risk Management		307		-		33		340
Operating Margin		2,187		207		491		2,885

	Basis of Netback Calculation										Adjustments							Per Above Table
	Bitumen		Heavy Crude Oil		Light and Medium Crude Oil		NGLs		Gas		Condensate		Inventory(3)		Other			Total  Upstream
Gross Sales		4,290		383		590		221		542		3,145		-		55			9,226
Royalties		230		51		119		22		23		-		-		-			445
Transportation and Blending		653		35		29		16		47		3,145		-		2			3,927
Operating		868		117		169		48		327		-		-		81			1,610
Production and Mineral Taxes		-		-		17		-		2		-		-		-			19
Netback		2,539		180		256		135		143		-		-		(28	)		3,225
(Gain) Loss on Risk Management																			340
Operating Margin																			2,885

(1) Found in Note 1 of the Consolidated Financial Statements.

(2) Found in Note 11 of the Consolidated Financial Statements.

(3) Netbacks do not reflect non-cash write-downs of product inventory until the inventory is sold.

Cenovus Energy Inc. D1   2017 Annual Information Form

Three months ended December 31, 2017

($ millions)

	Per Consolidated Financial Statements
	Oil Sands(1)		Deep Basin(1)		Conventional(2)		Total Upstream
Revenues
Gross Sales		2,424		231		218		2,873
Less: Royalties		113		20		29		162
		2,311		211		189		2,711
Expenses
Transportation and Blending		1,193		24		18		1,235
Operating		271		94		83		448
Production and Mineral Taxes		-		1		4		5
Netback		847		92		84		1,023
(Gain) Loss on Risk Management		235		-		14		249
Operating Margin		612		92		70		774

	Basis of Netback Calculation										Adjustments							Per Above Table
	Bitumen		Heavy Crude Oil		Light and Medium Crude Oil		NGLs		Gas		Condensate		Inventory(3)		Other			Total       Upstream
Gross Sales		1,430		40		144		99		141		998		-		21			2,873
Royalties		113		2		29		10		7		-		-		1			162
Transportation and Blending		202		3		7		7		18		998		1		(1	)		1,235
Operating		260		14		39		17		101		-		-		17			448
Production and Mineral Taxes		-		-		4		-		1		-		-		-			5
Netback		855		21		65		65		14		-		(1)		4			1,023
(Gain) Loss on Risk Management																			249
Operating Margin																			774

(1) Found in Note 1 of the Interim Consolidated Financial Statements.

(2) Found in Note 9 of the Interim Consolidated Financial Statements.

(3) Netbacks do not reflect non-cash write-downs of product inventory until the inventory is sold.

Three months ended September 30, 2017

($ millions)

	Per Consolidated Financial Statements
	Oil Sands(1)		Deep Basin(1)		Conventional(2)		Total Upstream
Revenues
Gross Sales		2,210		200		331		2,741
Less: Royalties		54		13		45		112
		2,156		187		286		2,629
Expenses
Transportation and Blending		1,066		22		44		1,132
Operating(4)		259		101		118		478
Production and Mineral Taxes		-		-		4		4
Netback		831		64		120		1,015
(Gain) Loss on Risk Management		9		-		3		12
Operating Margin		822		64		117		1,003

	Basis of Netback Calculation										Adjustments							Per Above Table
	Bitumen		Heavy Crude Oil		Light and Medium       Crude Oil		NGLs		Gas		Condensate		Inventory(3)		Other			Total       Upstream
Gross Sales		1,340		111		162		79		144		885		-		20			2,741
Royalties		54		17		30		8		5		-		-		(2	)		112
Transportation and Blending		205		13		7		7		16		885		(1)		-			1,132
Operating		254		35		50		22		108		-		-		9			478
Production and Mineral Taxes		-		-		4		-		-		-		-		-			4
Netback		827		46		71		42		15		-		1		13			1,015
(Gain) Loss on Risk Management																			12
Operating Margin																			1,003

(1) Found in Note 1 of the Interim Consolidated Financial Statements.

(2) Found in Note 8 of the Interim Consolidated Financial Statements.

(3) Netbacks do not reflect non-cash write-downs of product inventory until the inventory is sold.

(4) As a result of measurement period adjustments related to the Acquisition, operating costs for the Oil Sands segment was increased by $2 million in the third quarter of 2017.

Cenovus Energy Inc. D2   2017 Annual Information Form

Three months ended June 30, 2017

($ millions)

	Per Consolidated Financial Statements
	Oil Sands(1)		Deep Basin(1)		Conventional(2)		Total Upstream
Revenues
Gross Sales		1,666		124		386		2,176
Less: Royalties		36		8		50		94
		1,630		116		336		2,082
Expenses
Transportation and Blending		879		10		54		943
Operating(4)		264		55		115		434
Production and Mineral Taxes		-		-		5		5
Netback		487		51		162		700
(Gain) Loss on Risk Management		(14)		-		3		(11	)
Operating Margin		501		51		159		711

	Basis of Netback Calculation										Adjustments							Per Above Table
	Bitumen		Heavy Crude Oil		Light and Medium Crude Oil		NGLs		Gas		Condensate		Inventory(3)		Other			Total Upstream
Gross Sales		943		119		156		38		160		751		-		9			2,176
Royalties		36		16		31		3		7		-		-		1			94
Transportation and Blending		158		11		9		2		9		751		-		3			943
Operating		218		37		42		9		74		-		-		54			434
Production and Mineral Taxes		-		-		5		-		-		-		-		-			5
Netback		531		55		69		24		70		-		-		(49	)		700
(Gain) Loss on Risk Management																			(11	)
Operating Margin																			711

(1) Found in Note 1 of the Interim Consolidated Financial Statements.

(2) Found in Note 8 of the Interim Consolidated Financial Statements.

(3) Netbacks do not reflect non-cash write-downs of product inventory until the inventory is sold.

(4) As a result of measurement period adjustments related to the Acquisition, operating costs for the Oil Sands and Deep Basin segments were increased by $43 million and $4 million respectively, in the second quarter of 2017.

Three months ended March 31, 2017

($ millions)

	Per Consolidated Financial Statements
	Oil Sands(1)		Deep  Basin		Conventional(1)		Total Upstream
Revenues
Gross Sales		1,062		-		374		1,436
Less: Royalties		27		-		50		77
		1,035		-		324		1,359
Expenses
Transportation and Blending		566		-		51		617
Operating		140		-		110		250
Production and Mineral Taxes		-		-		5		5
Netback		329		-		158		487
(Gain) Loss on Risk Management		77		-		13		90
Operating Margin		252		-		145		397

	Basis of Netback Calculation										Adjustments						Per Above Table
	Bitumen		Heavy Crude Oil		Light and Medium Crude Oil		NGLs		Gas		Condensate		Inventory(2)		Other		Total   Upstream
Gross Sales		577		113		128		5		97		511		-		5		1,436
Royalties		27		16		29		1		4		-		-		-		77
Transportation and Blending		88		8		6		-		4		511		-		-		617
Operating		136		31		38		-		44		-		-		1		250
Production and Mineral Taxes		-		-		4		-		1		-		-		-		5
Netback		326		58		51		4		44		-		-		4		487
(Gain) Loss on Risk Management																		90
Operating Margin																		397

(1) Found in Note 1 of the Interim Consolidated Financial Statements.

(2) Netbacks do not reflect non-cash write-downs of product inventory until the inventory is sold.

Cenovus Energy Inc. D3   2017 Annual Information Form

The following table provides the sales volumes used to calculate Netback.

Sales Volumes

(barrels per day, unless otherwise stated)	2017	Q4	Q3	Q2	Q1
Bitumen
Foster Creek	121,806	143,586	157,850	106,115	78,562
Christina Lake	161,514	193,734	206,338	154,431	89,919
Total Bitumen	283,320	337,320	364,188	260,546	168,481
Crude Oil (Heavy, Light and Medium) and NGLs
Heavy Oil	21,669	7,485	25,047	28,089	26,222
Light and Medium Oil	28,493	24,957	33,988	29,894	25,074
NGLs	18,001	28,018	27,571	14,967	1,047
Total Bitumen, Crude Oil (Heavy, Light and Medium) and NGLs Sales	351,483	397,780	450,794	333,496	220,824
Natural Gas Sales (MMcf per day)	659	795	851	620	363
Total Sales (BOE per day)	461,268	530,230	592,591	436,761	281,324

Cenovus Energy Inc. D4   2017 Annual Information Form

EX-99.2

Exhibit 99.2

MANAGEMENT’S DISCUSSION AND ANALYSIS

FOR THE YEAR ENDED DECEMBER 31, 2017

OVERVIEW OF CENOVUS	2
2017 HIGHLIGHTS	4
OPERATING RESULTS	5
COMMODITY PRICES UNDERLYING OUR FINANCIAL RESULTS	7
FINANCIAL RESULTS	9
REPORTABLE SEGMENTS	14
OIL SANDS	15
DEEP BASIN	19
REFINING AND MARKETING	22
CORPORATE AND ELIMINATIONS	23
DISCONTINUED OPERATIONS	26
QUARTERLY RESULTS	29
OIL AND GAS RESERVES	32
LIQUIDITY AND CAPITAL RESOURCES	33
RISK MANAGEMENT AND RISK FACTORS	37
CRITICAL ACCOUNTING JUDGMENTS, ESTIMATION UNCERTAINTIES AND ACCOUNTING POLICIES	53
CONTROL ENVIRONMENT	56
CORPORATE RESPONSIBILITY	57
OUTLOOK	57
ADVISORY	60
ABBREVIATIONS	62
NETBACK RECONCILIATIONS	62

This Management’s Discussion and Analysis (“MD&A”) for Cenovus Energy Inc. (which includes references to “we”, “our”, “us”, “its”, the “Company”, or “Cenovus”, mean Cenovus Energy Inc., the subsidiaries of, and partnership interests held by, Cenovus Energy Inc. and its subsidiaries) dated February 14, 2018, should be read in conjunction with December 31, 2017 audited Consolidated Financial Statements and accompanying notes (“Consolidated Financial Statements”). All of the information and statements contained in this MD&A are made as of February 14, 2018, unless otherwise indicated. This MD&A contains forward-looking information about our current expectations, estimates, projections and assumptions. The information in this MD&A, as it relates to our operations for 2017, reflects the closing of the Acquisition (as defined in this MD&A) on May 17, 2017. See the Advisory for information on the risk factors that could cause actual results to differ materially and the assumptions underlying our forward-looking information. Cenovus management (“Management”) prepared the MD&A. The Audit Committee of the Cenovus Board of Directors (the “Board”) reviewed and recommended the MD&A for approval by the Board, which occurred on February 14, 2018. Additional information about Cenovus, including our quarterly and annual reports, the Annual Information Form (“AIF”) and Form 40-F, is available on SEDAR at sedar.com, on EDGAR at sec.gov, and on our website at cenovus.com. Information on or connected to our website, even if referred to in this MD&A, does not constitute part of this MD&A.

Basis of Presentation

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

Non-GAAP Measures and Additional Subtotals

Certain financial measures in this document do not have a standardized meaning as prescribed by IFRS, such as Netbacks, Adjusted Funds Flow, Operating Earnings, Free Funds Flow, Debt, Net Debt, Capitalization and Adjusted Earnings Before Interest, Taxes, Depreciation and Amortization (“Adjusted EBITDA”) and therefore are considered non-GAAP measures. In addition, Operating Margin is considered an additional subtotal found in Notes 1 and 11 of our Consolidated Financial Statements. These measures may not be comparable to similar measures presented by other issuers. These measures have been described and presented in order to provide shareholders and potential investors with additional measures for analyzing our ability to generate funds to finance our operations and information regarding our liquidity. This additional information should not be considered in isolation or as a substitute for measures prepared in accordance with IFRS.

The definition and reconciliation, if applicable, of each non-GAAP measure or additional subtotal is presented in the Operating Results, Financial Results, Liquidity and Capital Resources, or Advisory sections of this MD&A.

Cenovus Energy Inc. 1 2017 Management’s Discussion and Analysis

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, 2017, we had an enterprise value of approximately $24 billion. We are in the business of developing, producing and marketing crude oil, natural gas liquids (“NGLs”) and natural gas in Western Canada. We also conduct marketing activities and have refining operations in the United States (“U.S.”). Our average crude oil and NGLs (collectively, “liquids”) production in 2017 was 360,704 barrels per day, our average natural gas production was 659 MMcf per day, and our total production was 470,490 BOE per day. The refining operations processed an average of 442,000 gross barrels per day of crude oil feedstock into an average of 470,000 gross barrels per day of refined products.

Year in Review

2017 was a year of significant change for Cenovus, where we gained full ownership of our oil sands assets, acquired an additional core operating area in the Deep Basin and divested the majority of our legacy Conventional assets. On May 17, 2017, we acquired from ConocoPhillips Company and certain of its subsidiaries (collectively, “ConocoPhillips”) their 50 percent interest in the FCCL Partnership (“FCCL”), and the majority of ConocoPhillips’ western Canadian conventional assets in the Deep Basin in Alberta and British Columbia for total consideration of $17.9 billion (“the Acquisition”).

The Acquisition effectively doubled our oil sands production and proved bitumen reserves. In addition, we acquired more than three million net acres of land, exploration and production assets, and related infrastructure in Alberta and British Columbia (collectively, the “Deep Basin Assets”). The Deep Basin Assets are expected to provide short-cycle development opportunities with high-return potential that complement our long-cycle oil sands investments.

The purchase consideration included US$10.6 billion in cash, before adjustments, and 208 million Cenovus common shares. The cash portion of the consideration was funded through a combination of cash on hand, a draw on our existing committed credit facility, an offering of senior unsecured notes (US$2.9 billion), a committed asset-sale bridge credit facility ($3.6 billion) (“Bridge Facility”), and a bought-deal common share offering ($3.0 billion).

In the second half of 2017, we sold the majority of our legacy Conventional crude oil and natural gas assets for aggregate gross cash proceeds of approximately $3.2 billion. The net proceeds and cash on hand were used to fully repay and retire the Bridge Facility. The sale of Suffield, our remaining legacy Conventional segment asset, closed on January 5, 2018 for gross proceeds of $512 million. In aggregate, gross proceeds for all legacy Conventional crude oil and natural gas assets divested was $3.7 billion, before closing adjustments, and resulted in a before-tax gain on discontinuance of approximately $1.6 billion, of which $1.3 billion was recorded in 2017.

In December 2017, we also commenced marketing for sale certain non-core assets located in the East and West Clearwater areas of the Deep Basin, representing approximately 15,000 BOE per day of production, to further streamline our portfolio and deleverage our balance sheet.

Over the course of 2017, Cenovus has transitioned its asset base and strategy to support focused development in the oil sands and Deep Basin, providing opportunities for disciplined growth and long-term cash flow generation. At the same time, investor concern about the Acquisition, volatile commodity prices and a number of other factors contributed to a more than 40 percent decline in our share price. Over the last few months, Cenovus has made considerable progress in reducing debt and is taking steps to right-size the Company for the current environment. Effective November 6, 2017, Alex Pourbaix was appointed Cenovus’s President and Chief Executive Officer, and he subsequently announced changes to the senior leadership team in December 2017.

Cenovus’s 2018 budget was announced in December, with total capital expenditures expected to be between $1.5 billion and $1.7 billion. This budget reflects Cenovus’s focus on capital discipline, cost reductions and deleveraging.

Our Strategy

Our strategy is to increase cash flows through disciplined production growth from our industry leading portfolio of oil sands and Deep Basin natural gas and liquids assets in Western Canada. We are focused on increasing our current share price and maximizing shareholder value through cost leadership and realizing the best margins for our products to help us maintain financial resilience and deliver sustainable dividend growth. We plan to achieve our strategy by drawing on the expertise of our people and leveraging our strategic differentiators: premium asset quality, executional excellence, value-added integration, focused innovation and trusted reputation.

Our Key Strategic Differentiators

Premium Asset Quality

Cenovus has a deep portfolio of premium-quality oil sands, natural gas and NGLs assets that we believe provide us with significant cost and environmental performance advantages. Our in-situ oil sands projects and Deep Basin Assets in Western Canada offer long and short-cycle opportunities that provide the capital investment flexibility to position us to deliver value growth at various points of the price cycle. In addition to our exploration and production assets, we have complementary interests in refineries and product transportation infrastructure.

Cenovus Energy Inc. 2 2017 Management’s Discussion and Analysis

Executional Excellence

Our team is committed to delivering on our business plan in a safe, disciplined and responsible manner and continuously improving our performance to help manage risk and optimize returns. We use a manufacturing approach to support consistent performance and enhance reliability. This involves applying standardized and repeatable designs and processes to the construction and operation of our facilities to reduce costs and improve efficiencies at all project stages. We strive to execute our work in an agile manner with a focus on using our resources effectively.

Value-Added Integration

Our integrated business approach helps provide stability to our cash flows and maximize value for the oil and natural gas we produce. Having ownership in oil refineries positions us to capture the full value chain from production to high-quality end products like transportation fuels. In addition, our pipeline commitments, crude-by-rail loading facility and product marketing activities assist us to obtain global pricing for our oil. As a consumer of natural gas at our oil sands facilities and refineries, our natural gas production acts as an economic hedge to help manage price volatility. In addition, our cogeneration plants efficiently provide power for our oil sands facilities with the added value of excess electricity being sold to the Alberta electricity grid.

Focused Innovation

We focus our innovation efforts on accelerating the adoption of technology solutions and methods of operating to enhance safety, reduce costs, improve margins and lower emissions. We expect innovation at Cenovus to mean significant improvements and game-changing developments that are implemented to generate value. We aim to complement our internal technology development efforts with external collaboration that will leverage our technology spend.

Trusted Reputation

We are a responsible, progressive company that is committed to providing a safe and healthy workplace, building strong external relationships, minimizing our environmental footprint and being a part of a lower carbon future. Our actions are intended to support our trusted reputation and enable us to attract and retain top-quality staff and to engage with and be respected by our stakeholders: investors, the communities in which we operate, environmental groups, governments, Aboriginal people, media, project partners and the general public.

We measure our performance through a scorecard that reflects our financial, operational, safety, environmental and organizational health goals.

Our Operations

Oil Sands

Our oil sands assets include steam-assisted gravity drainage (“SAGD”) oil sands projects in northern Alberta, including Foster Creek, Christina Lake, Narrows Lake and other emerging projects. Foster Creek and Christina Lake are producing, while Narrows Lake is in the initial stages of development. These three projects are located in the Athabasca region of northeastern Alberta, and our project at Telephone Lake is located within the Borealis region of northeastern Alberta. The Oil Sands segment also includes the Athabasca natural gas property, from which a portion of the natural gas production is used as fuel at the adjacent Foster Creek operations.

	2017
($ millions)	Crude Oil		Natural Gas
Operating Margin		2,231		1
Capital Investment		969		4
Operating Margin Net of Related Capital Investment		1,262		(3	)

Deep Basin

Our Deep Basin Assets include approximately three million net acres of land rich in natural gas, condensate and other NGLs, and light and medium oil. The assets are located primarily in the Elmworth-Wapiti, Kaybob-Edson, and Clearwater operating areas of British Columbia and Alberta, and include interests in numerous natural gas processing facilities. The Deep Basin Assets are expected to provide short-cycle development opportunities with high return potential that complement our long-term oil sands development and provide an economic hedge for the natural gas required as a fuel source at both our oil sands and refining operations.

($ millions)	May 17 – December 31, 2017
Operating Margin		207
Capital Investment		225
Operating Margin Net of Related Capital Investment		(18	)

Cenovus Energy Inc. 3 2017 Management’s Discussion and Analysis

Conventional

All references to our legacy Conventional segment are accounted for as a discontinued operation.

In late 2017, we sold the majority of our legacy Conventional crude oil and natural gas assets for gross cash proceeds totaling approximately $3.2 billion, resulting in a net before-tax gain on discontinuance of approximately $1.3 billion. The sale of our remaining Conventional segment asset, Suffield, closed on January 5, 2018 for gross proceeds of $512 million and resulted in a before-tax gain on sale of approximately $350 million.

The Conventional segment produced crude oil, NGLs and natural gas in Alberta and Saskatchewan, including the heavy oil assets at Pelican Lake, the carbon dioxide (“CO₂”) enhanced oil recovery project at Weyburn and tight oil opportunities in the Palliser block in southern Alberta.

	2017
($ millions)	Liquids		Natural Gas
Operating Margin		360		124
Capital Investment		195		11
Operating Margin Net of Related Capital Investment		165		113

Refining and Marketing

Our operations include two refineries located in Illinois and Texas that are jointly owned with (50 percent interest) and operated by Phillips 66, an unrelated U.S. public company. The gross crude oil capacity at the Wood River and Borger refineries (the “Refineries”) is approximately 314,000 barrels per day and 146,000 barrels per day, respectively. This includes processing capability of up to 255,000 gross barrels per day of blended heavy crude oil. The refining operations allow us to capture the value from crude oil production through to refined products, such as diesel, gasoline and jet fuel, to partially mitigate volatility associated with regional North American light/heavy crude oil price differential fluctuations.

This segment also includes our crude-by-rail terminal operations, located in Bruderheim, Alberta, and the marketing of third-party purchases and sales of product undertaken to provide operational flexibility for transportation commitments, product quality, delivery points and customer diversification.

($ millions)	2017
Operating Margin	598
Capital Investment	180
Operating Margin Net of Related Capital Investment	418

2017 HIGHLIGHTS

In 2017, we completed the Acquisition which gave us full ownership of our oil sands operations and provided an additional core operating area with the Deep Basin Assets.

Including the Suffield divestiture which closed on January 5, 2018, all of our legacy Conventional oil and gas assets have been sold for combined gross cash proceeds of $3.7 billion. Gross proceeds received prior to December 31, 2017 of $3.2 billion, combined with cash on hand, were used to fully repay and retire the $3.6 billion Bridge Facility that was drawn to help fund the Acquisition.

Crude oil prices continued to be volatile throughout the year. West Texas Intermediate (“WTI”) benchmark crude price ranged from a high of US$60.42 per barrel to a low of US$42.53 per barrel and averaged 18 percent higher compared with 2016. Western Canadian Select (“WCS”), a blended heavy oil benchmark, ranged from a high of US$44.79 per barrel to a low of US$29.56 per barrel, while averaging 32 percent higher in 2017 compared to 2016. In addition, natural gas prices were very volatile, ranging from a high of $3.75 per Mcf to a low of $1.07 per Mcf; however, still averaging 16 percent higher than 2016.

In 2017, we:

● Produced 470,490 BOE per day, a 73 percent increase from 2016;

● Earned an average companywide Netback from continuing operations of $20.89 per BOE, before realized hedging, an increase of 78 percent from 2016;

● Generated upstream operating margin, excluding the Conventional segment, of $2,394 million compared with $877 million in 2016 primarily due to the Acquisition, a rise in sales volumes and higher liquids sales prices;

● Achieved cash from operating activities and Adjusted Funds Flow of $3,059 million and $2,914 million, respectively, increasing significantly from 2016;

● Recorded a $275 million tax recovery as a result of the U.S. federal corporate income tax rate change announced in 2017;

● Recorded Net Earnings from continuing operations of $2,268 million (2016 – Net Loss from continuing operations of $459 million);

● Invested $1,661 million in capital which allowed us to generate Free Funds Flow of $1,253 million, a threefold increase from $397 million in 2016;

Cenovus Energy Inc. 4 2017 Management’s Discussion and Analysis

· Divested of the majority of our legacy Conventional crude oil and natural gas assets, recognizing a before-tax gain of $1.3 billion in discontinued operations;

· Announced the appointment of Alex Pourbaix as President and Chief Executive Officer in November, and announced changes to the senior leadership team in December;

· Re-evaluated our oil sands Exploration & Evaluation (“E&E”) projects in line with our current business plans. As a result, we wrote off $887 million in the fourth quarter as exploration expense; and

· Announced our 2018 budget in December, focusing on capital discipline, cost reductions and deleveraging.

OPERATING RESULTS

Our upstream assets continued to perform well in 2017. Total production increased primarily due to the Acquisition, slightly offset by the disposition of legacy Conventional assets late in the year.

Production Volumes

	2017	Percent Change	2016	Percent Change	2015
Continuing Operations
Liquids (barrels per day)
Oil Sands
Foster Creek	124,752	78%	70,244	7%	65,345
Christina Lake	167,727	111%	79,449	6%	74,975
	292,479	95%	149,693	7%	140,320
Deep Basin
Light and Medium Oil	3,922	-%	-	-%	-
NGLs	16,928	-%	-	-%	-
	20,850	-%	-	-%	-
Liquids Production (barrels per day)	313,329	109%	149,693	7%	140,320
Natural Gas (MMcf per day)
Oil Sands	10	(41)%	17	(11)%	19
Deep Basin	316	-%	-	-%	-
	326	1,818%	17	(11)%	19
Conventional Production (BOE per day)	-	-%	-	-%	4,163
Production From Continuing Operations (BOE per day)	367,635	141%	152,527	3%	147,701
Discontinued Operations (Conventional)
Liquids (barrels per day)
Heavy Oil	21,478	(26)%	29,185	(15)%	34,256
Light and Medium Oil	24,824	(4)%	25,915	(10)%	28,675
NGLs	1,073	1%	1,065	(7)%	1,149
	47,375	(16)%	56,165	(12)%	64,080
Natural Gas (MMcf per day)	333	(12)%	377	(8)%	412
Production From Discontinued Operations (BOE per day)	102,855	(14)%	118,998	(10)%	132,746
Total Production (BOE per day)	470,490	73%	271,525	(3)%	280,447

In 2017, Oil Sands production increased primarily as a result of the Acquisition. Incremental production at Foster Creek and Christina Lake from May 17, 2017, the closing date of the Acquisition, until December 31, 2017 was 76,748 barrels per day and 102,945 barrels per day, respectively. Foster Creek also had incremental production volumes related to the phase G expansion, partially offset by reduced volumes as a result of temporary treating issues and a 20-day planned plant turnaround. The phase F expansion at Christina Lake contributed incremental production volumes.

Total production in the Deep Basin averaged 117,138 BOE per day for the period of May 17, 2017 to December 31, 2017. Incremental volumes due to the drilling and completion of horizontal production wells in the second half of the year was partially offset by downtime associated with third party pipeline and facility outages.

Prior to the dispositions, our Conventional liquids production was lower than in 2016 primarily due to expected natural declines partially offset by new production from our tight oil drilling program in the first half of 2017 before growth capital was reduced as a result of the decision to divest the Palliser asset. Our Conventional natural gas production decreased in 2017, relative to the same period in 2016 due to expected natural declines.

Cenovus Energy Inc. 5 2017 Management’s Discussion and Analysis

Oil and Gas Reserves

Based on our reserves report prepared by independent qualified reserves evaluators (“IQREs”), our proved bitumen reserves increased 103 percent to approximately 4.75 billion barrels and our proved plus probable bitumen reserves increased 92 percent to approximately 6.38 billion barrels. Our Deep Basin proved reserves were 410 MMBOE and our proved plus probable reserves were 660 MMBOE.

Additional information about our reserves is included in the Oil and Gas Reserves section of this MD&A.

Netbacks From Continuing Operations

Netback is a non-GAAP measure commonly used in the oil and gas industry to assist in measuring operating performance on a per-unit basis, and is defined in the Canadian Oil and Gas Evaluation Handbook. Netbacks reflect our margin on a per-barrel of oil equivalent basis. Netback is defined as gross sales less royalties, transportation and blending, operating expenses and production and mineral taxes divided by sales volumes. Netbacks do not reflect the non-cash write-downs of product inventory until the product is sold. The sales price, transportation and blending costs, and sales volumes exclude the impact of purchased condensate. Condensate is blended with the heavy oil to reduce its thickness in order to transport it to market. Our Netback calculation is aligned with the definition found in the Canadian Oil and Gas Evaluation Handbook. For a reconciliation of our Netbacks see the Advisory section of this MD&A.

($/BOE)	2017			2016		2015
Sales Price		36.86			27.37		30.81
Royalties		2.07			0.17		0.56
Transportation and Blending		5.43			6.51		6.34
Operating Expenses		8.46			8.94		9.94
Production and Mineral Taxes		0.01			-		0.03
Netback Excluding Realized Risk Management (1)		20.89			11.75		13.94
Realized Risk Management Gain (Loss)		(2.35	)		3.22		7.60
Netback Including Realized Risk Management (1)		18.54			14.97		21.54

(1) Excludes results from our Conventional segment, which has been classified as a discontinued operation.

Our average Netback improved primarily due to higher liquids sales prices, partially offset by increased royalties and the strengthening of the Canadian dollar relative to the U.S. dollar. The strengthening of the Canadian dollar compared with 2016 had a negative impact on our sales price of approximately $0.78 per BOE.

Refining and Marketing

Crude oil runs and refined product output in 2017 remained consistent compared with 2016. The planned and unplanned maintenance at both Refineries in 2017 had a similar impact on crude oil runs and refined product output as the planned and unplanned maintenance in 2016.

	2017		Percent    Change		2016		Percent    Change		2015
Crude Oil Runs (1) (Mbbls/d)		442		-%		444		6%		419
Heavy Crude Oil (1)		202		(13)%		233		17%		200
Refined Product (1) (Mbbls/d)		470		-%		471		6%		444
Crude Utilization (1) (percent)		96		(1)%		97		6%		91

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

In 2017, Operating Margin from our Refining and Marketing segment increased 73 percent compared with 2016 due to higher average market crack spreads and increased margins on the sale of our secondary products due to higher realized pricing. These increases were partially offset by narrowing heavy crude oil differentials, which increase crude input costs to the refinery, and the strengthening of the Canadian dollar relative to the U.S. dollar.

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

Cenovus Energy Inc. 6 2017 Management’s Discussion and Analysis

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⁾

(US$/bbl, unless otherwise indicated)	Q4  2017			Q4   2016			2017			Percent   Change		2016			2015
Crude Oil Prices
Brent
Average		61.54			51.13			54.82			22%		45.04			53.64
End of Period		66.87			56.82			66.87			18%		56.82			37.28
WTI
Average		55.40			49.29			50.95			18%		43.32			48.80
End of Period		60.42			53.72			60.42			12%		53.72			37.04
Average Differential Brent-WTI		6.14			1.84			3.87			125%		1.72			4.84
WCS
Average		43.14			34.97			38.97			32%		29.48			35.28
Average (C$/bbl)		54.84			46.63			50.56			29%		39.05			45.12
End of Period		34.93			38.81			34.93			(10)%		38.81			24.98
Average Differential WTI-WCS		12.26			14.32			11.98			(13)%		13.84			13.52
Condensate (C5 @ Edmonton)
Average (2)		57.97			48.33			51.57			21%		42.47			47.36
Average Differential WTI-Condensate (Premium)/Discount		(2.57	)		0.96			(0.62	)		(173)%		0.85			1.44
Average Differential WCS-Condensate (Premium)/Discount		(14.83	)		(13.36	)		(12.60	)		(3)%		(12.99	)		(12.08	)
Mixed Sweet Blend (“MSW” @ Edmonton)
Average (3)		54.26			46.18			48.49			21%		40.11			45.32
End of Period		53.03			51.26			53.03			3%		51.26			34.98
Average Refined Product Prices
Chicago Regular Unleaded Gasoline (“RUL”)		74.36			59.46			66.95			19%		56.24			67.68
Chicago Ultra-low Sulphur Diesel (“ULSD”)		80.58			61.50			69.09			23%		56.33			68.12
Refining Margin: Average 3-2-1 Crack Spreads (4)
Chicago		21.09			10.96			16.77			28%		13.07			19.11
Average Natural Gas Prices
AECO (C$/Mcf) (5)		1.96			2.81			2.43			16%		2.09			2.77
NYMEX (US$/Mcf)		2.93			2.98			3.11			26%		2.46			2.66
Basis Differential NYMEX-AECO (US$/Mcf)		1.40			0.86			1.26			42%		0.89			0.49
Foreign Exchange Rate (US$ per C$1)
Average		0.787			0.750			0.771			2%		0.755			0.782

(1) These benchmark prices are not our realized sales prices. For our average realized sales prices and realized risk management results, refer to the Netbacks tables in the Operating Results, Reportable Segments and Discontinued Operations sections of this MD&A.

(2) The average Canadian dollar condensate benchmark price for 2017 was $66.89 per barrel (2016 – $56.25 per barrel; 2015 – $60.56 per barrel); fourth quarter average condensate benchmark price was $73.66 per barrel (2016 – $64.44 per barrel).

(3) The average Canadian dollar MSW benchmark price for 2017 was $62.89 per barrel (2016 – $53.13 per barrel; 2015 – $57.95 per barrel); fourth quarter average Canadian dollar MSW benchmark price was $68.95 per barrel (2016 – $61.57 per barrel).

(4) The average 3-2-1 Crack Spread is an indicator of the refining margin and is valued on a last in, first out accounting basis.

(5) Alberta Energy Company (“AECO”) natural gas.

Crude Oil Benchmarks

The average Brent, WTI and WCS benchmark prices improved in 2017. Compliance with the production cuts outlined in the fourth quarter of 2016 by the Organization of Petroleum Exporting Countries (“OPEC”) led to widespread market expectations of an accelerated return to normal inventory levels. However, without supporting supply and demand drivers, prices continued to be volatile in 2017 as growing supply from the U.S., unstable supply from Libya and Nigeria, severe weather related incidents, and strong global demand resulted in varying expectations on the pace of crude oil and refined product inventory draws.

WTI is an important benchmark for Canadian crude oil since it reflects inland North American crude oil prices and its Canadian dollar equivalent is the basis for determining royalties for a number of our crude oil properties. In 2017, WTI benchmark prices weakened relative to Brent compared with 2016 due to growing U.S. crude oil supply and refinery disruptions from hurricanes in the U.S. Gulf Coast resulting in increased crude oil inventories.

WCS is blended heavy oil which consists of both conventional heavy oil and unconventional diluted bitumen. The average WTI-WCS differential narrowed in 2017 compared with 2016. WCS strengthened relative to WTI due to a temporary decrease in supply of blended heavy oil in Alberta and OPEC’s compliance with production cuts reducing global heavy oil supply.

Cenovus Energy Inc. 7 2017 Management’s Discussion and Analysis

Blending condensate with bitumen and heavy oil enables our production to be transported through pipelines. Our blending ratios in 2017 ranged from approximately 10 percent to 33 percent. The WCS-Condensate differential is an important benchmark as a narrower differential generally results in an increase in the recovery of condensate costs when selling a barrel of blended crude oil. When the supply of condensate in Alberta does not meet the demand, Edmonton condensate prices may be driven by U.S. Gulf Coast condensate prices plus the cost to transport the condensate to Edmonton.

The average WTI-Condensate differential changed by US$1.47 per barrel, with condensate being sold at a premium to WTI in 2017 as compared with being sold at a discount in 2016. This change in benchmark pricing resulted from incremental demand for diluent due to a rise in Alberta heavy oil production, and minimal spare capacity on pipelines which increased the cost of transporting condensate to Edmonton.

MSW is an Alberta based light sweet crude oil benchmark that is representative of Canadian conventional production, comparable to the crude oil produced by our Deep Basin Assets. The average MSW benchmark price improved in 2017 compared with 2016, consistent with the general increase in average crude oil benchmark prices.

Refining Benchmarks

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

Average Chicago refined product prices increased in 2017 primarily due to strong refined product demand and severe weather related events that impacted the refined product supply output of U.S. Gulf Coast refineries. Average Chicago 3-2-1 crack spreads rose in 2017 compared with 2016 due to the wider Brent-WTI differential reflecting product prices trending with global crude oil prices, significant regional refinery maintenance causing product shortages and strong refined product demand. Our realized crack spreads are affected by many other factors such as the variety of crude oil feedstock, refinery configuration and product output, the time lag between the purchase and delivery of crude oil feedstock, and the cost of feedstock which is valued on a first in, first out (“FIFO”) accounting basis.

Natural Gas Benchmarks

Average AECO and NYMEX natural gas prices rose compared with 2016. Natural gas prices strengthened as North American inventory levels declined due to lower production and stronger demand. Production decreased as a result of reduced drilling programs while demand increased from additional capacity to export North American natural gas to foreign markets. In addition, natural gas prices in 2016 were negatively impacted by an exceptionally warm winter that resulted in poor heating demand and record-high seasonal North American natural gas storage levels.

Cenovus Energy Inc. 8 2017 Management’s Discussion and Analysis

Foreign Exchange Benchmark

Our revenues are subject to foreign exchange exposure as the sales prices of our crude oil, natural gas and refined products are determined by reference to U.S. benchmark prices. An increase in the value of the Canadian dollar compared with the U.S. dollar has a negative impact on our reported results. Likewise, as the Canadian dollar weakens, our reported results are higher. In addition to our revenues being denominated in U.S. dollars, our long-term debt is also U.S. dollar denominated. In periods of a strengthening Canadian dollar, our U.S. dollar debt gives rise to unrealized foreign exchange gains when translated to Canadian dollars.

In 2017, the Canadian dollar strengthened relative to the U.S. dollar, which had a negative impact of approximately $360 million on our revenues, excluding our Conventional segment. The Canadian dollar as at December 31, 2017 compared with December 31, 2016 was stronger relative to the U.S. dollar, resulting in $665 million of unrealized foreign exchange gains on the translation of our U.S. dollar debt.

FINANCIAL RESULTS

Selected Consolidated Financial Results

The Acquisition and improvements in commodity prices, as referred to above, were the primary drivers of our financial results in 2017. The following key performance measures are discussed in more detail within this MD&A.

($ millions, except per share amounts)	2017		Percent   Change		2016		Percent             Change		2015
Revenues		17,043		55%		11,006		(5)%		11,529
Operating Margin (1)
From Continuing Operations		2,992		145%		1,223		(18)%		1,499
Total Operating Margin		3,483		97%		1,767		(28)%		2,439
Cash From Operating Activities
From Continuing Operations		2,611		513%		426		(39)%		696
Total Cash From Operating Activities		3,059		255%		861		(42)%		1,474
Adjusted Funds Flow (2)
From Continuing Operations		2,447		154%		965		8%		896
Total Adjusted Funds Flow		2,914		105%		1,423		(16)%		1,691
Operating Earnings (Loss) (2)
From Continuing Operations		(34)		88%		(291)		(172)%		(107)
Per Share – Diluted ($)		(0.03)		91%		(0.35)		(169)%		(0.13)
Total Operating Earnings (Loss)		126		(133)%		(377)		6%		(403)
Per Share – Diluted ($)		0.11		(124)%		(0.45)		8%		(0.49)
Net Earnings (Loss)
From Continuing Operations		2,268		(594)%		(459)		(150)%		914
Per Share – Basic and Diluted ($)		2.06		(475)%		(0.55)		(149)%		1.12
Total Net Earnings (Loss)		3,366		(718)%		(545)		(188)%		618
Per Share – Basic and Diluted ($)		3.05		(569)%		(0.65)		(187)%		0.75
Total Assets		40,933		62%		25,258		(2)%		25,791
Total Long-Term Financial Liabilities (3)		9,717		52%		6,373		(2)%		6,552
Capital Investment (4)
From Continuing Operations		1,455		70%		855		(42)%		1,470
Total Capital Investment		1,661		62%		1,026		(40)%		1,714
Dividends (5)
Cash Dividends		225		36%		166		(69)%		528
Per Share ($)		0.20		-%		0.20		(77)%		0.8524

(1) Additional subtotal found in Notes 1 and 11 of the Consolidated Financial Statements and defined in this MD&A.

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

(3) Includes Long-Term Debt, Risk Management, Contingent Payment Liabilities and other financial liabilities included within Other Liabilities on the Consolidated Balance Sheets.

(4) Includes expenditures on Property, Plant and Equipment (“PP&E”), E&E assets, and assets held for sale.

(5) Dividends issued in shares from treasury for 2017 were $nil (2016 – $nil; 2015 – $182 million).

Cenovus Energy Inc. 9 2017 Management’s Discussion and Analysis

Revenues

($ millions)	2017  vs. 2016	2016   vs. 2015
Revenues, Comparative Year	11,006	11,529
Increase (Decrease) due to:
Oil Sands	4,212	(81)
Deep Basin	514	-
Refining and Marketing	1,413	(366)
Corporate and Eliminations	(102)	(76)
Revenues, End of Year	17,043	11,006

Upstream revenues from continuing operations increased significantly in 2017 compared with 2016. The rise was primarily related to the Acquisition, incremental sales volumes from our oil sands expansion phases, and higher commodity prices. These increases were partially offset by the strengthening of the Canadian dollar relative to the U.S. dollar and higher royalties.

In 2017, Refining and Marketing revenues increased 17 percent compared with 2016. Refining revenues increased primarily due to higher refined product pricing, consistent with the rise in average Chicago refined product benchmark prices, partially offset by the strengthening of the Canadian dollar relative to the U.S. dollar. Revenues from third-party crude oil and natural gas sales undertaken by our marketing group increased slightly in 2017 compared with 2016 due to higher crude oil prices and natural gas volumes sold, partially offset by a decline in crude oil volumes and natural gas prices.

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

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

Operating Margin

Operating Margin is an additional subtotal found in Notes 1 and 11 of the Consolidated Financial Statements and is used to provide a consistent measure of the cash generating performance of our assets for comparability of our underlying financial performance between periods. Operating Margin is defined as revenues less purchased product, transportation and blending, operating expenses, production and mineral taxes plus realized gains less realized losses on risk management activities. Items within the Corporate and Eliminations segment are excluded from the calculation of Operating Margin.

($ millions)	2017		2016			2015 (1)
Revenues		17,498		11,359			11,866
(Add) Deduct:
Purchased Product		8,476		7,325			7,709
Transportation and Blending		3,760		1,721			1,816
Operating Expenses		1,956		1,243			1,288
Production and Mineral Taxes		1		-			1
Realized (Gain) Loss on Risk Management Activities		313		(153	)		(447	)
Operating Margin From Continuing Operations		2,992		1,223			1,499
Conventional (Discontinued Operations)		491		544			940
Total Operating Margin		3,483		1,767			2,439

⁽¹⁾  2015 Operating Margin From Continuing Operations includes $55 million related to certain legacy Conventional royalty interest assets which were sold in 2015 and has been included in the Corporate and Eliminations Segment.

Operating Margin from continuing operations increased significantly in 2017 compared with 2016 primarily due to: •     Increased sales volumes; •     Higher average liquids sales prices; and •     A higher Operating Margin from Refining and Marketing.

Cenovus Energy Inc. 10 2017 Management’s Discussion and Analysis

These increases in Operating Margin from continuing operations were partially offset by:

· A rise in transportation and blending expenses primarily due to higher condensate prices along with an increase in condensate volumes required for blending our increased oil sands production;

· An increase in upstream operating expenses primarily due to the Acquisition and higher fuel costs related to the increase in natural gas consumption;

· Realized risk management losses of $307 million, compared with gains of $179 million in 2016; and

· Higher royalties primarily due to an increase in the WTI benchmark price (which determines the royalty rate), a rise in our liquids sales price and additional sales volumes.

Operating Margin From Continuing Operations Variance

(1) Other includes the value of condensate sold as heavy oil blend recorded in revenues and condensate costs recorded in transportation and blending expense. The crude oil price excludes the impact of condensate purchases.

Additional details explaining the changes in Operating Margin from continuing operations can be found in the Reportable Segments section of this MD&A.

Cash From Operating Activities and Adjusted Funds Flow

Adjusted Funds Flow is a non-GAAP measure commonly used in the oil and gas industry to assist in measuring a company’s ability to finance its capital programs and meet its financial obligations. Adjusted Funds Flow is defined as cash from operating activities excluding net change in other assets and liabilities and net change in non-cash working capital. Non-cash working capital is composed of current assets and current liabilities, excluding cash and cash equivalents, risk management, the contingent payment, assets held for sale and liabilities related to assets held for sale. Net change in other assets and liabilities is composed of site restoration costs and pension funding.

Total Cash From Operating Activities and Adjusted Funds Flow

($ millions)	2017			2016			2015
Cash From Operating Activities (1)		3,059			861			1,474
(Add) Deduct:
Net Change in Other Assets and Liabilities		(107	)		(91	)		(107	)
Net Change in Non-Cash Working Capital		252			(471	)		(110	)
Adjusted Funds Flow (1)		2,914			1,423			1,691

(1) Includes results from our Conventional segment, which has been classified as a discontinued operation.

Cash From Operating Activities and Adjusted Funds Flow increased compared with 2016 due to a higher Operating Margin, as discussed above, and a realized risk management gain on foreign exchange contracts due to hedging activity undertaken to support the Acquisition. These increases were partially offset by a rise in finance costs primarily associated with additional debt incurred to finance the Acquisition and an increase in realized foreign exchange losses on working capital items.

The change in non-cash working capital in 2017 was primarily due to a decrease in accounts receivable and inventory, partially offset by higher income tax receivable and a decrease in accounts payable. For 2016, the change in non-cash working capital was primarily due to an increase in accounts receivable and a rise in inventory, partially offset by an increase in accounts payable.

Cenovus Energy Inc. 11 2017 Management’s Discussion and Analysis

Operating Earnings (Loss)

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

($ millions)	2017			2016			2015
Earnings (Loss) From Continuing Operations, Before Income Tax		2,216			(802	)		890
Add (Deduct):
Unrealized Risk Management (Gain) Loss (1)		729			554			195
Non-Operating Unrealized Foreign Exchange (Gain) Loss (2)		(651	)		(196	)		1,064
Revaluation (Gain)		(2,555	)		-			-
(Gain) Loss on Divestiture of Assets		1			6			(2,392	)
Operating Earnings (Loss) From Continuing Operations, Before Income Tax		(260	)		(438	)		(243	)
Income Tax Expense (Recovery)		(226	)		(147	)		(136	)
Operating Earnings (Loss) From Continuing Operations		(34	)		(291	)		(107	)
Operating Earnings (Loss) From Discontinued Operations		160			(86	)		(296	)
Total Operating Earnings (Loss)		126			(377	)		(403	)

(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 from continuing operations increased in 2017 compared with 2016 primarily due to higher cash from operating activities and Adjusted Funds Flow, as discussed above, greater unrealized foreign exchange gains on operating items compared with losses in 2016, and the re-measurement of the contingent payment, partially offset by an increase in depreciation, depletion and amortization (“DD&A”) and exploration expense due to asset writedowns.

Net Earnings (Loss)

($ millions)	2017       vs. 2016			2016      vs. 2015
Net Earnings (Loss) From Continuing Operations, Comparative Year		(459	)		914
Increase (Decrease) due to:
Operating Margin From Continuing Operations		1,769			(276	)
Corporate and Eliminations:
Unrealized Risk Management Gain (Loss)		(175	)		(359	)
Unrealized Foreign Exchange Gain (Loss)		668			1,286
Revaluation Gain		2,555			-
Re-measurement of Contingent Payment		138			-
Gain (Loss) on Divestiture of Assets		5			(2,398	)
Expenses (1)		(149	)		(72	)
DD&A		(907	)		62
Exploration Expense		(886	)		65
Income Tax Recovery (Expense)		(291	)		319
Net Earnings (Loss) From Continuing Operations		2,268			(459	)

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

Net Earnings from continuing operations in 2017 increased due to:

· The revaluation gain of $2,555 million related to the deemed disposition of our pre-existing interest in FCCL;

· Non-operating unrealized foreign exchange gains of $651 million compared with $196 million in 2016; and

· Higher Operating Earnings, as discussed above.

These increases were partially offset by a deferred income tax expense in 2017. The gain on the revaluation of our pre-existing interest in FCCL resulted in a deferred tax expense, which was partially offset by a recovery due to the reduction of the U.S. federal corporate income tax rate. In 2016, a deferred tax recovery was recorded largely due to risk management losses and the recognition of operating losses.

Net Earnings from discontinued operations in 2017 was $1,098 million, including an after-tax gain of $938 million on the divestiture of the Conventional segment assets. In 2016, discontinued operations generated a net loss of $86 million.

Cenovus Energy Inc. 12 2017 Management’s Discussion and Analysis

Net Capital Investment

($ millions)	2017			2016			2015
Oil Sands		973			604			1,185
Deep Basin		225			-			-
Refining and Marketing		180			220			248
Corporate and Eliminations		77			31			37
Capital Investment – Continuing Operations		1,455			855			1,470
Conventional (Discontinued Operations)		206			171			244
Total Capital Investment		1,661			1,026			1,714
Acquisitions (1)		18,388			11			87
Divestitures (1)		(3,210	)		(8	)		(3,344	)
Net Capital Investment (2)		16,839			1,029			(1,543	)

(1) In connection with the Acquisition that was completed in the second quarter of 2017, Cenovus was deemed to have disposed of its pre-existing interest in FCCL and reacquired it at fair value as required by IFRS 3 “Business Combinations” (“IFRS 3”), which is not reflected in the table above. The carrying value of the pre-existing interest was $9,081 million and the estimated fair value was $11,605 million as at May 17, 2017.

(2) Includes expenditures on PP&E, E&E assets and assets held for sale.

Capital investment in continuing operations in 2017 increased $600 million compared with 2016, reflecting our increased ownership in FCCL through the Acquisition. Oil Sands capital investment focused on sustaining capital related to existing production; Christina Lake expansion phase G; and stratigraphic test wells to determine pad placement for sustaining wells, near-term expansion phases, and progression of certain emerging assets. Deep Basin capital investment related to asset development planning and our horizontal drilling and completion program targeting liquids-rich natural gas within the Deep Basin corridor.

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

Capital Investment Decisions

We have now completed the divestiture of our legacy Conventional assets. However, we continue to focus on deleveraging our balance sheet and are currently marketing for sale certain non-core Deep Basin Assets in order to further streamline our portfolio. In addition to our commitment to continue reducing our debt, we are actively identifying further cost reduction opportunities.

Once our balance sheet leverage is more in line with our target debt metric, our disciplined approach to capital allocation includes prioritizing our uses of cash in the following manner:

· First, to sustaining and maintenance capital for our existing business operations;

· Second, to paying our current dividend as part of providing strong total shareholder return; and

· Third, for growth or discretionary capital.

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

($ millions)	2017		2016		2015
Adjusted Funds Flow (1)		2,914		1,423		1,691
Total Capital Investment (1)		1,661		1,026		1,714
Free Funds Flow (1) (2)		1,253		397		(23	)
Cash Dividends		225		166		528
		1,028		231		(551	)

(1) Includes our Conventional segment, which has been classified as a discontinued operation.

(2) Free Funds Flow is a non-GAAP measure defined as Adjusted Funds Flow less capital investment.

We expect our capital investment and cash dividends for 2018 to be funded from our internally generated cash flows and our cash balance on hand.

Cenovus Energy Inc. 13 2017 Management’s Discussion and Analysis

REPORTABLE SEGMENTS

Our reportable segments are as follows:   Oil Sands, which includes the development and production of bitumen and natural gas in northeast Alberta. Cenovus’s bitumen assets include Foster Creek, Christina Lake and Narrows Lake as well as other projects in the early stages of development. Our interest in certain of our operated oil sands properties, notably Foster Creek, Christina Lake and Narrows Lake increased from 50 percent to 100 percent on May 17, 2017.   Deep Basin, which includes approximately three million net acres of land primarily in the Elmworth-Wapiti, Kaybob-Edson, and Clearwater operating areas, rich in natural gas and natural gas liquids. The assets reside in Alberta and British Columbia and include interests in numerous natural gas processing facilities. The Deep Basin Assets were acquired on May 17, 2017.   Refining and Marketing, which is responsible for transporting, selling and refining crude oil into petroleum and chemical products. Cenovus jointly owns two refineries in the U.S. with the operator Phillips 66, an unrelated U.S. public company. In addition, Cenovus owns and operates a crude-by-rail terminal in Alberta. This segment coordinates Cenovus’s marketing and transportation initiatives to optimize product mix, delivery points, transportation commitments and customer diversification.   Corporate and Eliminations, which primarily includes unrealized gains and losses recorded on derivative financial instruments, gains and losses on divestiture of assets, as well as other Cenovus-wide costs for general and administrative, financing activities and research costs. As financial instruments are settled, the realized gains and losses are recorded in the reportable segment to which the derivative instrument relates. Eliminations relate to sales and operating revenues, and purchased product between segments, recorded at transfer prices based on current market prices, and to unrealized intersegment profits in inventory.

In 2017, Cenovus divested the majority of the crude oil and natural gas assets in the Company’s Conventional segment. As such, the results of operations have been presented as a discontinued operation and all prior periods restated. This segment included the production of conventional crude oil, NGLs and natural gas in Alberta and Saskatchewan, including the heavy oil assets at Pelican Lake, the CO₂ enhanced oil recovery project at Weyburn and emerging tight oil opportunities. As at December 31, 2017, all Conventional assets were sold, except for the Company’s Suffield operations. The sale of the Suffield assets closed on January 5, 2018. Refer to the Discontinued Operations section of this MD&A for more information.

Revenues by Reportable Segment

($ millions)	2017	2016		2015
Oil Sands (1)	7,132		2,920		3,001
Deep Basin (2)	514		-		-
Refining and Marketing	9,852		8,439		8,805
Corporate and Eliminations	(455)		(353)		(277)
	17,043		11,006		11,529

(1) Our 2017 results include 229 days of FCCL operations at 100 percent. See the Oil Sands segment section of this MD&A for more details.

(2) Our 2017 results include 229 days of operations from the Deep Basin Assets. See the Deep Basin segment section of this MD&A for more details.

Cenovus Energy Inc. 14 2017 Management’s Discussion and Analysis

OIL SANDS

In northeastern Alberta, we own 100 percent of the Foster Creek, Christina Lake and Narrows Lake oil sands projects following the completion of the Acquisition. In addition, we have several emerging projects in the early stages of development. The Oil Sands segment includes the Athabasca natural gas property, from which a portion of the natural gas production is used as fuel at the adjacent Foster Creek operations.

Significant developments in our Oil Sands segment in 2017 compared with 2016 include:

· Increasing our crude oil production by 95 percent primarily due to the Acquisition and incremental production volumes from Christina Lake phase F and Foster Creek phase G, both of which started up in the second half of 2016;

· Crude oil netbacks, excluding realized risk management activities, of $24.54 per barrel (2016 – $11.94 per barrel); and

· Generating Operating Margin net of capital investment of $1,214 million, an increase of $941 million.

Oil Sands – Crude Oil

Financial Results

($ millions)	2017		2016		2015
Gross Sales		7,340		2,911		3,000
Less: Royalties		230		9		29
Revenues		7,110		2,902		2,971
Expenses
Transportation and Blending		3,704		1,720		1,814
Operating		868		486		511
(Gain) Loss on Risk Management		307		(179)		(400)
Operating Margin		2,231		875		1,046
Capital Investment		969		601		1,184
Operating Margin Net of Related Capital Investment		1,262		274		(138)

Operating Margin Variance

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

Revenues

Price

In 2017, our average crude oil sales price increased to $41.49 per barrel (2016 – $27.64 per barrel). The rise in our crude oil price was consistent with the increase in the WCS and Christina Dilbit Blend (“CDB”) benchmark prices and the narrowing of the WCS-Condensate differential, partially offset by the strengthening of the Canadian dollar relative to the U.S. dollar. The WCS-CDB differential narrowed to a discount of US$1.67 per barrel (2016 – discount of US$2.05 per barrel).

Our crude oil sales price is influenced by the cost of condensate used in blending. Our blending ratios range between 25 percent and 33 percent. As the cost of condensate increases relative to the price of blended crude oil, our bitumen sales price decreases. Due to high demand for condensate at Edmonton, we also purchase condensate from U.S. markets. As such, our average cost of condensate is generally higher than the Edmonton benchmark price due to transportation between market hubs and transportation to field locations. In addition, up to three months may elapse from when we purchase condensate to when we blend it with our production. In a rising price environment, we expect to see some benefit in our bitumen sales price as we are using condensate purchased at a lower price earlier in the year.

Cenovus Energy Inc. 15 2017 Management’s Discussion and Analysis

Production Volumes

(barrels per day)	2017		Percent   Change		2016		Percent             Change		2015
Foster Creek		124,752		78%		70,244		7%		65,345
Christina Lake		167,727		111%		79,449		6%		74,975
		292,479		95%		149,693		7%		140,320

In 2017, production increased primarily due to incremental volumes at Foster Creek and Christina Lake of 48,080 barrels per day and 64,437 barrels per day, respectively, as a result of the Acquisition. The phase G expansion at Foster Creek and the phase F expansion at Christina Lake also contributed to higher volumes. Production at Foster Creek was reduced as a result of temporary treating issues and a 20-day planned turnaround completed in 2017.

Condensate

The bitumen currently produced by Cenovus must be blended with condensate to reduce its thickness in order to transport it to market through pipelines. Revenues represent the total value of blended crude oil sold and include the value of condensate. Consistent with the narrowing of the WCS-Condensate differential during 2017, the proportion of the cost of condensate recovered increased. The total amount of condensate used increased as a result of higher production volumes.

Royalties

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

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

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

Effective Royalty Rates

(percent)	2017		2016		2015
Foster Creek		11.4		-		1.9
Christina Lake		2.5		1.6		2.8

Royalties increased $221 million in 2017 compared with 2016. Royalties at Foster Creek increased primarily due to a higher WTI benchmark price (which determines the royalty rate). The royalty calculation was based on net profits as compared with a calculation based on gross revenues for 2016, resulting in a significant increase in the royalty rate. In 2016, the low royalty rate was primarily due to low crude oil sales prices, a decline in the WTI benchmark price and a true-up of the 2015 royalty calculation.

Christina Lake royalties increased in 2017 primarily as a result of a rise in the WTI benchmark price (which determines the royalty rate) and higher crude oil sales prices.

Expenses

Transportation and Blending

Transportation and blending costs increased $1,984 million. Blending costs increased due to a rise in condensate volumes required for our increased production as well as higher condensate prices. Our condensate costs were higher than the average Edmonton benchmark price, primarily due to the transportation expense associated with moving the condensate between market hubs and to our oil sands projects.

Transportation costs increased primarily due to incremental sales volumes as a result of the Acquisition and expansion phases. In addition, rail costs rose as a result of moving higher volumes by rail over longer distances to U.S. markets. We transported an average of 9,743 barrels per day of crude oil by rail (2016 – 4,906 barrels per day).

Cenovus Energy Inc. 16 2017 Management’s Discussion and Analysis

Per-unit Transportation Expenses

At both Foster Creek and Christina Lake, per-barrel transportation costs declined primarily due to lower pipeline tariffs from an increase in the proportion of Canadian sales in 2017. Foster Creek per-barrel transportation costs were partially offset by higher rail costs from additional volumes shipped to the U.S. by unit trains.

Operating

Primary drivers of our operating expenses in 2017 were workforce costs, fuel, repairs and maintenance, chemical costs and workovers. While unit operating costs decreased six percent, total operating expenses increased $382 million primarily due to the Acquisition, higher fuel costs due to increased fuel consumption, additional repairs and maintenance, as well as increased chemical and workforce costs associated with the phase F expansion at Christina Lake. In addition, repairs and maintenance costs, as well as fluid, waste handling and trucking costs increased in 2017 due to the 20-day turnaround at Foster Creek.

Per-unit Operating Expenses

($/bbl)	2017		Percent  Change		2016		Percent  Change		2015
Foster Creek
Fuel		2.44		(1)%		2.46		(12)%		2.80
Non-fuel		8.02		(1)%		8.09		(17)%		9.80
Total		10.46		(1)%		10.55		(16)%		12.60
Christina Lake
Fuel		2.06		(1)%		2.08		(5)%		2.20
Non-fuel		4.78		(11)%		5.40		(7)%		5.81
Total		6.84		(9)%		7.48		(7)%		8.01
Total		8.40		(6)%		8.91		(12)%		10.13

At Foster Creek, per-barrel fuel costs decreased slightly due to lower natural gas prices, partially offset by increased consumption. Per-barrel non-fuel operating expenses declined in 2017 primarily due to higher production, partially offset by higher repairs and maintenance, an increase in workover costs due to increased pump changes, higher chemical costs, as well as increased fluid, waste handling and trucking costs due to the 20-day planned turnaround in the second quarter. This represents the largest scale turnaround executed to date and it was completed under budget.

At Christina Lake, fuel costs declined on a per-barrel basis due to lower natural gas prices, partially offset by increased consumption. Per-barrel non-fuel operating expenses decreased primarily due to higher production, partially offset by increased workforce and chemical costs associated with the phase F expansion, as well as higher repairs and maintenance activities.

Netbacks ⁽¹⁾

	Foster Creek						Christina Lake
($/bbl)	2017		2016		2015		2017		2016		2015
Sales Price		43.75		30.32		33.65		39.78		25.30		28.45
Royalties		4.00		(0.01)		0.47		0.87		0.33		0.67
Transportation and Blending		8.73		8.84		8.84		4.52		4.68		4.72
Operating Expenses		10.46		10.55		12.60		6.84		7.48		8.01
Netback Excluding Realized Risk Management		20.56		10.94		11.74		27.55		12.81		15.05
Realized Risk Management Gain (Loss)		(2.95)		3.51		8.60		(2.99)		3.08		7.33
Netback Including Realized Risk Management		17.61		14.45		20.34		24.56		15.89		22.38

(1) Netbacks reflect our margin on a per-barrel basis of unblended crude oil.

Risk Management

Risk management activities in 2017 resulted in realized losses of $307 million (2016 – realized gains of $179 million), consistent with average benchmark prices exceeding our contract prices.

Oil Sands – Natural Gas

Oil Sands includes our natural gas operations in northeastern Alberta. A portion of the natural gas produced from our Athabasca property is used as fuel at Foster Creek. Our natural gas production in 2017, net of internal usage, was 10 MMcf per day (2016 – 17 MMcf per day).

Operating Margin was $1 million in 2017 (2016 – $4 million), decreasing as a result of lower natural gas volumes, partially offset by higher natural gas sales prices.

Cenovus Energy Inc. 17 2017 Management’s Discussion and Analysis

Oil Sands – Capital Investment

($ millions)	2017		2016		2015
Foster Creek		455		263		403
Christina Lake		426		282		647
		881		545		1,050
Narrows Lake		12		7		47
Telephone Lake		34		16		24
Grand Rapids (1)		1		6		38
Other (2)		45		30		26
Capital Investment (3)		973		604		1,185

(1) Grand Rapids asset was included in the Pelican Lake divestiture package; the divestiture closed on September 29, 2017.

(2) Includes new resource plays and Athabasca natural gas.

(3) Includes expenditures on PP&E, E&E assets and assets held for sale.

Existing Projects

Capital investment in 2017 increased by $369 million from 2016, reflecting our 100 percent ownership of FCCL as of May 17, 2017. At Foster Creek, capital investment in 2017 was focused on sustaining capital related to existing production and stratigraphic test wells. In 2016, capital investment included sustaining capital related to existing production and stratigraphic test wells, as well as capital associated with the completion of phase G.

In 2017, Christina Lake capital investment focused on sustaining capital related to existing production, the phase G expansion and stratigraphic test wells. In 2016, capital was focused on sustaining capital related to existing production, the completion of expansion phase F and stratigraphic test wells.

Capital investment at Narrows Lake in 2017 and 2016 primarily related to drilling of stratigraphic test wells to further progress the project, as well as preservation of equipment at site.

Emerging Projects

In 2017, Telephone Lake capital investment concentrated on drilling stratigraphic test wells to further assess the project. In 2016, spending was reduced in response to the low commodity price environment and focused on front-end engineering work for the central processing facility.

Drilling Activity

	Gross Stratigraphic Test Wells					Gross Production Wells (1)
	2017	2016		2015		2017	2016		2015
Foster Creek	96		95		124	41		18		28
Christina Lake	108		104		40	25		35		67
	204		199		164	66		53		95
Narrows Lake	2		1		-	-		-		-
Telephone Lake	13		-		-	-		-		-
Other (2)	1		5		-	-		1		1
	220		205		164	66		54		96

(1) SAGD well pairs are counted as a single producing well.

(2) Includes Grand Rapids which was included in the Pelican Lake divestiture package; the divestiture closed on September 29, 2017.

Stratigraphic test wells were drilled to help identify well pad locations for sustaining wells and near-term expansion phases and to further progress the evaluation of emerging assets.

Future Capital Investment

Foster Creek is currently producing from phases A through G. Capital investment for 2018 is forecast to be between $500 million and $550 million. We plan to continue focusing on sustaining capital related to existing production.

Christina Lake is producing from phases A through F. Capital investment for 2018 is forecast to be between $500 million and $550 million, focused on sustaining capital and construction of the phase G expansion. Field construction of phase G, which has an initial design capacity of 50,000 barrels per day, is progressing well and remains on track. Phase G is expected to start producing in the second half of 2019.

Capital investment at Narrows Lake in 2018 is forecast to be between $5 million and $10 million and will focus primarily on equipment preservation related to the suspension of construction at Narrows Lake.

In 2018, our Technology and other capital, forecast to be between $35 million and $45 million, relates to technology development initiatives and annual environmental and regulatory commitments.

Our 2018 Oil Sands capital investment is forecast to be between $1,040 million and $1,155 million. For more information, we direct our readers to review the news release for our 2018 guidance dated December 13, 2017. The news release is available on SEDAR at sedar.com, on EDGAR at sec.gov, and on our website at cenovus.com.

Cenovus Energy Inc. 18 2017 Management’s Discussion and Analysis

DD&A

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

In 2017, Oil Sands DD&A increased $575 million primarily due to higher sales volumes as a result of the Acquisition. The average depletion rate was approximately $11.50 per barrel compared with $11.30 per barrel in 2016. Our DD&A rate increased primarily due to an increase in the carrying value of our assets as a result of the re-measurement of our pre-existing interest in FCCL and the acquisition of the additional 50 percent interest of FCCL, which was partially offset by proved reserve additions.

Future development costs declined due to cost savings at both Foster Creek and Christina Lake related to a reduction in per well costs and increased well pair spacing. This decline was partially offset by an increase in costs related to the expansion of the development area and inclusion of phase G costs at Christina Lake.

Exploration Expense

For the year ended December 31, 2017, Management has determined that costs incurred to date on certain E&E assets, primarily in the Greater Borealis area, were not recoverable. As a result, $888 million of previously capitalized costs were recorded as exploration expense. In 2016, exploration expense was $2 million.

Management’s decision was based on a comprehensive review of spending to date, decisions to limit spending on these assets in recent years and the current business plan spending on the assets going forward. At this point, Management is not committing further material funding beyond that required to retain ownership of this significant resource. In addition, regulatory changes to the Oil Sands Royalty application process impact the economic viability of these projects. These assets reside primarily in the Borealis cash-generating unit (“CGU”) within the Oil Sands segment.

DEEP BASIN

On May 17, 2017, we acquired the majority of ConocoPhillips’ western Canadian conventional crude oil and natural gas assets including undeveloped land, exploration and production assets, and related infrastructure in Alberta and British Columbia. Our Deep Basin Assets include approximately three million net acres of land primarily in the Elmworth-Wapiti, Kaybob-Edson, and Clearwater operating areas, with an average working interest of 70 percent. In addition, the Deep Basin Assets include interests in numerous natural gas processing plants with an estimated net processing capacity of 1.4 Bcf per day. The Deep Basin Assets are expected to provide short-cycle development opportunities with high return potential that complement our long-term oil sands development. We have now successfully integrated the Deep Basin Assets, maintained business continuity and continue to deliver safe and reliable operations.

Significant developments in our Deep Basin segment in 2017 include:

· Successful integration of the Deep Basin Assets;

· Total capital investment of $225 million related to the drilling of 28 horizontal production wells targeting liquids rich natural gas, the completion of 20 wells, and bringing 14 wells on production;

· Netback of $7.32 per BOE;

· Total production from the date of the Acquisition averaging 117,138 BOE per day, equivalent to 73,492 BOE per day for the year; and

· Generating Operating Margin of $207 million.

Financial Results

($ millions)	May 17 –   December 31,   2017
Gross Sales	555
Less: Royalties	41
Revenues	514
Expenses
Transportation and Blending	56
Operating	250
Production and Mineral Taxes	1
Operating Margin	207
Capital Investment	225
Operating Margin Net of Related Capital Investment	(18)

Cenovus Energy Inc. 19 2017 Management’s Discussion and Analysis

Revenues

Price

	May 17 –   December 31,   2017
NGLs ($/bbl)	33.05
Light and Medium Oil ($/bbl)	60.01
Natural Gas ($/mcf)	2.03
Total Oil Equivalent ($/BOE)	19.52

Our Deep Basin Assets produce a variety of products from natural gas, condensate, other NGLs (including ethane, propane, butane and pentane) and light and medium oil.

In 2017, revenues included $31 million of processing fee revenue related to our interests in natural gas processing facilities. We do not include processing fee revenue in our per-unit pricing metrics or our netbacks.

Production Volumes

	2017
Liquids
NGLs (barrels per day)	16,928
Light and Medium Oil (barrels per day)	3,922
	20,850
Natural Gas (MMcf per day)	316
Total Production (BOE/day)	73,492
Natural Gas Production (percentage of total)	72%
Liquids Production (percentage of total)	28%

Royalties

The Deep Basin Assets are subject to royalty regimes in both Alberta and British Columbia. In Alberta, royalties benefit from a number of different programs that reduce the royalty rate on natural gas production. Natural gas wells in Alberta also benefit from the Gas Cost Allowance (“GCA”), which reduces royalties, to account for capital and operating costs incurred to process and transport the Crown’s portion of natural gas production.

Effective January 1, 2017, the Alberta Government released a new Royalty Regime, Alberta’s Modernized Royalty Framework (“MRF”), which applies to all producing wells after January 1, 2017. Under this new framework, Cenovus will pay a five percent pre-payout royalty on all production until the total revenue from a well equals the drilling and completion cost allowance calculated for each well that meets certain MRF criteria. Subsequently, a higher post-payout royalty rate will apply and will vary based on product-specific market prices. Once a well reaches a maturity threshold, the royalty rate will drop to better match declining production rates. Wells drilled before January 1, 2017 will be managed under the old framework until 2027 and then will convert to the MRF.

In British Columbia, royalties also benefit from programs to reduce the rate on natural gas production. British Columbia applies a GCA, but only on natural gas processed through producer-owned plants. British Columbia also offers a Producer Cost of Service allowance, which reduces the royalty for the processing of the Crown’s portion of natural gas production.

In 2017, our effective royalty rate was 12.1 percent for liquids and 4.4 percent for natural gas.

Expenses

Transportation

Transportation costs capture charges for the movement of crude oil, natural gas and NGLs from the point of production to where the product is sold. In 2017, the majority of Deep Basin products were sold into the Alberta market. Transportation costs averaged $2.08 per BOE in 2017.

Operating

Primary drivers of our operating expenses in 2017 were related to workforce, repairs and maintenance, processing fee expenses, and property tax and lease costs. Since the Acquisition, optimization of maintenance processes has enabled the extension of maintenance intervals, resulting in increased runtimes and lower repairs and maintenance costs. In 2017, Deep Basin operating costs were $8.56 per BOE, in line with our expectations.

Cenovus Energy Inc. 20 2017 Management’s Discussion and Analysis

Netbacks

($/BOE)	May 17 –   December 31,   2017
Sales Price	19.52
Royalties	1.54
Transportation and Blending	2.08
Operating Expenses	8.56
Production and Mineral Taxes	0.02
Netback Excluding Realized Risk Management	7.32
Realized Risk Management Gain (Loss)	-
Netback Including Realized Risk Management	7.32

Deep Basin – Capital Investment

In 2017, capital investment was focused on developing all three operating areas, and included the drilling of 24 net horizontal wells in addition to participating in the drilling of four non-operated net horizontal wells targeting liquids rich natural gas. The Elmworth-Wapiti operating area focused on drilling nine net horizontal production wells within the Falher and Montney plays, with five net completions. The Kaybob-Edson operating area focused on drilling seven net horizontal production wells within the Spirit River play and five net completions. The Clearwater operating area focused on drilling 12 net horizontal production wells within the Spirit River play and 10 net completions.

($ millions)	May 17 –   December 31,   2017
Drilling and Completions	152
Facilities	32
Other	41
Capital Investment (1)	225

(1) Includes expenditures on PP&E, E&E assets and assets held for sale.

Drilling Activity

(net wells, unless otherwise stated)	May 17 –   December 31,   2017
Drilled (1)	28
Completed	20
Tied-in	14

(1) Includes 24 net horizontal wells and four non-operated net horizontal wells.

Future Capital Investment

Our 2018 Deep Basin capital investment is forecast to be between $175 million and $195 million.

We are taking a disciplined development approach in the Deep Basin in 2018. We plan to focus capital investment on a number of drilling, completion and tie-in opportunities that have the potential to generate strong returns and increase throughput at facilities that are currently underutilized. For more information, we direct our readers to review the news release for our 2018 guidance dated December 13, 2017. The news release is available on SEDAR at sedar.com, on EDGAR at sec.gov, and on our website at cenovus.com.

DD&A

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

As at December 31, 2017, it was determined that the carrying amount of the Clearwater CGU exceeded its recoverable amount, resulting in an impairment loss of $56 million. The impairment was recorded as additional DD&A. Future cash flows for the CGU declined due to lower forward crude oil prices and revisions to the development plan. Total Deep Basin DD&A was $331 million in 2017.

Assets and Liabilities Held for Sale

In December 2017, we commenced marketing for sale certain non-core assets located in the East and West Clearwater areas. The properties currently produce approximately 15,000 BOE per day of natural gas and liquids. These assets were reclassified as assets held for sale and recorded at the lesser of their carrying amount and fair value less costs to sell.

Cenovus Energy Inc. 21 2017 Management’s Discussion and Analysis

REFINING AND MARKETING

Cenovus is a 50 percent partner in the Wood River and Borger refineries, which are located in the U.S. and operated by our partner, Phillips 66. Our Refining and Marketing segment positions us to capture the value from crude oil production through to refined products such as diesel, gasoline and jet fuel. Our integrated approach provides a natural economic hedge against widening crude oil price differentials by providing lower feedstock prices to the Refineries. This segment captures our marketing and transportation initiatives as well as our crude-by-rail terminal operations located in Bruderheim, Alberta. In 2017, we loaded an average of 12,176 gross barrels per day (2016 – 11,584 gross barrels per day).

Significant developments that impacted our Refining and Marketing segment in 2017 compared with 2016 include:

· Generating Operating Margin of $598 million, a 73 percent increase from 2016; and

· Maintaining strong crude utilization and operating performance at the Refineries.

Refinery Operations ⁽¹⁾

	2017		2016		2015
Crude Oil Capacity (Mbbls/d)		460		460		460
Crude Oil Runs (Mbbls/d)		442		444		419
Heavy Crude Oil		202		233		200
Light/Medium		240		211		219
Refined Products (Mbbls/d)		470		471		444
Gasoline		238		236		228
Distillate		149		146		137
Other		83		89		79
Crude Utilization (percent)		96		97		91

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

On a 100 percent basis, the Refineries have a total processing capacity of approximately 460,000 gross barrels per day of crude oil, including processing capability of up to 255,000 gross barrels per day of blended heavy crude oil and 45,000 gross barrels per day of NGLs. The ability to process a wide slate of crude oils allows the Refineries to economically integrate heavy crude oil production. Processing less expensive crude oil relative to WTI creates a feedstock cost advantage, illustrated by the discount of WCS relative to WTI. The amount of heavy crude oil processed, such as WCS and CDB, is dependent on the quality and quantity of available crude oil with the total input slate optimized at each refinery to maximize economic benefit. Crude utilization represents the percentage of total crude oil processed in the Refineries relative to the total capacity.

Crude oil runs and refined product output in 2017 were consistent with 2016. The planned turnarounds and maintenance and unplanned maintenance at both refineries in 2017 had a similar impact on crude oil runs and refined product output as the planned and unplanned maintenance in 2016. Lower heavy crude oil volumes were processed due to optimization of the total crude input slate.

Financial Results

($ millions)	2017		2016		2015
Revenues		9,852		8,439		8,805
Purchased Product		8,476		7,325		7,709
Gross Margin		1,376		1,114		1,096
Expenses
Operating		772		742		754
(Gain) Loss on Risk Management		6		26		(43)
Operating Margin		598		346		385
Capital Investment		180		220		248
Operating Margin Net of Related Capital Investment		418		126		137

Gross Margin

The refining realized crack spread, which is the gross margin on a per barrel basis, is affected by many factors, such as the variety of feedstock crude oil processed; refinery configuration and the proportion of gasoline, distillate and secondary product output; the time lag between the purchase of crude oil feedstock and the processing of that crude oil through the Refineries; and the cost of feedstock. Feedstock costs are valued on a FIFO accounting basis.

In 2017, Refining and Marketing gross margin increased primarily due to:

· Higher average market crack spreads; and

· Increased margins on the sale of our secondary products, such as NGLs, due to higher realized prices.

These increases in gross margin were partially offset by:

· Narrowing heavy crude oil differentials, increasing the cost of purchased crude; and

· The strengthening of the Canadian dollar relative to the U.S. dollar, which had a negative impact of approximately $27 million on our gross margin.

Cenovus Energy Inc. 22 2017 Management’s Discussion and Analysis

The costs associated with Renewable Identification Numbers (“RINs”) were $296 million in 2017 (2016 – $294 million). The costs of RINs remained relatively consistent as the decrease in RINs benchmark prices was offset by an increase in the required RINs volume obligation.

Operating Expense

Primary drivers of operating expenses were labour, maintenance, utilities and supplies. In 2017, operating expenses increased due to an increase in maintenance costs associated with the plant turnarounds in the first quarter of 2017, and higher utility costs resulting from higher natural gas prices.

Refining and Marketing – Capital Investment

($ millions)	2017		2016		2015
Wood River Refinery		114		147		162
Borger Refinery		54		66		78
Marketing		12		7		8
		180		220		248

Capital expenditures in 2017 focused on capital maintenance and reliability work. Capital investment declined primarily due to the completion of work on the debottlenecking project at the Wood River refinery in the third quarter of 2016.

In 2018, we expect to invest between $180 million and $210 million mainly related to capital maintenance and reliability work. For more information, we direct our readers to review the news release for our 2018 guidance dated December 13, 2017. The news release is available on SEDAR at sedar.com, on EDGAR at sec.gov, and on our website at cenovus.com.

DD&A

Refining and the crude-by-rail terminal assets are depreciated on a straight-line basis over the estimated service life of each component of the facilities, which range from three to 40 years. The service lives of these assets are reviewed on an annual basis. Refining and Marketing DD&A was $215 million in 2017 compared with $211 million in 2016.

CORPORATE AND ELIMINATIONS

The Corporate and Eliminations segment includes intersegment eliminations relating to transactions that have been recorded at transfer prices based on current market prices, as well as unrealized intersegment profits in inventory. The gains and losses on risk management represent the unrealized mark-to-market gains and losses related to derivative financial instruments used to mitigate fluctuations in commodity prices, power costs, interest rates, and foreign exchange rates, as well as realized risk management gains, if any, on interest rate swaps and foreign exchange contracts. In 2017, our risk management activities resulted in $729 million of unrealized losses (2016 – $554 million of unrealized losses). As financial instruments are settled, the realized gains and losses are recorded in the reportable segment to which the derivative instrument relates. In 2017, we realized $146 million of risk management gains on foreign exchange contracts primarily due to hedging activity undertaken to support the Acquisition which were reported in the Corporate and Eliminations segment.

The Corporate and Eliminations segment also includes Cenovus-wide costs for general and administrative, finance costs, interest income, foreign exchange (gain) loss, revaluation (gain), transaction costs, re-measurement of the contingent payment, research costs, (gain) loss on divestiture of assets, and other (income) loss.

($ millions)	2017			2016			2015
General and Administrative		308			326			335
Finance Costs		645			390			381
Interest Income		(62	)		(52	)		(28	)
Foreign Exchange (Gain) Loss, Net		(812	)		(198	)		1,036
Revaluation (Gain)		(2,555	)		-			-
Transaction Costs		56			-			-
Re-measurement of Contingent Payment		(138	)		-			-
Research Costs		36			36			27
(Gain) Loss on Divestiture of Assets		1			6			(2,392	)
Other (Income) Loss, Net		(5	)		34			2
		(2,526	)		542			(639	)

Cenovus Energy Inc. 23 2017 Management’s Discussion and Analysis

Expenses

General and Administrative

Primary drivers of our general and administrative expenses in 2017 were workforce costs and office rent. In 2017, general and administrative expenses decreased by $18 million compared with 2016 due to:

· Lower long-term employee incentive costs related to a decline in our share price;

· A non-cash expense of $9 million for certain Calgary office space in excess of Cenovus’s current and near-term requirements, compared with $61 million in 2016; and

· Lower information technology costs due to process improvements.

Office rent, which makes up a large percentage of our G&A at $95 million, was consistent with 2016.

These decreases were partially offset by approximately $40 million of transitional services provided by ConocoPhillips. Under the Acquisition purchase and sales agreement, ConocoPhillips agreed to provide certain day-to-day services required by Cenovus for a period of approximately nine months. These transactions are in the normal course of operations and are measured at the exchange amounts.

Finance Costs

Finance costs include interest expense on our long-term debt and short-term borrowings as well as the unwinding of the discount on decommissioning liabilities. In 2017, finance costs increased by $255 million primarily due to costs associated with additional debt incurred to finance the Acquisition, including US$2.9 billion of senior unsecured notes and $3.6 billion borrowed under a committed Bridge Facility. The committed Bridge Facility was fully repaid and retired in December 2017 with proceeds from the sale of our legacy Conventional assets and cash on hand.

The weighted average interest rate on outstanding debt for 2017 was 4.9 percent (2016 – 5.3 percent).

Foreign Exchange

($ millions)	2017		2016		2015
Unrealized Foreign Exchange (Gain) Loss		(857)		(189)		1,097
Realized Foreign Exchange (Gain) Loss		45		(9)		(61)
		(812)		(198)		1,036

In 2017, unrealized foreign exchange gains of $665 million resulted from the translation of our U.S. dollar denominated debt. The Canadian dollar relative to the U.S. dollar as at December 31, 2017 strengthened by seven percent in comparison to December 31, 2016. Unrealized foreign exchange gains also resulted from the translation of U.S. cash that was accumulated in advance of the Acquisition.

Realized foreign exchange losses in 2017 primarily resulted from an increase in the number of sales contracts denominated in U.S. dollars.

Revaluation Gain

Prior to the Acquisition, our 50 percent interest in FCCL was jointly controlled with ConocoPhillips and met the definition of a joint operation under IFRS 11, “Joint Arrangements” (“IFRS 11”) and as such Cenovus recognized its share of the assets, liabilities, revenues and expenses in its consolidated results. Subsequent to the Acquisition, we control FCCL, as defined under IFRS 10, “Consolidated Financial Statements” (“IFRS 10”) and accordingly, FCCL has been consolidated. As required by IFRS 3 when control is achieved in stages, the previously held interest in FCCL was re-measured to its fair value of $12.3 billion and a non-cash revaluation gain of $2.6 billion ($1.9 billion, after-tax) was recorded in net earnings in the second quarter of 2017.

Transaction Costs

In 2017, we expensed $56 million of transaction costs related to the Acquisition.

Re-measurement of Contingent Payment

Related to oil sands production, Cenovus has agreed to make quarterly payments to ConocoPhillips during the five years subsequent to the closing date of the Acquisition for quarters in which the average WCS crude oil price exceeds $52 per barrel during the quarter. The quarterly payment will be $6 million for each dollar that the WCS price exceeds $52 per barrel. There are no maximum payment terms. The calculation includes an adjustment mechanism related to certain significant production outages at Foster Creek and Christina Lake, which may reduce the amount of a contingent payment.

The contingent payment is accounted for as a financial option. The fair value of $361 million on May 17, 2017 was estimated by calculating the present value of the future expected cash flows using an option pricing model. The contingent payment is subsequently re-measured at fair value at each reporting date with changes in fair value recognized in net earnings. At December 31, 2017, the contingent payment was valued at $206 million, resulting in a re-measurement gain of $138 million. In the fourth quarter of 2017, WCS averaged above $52 per barrel; therefore, $17 million is payable under this agreement.

Cenovus Energy Inc. 24 2017 Management’s Discussion and Analysis

Average WCS forward pricing for the remaining term of the contingent payment is US$35.51 or C$44.55 per barrel. Estimated quarterly WCS forward prices for the remaining term of the agreement range between approximately C$39.60 per barrel and C$52.60 per barrel.

DD&A

Corporate and Eliminations DD&A includes provisions in respect of corporate assets, such as computer equipment, leasehold improvements and office furniture. Costs associated with corporate assets are depreciated on a straight-line basis over the estimated service life of the assets, which range from three to 25 years. The service lives of these assets are reviewed on an annual basis. DD&A in 2017 was $62 million (2016 – $65 million; 2015 – $105 million).

Income Tax

($ millions)	2017		2016		2015
Current Tax
Canada		(217)		(260)		441
United States		(38)		1		(12)
Current Tax Expense (Recovery)		(255)		(259)		429
Deferred Tax Expense (Recovery)		203		(84)		(453)
Total Tax Expense (Recovery) From Continuing Operations		(52)		(343)		(24)
The following table reconciles income taxes calculated at the Canadian statutory rate with the recorded income taxes:
($ millions)	2017		2016		2015
Earnings (Loss) From Continuing Operations Before Income Tax		2,216		(802)		890
Canadian Statutory Rate		27.0%		27.0%		26.1%
Expected Income Tax Expense (Recovery) From Continuing Operations		598		(217)		232
Effect of Taxes Resulting From:
Foreign Tax Rate Differential		(17)		(46)		(41)
Non-Taxable Capital (Gains) Losses		(148)		(26)		137
Non-Recognition of Capital (Gains) Losses		(118)		(26)		135
Adjustments Arising From Prior Year Tax Filings		(41)		(46)		(55)
(Recognition) of Previously Unrecognized Capital Losses		(68)		-		(149)
(Recognition) of U.S. Tax Basis		-		-		(415)
Change in Statutory Rate		(275)		-		114
Non-Deductible Expenses		(5)		5		7
Other		22		13		11
Total Tax Expense (Recovery) From Continuing Operations		(52)		(343)		(24)
Effective Tax Rate		(2.3)%		(42.8)%		(2.7)%

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

In 2017, a current tax recovery was recorded in continuing operations resulting from the carry back of current and prior year losses and an adjustment related to prior years. A deferred tax expense was recorded in 2017 compared with a recovery in 2016 on continuing operations due to the revaluation gain of our pre-existing interest in connection with the Acquisition, partially offset by a $275 million recovery from the reduction of the U.S. federal corporate income tax rate from 35 to 21 percent, reducing our deferred income tax liability, and the impact of E&E writedowns.

In 2017, the U.S. issued new tax legislation which:

· Reduces the federal income tax rate from 35 percent to 21 percent;

· Permits the full deductibility of allowed capital expenditures until January 1, 2023;

· Limits the use of operating tax losses incurred after 2017 to 80 percent of taxable income;

· Limits the deductibility of interest expense to 30 percent of “adjusted taxable income”; and

· Introduces a base erosion and anti-abuse tax that imposes a five percent minimum tax in 2018, increasing to 10 percent in 2019, to the extent that a corporation makes significant tax deductible payments to a related party.

In 2017, we recorded an income tax expense of $404 million related to discontinued operations (2016 – income tax recovery of $39 million), of which $347 million deferred tax expense relates to the gain on discontinuance.

Cenovus Energy Inc. 25 2017 Management’s Discussion and Analysis

Our effective tax rate is a function of the relationship between total tax expense (recovery) and the amount of earnings (loss) before income taxes. The effective tax rate differs from the statutory tax rate as it reflects different tax rates in other jurisdictions, non-taxable foreign exchange (gains) losses, adjustments for changes in tax rates and other tax legislation, adjustments to the tax basis of the refining assets, variations in the estimate of reserves, differences between the provision and the actual amounts subsequently reported on the tax returns, and other permanent differences. Our effective tax rate differs from the statutory tax rate due to non-taxable foreign exchange gains and the recognition of the benefit of other capital losses and a recovery relating to the change in the U.S. federal tax rate.

DISCONTINUED OPERATIONS

Following the Acquisition, we announced our intention to divest all of our legacy Conventional assets and therefore the Conventional segment has been reported as a discontinued operation.

In late 2017, we sold the majority of our legacy Conventional assets. The sale of Suffield, the one remaining legacy asset as at December 31, 2017, closed on January 5, 2018 for gross proceeds of $512 million. The divestitures completed in 2017 generated total gross cash proceeds of $3.2 billion before closing adjustments and a before-tax gain of $1.3 billion. Details of the asset sales are:

· On September 29, 2017, we completed the sale of our Pelican Lake heavy oil operations, as well as other miscellaneous assets in northern Alberta, for gross cash proceeds of $975 million before closing adjustments. A before-tax loss on discontinuance of $623 million was recorded on the sale;

· On December 7, 2017, our Palliser crude oil and natural gas operations in southern Alberta were sold for gross cash proceeds of $1.3 billion before closing adjustments. A before-tax gain on discontinuance of $1.6 billion was recorded on the sale; and

· On December 14, 2017, the sale of our Weyburn assets in southern Saskatchewan was completed for gross cash proceeds of $940 million before closing adjustments. A before-tax gain on discontinuance of $276 million was recorded on the sale.

Financial Results

($ millions)	2017		2016		2015
Gross Sales		1,309		1,267		1,648
Less: Royalties		174		139		113
Revenues		1,135		1,128		1,535
Expenses
Transportation and Blending		167		186		229
Operating		426		444		558
Production and Mineral Taxes		18		12		17
(Gain) Loss on Risk Management		33		(58)		(209)
Operating Margin		491		544		940
Depreciation, Depletion and Amortization		192		567		1,121
Exploration Expense		2		-		71
Finance Costs		80		102		101
Earnings (Loss) From Discontinued Operations Before Income Tax		217		(125)		(353)
Current Tax Expense (Recovery)		24		86		145
Deferred Tax Expense (Recovery)		33		(125)		(202)
After-tax Earnings (Loss) From Discontinued Operations		160		(86)		(296)
After-tax Gain on Discontinuance (1)		938		-		-
Net Earnings (Loss) From Discontinued Operations		1,098		(86)		(296)

(1) Net of deferred tax expense of $347 million in the year ended December 31, 2017.

Cenovus Energy Inc. 26 2017 Management’s Discussion and Analysis

Operating Margin Variance

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

Revenues

Price

	2017		2016		2015
Total Liquids ($/bbl)		52.38		40.67		44.31
Natural Gas ($/mcf)		2.47		2.33		2.92
Total Oil Equivalent ($/BOE)		32.10		26.54		30.51

Our Conventional assets produced a variety of natural gas, NGLs, condensate and crude oils, ranging from heavy oil, which realizes a price based on the WCS benchmark, to light oil, which realizes a price closer to the WTI benchmark.

Production Volumes

(barrels per day)	2017		Percent           Change		2016		Percent           Change		2015
Liquids
Heavy Oil		21,478		(26)%		29,185		(15)%		34,256
Light and Medium Oil		24,824		(4)%		25,915		(10)%		28,675
NGLs		1,073		1%		1,065		(7)%		1,149
Total Liquids Production (barrels per day)		47,375		(16)%		56,165		(12)%		64,080
Natural Gas (MMcf per day)		333		(12)%		377		(8)%		412
Total Production (BOE per day)		102,855		(14)%		118,998		(10)%		132,746

Total production decreased primarily due to the divestiture of our Conventional assets late in 2017 and expected natural declines. These decreases were partially offset by an increase in production associated with our tight oil drilling program in southern Alberta.

Condensate

Heavy oil currently must be blended with condensate to reduce its thickness in order to transport it to market through pipelines. Blending ratios for Conventional heavy oil ranged between 10 percent and 16 percent. Revenues represent the total value of blended crude oil sold and include the value of condensate. Consistent with the narrowing of the WCS-Condensate differential in 2017, the proportion of the cost of condensate recovered increased.

Royalties

Royalties increased $35 million in 2017 primarily due to an increase in our liquids sales prices, higher royalty rates, and lower allowable costs for royalty purposes at Weyburn and Pelican Lake, partially offset by a reduction in sales volumes. In 2017, the effective liquids royalty rate was 19.3 percent (2016 – 16.3 percent) and the average natural gas royalty rate was 4.8 percent (2016 – 4.7 percent).

Expenses

Transportation and Blending

Transportation and blending costs decreased $19 million in 2017 primarily due to the sale of Pelican Lake completed on September 29, 2017, resulting in lower production as well as a decrease in blended condensate volumes. This decrease was partially offset by higher blending costs as a result of increased condensate prices.

Cenovus Energy Inc. 27 2017 Management’s Discussion and Analysis

Operating

Primary drivers of our operating expenses in 2017 were property taxes and lease costs, workforce costs, workover activities, electricity, and repairs and maintenance. Operating expenses increased $1.02 per barrel. The per unit increase was primarily due to lower production volumes, an increase in repairs and maintenance activities, and higher energy costs. This increase was partially offset by reduced workforce costs, lower property and lease costs, fewer workovers and a decrease in electricity costs due to lower consumption and price.

In 2017, production and mineral taxes increased due to the rise in crude oil prices.

Netbacks

($/BOE)	2017		2016		2015
Sales Price		32.10		26.54		30.51
Royalties		4.65		3.18		2.33
Transportation and Blending		1.93		2.08		1.88
Operating Expenses		11.25		10.23		11.58
Production and Mineral Taxes		0.49		0.27		0.35
Netback Excluding Realized Risk Management		13.78		10.78		14.37
Realized Risk Management Gain (Loss)		(0.88)		1.45		4.50
Netback Including Realized Risk Management		12.90		12.23		18.87

Risk Management

Risk management activities for 2017 resulted in realized losses of $33 million (2016 – realized gains of $58 million), consistent with average benchmark prices exceeding our contract prices.

Net Earnings (Loss) From Discontinued Operations

Net Earnings From Discontinued Operations was $1,098 million in 2017 compared with a loss of $86 million in 2016. The significant increase was due to the after-tax gain on discontinuance of $938 million, and lower DD&A expense due to the decision to divest our Conventional assets, partially offset by higher tax expense and a decline in operating margin.

Conventional – Capital Investment

($ millions)	2017		2016		2015
Heavy Oil		32		44		63
Light and Medium Oil		163		117		168
Natural Gas		11		10		13
Capital Investment (1)		206		171		244

(1) Includes expenditures on PP&E, E&E assets, and assets held for sale.

Capital investment in 2017 was primarily related to sustaining capital, the purchase of CO₂ at Weyburn, and tight oil drilling opportunities in southern Alberta. Our drilling program was suspended early in the third quarter of 2017 in anticipation of the asset divestitures. Capital investment increased compared with 2016 as a result of limited crude oil capital investment activities in 2016 in response to the low commodity price environment.

DD&A

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

DD&A decreased $375 million year over year primarily due to impairment losses of $445 million recorded in 2016, and a decline in sales volumes. In addition, on classification of our Conventional assets as held for sale in the first and second quarters of 2017, DD&A was no longer recorded, as required by IFRS.

Cenovus Energy Inc. 28 2017 Management’s Discussion and Analysis

QUARTERLY RESULTS

Our quarterly results over the last eight quarters were impacted primarily by volatility in commodity prices, with the Acquisition having a significant impact on the last three quarters. Crude oil prices reached a 13 year low, with WTI averaging US$33.45 per barrel in the first quarter of 2016 and gradually increasing to an average of US$55.40 per barrel in the fourth quarter of 2017. Average WTI and WCS benchmark prices increased 12 percent and 23 percent, respectively in the fourth quarter 2017 compared with 2016. Our companywide Netback from continuing operations of $22.38 per BOE in the fourth quarter of 2017, before realized risk management activities, increased six percent compared with 2016.

($ millions, except per share amounts or where otherwise indicated)	2017											2016
	Q4			Q3			Q2		Q1			Q4			Q3			Q2			Q1
Production Volumes
Total Liquids (barrels per day)		422,157			449,055			333,664		234,914			219,551			208,072			198,080			197,551
Natural Gas (MMcf/d)		795			851			620		363			379			392			399			408
Total Production (BOE per day)		554,606			590,851			436,929		295,414			282,718			273,405			264,580			265,551
Total Production From Continuing Operations (BOE per day)		480,497			478,817			322,792		184,001			167,230			156,591			145,604			140,808
Refinery Operations
Crude Oil Runs (Mbbls/d)		450			462			449		406			421			463			458			435
Refined Products (Mbbls/d)		480			490			476		433			448			494			483			460
Revenues		5,079			4,386			4,037		3,541			3,324			2,945			2,746			1,991
Operating Margin (1)
From Continuing Operations		1,018			1,097			572		305			442			335			424			22
Total Operating Margin		1,088			1,214			731		450			595			487			541			144
Cash From Operating Activities
From Continuing Operations		833			481			1,102		195			22			189			121			94
Total Cash From Operating Activities		900			592			1,239		328			164			310			205			182
Adjusted Funds Flow (2)
From Continuing Operations		796			865			603		183			382			296			352			(65	)
Total Adjusted Funds Flow		866			980			745		323			535			422			440			26
Operating Earnings (Loss) (2)
From Continuing Operations		(533	)		240			298		(39	)		21			(40	)		(3	)		(269	)
Per Share – Diluted ($)		(0.43	)		0.20			0.27		(0.05	)		0.03			(0.05	)		-			(0.32	)
Total Operating Earnings (Loss)		(514	)		327			352		(39	)		321			(236	)		(39	)		(423	)
Per Share – Diluted ($)		(0.42	)		0.27			0.32		(0.05	)		0.39			(0.28	)		(0.05	)		(0.51	)
Net Earnings (Loss)
From Continuing Operations		(776	)		275			2,558		211			(209	)		(55	)		(231	)		36
Per Share – Basic and Diluted ($)		(0.63	)		0.22			2.30		0.25			(0.25	)		(0.07	)		(0.28	)		0.04
Total Net Earnings (Loss)		620			(82	)		2,617		211			91			(251	)		(267	)		(118	)
Per Share – Basic and Diluted ($)		0.50			(0.07	)		2.35		0.25			0.11			(0.30	)		(0.32	)		(0.14	)
Capital Investment (3)
From Continuing Operations		557			396			277		225			202			167			202			284
Total Capital Investment		583			438			327		313			259			208			236			323
Dividends
Cash Dividends		61			62			61		41			42			41			42			41
Per Share ($)		0.05			0.05			0.05		0.05			0.05			0.05			0.05			0.05

(1) Additional subtotal found in Note 1 and Note 11 of the Consolidated Financial Statements and defined in this MD&A.

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

(3) Includes expenditures on PP&E, E&E assets, and assets held for sale.

(4) In the second quarter of 2017, the Company’s Conventional segment was classified as a discontinued operation. Prior periods have been restated to reflect this classification.

Cenovus Energy Inc. 29 2017 Management’s Discussion and Analysis

Fourth Quarter 2017 Results Compared With the Fourth Quarter 2016

Continuing Operations

Production Volumes

Total production from continuing operations increased 187 percent in the fourth quarter of 2017 compared with 2016. The increase in production was primarily due to the Acquisition and the incremental production volumes from Christina Lake phase F, which started up in the fourth quarter of 2016.

Refinery Operations

Crude oil runs and refined product output increased in 2017 primarily due to unplanned outages at the Borger refinery in the fourth quarter of 2016.

Revenues

Revenues increased $1,755 million in 2017 primarily due to:

· A rise in sales volumes due to the Acquisition and the incremental production volumes from Christina Lake phase F;

· A 25 percent rise in our liquids sales prices from continuing operations to $45.85 per barrel; and

· An increase in refining revenues largely due to higher refined product pricing.

The increases to revenues were partially offset by lower revenues from third-party crude oil and natural gas sales undertaken by the marketing group, the strengthening of the Canadian dollar relative to the U.S. dollar, as well as higher crude oil royalties.

Operating Margin

Operating Margin from continuing operations increased 130 percent in the fourth quarter of 2017 compared with 2016. Upstream Operating Margin rose 111 percent primarily due to an increase in our liquids and natural gas sales volumes as a result of the Acquisition and a rise in our average liquids sales prices due to improved benchmark prices.

These increases were partially offset by:

· A rise in transportation and blending expenses related to higher condensate prices and a rise in condensate volumes required for our increased production;

· Realized risk management losses of $235 million compared with gains of $14 million in 2016;

· An increase in upstream operating expenses primarily due to the Acquisition;

· Higher royalties primarily due to an increase in the WTI benchmark price (which determines the royalty rate), increased sales volumes due to the Acquisition, and a rise in our liquids sales price; and

· Lower average natural gas sales prices, consistent with the decline in the AECO benchmark price.

Refining and Marketing Operating Margin increased by $206 million. The increase was primarily due to higher average market crack spreads, a rise in margins on the sale of our secondary products, and an increase in crude utilization rates.

These increases were partially offset by narrowing heavy crude oil differentials, increased operating costs and the strengthening of the Canadian dollar relative to the U.S. dollar.

Operating Margin From Continuing Operations Variance

(1) Other includes the value of condensate sold as heavy oil blend recorded in revenues and condensate costs recorded in transportation and blending expense. The crude oil price excludes the impact of condensate purchases.

Cenovus Energy Inc. 30 2017 Management’s Discussion and Analysis

Discontinued Operations

Production Volumes

Total production decreased 36 percent in the fourth quarter of 2017 compared with 2016, primarily as a result of the divestiture of our Conventional assets late in 2017 as well as expected natural declines.

Operating Margin

Operating Margin decreased 54 percent in the fourth quarter of 2017 compared with 2016, primarily as a result of reduced sales volumes due to the sale of the majority of our legacy Conventional assets and natural declines, partially offset by a decrease in royalties.

Consolidated Operations

Cash From Operating Activities and Adjusted Funds Flow

Total Cash From Operating Activities and Adjusted Funds Flow increased in the fourth quarter of 2017 compared with 2016, primarily due to a higher Operating Margin, as discussed above, partially offset by current income tax expense in 2017 compared with a recovery in 2016 and a rise in finance costs primarily associated with additional debt incurred to finance the Acquisition.

The change in non-cash working capital in the fourth quarter of 2017 was primarily due to an increase in accounts payable and income tax payable, partially offset by an increase in accounts receivable and inventory. For 2016, the change in non-cash working capital was primarily due to an increase in accounts receivable and a rise in inventory, partially offset by an increase in accounts payable.

Operating Earnings (Loss)

Operating Earnings from continuing operations decreased $554 million in the three months ended December 31, 2017 compared with 2016. Higher Cash From Operating Activities and Adjusted Funds Flow, as discussed above, was more than offset by exploration expense of $887 million, and an increase in DD&A as a result of the Acquisition.

Operating Earnings from discontinued operations of $19 million decreased $281 million in the three months ended December 31, 2017 compared with 2016 due to a decrease in production volumes and operating margin, as discussed above. In addition, 2016 included an impairment reversal of $462 million which arose primarily due to the increase in our Northern Alberta CGU’s estimated recoverable amount caused by a reduction in expected average future operating costs and lower future development costs, partially offset by a decline in estimated reserves.

Net Earnings (Loss)

Net loss from continuing operations for the three months ended December 31, 2017 increased $567 million compared with 2016. The increase in net loss was primarily due to lower operating earnings, as discussed above, and unrealized risk management losses of $654 million compared with $114 million in 2016, partially offset by non-operating unrealized foreign exchange losses of $51 million compared with $152 million in 2016. In addition, a deferred tax recovery of $275 million was recorded to reflect the benefit of the decreased U.S. federal corporate income tax rate.

Net earnings from discontinued operations in the fourth quarter includes a $1,378 million after-tax gain on the divestiture of our Conventional segment assets.

Capital Investment

Capital investment from continuing operations in the fourth quarter of 2017 was $557 million, an increase of $355 million from 2016. The increase was primarily due to the drilling and completion of horizontal production wells within the Deep Basin corridor.

Capital investment from discontinued operations was down 54 percent to $26 million in the fourth quarter of 2017 compared with 2016 due to reduced spending as a result of the decision to divest our legacy Conventional assets in first and second quarters of 2017.

Cenovus Energy Inc. 31 2017 Management’s Discussion and Analysis

OIL AND GAS RESERVES

We retain IQREs to evaluate and prepare reports on 100 percent of our bitumen, heavy oil, light and medium oil, NGLs, conventional natural gas and shale gas proved and probable reserves.

Developments in 2017 compared with 2016 include:

· Bitumen proved reserves increasing 103 percent primarily due to the acquisition of the remaining 50 percent working interest in FCCL. In addition, 169 million barrels of proved reserves were added at Foster Creek and Narrows Lake as a result of the Alberta Energy Regulator’s (the “AER”) approval of expansions converting probable reserves to proved reserves, and from improved reservoir performance;

· Proved plus probable bitumen reserves increasing 92 percent as the acquisition of the remaining 50 percent working interest in FCCL was partially offset by the Grand Rapids divestiture;

· Heavy oil proved reserves declining 87 percent and heavy oil proved plus probable reserves declining 86 percent primarily due to the divestiture of Pelican Lake;

· Both light and medium oil proved reserves and proved plus probable reserves decreasing 87 percent, primarily as a result of the Palliser and Weyburn dispositions;

· NGLs proved and probable reserves increasing 101 million barrels and 67 million barrels, respectively, due to the acquisition of the Deep Basin Assets;

· Conventional natural gas proved reserves increased by 1,175 billion cubic feet and conventional natural gas probable reserves increased by 648 billion cubic feet as the acquisition of the Deep Basin Assets more than offset the Palliser disposition; and

· Shale gas proved and proved plus probable reserves of 283 billion cubic feet and 568 billion cubic feet, respectively, were booked as a result of the acquisition of the Deep Basin Assets.

The reserves data that follows is presented as at December 31, 2017 using an average of forecasts (“IQRE Average Forecast”) by McDaniel & Associates Consultants Ltd., GLJ Petroleum Consultants Ltd. and Sproule Associates Limited. The IQRE Average Forecast prices and inflation is dated January 1, 2018. Comparative information as at December 31, 2016 uses McDaniel’s January 1, 2017 forecast prices and inflation.

Reserves

As at December 31, 2017 (before royalties) (1)	Bitumen     (MMbbls)			Heavy   Oil   (MMbbls)			Light &   Medium   Oil   (MMbbls)			NGLs      (MMbbls)			Conventional   Natural   Gas   (Bcf)			Shale   Gas   (Bcf)			Total    (MMBOE)
Proved		4,750			15			13			103			1,827			283		5,232
Probable		1,633			12			6			68			860			285		1,910
Proved plus Probable		6,383			27			19			171			2,687			568		7,142
(1)  Includes reserves associated with the Suffield asset sold January 5, 2018, representing before royalties 69 MMBOE and 82 MMBOE on a proved and proved plus probable basis, respectively. Reconciliation of Proved Reserves
(before royalties)	Bitumen (MMbbls)			Heavy Oil (MMbbls)			Light & Medium Oil (MMbbls)			NGLs (MMbbls)			Conventional Natural Gas (1) (Bcf)			Shale Gas (Bcf)			Total  (MMBOE)
December 31, 2016		2,343			114			99			2			652			-		2,667
Extensions and Improved Recovery		141			-			-			1			35			-		148
Discoveries		-			2			-			-			-			-		2
Technical Revisions		28			2			-			-			86			-		43
Economic Factors		-			-			-			-			-			-		-
Acquisitions		2,345			-			14			108			1,557			289		2,775
Dispositions		-			(95	)		(90	)		(2	)		(266	)		-		(231)
Production (2)		(107	)		(8	)		(10	)		(6	)		(237	)		(6	)	(172)
December 31, 2017		4,750			15			13			103			1,827			283		5,232
Year Over Year Change		2,407			(99	)		(86	)		101			1,175			283		2,565
		103%			(87)%			(87)%			5,050%			180%			-%		96%

(1) Includes coal bed methane (“CBM”) as at December 31, 2016. No CBM remains at December 31, 2017 due to dispositions.

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

Cenovus Energy Inc. 32 2017 Management’s Discussion and Analysis

Reconciliation of Probable Reserves

(before royalties)	Bitumen   (MMbbls)		Heavy Oil (MMbbls)	Light & Medium Oil (MMbbls)	NGLs (MMbbls)	Conventional Natural Gas (1) (Bcf)	Shale  Gas  (Bcf)	Total   (MMBOE)
December 31, 2016		976	75	43	1	212	-	1,130
Extensions and Improved Recovery		(141)	-	-	3	21	15	(132)
Discoveries		-	7	-	-	-	-	7
Technical Revisions		(10)	-	-	-	(3)	-	(10)
Economic Factors		-	-	-	-	-	-	-
Acquisitions		887	-	6	65	748	270	1,128
Dispositions		(79)	(70)	(43)	(1)	(118)	-	(213)
Production		-	-	-	-	-	-	-
December 31, 2017		1,633	12	6	68	860	285	1,910
Year Over Year Change		657	(63)	(37)	67	648	285	780
		67%	(84)%	(86)%	6,700%	306%	-%	69%

(1) Includes CBM as at December 31, 2016. No CBM remains at December 31, 2017 due to dispositions.

Additional information with respect to the evaluation and reporting of our reserves in accordance with National Instrument 51-101, Standards of Disclosure for Oil and Gas Activities (“NI 51-101”) is contained in our AIF for the year ended December 31, 2017. Our AIF is available on SEDAR at sedar.com, on EDGAR at sec.gov and on our website at cenovus.com. Material risks and uncertainties associated with estimates of reserves are discussed in this MD&A in the “Risk Management and Risk Factors” section.

LIQUIDITY AND CAPITAL RESOURCES

($ millions)	2017			2016			2015
Cash From (Used In)
Operating Activities – Continuing Operations		2,611			426			696
Operating Activities – Discontinued Operations		448			435			778
Total Operating Activities		3,059			861			1,474
Investing Activities – Continuing Operations		(15,859	)		(911	)		1,131
Investing Activities – Discontinued Operations		2,993			(168	)		(243	)
Total Investing Activities		(12,866	)		(1,079	)		888
Net Cash Provided (Used) Before Financing Activities		(9,807	)		(218	)		2,362
Financing Activities		6,515			(168	)		894
Foreign Exchange Gain (Loss) on Cash and Cash Equivalents Held in Foreign Currency		182			1			(34	)
Increase (Decrease) in Cash and Cash Equivalents		(3,110	)		(385	)		3,222
As at December 31,	2017			2016			2015
Cash and Cash Equivalents		610			3,720			4,105
Committed and Undrawn Credit Facility		4,500			4,000			4,000

Cash From (Used In) Operating Activities

Cash From Operating Activities increased in 2017 mainly due to higher Operating Margin, as discussed in the Financial Results section of this MD&A. Excluding risk management assets and liabilities, assets and liabilities held for sale, and the current portion of the contingent payment, our working capital was $1,133 million at December 31, 2017 compared with $4,423 million at December 31, 2016. Working capital declined primarily due to the use of cash and cash equivalents to fund the Acquisition.

We anticipate that we will continue to meet our payment obligations as they come due.

Cash From (Used In) Investing Activities

In 2017, the increase in cash used in investing activities was primarily due to the Acquisition and an increase in capital investment, partially offset by $3.2 billion in proceeds from the divestiture of our legacy Conventional assets. In 2016, capital investment was limited due to spending reductions in response to the low commodity price environment.

Cenovus Energy Inc. 33 2017 Management’s Discussion and Analysis

Cash From (Used In) Financing Activities

Cash from financing activities increased in 2017 primarily due to the issuance of debt and common shares to help finance the Acquisition.

Total debt as at December 31, 2017 was $9,513 million (December 31, 2016 – $6,332 million), with no principal payments due until October 15, 2019 (US$1.3 billion). The increase in total debt is primarily due to the Acquisition financing.

As at December 31, 2017, we were in compliance with all of the terms of our debt agreements.

Senior Unsecured Notes

In connection with the Acquisition, we completed an offering in the U.S. on April 7, 2017 for US$2.9 billion of senior unsecured notes issued in three tranches, US$1.2 billion 4.25 percent senior unsecured notes due April 2027, US$700 million 5.25 percent senior unsecured notes due June 2037, and US$1.0 billion 5.40 percent senior unsecured notes due June 2047 (collectively, the “2017 Notes”). In the fourth quarter of 2017, we completed an exchange offer (“Exchange Offering”) whereby substantially all of the 2017 Notes were exchanged for notes registered under the U.S. Securities Act of 1933 with essentially the same terms and provisions as the 2017 Notes.

Committed Bridge Facility

On May 17, 2017, concurrent with the close of the Acquisition, we borrowed $3.6 billion under a committed Bridge Facility. The committed Bridge Facility was repaid in full, using the proceeds from divestiture of our legacy Conventional assets as well as cash on hand, and retired prior to December 31, 2017.

Common Shares

In connection with the Acquisition, on April 6, 2017, Cenovus closed a bought-deal common share offering for 187.5 million common shares for gross proceeds of $3.0 billion.

Dividends

In 2017, we paid dividends of $0.20 per share or $225 million (2016 – $0.20 per share or $166 million). The declaration of dividends is at the sole discretion of the Board and is considered quarterly.

Available Sources of Liquidity

We expect cash flows from our liquids, natural gas and refining operations to fund all of our cash requirements in 2018. Any potential shortfalls may be required to be funded through prudent use of our balance sheet capacity, management of our asset portfolio and other corporate and financial opportunities that may be available to us. We remain committed to maintaining our investment grade credit ratings at S&P Global Ratings, DBRS Limited and Fitch Ratings.

The following sources of liquidity are available at December 31, 2017:

($ millions)	Term	Amount
Cash and Cash Equivalents	Not applicable	610
Committed Credit Facility – Tranche A	November 2021	3,300
Committed Credit Facility – Tranche B	November 2020	1,200

Committed Credit Facility

On April 28, 2017, we amended our existing committed credit facility to increase the capacity by $0.5 billion to $4.5 billion and to extend the maturity dates. The committed credit facility consists of a $1.2 billion tranche maturing on November 30, 2020 and $3.3 billion tranche maturing on November 30, 2021. As of December 31, 2017, no amounts were drawn on our committed credit facility.

Under the committed credit facility, Cenovus is required to maintain a debt to capitalization ratio not to exceed 65 percent; we are well below this limit.

Base Shelf Prospectus

On October 10, 2017, we filed a base shelf prospectus that allows us to offer, from time to time, up to US$7.5 billion, or the equivalent in other currencies, of debt securities, common shares, preferred shares, subscription receipts, warrants, share purchase contracts and units in Canada, the U.S. and elsewhere, where permitted by law. The base shelf prospectus is available to ConocoPhillips to offer, should they so choose from time to time, the common shares they acquired in connection with the Acquisition. The base shelf prospectus will expire in November 2019 and replaced our US$5.0 billion base shelf prospectus, which would have expired in March 2018. Offerings under the base shelf prospectus are subject to market conditions.

Following the completion of the Exchange Offering and as at December 31, 2017, US$4.6 billion remains available under the base shelf prospectus.

Cenovus Energy Inc. 34 2017 Management’s Discussion and Analysis

Financial Metrics

We monitor our capital structure and financing requirements using, among other things, non-GAAP financial metrics consisting of Net Debt to Adjusted EBITDA and Net Debt to Capitalization. We define our non-GAAP measure of Net Debt as short-term borrowings, and the current and long-term portions of long-term debt, net of cash and cash equivalents. We define Capitalization as Net Debt plus Shareholders’ Equity. We define Adjusted EBITDA as net earnings before finance costs, interest income, income tax expense, DD&A, goodwill impairments, asset impairments and reversals, unrealized gains (losses) on risk management, foreign exchange gains (losses), revaluation gain, re-measurement of contingent payment, gains (losses) on divestiture of assets, and other income (loss), net, calculated on a trailing 12-month basis. These measures are used to steward our overall debt position and as measures of our overall financial strength.

Over the long term, we target a Net Debt to Adjusted EBITDA ratio of less than 2.0 times. At different points within the economic cycle, we expect this ratio may periodically be above the target. We also manage our Net Debt to Capitalization ratio to ensure compliance with the associated covenant as defined in our committed credit facility agreement.

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

As at December 31,	2017			2016			2015
Long-Term Debt		9,513			6,332			6,525
Less: Cash and Cash Equivalents		(610	)		(3,720	)		(4,105	)
Net Debt		8,903			2,612			2,420
Net Earnings (Loss)		3,366			(545	)		618
Add (Deduct):
Finance Costs		725			492			482
Interest Income		(62	)		(52	)		(28	)
Income Tax (Recovery) Expense		352			(382	)		(81	)
DD&A		2,030			1,498			2,114
E&E Impairment		890			2			138
Unrealized (Gain) Loss on Risk Management		729			554			195
Foreign Exchange (Gain) Loss, Net		(812	)		(198	)		1,036
Revaluation Gain		(2,555	)		-			-
Re-measurement of Contingent Payment		(138	)		-			-
(Gain) Loss on Discontinuance		(1,285	)		-			-
(Gain) Loss on Divestiture of Assets		1			6			(2,392	)
Other (Income) Loss, Net		(5	)		34			2
Adjusted EBITDA (1)		3,236			1,409			2,084
Net Debt to Adjusted EBITDA		2.8x			1.9x			1.2x
(1)  Calculated on a trailing 12-month basis. Includes discontinued operations. Net Debt to Capitalization is calculated as follows:
As at December 31,	2017			2016			2015
Net Debt		8,903			2,612			2,420
Shareholders’ Equity		19,981			11,590			12,391
Capitalization		28,884			14,202			14,811
Net Debt to Capitalization (1)		31%			18%			16%

(1) Net Debt to Capitalization is defined as Net Debt divided by Net Debt plus Shareholders’ Equity.

As at December 31, 2017, Cenovus’s Net Debt to Adjusted EBITDA is 2.8x, which is above our target. However, it is important to note that Adjusted EBITDA is calculated on a trailing 12-month basis and as such, only includes the financial results from the Deep Basin Assets and the additional 50 percent of FCCL for the period May 17, 2017 to December 31, 2017. Net debt is presented as at December 31, 2017; therefore, the ratio is burdened by the debt issued to finance the Acquisition. If Adjusted EBITDA reflected a full twelve months of earnings from the acquired assets, Cenovus’s Net Debt to Adjusted EBITDA ratio would be lower. Net Debt to Adjusted EBITDA increased as a result of a higher long-term debt balance, partially offset by higher Adjusted EBITDA due to the rise in sales volumes as a result of the Acquisition and higher commodity prices.

Net Debt to Capitalization increased as a result of the higher long-term debt balance, related to the Acquisition, partially offset by the increase in Shareholders’ Equity and the strengthening of the Canadian dollar relative to the U.S. dollar.

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

Cenovus Energy Inc. 35 2017 Management’s Discussion and Analysis

Share Capital and Stock-Based Compensation Plans

As at December 31, 2017, there were approximately 1,229 million common shares outstanding (2016 – 833 million common shares). In connection with the Acquisition, Cenovus closed a bought-deal common share financing on April 6, 2017 for 187.5 million common shares, raising gross proceeds of $3.0 billion ($2.9 billion net of $101 million of share issuance costs).

In addition, we issued 208 million common shares to ConocoPhillips on May 17, 2017 as partial consideration for the Acquisition. In relation to the share consideration, Cenovus and ConocoPhillips entered into an investor agreement, and a registration rights agreement which, among other things, restricted ConocoPhillips from selling or hedging its Cenovus common shares until November 17, 2017. ConocoPhillips is also restricted from nominating new members to Cenovus’s Board of Directors and must vote its Cenovus common shares in accordance with management recommendations or abstain from voting until such time ConocoPhillips owns 3.5 percent or less of the outstanding common shares of Cenovus. As at December 31, 2017, ConocoPhillips continued to hold these shares.

As part of our long-term incentive program, Cenovus has an employee Stock Option Plan as well as Performance Share Unit (“PSU”) Plan, a Restricted Share Unit (“RSU”) Plan and two Deferred Share Unit (“DSU”) Plans. Certain directors, officers or employees chose prior to December 31, 2017 to convert a portion of their remuneration, paid in the first quarter of 2018, into DSUs. The election for any particular year is irrevocable. DSUs may not be redeemed until after departure from Cenovus. Directors also received an annual grant of DSUs.

Refer to Note 29 of the Consolidated Financial Statements for more details on our Stock Option Plan and our PSU, RSU and DSU Plans.

As at January 31, 2018	Units   Outstanding   (thousands)	Units   Exercisable   (thousands)
Common Shares	1,228,790	N/A
Stock Options	42,337	35,263
Other Stock-Based Compensation Plans	13,963	1,439

Contractual Obligations and Commitments

Cenovus has obligations for goods and services that were entered into in the normal course of business. Obligations are primarily related to transportation agreements, operating leases on buildings, our risk management program and an obligation to fund our defined benefit pension and other post-employment benefit plans. Obligations that have original maturities of less than one year are excluded. For further information, see the notes to the Consolidated Financial Statements. The items below have been grouped as operating, investing and financing, relating to the type of cash outflow that will arise.

	Expected Payment Date
($ millions)	2018	2019	2020	2021	2022	Thereafter	Total
Operating
Transportation and Storage (1)	899	886	919	1,123	1,223	13,260	18,310
Operating Leases (Building Leases)	155	146	142	141	140	2,305	3,029
Other Long-term Commitments	109	39	32	28	25	122	355
Interest on Long-term Debt	494	494	402	401	401	5,970	8,162
Decommissioning Liabilities	23	41	45	43	35	1,717	1,904
Other	11	11	9	5	4	14	54
Total Operating	1,691	1,617	1,549	1,741	1,828	23,388	31,814
Investing
Capital Commitments	16	2	-	-	-	-	18
Total Investing	16	2	-	-	-	-	18
Financing
Long-term Debt (principal only)	-	1,631	-	-	627	7,339	9,597
Other	-	-	1	-	1	2	4
Total Financing	-	1,631	1	-	628	7,341	9,601
Total Payments (2) (3)	1,707	3,250	1,550	1,741	2,456	30,729	41,433

(1) Includes transportation commitments of $9 billion that are subject to regulatory approval or have been approved but are not yet in service.

(2) Contracts on behalf of WRB Refining LP (“WRB”) are reflected at our 50 percent interest.

(3) Total commitments as at December 31, 2017 includes $29 million related to the Suffield assets that were divested on January 5, 2018.

Commitments for various pipeline transportation arrangements decreased $8.0 billion from 2016 primarily due to pipeline project cancellations, partially offset by incremental commitments included with the Acquisition and newly executed transportation agreements. Terms are up to 20 years subsequent to the date of commencement.

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

Cenovus Energy Inc. 36 2017 Management’s Discussion and Analysis

As at December 31, 2017, there were outstanding letters of credit aggregating $376 million issued as security for performance under certain contracts (December 31, 2016 – $258 million).

Legal Proceedings

We are involved in a limited number of legal claims associated with the normal course of operations. We believe that any liabilities that might arise from such matters, to the extent not provided for, are not likely to have a material effect on our Consolidated Financial Statements.

Contingent Payment

In connection with the Acquisition and related to oil sands production, we agreed to make quarterly payments to ConocoPhillips during the five years subsequent to May 17, 2017 for quarters in which the average WCS crude oil price exceeds $52 per barrel during the quarter. As at December 31, 2017, the estimated fair value of the contingent payment was $206 million. WCS averaged above $52 per barrel in the fourth quarter of 2017; therefore, $17 million is payable under this agreement. The calculation includes an adjustment mechanism related to certain significant production outages at Foster Creek and Christina Lake, which may reduce the amount of a contingent payment. As production capacity increases with future expansions, the percentage of upside available to Cenovus will increase further.

See the Corporate and Eliminations section of this MD&A for more details.

RISK MANAGEMENT AND RISK FACTORS

Cenovus is exposed to a number of risks through the pursuit of our strategic objectives. Some of these risks impact the oil and gas industry as a whole and others are unique to our operations. The impact of any risk or a combination of risks may adversely affect, among other things, Cenovus’s business, reputation, financial condition, results of operations and cash flows, which may reduce or restrict our ability to pay a dividend to our shareholders and may materially affect the market price of our securities.

Our Enterprise Risk Management (“ERM”) program drives the identification, measurement, prioritization, and management of risk across Cenovus and is integrated with the Cenovus Operations Management System (“COMS”). In addition, we continuously monitor our risk profile as well as industry best practices.

Risk Governance   The ERM Policy, approved by our Board, outlines our risk management principles and expectations, as well as the roles and responsibilities of all staff. Building on the ERM Policy, we have established Risk Management Practices, a Risk Management Framework and Risk Assessment Tools. Our Risk Management Framework contains the key attributes recommended by the International Standards Organization (“ISO”) in its ISO 31000 – Risk Management Principles and Guidelines. The results of our ERM program are documented in an Annual Risk Report presented to the Board as well as through quarterly updates.   Risk Assessment   All risks are assessed for their potential impact on the achievement of Cenovus’s strategic objectives as well as their likelihood of occurring. Risks are analyzed through the use of a Risk Matrix and other standardized risk assessment tools and each risk is classified on a continuum ranging from “Low” to “Extreme”. Management determines what, if any, additional risk treatment is required based on the residual risk ranking. There are prescribed actions for escalating and communicating risk to the right decision makers.

Significant Risk Factors

The following discussion describes the financial, operational, regulatory, environmental, reputational and other risks related to Cenovus. Each risk identified in this MD&A may individually, or in combination with other risks, have a material impact on our business, financial condition, results of operations, cash flows, or reputation.

Financial Risk

Financial risk is the risk of loss or lost opportunity resulting from financial management and market conditions. Financial risks include, but are not limited to: fluctuations in commodity prices; development and operating costs; risks related to Cenovus’s hedging activities; exposure to counterparties; availability of capital and access to sufficient liquidity; risks related to Cenovus’s credit ratings; fluctuations in foreign exchange and interest rates; and risks related to our ability to pay a dividend to shareholders. Changes in any of these economic conditions could impact a number of factors including, but not limited to, Cenovus’s cash flows, financial condition, results of

Cenovus Energy Inc. 37 2017 Management’s Discussion and Analysis

operations and growth, the maintenance of our existing operations, financial strength of our counterparties, access to capital and cost of borrowing.

Commodity Prices

Our financial performance is significantly dependent on the prevailing prices of crude oil, natural gas and refined products. Crude oil prices are impacted by a number of factors including, but not limited to: the supply of and demand for crude oil; global economic conditions; the actions of OPEC including, without limitation, compliance or non-compliance with quotas agreed upon by OPEC members and decisions by OPEC not to impose production quotas on its members; enforcement of government or environmental regulations; political stability; market access constraints and transportation interruptions (pipeline, marine or rail); the availability of alternate fuel sources; and weather conditions. Natural gas prices are impacted by a number of factors including, but not limited to: North American supply and demand; developments related to the market for liquefied natural gas; weather conditions; prices of alternate sources of energy; government or environmental regulations; and economic conditions. Refined product prices are impacted by a number of factors including, but not limited to: global supply and demand for refined products; market competitiveness; levels of refined product inventories; refinery availability; planned and unplanned refinery maintenance; weather conditions; and the availability of alternate fuel sources. All of these factors are beyond our control and can result in a high degree of price volatility. Fluctuations in currency exchange rates further compound this volatility when the commodity prices, which are generally set in U.S. dollars, are stated in Canadian dollars.

Our financial performance is also impacted by discounted or reduced commodity prices for our oil production relative to certain international benchmark prices, due, in part, to constraints on the ability to transport and sell products to international markets and the quality of oil produced. Of particular importance to us are diluent cost and supply and the price differentials between bitumen and both light to medium crude oil and heavy crude oil. Bitumen is more expensive for refineries to process and therefore trades at a discount to the market price for light and medium crude oil and heavy crude oil.

The financial performance of our refining operations is impacted by the relationship, or margin, between refined product prices and the prices of refinery feedstock. Refining margins are subject to seasonal factors as production changes to match seasonal demand. Sales volumes, prices, inventory levels and inventory values will fluctuate accordingly. Future refining margins are uncertain and decreases in refining margins may have a negative impact on our business.

Fluctuations in the price of commodities, associated price differentials and refining margins may impact the value of our assets, our cash flows, our ability to maintain our business and to fund growth projects including, but not limited to, the continued development of our oil sands properties. Prolonged periods of commodity price volatility may also negatively impact our ability to meet guidance targets and meet all of our financial obligations as they come due. Any substantial decline in these commodity prices or extended period of low commodity prices may result in a delay or cancellation of existing or future drilling, development or construction programs, curtailment in production, unutilized long-term transportation commitments and/or low utilization levels at Cenovus’s refineries.

The commodity price risks noted above, as well as the other risks such as market access constraints and transportation restrictions, reserves replacement and reserves estimates, and cost management that are more fully described herein, that may have a material impact on our business, financial condition, results of operations, cash flows or reputation, may be considered to be indicators of impairment. Another indicator of impairment is the comparison of the carrying value of our assets to our market capitalization.

As discussed in this MD&A, we conduct an annual assessment of the carrying value of our assets in accordance with IFRS. If crude oil and natural gas prices decline significantly and remain at low levels for an extended period of time, the carrying value of our assets may be subject to impairment and our net earnings could be adversely affected.

Development and Operating Costs

Our financial performance is significantly affected by the cost of developing and operating our assets. Development and operating costs are affected by a number of factors including, but not limited to: development, adoption and success of new technologies; inflationary price pressure; scheduling delays; failure to maintain quality construction and manufacturing standards; and supply chain disruptions, including access to skilled labour. Electricity, water, diluent, chemicals, supplies, reclamation, abandonment and labour costs are examples of operating costs that are susceptible to significant fluctuation.

Hedging Activities

Cenovus’s Market Risk Mitigation Policy, which has been approved by the Board, allows Management to use derivative instruments to help mitigate the impact of changes in oil and natural gas prices, diluent or condensate supply prices, refining margins, power prices, as well as fluctuations in foreign exchange rates and interest rates. Cenovus also uses derivative instruments in various operational markets to help optimize our supply cost or sales.

The use of such hedging activities exposes us to risks which may cause significant loss. These risks include, but are not limited to: changes in the valuation of the hedge instrument being not well correlated to the change in the valuation of the underlying exposures being hedged; change in price of the underlying commodity; insufficient

Cenovus Energy Inc. 38 2017 Management’s Discussion and Analysis

counterparties to transact with; counterparty default; deficiency in systems or controls; human error; and the unenforceability of contracts.

There is risk that the consequences of hedging to protect against unfavourable market conditions may limit the benefit to us of commodity price increases or changes in interest rates and foreign exchange rates. We may also suffer financial loss due to hedging arrangements if we are unable to produce oil, natural gas or refined products to fulfill our delivery obligations related to the underlying physical transaction.

We partially mitigate our exposure to commodity price risk through the integration of our business, financial instruments, physical contracts and market access commitments. Financial instruments utilized within the refining business are primarily for purchased product. For details of our financial instruments, including classification, assumptions made in the calculation of fair value and additional discussion on exposure of risks and the management of those risks, see Notes 3 and 33 to the Consolidated Financial Statements.

Impact of Financial Risk Management Activities

	2017									2016
($ millions)	Realized			Unrealized			Total			Realized			Unrealized			Total
Crude Oil (1)		307			716			1,023			(152	)		560			408
Refining		6			-			6			(1	)		5			4
Power		-			-			-			-			(14	)		(14	)
Interest Rate		-			13			13			-			3			3
Foreign Exchange		(146	)		-			(146	)		-			-			-
(Gain) Loss on Risk Management		167			729			896			(153	)		554			401
Income Tax Expense (Recovery)		(60	)		(197	)		(257	)		39			(150	)		(111	)
(Gain) Loss on Risk Management, After Tax		107			532			639			(114	)		404			290

(1) Excludes $33 million of realized risk management losses on crude oil contracts from our Conventional segment (2016 – $58 million realized risk management gains), which has been classified as a discontinued operation.

In 2017, we incurred realized losses on crude oil risk management activities, consistent with the average benchmark prices exceeding our contract prices and realized gains on foreign exchange contracts primarily due to hedging activity undertaken to support the Acquisition. Unrealized losses were recorded on our crude oil financial instruments in 2017 primarily due to the realization of settled positions and changes in market prices.

Sensitivities – Risk Management Positions

The following table summarizes the sensitivities of the fair value of our risk management positions to fluctuations in commodity prices and interest rates with all other variables held constant. Management believes the price fluctuations identified in the table below are a reasonable measure of volatility. The impact of fluctuations in commodity prices and interest rates on risk management positions as at December 31, 2017 could have resulted in unrealized gains (losses) for the year as follows:

	Sensitivity Range	Increase			Decrease
Crude Oil Commodity Price	± US$5.00 per bbl Applied to Brent, WTI and Condensate Hedges		(529	)		507
Crude Oil Differential Price	± US$2.50 per bbl Applied to Differential Hedges Tied to Production		11			(11	)
Interest Rate Swaps	± 50 Basis Points		44			(50	)

For further information on our risk management positions, see Note 34 to the Consolidated Financial Statements.

Risks Associated with Derivative Financial Instruments

Financial instruments expose Cenovus to the risk that a counterparty will default on its contractual obligations. This risk is partially mitigated through credit exposure limits, frequent assessment of counterparty credit ratings and netting arrangements, as outlined in our Credit Policy.

Exposure to Counterparties

In the normal course of business, we enter into contractual relationships with suppliers, partners and other counterparties in the energy industry and other industries for the provision and sale of goods and services. If such counterparties do not fulfill their contractual obligations, we may suffer financial losses, delays of our development plans or we may have to forego other opportunities which could materially impact our financial condition or operational results.

Credit, Liquidity and Availability of Future Financing

The future development of our business may be dependent on our ability to obtain additional capital including, but not limited to, debt and equity financing. Among other things, unpredictable financial markets, a sustained commodity price downturn, a change in market fundamentals, business operations or credit rating, or significant unanticipated expenses, may impede our ability to secure and maintain cost-effective financing. An inability to access capital could affect our ability to make future capital expenditures and to meet all of our financial obligations

Cenovus Energy Inc. 39 2017 Management’s Discussion and Analysis

as they come due, potentially creating a material adverse effect on our financial condition, results of operations, ability to comply with various financial and operating covenants, credit ratings and reputation.

Our ability to service our debt will depend upon, among other things, our future financial and operating performance, which will be affected by prevailing economic, business, market and other conditions, some of which are beyond our control. If our operating and financial results are not sufficient to service current or future indebtedness, Cenovus may take actions such as reducing dividends, reducing or delaying business activities, investments or capital expenditures, selling assets, restructuring or refinancing our debt, or seeking additional equity capital.

We mitigate our liquidity risk through the active management of cash and debt by ensuring that we have access to multiple sources of capital.

We are required to comply with various financial and operating covenants under our credit facilities and the indentures governing our debt securities. We routinely review our covenants and we may make changes to development plans or dividend policy, or take alternative actions to ensure compliance. In the event that we do not comply with such covenants, our access to capital could be restricted or repayment could be accelerated.

Credit Ratings

Our company and our long-term and short-term debt are regularly evaluated by the credit rating agencies. Credit ratings are based on our financial and operational strength and a number of factors not entirely within our control, including conditions affecting the oil and gas industry generally, and the state of the economy. There can be no assurance that one or more of our credit ratings will not be downgraded or withdrawn entirely by a rating agency.

A reduction in any of our credit ratings could adversely affect the cost and availability of borrowing, and access to sources of liquidity and capital. A failure by Cenovus to maintain current credit ratings could affect our business relationships with counterparties, operating partners and suppliers.

If one or more of our credit ratings falls below certain ratings floors we may be obligated to post collateral in the form of cash, letters of credit or other financial instruments in order to establish or maintain business arrangements. Additional collateral may be required due to further downgrades below certain ratings floors. Failure to provide adequate risk assurance to counterparties and suppliers may result in foregoing or having contractual business arrangements terminated.

Foreign Exchange Rates

Fluctuations in foreign exchange rates may affect our results as global prices for crude oil, natural gas and refined products are generally set in U.S. dollars, while many of our operating and capital costs are in Canadian dollars. A change in the value of the Canadian dollar relative to the U.S. dollar will increase or decrease revenues, as expressed in Canadian dollars, received from the sale of oil and refined products, and from some of our natural gas sales. In addition, we have chosen to borrow U.S. dollar long-term debt. A change in the value of the Canadian dollar against the U.S. dollar will result in an increase or decrease in our U.S. dollar denominated debt and related interest expense, as expressed in Canadian dollars.

To manage exposure to exchange rate fluctuations, we may periodically enter into transactions to mitigate our exposure. Exchange rate fluctuations could have a material adverse effect on our financial condition, results of operations and cash flows.

Interest Rates

We may be exposed to fluctuations in interest rates as a result of the use of floating rate securities or borrowings. An increase in interest rates could increase our net interest expense and affect how certain liabilities are recorded, both of which could negatively impact financial results. Additionally, we are exposed to interest rate fluctuations upon the refinancing of maturing long-term debt and potential future financings at prevailing interest rates.

Ability to Pay Dividends

The payment of dividends is at the discretion of the Board. Dividend payments are regularly reviewed by the Board and may be increased, reduced or suspended from time to time. Our ability to pay dividends and the actual amount of such dividends is dependent upon, among other things, financial performance, debt covenants, ability to meet financial obligations as they come due, working capital requirements, future tax obligations, future capital requirements, commodity prices and the risk factors set forth in this MD&A.

Disclosure Controls and Procedures and Internal Controls over Financial Reporting

Based on their inherent limitations, disclosure controls and procedures and internal controls over financial reporting may not prevent or detect misstatements, and even those controls determined to be effective can only provide reasonable assurance with respect to financial statement preparation and presentation. Failure to adequately prevent, detect and correct misstatements could have a material adverse effect on our business, financial condition, results of operations, cash flows, and our reputation.

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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 risks, we have a system of standards, practices and procedures called the COMS to identify, assess and mitigate safety, operational and environmental risk across our operations. In addition to leveraging COMS, we attempt to partially mitigate operational risks by maintaining a comprehensive insurance program in respect of our assets and operations.

Health and Safety

The operation of our properties is subject to hazards of finding, recovering, transporting and processing hydrocarbons including, but not limited to: blowouts; fires; explosions; railcar incident or derailment; gaseous leaks; migration of harmful substances; oil spills; corrosion; acts of vandalism and terrorism; and other accidents or hazards that may occur at or during transport to or from commercial or industrial sites. Any of these hazards can interrupt operations, impact our reputation, cause loss of life or personal injury, result in loss of or damage to equipment, property, information technology systems, related data and control systems, cause environmental damage that may include polluting water, land or air, and may result in fines, civil suits, or criminal charges against Cenovus.

Market Access Constraints and Transportation Restrictions

Our production is transported through various pipelines and our refineries are reliant on various pipelines to receive feedstock. Disruptions in, or restricted availability of, pipeline service and/or marine or rail transport, could adversely affect crude oil and natural gas sales, projected production growth, upstream or refining operations and cash flows.

Interruptions or restrictions in the availability of these pipeline systems may limit the ability to deliver production volumes and could adversely impact commodity prices, sales volumes and/or the prices received for our products. These interruptions and restrictions may be caused by the inability of the pipeline to operate, or they may be related to capacity constraints as the supply of feedstock into the system exceeds the infrastructure capacity. There can be no certainty that investments in new pipeline projects, which would result in an increase in long-term takeaway capacity, will be made by applicable third-party pipeline providers or that any applications to expand capacity will receive the required regulatory approval, or that any such approvals will result in the construction of the pipeline project. There is also no certainty that short-term operational constraints on the pipeline system, arising from pipeline interruption and/or increased supply of crude oil, will not occur.

There is no certainty that crude-by-rail, marine transport and other alternative types of transportation for our production will be sufficient to address any gaps caused by operational constraints on the pipeline system. In addition, our crude-by-rail and marine shipments may be impacted by service delays, inclement weather, railcar derailment or other rail or marine transport incidents and could adversely impact crude oil sales volumes or the price received for product or impact our reputation or result in legal liability, loss of life or personal injury, loss of equipment or property, or environmental damage. In addition, new regulations, which will be phased in over time until 2025, will require tank cars used to transport crude oil to be replaced with newer, safer tank cars, or to be retrofitted to meet the same standards. The costs of complying with the new standards, or any further revised standards, will likely be passed on to rail shippers and may adversely affect our ability to transport crude-by-rail or the economics associated with rail transportation. Finally, planned or unplanned shutdowns or closures of our refinery customers may limit our ability to deliver product with negative implications on sales and cash from operating activities.

On January 30, 2018, the British Columbia Minister of Environment and Climate Change Strategy announced proposed regulatory measures that would limit increases of diluted bitumen being transported through the province while an advisory panel studies if and how heavy oil can be transported safely. It is not clear at this time how or when the restrictions will be implemented, but they could have a material adverse impact on our ability to transport diluted bitumen.

Insufficient transportation capacity for our production will impact our ability to efficiently access end markets. This may negatively impact our financial performance by way of higher transportation costs, wider price differentials, lower sales prices at specific locations or for specific grades of crude oil, and, in extreme situations, production curtailment.

Operational Considerations

Our crude oil and natural gas operations are subject to all of the risks normally incidental to: (i) the storing, transporting, processing, refining and marketing of crude oil, natural gas and other related products; (ii) drilling and completion of crude oil and natural gas wells; and (iii) the operation and development of crude oil and natural gas properties including, but not limited to: encountering unexpected formations or pressures; premature declines of reservoir pressure or productivity; fires; explosions; blowouts; gaseous leaks; power outages; migration of harmful substances into water systems; oil spills; uncontrollable flows of crude oil, natural gas or well fluids; failure to follow operating procedures or operate within established operating parameters; equipment failures and other accidents; adverse weather conditions; pollution; and other environmental risks.

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Producing and refining oil requires high levels of investment and involves particular risks and uncertainties. Our oil operations are susceptible to loss of production, slowdowns, shutdowns, or restrictions on our ability to produce higher value products due to the interdependence of our component systems. Delineation of the resources, the costs associated with production, including drilling wells for SAGD operations, and the costs associated with refining oil can entail significant capital outlays. The operating costs associated with oil production are largely fixed in the short-term and, as a result, operating costs per unit are largely dependent on levels of production.

Although we are not the operator of the two U.S. refineries in which we have a 50 percent interest, the refining and marketing business is subject to all of the risks inherent in the operation of refineries, terminals, pipelines and other transportation and distribution facilities including, but not limited to: loss of product; failure to follow operating procedures or operate within established operating parameters; slowdowns due to equipment failure or transportation disruptions; railcar incidents or derailments; marine transport incidents; weather; fires and/or explosions; unavailability of feedstock; and price and quality of feedstock.

We do not insure against all potential occurrences and disruptions and it cannot be guaranteed that insurance will be sufficient to cover any such occurrences or disruptions. Our operations could also be interrupted by natural disasters or other events beyond our control.

Reserves Replacement and Reserve Estimates

If we fail to acquire, develop or find additional crude oil and natural gas reserves, our reserves and production will decline materially from their current levels. Our financial condition, results of operations and cash flows are highly dependent upon successfully producing from current reserves and acquiring, discovering or developing additional reserves.

There are numerous uncertainties inherent in estimating quantities of reserves, including many factors beyond our control. In general, estimates of economically recoverable crude oil and natural gas reserves and the future net cash flows and revenue derived therefrom are based on a number of variable factors and assumptions including, but not limited to: product prices; future operating and capital costs; historical production from the properties and the assumed effects of regulation by governmental agencies, including royalty payments and taxes; initial production rates; production decline rates; and the availability, proximity and capacity of oil and gas gathering systems, pipelines, rail transportation and processing facilities, all of which may cause actual results to vary materially from estimated results.

All such estimates are to some degree uncertain and classifications of reserves are only attempts to define the degree of uncertainty involved. For those reasons, estimates of the economically recoverable crude oil and natural gas reserves attributable to any particular group of properties, classification of such reserves based on risk of recovery and estimates of future net revenue expected therefrom, prepared by different engineers or by the same engineers at different times, may vary substantially. Our actual production, revenues, taxes and development and operating expenditures with respect to our reserves may vary from current estimates and such variances may be material.

Estimates with respect to reserves that may be developed and produced in the future are often based on volumetric calculations and upon analogy to similar types of reserves, rather than upon actual production history. Subsequent evaluation of the same reserves based on production history will result in variations, which may be material, in the estimated reserves.

The production rate of oil and gas properties tends to decline as reserves are depleted while the associated operating costs increase. Maintaining an inventory of developable projects to support future production of crude oil and natural gas depends on, among other things: obtaining and renewing rights to explore, develop and produce oil and natural gas; drilling success; completing long-lead time capital intensive projects on budget and on schedule; and the application of successful exploitation techniques on mature properties. Our business, financial condition, results of operations and cash flows are highly dependent upon successfully producing current reserves and adding additional reserves.

Cost Management

Our operating costs could escalate and become uncompetitive due to inflationary cost pressures, equipment limitations, escalating supply costs, commodity prices, higher steam-to-oil ratios in our oil sands operations, and additional government or environmental regulations. Our inability to manage costs may impact project returns and future development decisions, which could have a material adverse effect on our financial condition, results of operations and cash flows.

Competition

The Canadian and international petroleum industry is highly competitive in all aspects, including the exploration for, and the development of, new and existing sources of supply, the acquisition of crude oil and natural gas interests and the refining, distribution and marketing of petroleum products. We compete with other producers and refiners, some of which may have lower operating costs or greater resources than our company does. Competing producers may develop and implement recovery techniques and technologies which are superior to those we employ. The petroleum industry also competes with other industries in supplying energy, fuel and related products to consumers.

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Companies may announce plans to enter the oil sands business, to begin production or to expand existing operations. Expansion of existing operations and development of new projects could materially increase the supply of crude oil in the marketplace which may decrease the market price of crude oil, constrain transportation and increase our input costs for and constrain the supply of skilled labour and materials.

Project Execution

There are risks associated with the execution and operation of our upstream growth and development projects. These risks include, but are not limited to: our ability to obtain the necessary environmental and regulatory approvals; risks relating to schedule, resources and costs, including the availability and cost of materials, equipment and qualified personnel; the impact of general economic, business and market conditions; the impact of weather conditions; risk related to the accuracy of project cost estimates; ability to finance growth; ability to source or complete strategic transactions; and the effect of changing government regulation and public expectations in relation to the impact of oil sands and conventional development on the environment. The commissioning and integration of new facilities within our existing asset base could cause delays in achieving performance targets and objectives. Failure to manage these risks could have a material adverse effect on our financial condition, results of operations and cash flows.

Partner Risks

Some of our assets are not operated by us or are held in partnership with others. Therefore, our results of operations and cash flows may be affected by the actions of third party operators or partners. Our refining assets are held in a partnership with Phillips 66 and operated by Phillips 66. The success of the refining operations is dependent on the ability of Phillips 66 to successfully operate this business and maintain the refining assets. We rely on the judgment and operating expertise of Phillips 66 in respect of the operation of such refining assets and we also rely on Phillips 66 to provide information on the status of such refining assets and related results of operations.

Phillips 66 may have objectives and interests that do not align with or may conflict with our interests. Major capital decisions affecting these refining assets require agreement between each respective partner, while certain operational decisions may be made by the operator of the assets. While we generally seek consensus with respect to major decisions concerning the direction and operation of these refining assets, no assurance can be provided that the future demands or expectations of either party relating to such assets will be satisfactorily met or met in a timely manner or at all. Unmet demands or expectations by either party or demands and expectations which are not satisfactorily met may affect our participation in the operation of such assets, our ability to obtain or maintain necessary licences or approvals or affect the timing of undertaking various activities.

Technology

Current SAGD technologies for the recovery of bitumen are energy intensive, requiring significant consumption of natural gas in the production of steam that is used in the recovery process. The amount of steam required in the production process varies and therefore impacts costs. The performance of the reservoir can also affect the timing and levels of production using this technology. A large increase in recovery costs could cause certain projects that rely on SAGD technology to become uneconomical, which could have a negative effect on our business, financial condition, results of operations and cash flows. There are risks associated with growth and other capital projects that rely largely or partly on new technologies and the incorporation of such technologies into new or existing operations. The success of projects incorporating new technologies cannot be assured.

Information Systems

We rely heavily on information technology, such as computer hardware and software systems, in order to properly operate our business. In the event we are unable to regularly deploy software and hardware, effectively upgrade systems and network infrastructure, and take other steps to maintain or improve the efficiency and efficacy of systems, the operation of such systems could be interrupted or result in the loss, corruption, or release of data.

In the ordinary course of business, we collect, use and store sensitive data, including intellectual property, proprietary business information and personal information of our employees and third parties. Despite our security measures, our information systems, technology and infrastructure may be vulnerable to attacks by hackers and/or cyberterrorists or breaches due to employee error, malfeasance or other disruptions, including natural disasters and acts of war. Any such breach could compromise information used or stored on our systems and/or networks and, as a result, the information could be accessed, publicly disclosed, lost or stolen. Any such access, disclosure or other loss of information could result in legal claims or proceedings, liability under laws that protect the privacy of personal information, regulatory penalties, operational disruption, site shut-down, leaks or other negative consequences, including damage to our reputation, which could have a material adverse effect on our business, financial condition, results of operations and cash flows.

Leadership and Talent

Our success is dependent upon our Management, our leadership capabilities and the quality and competency of our talent. In 2017, Cenovus implemented a number of changes at the executive leadership level, including the appointment of Alex Pourbaix as President & Chief Executive Officer and as a member of the Board. We believe that these leadership changes will help Cenovus continue to evolve into a highly effective organization focused on

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delivering strong returns for shareholders. Failure to align and effectively integrate the new leadership team, retain critical talent or to attract and retain new talent with the necessary leadership, professional and technical competencies could have a material adverse effect on our financial condition, results of operations and pace of growth.

Litigation

From time to time, we may be the subject of litigation arising out of our operations. Claims under such litigation may be material or may be indeterminate. Various types of claims may be made including, without limitation, environmental damages, breach of contract, negligence, product liability, antitrust, bribery and other forms of corruption, tax, patent infringement and employment matters. The outcome of such litigation is uncertain and may materially impact our financial condition or results of operations. Moreover, unfavorable outcomes or settlements of litigation could encourage the commencement of additional litigation. We may also be subject to adverse publicity associated with such matters, regardless of whether we are ultimately found responsible. We may be required to incur significant expenses or devote significant resources in defense against any such litigation.

Aboriginal Land and Rights Claims

Aboriginal groups have claimed aboriginal treaty, title and rights to portions of Western Canada, including British Columbia and Alberta, and such claims, if successful, could have a material negative impact on our operations or pace of growth. In 2014, the Supreme Court of Canada granted Aboriginal title over non-treaty lands, representing the first instance of such a declaration. There exist outstanding Aboriginal and treaty rights claims, which may include Aboriginal title claims, on lands where we operate. No certainty exists that any lands currently unaffected by claims brought by Aboriginal groups will remain unaffected by future claims. Recent outcomes of litigation concerning Aboriginal rights may result in increased claims and litigation activity in the future.

The federal and provincial governments have a duty to consult with Aboriginal people on actions and decisions that may affect the asserted Aboriginal or treaty rights and, in certain cases, accommodate their concerns. The scope of the duty to consult by federal and provincial governments is subject to ongoing litigation. The fulfillment of the duty to consult, and where required accommodate, Aboriginal people may adversely affect our ability to, or increase the timeline to, obtain or renew, permits, leases, licenses and other approvals, or to meet the terms and conditions of those approvals. Opposition by Aboriginal groups may also negatively impact us in terms of public perception, diversion of Management’s time and resources, legal and other advisory expenses, potential blockades or other interference by third parties in our operations, or court-ordered relief impacting operations. Challenges by Aboriginal groups could adversely impact our progress and ability to explore and develop properties.

In May 2016, Canada announced its support for the United Nations Declaration on the Rights of Indigenous Peoples (“UNDRIP”). The principles and objectives of UNDRIP have also been endorsed by the Government of Alberta and the Government of British Columbia. The means of implementation of UNDRIP by government bodies are uncertain and may include an increase in consultation obligations and processes associated with project development, posing risks and creating uncertainty with respect to project regulatory approval timelines and requirements.

Regulatory Risk

Regulatory risk is the risk of loss or lost opportunity resulting from the introduction of, or changes in, regulatory requirements or the failure to secure regulatory approval for upstream or downstream development projects. The implementation of new regulations or the modification of existing regulations could impact our existing and planned projects as well as result in compliance costs, adversely impacting our financial condition, results of operations and cash flows.

The oil and gas industry in general and our operations in particular are subject to regulation and intervention under federal, provincial, territorial, state and municipal legislation in Canada and the U.S. in matters such as, but not limited to: land tenure; permitting of production projects; royalties; taxes (including income taxes); government fees; production rates; environmental protection controls; protection of certain species or lands; provincial and federal land use designations; the reduction of greenhouse gases (“GHGs”) and other emissions; the export of crude oil, natural gas and other products; the transportation of crude-by-rail or marine transport; the awarding or acquisition of exploration and production, oil sands or other interests; the imposition of specific drilling obligations; control over the development, abandonment and reclamation of fields (including restrictions on production) and/or facilities; and possibly expropriation or cancellation of contract rights. Changes to government regulation could impact our existing and planned projects or increase capital investment or operating expenses, adversely impacting our financial condition, results of operations and cash flows.

Regulatory Approvals

Our operations require us to obtain approvals from various regulatory authorities and there are no guarantees that we will be able to obtain all necessary licences, permits and other approvals that may be required to carry out certain exploration and development activities on our properties. In addition, obtaining certain approvals from regulatory authorities can involve, among other things, stakeholder and Aboriginal consultation, environmental impact assessments and public hearings. Regulatory approvals obtained may be subject to the satisfaction of certain conditions including, but not limited to: security deposit obligations; ongoing regulatory oversight of projects; mitigating or avoiding project impacts; habitat assessments; and other commitments or obligations.

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Failure to obtain applicable regulatory approvals or satisfy any of the conditions thereto on a timely basis on satisfactory terms could result in delays, abandonment or restructuring of projects and increased costs.

Abandonment and Reclamation Cost Risk

The current oil and gas asset abandonment, reclamation and remediation (“A&R”) liability regime in Alberta as a general rule limits each party’s liability to its proportionate ownership of an asset. In the case where one joint owner becomes insolvent and is unable to fund the A&R activities, the solvent counterparties can claim the insolvent party’s share of the remediation costs against the Orphan Well Association (the “OWA”). The OWA administers orphaned assets and is funded through a levy imposed on licensees, including Cenovus, based on their proportionate share of deemed A&R liabilities for oil and gas facilities, wells and unreclaimed sites in Alberta. British Columbia has a similar liability management regime.

The Alberta Court of Queen’s Bench issued a decision in the case of Redwater Energy Corporation, (“Redwater”) that trustees and receivers of insolvent parties may disclaim or renounce uneconomic oil and gas assets to the AER before commencing the sales process for the insolvent party’s assets. These wells and facilities then become “orphans” to be remediated by the OWA. The Alberta Court of Appeal upheld the trial judge’s decision in Redwater (“Redwater Appeal”), and the AER has been granted leave to appeal the Redwater Appeal to the Supreme Court of Canada.

In response to Redwater, the AER released Bulletin 2016-16 which, among other things, implements important changes to the AER’s procedures relating to liability management ratings, licence eligibility and licence transfers. In addition, changes with respect to licence eligibility were codified in amendments to AER Directive 067: Eligibility Requirements for Acquiring and Holding Energy Licences and Approvals. Among other things, Directive 067 provides the AER with broad discretion to determine if a party poses an “unreasonable risk” such that they should not be eligible to hold AER licences.

The government of British Columbia has announced similar policies. The British Columbia Oil and Gas Commission is also exploring the development of a comprehensive liability management strategy, driven in part by the Redwater decision, and the proliferation of orphan sites. The imposition of timelines for inactive sites is among the measures under consideration.

These changes may impact Cenovus’s ability to transfer our licences, approvals or permits, and may result in increased costs and delays or require changes to or abandonment of projects and transactions. Because of Redwater and the current economic environment, the number of orphaned wells in Alberta has increased significantly and, accordingly, the aggregate value of the A&R liabilities assumed by the OWA has increased and may continue to increase. The OWA may seek funding for such liabilities from industry participants, including Cenovus through an increase in its annual levy, further changes to regulations or other means. While the impact on Cenovus of any legislative, regulatory or policy decisions as a result of the Redwater decision and its pending appeal cannot be reliably or accurately estimated, any cost recovery or other measures taken by applicable regulatory bodies may impact Cenovus and materially and adversely affect, among other things, our business, financial condition, results of operations and cash flows.

Royalty Regimes

Our cash flows may be directly affected by changes to royalty regimes. The governments of Alberta and British Columbia receive royalties on the production of hydrocarbons from lands in which they respectively own the mineral rights. Government regulation of Crown royalties is subject to change for a number of reasons, including, among other things, political factors. Royalties are typically calculated based on benchmark prices, productivity per well, location, date of discovery, recovery method, well depth and the nature and quality of petroleum product produced. There is also a mineral tax in each province levied on hydrocarbon production from lands in which the Crown does not own the mineral rights. The potential for changes in the royalty and mineral tax regimes applicable in the provinces in which Cenovus operates creates uncertainty relating to the ability to accurately estimate future Crown burdens and could have a significant impact on our business, financial condition, results of operations and cash flows.

The Government of Alberta has implemented a modernized royalty framework (the “Modernized Framework”) which applies to all conventional wells spud on or after January 1, 2017. The Modernized Framework does not apply to oil sands production, which has its own separate royalty framework. Wells spud prior to July 13, 2016 will continue to operate under the previous royalty framework. Wells spud between such dates may elect to opt-in to the Modernized Framework if certain criteria are met. After December 31, 2026, all wells will be subject to the Modernized Framework. As part of the Modernized Framework, the Alberta government announced two new strategic royalty programs to encourage oil and gas producers to boost production and explore resources in new areas: the Enhanced Hydrocarbon Recovery Program and the Emerging Resources Program. These programs will take into account the higher costs associated with development of emerging resources and enhanced recovery methods when calculating royalty rates. The royalty structure and rates for oil sands production in Alberta remain generally unchanged following the royalty review. The Government of Alberta has indicated that it plans to modernize the process of calculating costs and collecting oil sands royalties, and has recently implemented public disclosure of cost, revenue and collection information relating to oil sands projects and royalties.

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Further changes to any of the royalty regimes in Alberta, changes to the existing royalty regimes in British Columbia, changes to how existing royalty regimes are interpreted and applied by the applicable governments, or an increase in disclosure obligations for Cenovus could have a significant impact on our business, financial condition, results of operations and cash flows. An increase in the royalty rates in Alberta or British Columbia would reduce our earnings and could make, in the respective province, future capital expenditures or existing operations uneconomic. A material increase in royalties or mineral taxes may reduce the value of our associated assets.

Environmental Regulatory Risk

All phases of crude oil, natural gas and refining operations are subject to environmental regulation pursuant to a variety of Canadian and U.S. federal, provincial, territorial, state and municipal laws and regulations (collectively, the “environmental regulations”). Environmental regulations provide that wells, facility sites, refineries and other properties and practices associated with our operations be constructed, operated, maintained, abandoned, reclaimed and undertaken in accordance with the requirements set out therein. In addition, certain types of operations, including exploration and development projects and changes to certain existing projects, may require the submission and approval of environmental impact assessments or permit applications. Environmental regulations impose, among other things, restrictions, liabilities and obligations in connection with the generation, handling, use, storage, transportation, treatment and disposal of hazardous substances and waste and in connection with spills, releases and emissions of various substances in the environment. They also impose restrictions, liabilities and obligations in connection with the management of water sources that are being used, or whose use is contemplated, in connection with oil and gas operations. The complexities of changes in environmental regulations make it difficult to predict the potential future impact to Cenovus.

Compliance with environmental regulations can require significant expenditures, including costs and damages arising from releases or contaminated properties or spills, or from new compliance obligations. We anticipate that future capital expenditures and operating expenses could continue to increase as a result of the implementation of new environmental regulations. Failure to comply with environmental regulations may result in the imposition of fines, penalties, environmental protection orders, suspension of operations, and could adversely impact our reputation. The costs of complying with environmental regulations may have a material adverse effect on our business, financial condition, results of operations and cash flows. The implementation of new environmental regulations or the modification of existing environmental regulations affecting the crude oil and natural gas industry generally could reduce demand for crude oil and natural gas and increase compliance costs, and have an adverse impact on our business, financial condition, results of operations and cash flows. There is also risk that we could face litigation initiated by third parties relating to climate change or other environmental regulations.

Climate Change Regulation

Various federal, provincial and state governments have announced intentions to regulate GHG emissions. Some of these regulations are in effect while others remain in various phases of review, discussion or implementation in the U.S. and Canada.

In 2016, the Government of Canada ratified the international Paris Agreement on climate change and announced a new national carbon pricing regime (the “Carbon Strategy”). All Canadian provinces and territories except Saskatchewan and Manitoba signed the pan-Canadian framework to implement the Carbon Strategy. In 2018, the Federal Government released the draft Greenhouse Gas Pollution Pricing Act under the Carbon Strategy, which specifies (i) a carbon price on fossil fuels of $10 per tonne of carbon dioxide equivalent (“CO2e”) in 2018, rising by $10 per year to $50 per tonne CO2e in 2022 and (ii) an Output-Based Pricing System (“OBPS”) for industrial facilities with annual emissions of 50 kilotonnes of GHG per year or more. OBPS facilities will be subject to the carbon price on the portion of emissions that exceed an annual output-based emissions limit, which can be satisfied by paying a charge, applying federally issued surplus credits or eligible offset credits. The design of this system is currently under development.

The Alberta Climate Leadership Plan, sets forth several commitments relevant to the oil and gas sector: (1) the implementation of an economy-wide carbon levy; (2) limiting of oil sands emissions to a province-wide total of 100 megatonnes per year (compared to current industry emissions levels of approximately 70 megatonnes per year), with certain exceptions for cogeneration power sources and new upgrading capacity; and (3) a goal to reduce methane emissions from oil and gas activities by 45 percent by 2025. The economy-wide carbon levy is based on a rate of $30 per tonne for 2018 and exempts activities integral to oil and gas production processes until 2023.

The Alberta Carbon Competitiveness Incentive Regulation (“CCIR”, effective January 1, 2018) applies to facilities that emit greater than 100,000 tonnes of GHG per year. Facilities are exempt from the carbon levy, but are required to meet an emissions intensity benchmark which is set based on industry performance. Where emissions exceed the benchmark, the facility must reduce its net emissions by applying emissions offsets, emissions performance credits or fund credits against its actual emissions level. The benchmarks are subject to future adjustment.

The British Columbia Carbon Tax Act sets a carbon price of $30 per tonne of CO2e on fuel combustion. Beginning April 1, 2018, the provincial carbon tax is expected to increase by $5 per tonne of CO2e per year, reaching the federal target carbon price of $50 on April 1, 2021. The tax may also be expanded to fugitive and vented emissions

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from the oil and gas sector. The British Columbia government has signalled further measures, such as reducing upstream methane emissions by 45 percent and may establish separate sectoral reduction goals and plans. The government has also indicated their intention to work with emissions intensive industries to maintain their competitiveness. Further details have not yet been announced.

In 2017, the federal government also proposed regulations to limit the release of methane and volatile organic compounds with staged implementation over the 2020 to 2023 time period. Provinces may establish their own methane reduction regulations and set up equivalency agreements with the federal government. Alberta is developing methane reduction rules that are expected to align with the federal government’s proposed regulations.

It is expected that the carbon pricing systems in Alberta and British Columbia will meet the requirements of the federal Greenhouse Gas Pollution Pricing Act. Our operating oil sands assets and two of our natural gas processing facilities are subject to the CCIR and are therefore exempt from the Alberta carbon levy. The carbon levy exemption for activities integral to oil and gas production processes applies to the vast majority of emissions related to activities in our Deep Basin assets. In 2023, when the current exemptions are expected to end, we expect that some of our conventional oil and gas production facilities will be eligible to opt-in to the CCIR thereby mitigating a portion of the cost associated with the carbon levy.

Uncertainties exist relating to the timing and effects of these emerging regulations, other contemplated legislation, including how they may be harmonized, making it difficult to accurately determine the cost impacts and effects on our suppliers. Additional changes to climate change legislation may adversely affect our business, financial condition, results of operations and cash flows, which cannot be reliably or accurately estimated at this time.

Other possible effects from emerging regulations may also include, but are not limited to: increased compliance costs; permitting delays; substantial costs to generate or purchase emission credits or allowances, all of which may increase operating expenses. Further, emission allowances or offset credits may not be available for acquisition or may not be available on an economic basis, required emission reductions may not be technically or economically feasible to implement, in whole or in part, and failure to have access to such resources or technology to meet such emission reduction requirements or other compliance mechanisms may have a material adverse effect on our business resulting in, among other things, fines, permitting delays, penalties and the suspension of operations.

Cenovus’s analysis suggests that we will remain financially resilient over the long-term under a range of climate policy scenarios. However, the extent and magnitude of any adverse impacts of additional programs or regulations beyond reasonably foreseeable requirements cannot be reliably or accurately estimated at this time because specific legislative and regulatory requirements have not been finalized and uncertainty exists with respect to the additional measures being considered and the time frames for compliance. Consequently, no assurances can be given that the effect of future climate change regulations will not be significant to Cenovus.

Low Carbon Fuel Standards

Existing and proposed environmental legislation developed by certain U.S. states, Canadian provinces, the Canadian federal government and members of the European Union, regulating carbon fuel standards could result in increased costs and reduced revenue. The potential regulation may negatively affect the marketing of Cenovus’s bitumen, crude oil or refined products, and may require us to purchase emissions credits in order to affect sales in such jurisdictions.

On December 13, 2017, Environment and Climate Change Canada published a regulatory framework on its proposed clean fuel standard regulation to be adopted under the Canadian Environmental Protection Act, 1999. The federal government is expected to release draft regulations in 2018. The clean fuel standard regulation will establish lifecycle carbon intensity requirements separately for liquid, gaseous and solid fuels that are used in transportation, industry and buildings. The stated purpose of the clean fuel standard is to incent the use of a broad range of low carbon fuels, energy sources and technologies. The clean fuel standard will apply to liquid, gaseous and solid fuels combusted for the purpose of creating energy, including “self-produced and used” fuels (i.e., those fuels that are used by producers or importers). The clean fuel standard regulation has the potential to impact our business, financial condition, results of operations and cash flows, though at this time it is difficult to predict or quantify any such impacts.

The state of California and the province of British Columbia have implemented climate change regulation in the form of a Low Carbon Fuel Standard and the Renewable and Low Carbon Fuel Requirements Regulation, respectively. The regulations require the reduction of life cycle carbon emissions from transportation fuels. As an oil sands producer, we are not directly regulated and are not expected to have a compliance obligation. Refiners in California and British Columbia are required to comply with the legislation.

Renewable Fuel Standards

Our U.S. refining operations are subject to various laws and regulations that impose stringent and costly requirements. Of specific note is the Energy Independence and Security Act of 2007 (“EISA 2007”) that established energy management goals and requirements. Pursuant to EISA 2007, among other things, the Environmental Protection Agency issued the Renewable Fuel Standard program that mandates the total volume of renewable transportation fuel sold or introduced in the U.S. and requires renewable fuels such as ethanol and advanced biofuels to be blended with gasoline by the obligated party.

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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 RINs, in the open market. A RIN is a number assigned to each gallon of renewable fuel produced or imported into the U.S. RIN numbers were implemented to provide refiners with flexibility in complying with the renewable fuel standards.

Our refineries do not blend renewable fuels into the motor fuel products they produce and, consequently, we are obligated, through WRB, to purchase RINs in the open market, where prices fluctuate. In the future, the regulations could change the volume of renewable fuels required to be blended with refined products, creating volatility in the price for RINs or an insufficient number of RINs being available in order to meet the requirements. Our financial condition, results of operations, and cash flows may be materially adversely impacted as a result.

Marine Fuel Oil Sulphur Specification

As a specialized agency of the United Nations and the main regulatory body for the shipping industry, the International Maritime Organization (“IMO”) is the global standard-setting authority for the safety, security and environmental performance of international shipping. IMO has set a global limit for sulphur in fuel oil used on board ships of 0.5 weight percent from January 1, 2020, drastically changed from the current upper limit of 3.5 weight percent. This will significantly reduce the amount of sulphur oxide emanating from ships and IMO expects major health and environmental benefits for the world, particularly for populations living close to ports and coasts.

Refineries worldwide currently blend around three million barrels per day of high sulphur Residual Fuel Oil (“RFO”) with lighter oil to make bunker fuel oil for the shipping industry. RFO is an outlet at the refinery for difficult to process crude components, usually high sulphur residuum. Sulphur reduction for RFO is more difficult than for lighter distillates as the asphaltene content in RFO requires more costly and complex processing.

Cenovus crude production contains a large amount of high sulphur residuum. Most of Cenovus’s crude is processed by complex refineries. However, after 2020, the availability of complex refining capacity may become scarce. This coming IMO sulphur regulation has the potential to materially adversely impact our crude marketing and may materially contribute to increased widening of the light to heavy crude oil differential, distressing pricing for heavier crude oils including bitumen. The severity of the impact depends on the enforcement of the regulation, the worldwide heavy sour crude production and additional heavy processing availability.

Alberta’s Land-Use Framework

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

The Government of Alberta has implemented the Lower Athabasca Regional Plan (“LARP”), under the ALSA. The LARP identifies legally-binding management frameworks, including for air, land and water, which will incorporate cumulative limits and triggers as well as identifying areas related to conservation, tourism and recreation. Uncertainty exists with respect to the impact to future development applications in the areas covered by the LARP, including the potential for development restrictions and mineral rights cancellation.

The Government of Alberta has also implemented the South Saskatchewan Regional Plan (“SSRP”) and has commenced the regional planning process for the North Saskatchewan Regional Plan (“NSRP”) under the ALSA. SSRP is not expected to materially impact Cenovus’s existing operations, but may impact any future development Cenovus may undertake within the region. No assurance can be given that the NSRP, or any future regional plans developed and implemented by the Government of Alberta, will not materially impact operations or future operations in their applicable regions.

Species at Risk Act

The Canadian federal legislation, Species at Risk Act, and provincial counterparts regarding threatened or endangered species may limit the pace and the amount of development in areas identified as critical habitat for species of concern, such as woodland caribou. Recent litigation against the federal government in relation to the Species at Risk Act has raised issues associated with the protection of species at risk and their critical habitat both federally and on a provincial level. In Alberta, the Alberta Caribou Action and Range Planning Project has been established to develop range plans and action plans with a view to achieving the maintenance and recovery of Alberta’s 15 caribou populations. Similar planning has been undertaken in British Columbia by the Ministry of Environment and the Ministry of Forests, Lands, and Natural Resource Operations.

In 2017, the British Columbia government released its Draft Boreal Caribou Recovery Implementation Plan for comment, and the Alberta government released its Draft Provincial Woodland Caribou Range Plan for comment. Both draft plans focus largely on reduction of linear features, such as seismic lines. If action and range plans developed by the provinces are deemed not to provide sufficient likelihood of caribou recovery, the federal legislation includes the ability to implement measures that would preclude further development or modify existing operations. The federal and/or provincial implementation of measures to protect species at risk such as woodland caribou and their critical habitat in areas of Cenovus’s current or future operations may modify our pace and amount of development.

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Federal Air Quality Management System

The Multi-sector Air Pollutants Regulations (“MSAPR”), issued under the Canadian Environmental Protection Act, 1999, seek to protect the environment and health of Canadians by setting mandatory, nationally-consistent air pollutant emission standards. The MSAPR are aimed at equipment-specific Base-Level Industrial Emissions Requirements (“BLIERs”). Nitrogen oxide BLIERs from our non-utility boilers, heaters and reciprocating engines are regulated in accordance with specified performance standards. We do not anticipate a material impact to existing or future operations as a result of the MSAPR.

Canadian Ambient Air Quality Standards (“CAAQS”) for fine particulate matter (“PM2.5”) and ozone were introduced as part of a national Air Quality Management System (“AQMS”). Provincial level implementation of the CAAQS may occur at the regional air zone level and air zone management actions may include more stringent emissions standards applicable to industrial sources from approval holders in regions where Cenovus operates that may result in adverse impacts such as but not limited to increased operating costs.

Federal Review of Environmental and Regulatory Processes

In 2016, the Government of Canada commenced a review of the environmental and regulatory processes administered under the National Energy Board Act, Canadian Environmental Assessment Act, Fisheries Act, and the Navigation Protection Act. In February 2018, the Government of Canada proposed amendments to the Fisheries Act and the Navigation Protection Act, and proposed the enactment of the Impact Assessment Act, and the Canadian Energy Regulator Act.

The proposed Fisheries Act amendments restore the previous prohibition against “harmful alteration, disruption or destruction of fish habitat” (“HADD”) and introduce several new requirements to expand the act’s scope of protection and role of Aboriginal groups and interests. The HADD requirement may result in increased permitting requirements where our operations potentially impact fish habitat.

The proposed changes to the Navigation Protection Act, including renaming the Act to the Canadian Navigable Waters Act, will expand the scope to all navigable waters, create greater oversight for navigable waters and, consistent with the Fisheries Act, introduces requirements to expand the Act’s scope of protection and the role of Aboriginal groups and interests.

The proposed Impact Assessment Act, will replace the Canadian Environmental Assessment Act and, if passed, will establish the Impact Assessment Agency of Canada, which will lead and coordinate impact assessments for all designated projects, including those previously administered by the National Energy Board. The proposed amendments expand the assessment considerations beyond environment to include health, society, economy, social, gender and impacts on Aboriginal peoples. The proposed Canadian Energy Regulator Act is intended to replace the National Energy Board with the Canadian Energy Regulator and modify the regulator’s role.

The proposed amendments are subject to change as they work through the Parliamentary process. The extent and magnitude of any adverse impacts of changes to the legislation or programs on project development and operations cannot be reliably or accurately estimated at this time as uncertainty exists with respect to how the legislative changes that will be implemented and what the accompanying regulations, including the designated project list, will look like. Increased environmental assessment obligations and reporting obligations may create risk of increased costs and project development delays.

British Columbia Review of Environmental and Regulatory Processes

In 2017, the Government of British Columbia committed to reviewing the province’s environmental assessment process and other regulatory processes, including enacting an endangered species law and harmonizing other laws related to the environment. The government has commenced a review into the adequacy and oversight of professional reliance model employed in the natural resource sector and has introduced regulations requiring spill preparedness for transporters of liquid petroleum products in British Columbia. The government has also reaffirmed their commitment to proceed with a scientific review of hydraulic fracturing to determine impacts on water and the relationship to seismic activity.

The Government of British Columbia has proposed regulations relating to liquid petroleum spill response and recovery. The proposed regulations include regulating spill response times, compensation for loss of public and cultural use of land, resources or public amenities in the case of spills, and creating geographic response plans in certain areas. The government will also establish an independent scientific advisory panel to recommend whether, and how, heavy oils (such as bitumen) can be safely transported and cleaned up. As noted, while the advisory panel is proceeding, the government is proposing regulatory restrictions on the increase of diluted bitumen transportation.

The extent and magnitude of any adverse impacts of changes to the legislation or policies on project development and operations cannot be estimated at this time as uncertainty exists with respect to recommendations being considered or to be developed. Increased environmental assessment obligations or transportation restrictions may create risk of increased costs and project development delays.

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Water Licences

In Alberta, we utilize fresh water in certain operations, which is obtained under licences issued pursuant to the Water Act to provide domestic and utility water at our SAGD facilities and for our bitumen delineation programs and our activities in the Deep Basin. Currently, we are not required to pay for the water we use under these licenses. There can be no assurance that we will not have to pay a fee for the use of water in the future or that any such fees will be reasonable. If a change under these licences reduces the amount of water available for our use, production could decline or operating expenses could increase, both of which may have a material adverse effect on our business and financial performance. There can be no assurance that the licences to withdraw water will not be rescinded or that additional conditions will not be added to these licences. In addition, the expansion of our projects rely on securing licences for additional water withdrawal, and there can be no assurance that these licences will be granted on terms favourable to us, or at all, or that such additional water will in fact be available to divert under such licences.

In British Columbia, groundwater use is regulated with the coming into force of the Water Sustainability Act. Most groundwater use (other than domestic use) requires a water licence to divert water from an aquifer. There is a three year period for existing non-domestic groundwater users to transition into the current water licensing scheme and its first-in-time, first-in-right priority system. There are annual water rental fees established by the regulations to the Water Sustainability Act. Additional supporting regulations continue to be proposed and brought into force.

Water use fees may increase and licence terms and conditions may be amended in the future, which may adversely affect our business including ability to operate. In addition, there is no assurance that if we require new licences or amendments to existing licences, that these licences or amendments will be granted on favourable terms.

Alberta Wetland Policy

Wetland management within Alberta is regulated by section 36 of the Water Act, together with the Alberta Wetland Policy and the Provincial Wetland Restoration and Compensation Guide.

Pursuant to the Alberta Wetland Policy, developers of oil and gas assets in wetlands areas may be required to avoid the wetlands or mitigate the development’s effects on wetlands.

The Alberta Wetland Policy is not expected to affect Cenovus’s existing operations in Foster Creek, Christina Lake and Narrows Lake, where our 10 year wetlands mitigation and monitoring plans were approved under the previous wetland policy. However, new project developments and future phase expansions will likely be affected by aspects of this policy as our oil sands leases are in areas where wetlands cover over 50 percent of the landscape. Development of some projects within our Deep Basin asset near wetland regions will also be affected by the policy. ‘Avoidance’ may not be an option for new projects, developments and phase expansions. We expect to be required to comply with requirements for wetland reclamation or, where permanent wetland loss will occur, wetland replacement. In accordance with the Alberta Wetland Restoration Directive, 2016, mechanisms for restorative replacement include purchase of credits (under development), payment to an in-lieu fee program, or permittee-responsible replacement action.

Based on written statements in the Alberta Wetland Mitigation Directive, 2016 and consultation with Alberta Environment and Parks as well as the AER, we do not anticipate a material impact on our oil sands or unconventional assets in the Deep Basin. However, it remains unclear how the policy will be implemented and no assurance can be given that the policy will not have an impact on future development plans at this time.

Hydraulic Fracturing

Certain stakeholders have made claims that hydraulic fracturing techniques are harmful to surface water and drinking water sources and suggest that additional federal, provincial, territorial and/or municipal laws and regulations may be needed to more closely regulate the hydraulic fracturing process.

The Canadian federal government and certain provincial governments continue to review certain aspects of the existing scientific, regulatory and policy framework under which hydraulic fracturing operations are conducted. Further, certain governments in jurisdictions where the Company does not currently operate have considered or implemented moratoriums on hydraulic fracturing until further studies can be completed and some governments have adopted, and others have considered adopting, regulations that could impose more stringent permitting, disclosure and well construction requirements on hydraulic fracturing operations.

Any new laws, regulations or permitting requirements regarding hydraulic fracturing could lead to limitations or restrictions to oil and gas development activities, operational delays, additional operating requirements, or increased third-party or governmental claims that could increase our cost of compliance and doing business as well as reduce the amount of natural gas and oil that Cenovus is ultimately able to produce from its reserves.

Seismic Activity

Some areas of British Columbia and Alberta are experiencing increasing localized frequency of seismic activity which has been associated with oil and gas operations. Although the occurrence of seismicity in relation to oil and gas operations is generally very low, it has been linked to deep disposal of wastewater in the U.S. and has been correlated with hydraulic fracturing in western Canada which has prompted legislative and regulatory initiatives intended to address these concerns.

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These initiatives have the potential to require additional monitoring, restrict the injection of produced water in certain disposal wells and/or modify or curtail hydraulic fracturing operations which could lead to operational delays, increase compliance costs or otherwise adversely impact Cenovus’s operations.

Oil and Gas Activities Act

In British Columbia, the Oil and Gas Activities Act (the “OGAA”) impacts conventional crude oil and natural gas producers, shale gas producers and other operators of crude oil and natural gas facilities in the province. Under the OGAA, the British Columbia Oil and Gas Commission (the “Commission”) has broad powers, particularly with respect to compliance and enforcement and the setting of technical safety and operational standards for oil and natural gas activities. The Environmental Protection and Management Regulation establishes the government’s environmental objectives for Crown lands, water, riparian habitats, wildlife and wildlife habitat, old-growth forests and cultural heritage resources. The OGAA requires the Commission to consider these environmental objectives in deciding whether or not to authorize an oil and gas activity. In addition, although not exclusively an environmental statute, the Petroleum and Natural Gas Act, in conjunction with the OGAA, requires companies to obtain various approvals before undertaking exploration or production work, such as geophysical licenses, geophysical exploration project approvals, permits for the exclusive right to do geological work and geophysical exploration work, and well, test hole and water-source well authorizations. Such approvals are given subject to environmental considerations and licenses and project approvals can be suspended or cancelled for failure to comply with this legislation or its regulations.

Reputation Risk

We rely on our reputation to build and maintain positive relationships with stakeholders, to recruit and retain staff, and to be a credible, trusted company. Any actions we take that cause negative public opinion have the potential to negatively impact our reputation which may adversely affect our share price, development plans and our ability to continue operations.

Public Perception of Alberta Oil Sands

Development of the Alberta oil sands has received considerable attention in recent public commentary on the subjects of environmental impact, climate change and GHG emissions. Despite that much of the focus is on bitumen mining operations and not in-situ production, public concerns about oil sands generally and GHG emissions and water and land use practices in oil sands developments specifically may, directly or indirectly, impair the profitability of our current oil sands projects, and the viability of future oil sands projects, by creating significant regulatory uncertainty leading to uncertainty in economic modeling of current and future projects and delays relating to the sanctioning of future projects.

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

Other Risks

Risks Related to the Acquisition

Unexpected Costs or Liabilities Related to the Acquisition

Acquisitions of crude oil and natural gas properties are based largely on engineering, environmental and economic assessments made by the acquirer, independent engineers and consultants. These assessments include a series of assumptions regarding such factors as recoverability and marketability of crude oil and natural gas, environmental restrictions and prohibitions regarding releases and emissions of various substances, future prices of crude oil and natural gas and operating costs, future capital expenditures and royalties and other government levies which will be imposed over the producing life of the reserves. Many of these factors are subject to change and are beyond our control. All such assessments involve a measure of geologic, engineering, environmental and regulatory uncertainty that could result in lower production and reserves or higher operating or capital expenditures than anticipated.

Although we conducted title and environmental reviews in respect of the Deep Basin assets, which include approximately three million net acres of land containing liquids rich natural gas, condensate and other NGLs, and light and medium oil located primarily in the Elmworth-Wapiti, Kaybob-Edson and Clearwater operating areas and include interests in numerous natural gas processing facilities, such reviews cannot guarantee that any unforeseen defects in the chain of title will not arise to defeat our title to certain assets or that environmental defects or deficiencies do not exist.

In connection with the Acquisition, there may be liabilities that we failed to discover or were unable to quantify in our due diligence conducted prior to the execution of the purchase and sale agreement between ConocoPhillips and Cenovus dated March 29, 2017, as amended (the “Acquisition Agreement”), and we may not be indemnified for

Cenovus Energy Inc. 51 2017 Management’s Discussion and Analysis

some or all of these liabilities. The discovery or quantification of any material liabilities could have a material adverse effect on our business, financial condition or future prospects. In addition, the Acquisition Agreement limits the amount for which we are indemnified, such that liabilities in respect of the Acquisition may be greater than the amounts for which we are indemnified under the Acquisition Agreement.

Realization of Acquisition Benefits

We believe that the Acquisition will provide a number of benefits to Cenovus. However, there is a risk that some or all of the expected benefits of the Acquisition may fail to materialize, may cost more to achieve or may not occur within the time periods that we anticipate. The realization of such benefits may be affected by a number of factors, many of which are beyond our control.

Amount of Contingent Payments

In connection with the Acquisition, we have agreed to make contingent payments under certain circumstances. The amount of contingent payments will vary depending on the Canadian dollar WCS price from time to time during the five year period following the closing of the Acquisition, and such payments may be significant. In addition, in the event that such payments are made, this could have an adverse impact on our reported results and other metrics.

Effect on Market Price from Future Sales of common shares of Cenovus by ConocoPhillips

The future sales of common shares of Cenovus into the market held by ConocoPhillips, either through open market trades on the TSX or NYSE, through privately arranged block trades, or pursuant to prospectus offerings made in accordance with the registration rights agreement, could adversely affect prevailing market prices for the common shares. In addition, market perception regarding ConocoPhillips’ intention to make sales of Cenovus common shares may have a negative impact on the trading price of these common shares.

Tax Laws

Income tax laws, other laws or government incentive programs may in the future be changed or interpreted in a manner that adversely affects Cenovus and its shareholders. Tax authorities having jurisdiction over Cenovus may disagree with the manner in which we calculate our tax liabilities such that its provision for income taxes may not be sufficient, or such authorities could change their administrative practices to Cenovus’s detriment or the detriment of its shareholders. In addition, all of our tax filings are subject to audit by tax authorities who may disagree with such filings in a manner that adversely affects Cenovus and its shareholders.

United States Tax Risk

In the U.S., the Tax Cuts and Jobs Act was signed into law on December 22, 2017. The new legislation: reduces the federal corporate tax rate from 35 percent to 21 percent; allows immediate expensing of qualified property acquired prior to 2023; imposes a limitation on the utilization of net operating losses to 80 percent of taxable income; sets a limitation on the deductibility of interest expense; and introduces new provisions imposing a minimum tax in certain circumstances when a company has payments to a related foreign entity. There are currently significant gaps in the legislation that will reportedly be supplemented with regulations. Accordingly, there is significant uncertainty with respect to the interpretation and implementation of the legislation. There is also potential for some or all of the changes to be revised or reversed if there is a change in governing party. We expect there will be impacts to Cenovus in terms of the U.S. taxes paid by us, but it is difficult to estimate the potential magnitude and timing of impacts to Cenovus due to the uncertainties noted with respect to the Tax Cuts and Jobs Act.

United States Trade Risk relating to NAFTA Renegotiation

The outcome of the ongoing renegotiation of the North American Free Trade Agreement (“NAFTA”) could include significant changes to, or U.S. withdrawal from, the treaty. While Cenovus is not aware of any proposals in the renegotiation to materially alter the terms of trade for energy resources, if the outcome of the renegotiation did include any such changes, or if the U.S. were to withdraw from the NAFTA and adopt discriminatory or other measures adversely affecting the sale or transportation of our products in the U.S., this could have a significant negative impact on our financial condition or results from operations.

Arrangement Related Risk

We have certain post-Arrangement indemnification and other obligations under each of the arrangement agreement (the “Arrangement Agreement”) and the separation and transition agreement (the “Separation Agreement”), both of which are among Encana Corporation (“Encana”), 7050372 Canada Inc. and Cenovus Energy Inc. (formerly, Encana Finance Ltd.), dated October 20, 2009 and November 30, 2009 respectively, entered in connection with the Arrangement. Encana and Cenovus have agreed to indemnify each other for certain liabilities and obligations associated with, among other things, in the case of Encana’s indemnity, the business and assets retained by Encana, and in the case of Cenovus’s indemnity, the Cenovus business and assets. At the present time, we cannot determine whether we will have to indemnify Encana for any substantial obligations under the terms of the Arrangement. We also cannot assure that if Encana has to indemnify us and our affiliates for any substantial obligations, Encana will be able to satisfy such obligations.

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A discussion of additional risks, should they arise after the date of this MD&A, which may impact our business, prospects, financial condition, results of operation and cash flows, and in some cases our reputation, can be found in our subsequently filed MD&A, available on SEDAR at sedar.com, on EDGAR at sec.gov and cenovus.com.

CRITICAL ACCOUNTING JUDGMENTS, ESTIMATION UNCERTAINTIES AND ACCOUNTING POLICIES

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

Critical Judgments in Applying Accounting Policies

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

Joint Arrangements

The classification of a joint arrangement as either a joint operation or a joint venture requires judgment. Cenovus holds a 50 percent interest in WRB, a jointly controlled entity. It was determined that Cenovus has the rights to the assets and obligations for the liabilities of WRB. As a result, the joint arrangement is classified as a joint operation and the Company’s share of the assets, liabilities, revenues and expenses are recorded in the Consolidated Financial Statements.

Prior to May 17, 2017, Cenovus held a 50 percent interest in FCCL, which was jointly controlled with ConocoPhillips and met the definition of a joint operation under IFRS 11. As such, Cenovus recognized its share of the assets, liabilities, revenues and expenses in its consolidated results. Subsequent to the Acquisition, Cenovus controls FCCL, as defined under IFRS 10, and, accordingly, FCCL has been consolidated.

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

· The intention of the transaction creating FCCL and WRB was to form an integrated North American heavy oil business. The integrated business was structured, initially on a tax neutral basis, through two partnerships due to the assets residing in different tax jurisdictions. Partnerships are “flow-through” entities which have a limited life.

· The partnership agreements require the partners (Cenovus and ConocoPhillips or Phillips 66 or respective subsidiaries) to make contributions if funds are insufficient to meet the obligations or liabilities of the partnerships. The past and future development of FCCL and WRB is dependent on funding from the partners by way of partnership notes payable and loans. The partnerships do not have any third-party borrowings.

· FCCL operates like most typical western Canadian working interest relationships where the operating partner takes product on behalf of the participants. WRB has a very similar structure modified only to account for the operating environment of the refining business.

· Cenovus and Phillips 66, as operators, either directly or through wholly-owned subsidiaries, provide marketing services, purchase necessary feedstock, and arrange for transportation and storage on the partners’ behalf as the agreements prohibit the partnerships from undertaking these roles themselves. In addition, the partnerships do not have employees and, as such, are not capable of performing these roles.

· In each arrangement, output is taken by one of the partners, indicating that the partners have rights to the economic benefits of the assets and the obligation for funding the liabilities of the arrangements.

Exploration and Evaluation Assets

The application of Cenovus’s accounting policy for E&E expenditures requires judgment in determining whether it is likely that future economic benefit exists when activities have not reached a stage where technical feasibility and commercial viability can be reasonably determined. Factors such as drilling results, future capital programs, future operating expenses, as well as estimated reserves and resources are considered. In addition, Management uses judgment to determine when E&E assets are reclassified to PP&E. In making this determination, various factors are considered, including the existence of reserves, and whether the appropriate approvals have been received from regulatory bodies and Cenovus’s internal approval process.

Identification of CGUs

CGUs are defined as the lowest level of integrated assets for which there are separately identifiable cash flows that are largely independent of cash flows from other assets or groups of assets. The classification of assets and allocation of corporate assets into CGUs requires significant judgment and interpretation. Factors considered in the classification include the integration between assets, shared infrastructures, the existence of common sales points, geography, geologic structure, and the manner in which Management monitors and makes decisions about its

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operations. The recoverability of Cenovus’s upstream, refining, crude-by-rail and corporate assets are assessed at the CGU level. As such, the determination of a CGU could have a significant impact on impairment losses and reversals.

Key Sources of Estimation Uncertainty

Critical accounting estimates are those estimates that require Management to make particularly subjective or complex judgments about matters that are inherently uncertain. Estimates and underlying assumptions are reviewed on an ongoing basis and any revisions to accounting estimates are recorded in the period in which the estimates are revised. The following are the key assumptions about the future and other key sources of estimation at the end of the reporting period that changes to could result in a material adjustment to the carrying amount of assets and liabilities within the next financial year.

Crude Oil and Natural Gas Reserves

There are a number of inherent uncertainties associated with estimating crude oil and natural gas reserves. Reserves estimates are dependent upon variables including the recoverable quantities of hydrocarbons, the cost of the development of the required infrastructure to recover the hydrocarbons, production costs, estimated selling price of the hydrocarbons produced, royalty payments and taxes. Changes in these variables could significantly impact the reserves estimates which would affect the impairment test and DD&A expense of our crude oil and natural gas assets in the Oil Sands and Deep Basin segments. Cenovus’s crude oil and natural gas reserves are evaluated annually and reported to Cenovus by our IQREs. Refer to the Outlook section of this MD&A for more details on future commodity prices.

Recoverable Amounts

Determining the recoverable amount of a CGU or an individual asset requires the use of estimates and assumptions, which are subject to change as new information becomes available. For our upstream assets, these estimates include forward commodity prices, expected production volumes, quantity of reserves and resources, discount rates, future development and operating expenses, and income tax rates. Recoverable amounts for the refining assets and crude-by-rail terminal use assumptions such as throughput, forward commodity prices, operating expenses, transportation capacity, supply and demand conditions, and income tax rates. Changes in assumptions used in determining the recoverable amount could affect the carrying value of the related assets. Refer to the Reportable Segments section of this MD&A for more details on impairments and reversals.

As at December 31, 2017, the recoverable amounts of Cenovus’s upstream CGUs were determined based on fair value less costs of disposal or an evaluation of comparable asset transactions. The fair values for producing properties were calculated based on discounted after-tax cash flows of proved and probable reserves using forward prices and cost estimates, prepared by Cenovus’s IQREs. Key assumptions in the determination of future cash flows from reserves include crude oil and natural gas prices, costs to develop and the discount rate. All reserves have been evaluated as at December 31, 2017 by our IQREs.

Crude Oil and Natural Gas Prices

The forward prices as at December 31, 2017, used to determine future cash flows from crude oil and natural gas reserves were:

	2018		2019		2020		2021		2022		Average               Annual              Increase              Thereafter
WTI (US$/barrel)		57.50		60.90		64.13		68.33		71.19		2.1%
WCS (C$/barrel)		50.61		56.59		60.86		64.56		66.63		2.1%
Edmonton C5+ (C$/barrel)		72.41		74.90		77.07		81.07		83.32		2.1%
AECO (C$/Mcf) (1)		2.43		2.77		3.19		3.48		3.67		2.0%

(1) Assumes gas heating value of one million British Thermal Units per thousand cubic feet.

Discount and Inflation Rates

Discounted future cash flows are determined by applying a discount rate between 10 percent and 15 percent, based on the individual characteristics of the CGU and other economic and operating factors. Inflation is estimated at two percent, which is common industry practice and used by Cenovus’s IQREs in preparing their reserves reports.

Decommissioning Costs

Provisions are recorded for the future decommissioning and restoration of our upstream crude oil and natural gas assets, refining assets and crude-by-rail terminal at the end of their economic lives. Management uses judgment to assess the existence and to estimate the future liability. The actual cost of decommissioning and restoration is uncertain and cost estimates may change in response to numerous factors including changes in legal requirements, technological advances, inflation and the timing of expected decommissioning and restoration. In addition, Management determines the appropriate discount rate at the end of each reporting period. This discount rate, which is credit-adjusted, is used to determine the present value of the estimated future cash outflows required to

Cenovus Energy Inc. 54 2017 Management’s Discussion and Analysis

settle the obligation and may change in response to numerous market factors. Refer to Note 24 of the Consolidated Financial Statements for more details on changes to decommissioning costs.

Fair Value of Assets Acquired and Liabilities Assumed in a Business Combination

The fair value of assets acquired and liabilities assumed in a business combination, including contingent consideration and goodwill, is estimated based on information available at the date of acquisition. Various valuation techniques are applied for measuring fair value including market comparables and discounted cash flows which rely on assumptions such as forward prices, reserve and resources estimates, production costs, volatility, Canadian-U.S. foreign exchange rates and discount rates. Changes in these variables could significantly impact the carrying value of the net assets.

Income Tax Provisions

Tax regulations and legislation and the interpretations thereof in the various jurisdictions in which Cenovus operates are subject to change. There are usually a number of tax matters under review; therefore, income taxes are subject to measurement uncertainty.

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

Recent Accounting Pronouncements

There were no new or amended accounting standards or interpretations adopted during 2017.

New Accounting Standards and Interpretations not yet Adopted

A number of new accounting standards, amendments to accounting standards and interpretations are effective for annual periods beginning on or after January 1, 2018 and have not been applied in preparing the Consolidated Financial Statements for the year ended December 31, 2017. The standards applicable to Cenovus are as follows and will be adopted on their respective effective dates:

Financial Instruments

On July 24, 2014, the IASB issued the final version of IFRS 9, “Financial Instruments” (“IFRS 9”) to replace IAS 39, “Financial Instruments: Recognition and Measurement” (“IAS 39”).

IFRS 9 introduces a single approach to determine whether a financial asset is measured at amortized cost or fair value and replaces the multiple rules in IAS 39. The approach is based on how an entity manages its financial instruments in the context of its business model and the contractual cash flow characteristics of the financial assets. The IAS 39 measurement categories for financial assets will be replaced by fair value through profit or loss, fair value through other comprehensive income (“FVOCI”) and amortized cost. The standard eliminates the existing IAS 39 categories of held to maturity, loans and receivables and available for sale. Based on Management’s assessment, the change in categories will not have a material impact on the Consolidated Financial Statements. As at December 31, 2017, the Company has private equity investments classified as available for sale with a fair value of $37 million. Under IFRS 9, we have elected to measure these investments as FVOCI. As such, all fair value gains or losses will be recorded in other comprehensive income (“OCI”), impairments will not be recognized in net earnings and fair value gains or losses will not be recycled to net earnings on disposition.

IFRS 9 retains most of the IAS 39 requirements for financial liabilities. However, where the fair value option is applied to financial liabilities, the change in fair value resulting from an entity’s own credit risk is recorded in OCI rather than net earnings, unless this creates an accounting mismatch. Cenovus currently does not designate any financial liabilities as fair value through profit or loss; therefore, there will be no impact on the accounting for financial liabilities.

A new expected credit loss model for calculating impairment on financial assets replaces the incurred loss impairment model used in IAS 39. The new model will result in more timely recognition of expected credit losses. Based on Management’s assessment, no additional impairment loss is expected as at January 1, 2018, the date of adoption.

In addition, IFRS 9 includes a simplified hedge accounting model, aligning hedge accounting more closely with risk management. Cenovus does not currently apply hedge accounting.

IFRS 9 must be adopted for years beginning on or after January 1, 2018. We will apply the new standard retrospectively and elect to use the practical expedients permitted under the standard. Comparative periods will not be restated.

Cenovus Energy Inc. 55 2017 Management’s Discussion and Analysis

Revenue Recognition

On May 28, 2014, the IASB issued IFRS 15, “Revenue From Contracts With Customers” (“IFRS 15”) replacing IAS 11, “Construction Contracts”, IAS 18, “Revenue” and several revenue-related interpretations. IFRS 15 establishes a single revenue recognition framework that applies to contracts with customers. The standard requires an entity to recognize revenue to reflect the transfer of goods and services for the amount it expects to receive, when control is transferred to the purchaser. Disclosure requirements have also been expanded.

Management has assessed the impact of applying the new standard on the Consolidated Financial Statements and has not identified any material differences from its current revenue recognition practice.

The adoption of IFRS 15 is mandatory for years beginning on or after January 1, 2018. The standard may be applied either retrospectively or using a modified retrospective approach. We intend to adopt the standard using the modified retrospective approach recognizing the cumulative impact of adoption in retained earnings as of January 1, 2018. Comparative periods will not be restated. We will apply IFRS 15 using the practical expedient in paragraph C5(a) of IFRS 15, under which the Company will not restate contracts that are completed contracts as at the date of adoption.

Leases

On January 13, 2016, the IASB issued IFRS 16, “Leases” (“IFRS 16”), which requires entities to recognize lease assets and lease obligations on the balance sheet. For lessees, IFRS 16 removes the classification of leases as either operating leases or finance leases, effectively treating all leases as finance leases. Certain short-term leases (less than twelve months) and leases of low-value assets are exempt from the requirements, and may continue to be treated as operating leases.

Lessors will continue with a dual lease classification model. Classification will determine how and when a lessor will recognize lease revenue, and what assets would be recorded.

IFRS 16 is effective for years beginning on or after January 1, 2019, with early adoption permitted if IFRS 15 has been adopted. The standard may be applied retrospectively or using a modified retrospective approach. The modified retrospective approach does not require restatement of prior period financial information as it recognizes the cumulative effect of applying the standard to prior periods as an adjustment to opening retained earnings. It is anticipated that the adoption of IFRS 16 will have a material impact on our Consolidated Balance Sheets due to material operating lease commitments as disclosed in Note 36 of the Consolidated Financial Statements. Cenovus will adopt IFRS 16 effective January 1, 2019. We intend to adopt the standard using the retrospective with cumulative effect approach and apply several of the practical expedients available.

Uncertain Tax Positions

In June 2017, the IASB issued International Financial Reporting Interpretation Committee (“IFRIC”) 23, “Uncertainty over Income Tax Treatments”. The interpretation provides clarity on how to account for a tax position when there is uncertainty over income tax treatments. In determining the likely resolution of the uncertain tax positions, a position may be considered separately or as a group. In addition, an assessment is required to determine the probability that the tax authority will accept the tax position taken in income tax filings. If the uncertain income tax treatment is unlikely to be accepted, the accounting tax position must reflect an appropriate level of uncertainty. An uncertain tax position may be reassessed if new information changes the original assessment. IFRIC 23 is effective for annual periods beginning on or after January 1, 2019 using either a modified or full retrospective approach. IFRIC 23 is not expected to have a significant impact on the Consolidated Financial Statements.

CONTROL ENVIRONMENT

Management, including our President & Chief Executive Officer and Executive Vice-President & Chief Financial Officer, assessed the design and effectiveness of internal control over financial reporting (“ICFR”) and disclosure controls and procedures (“DC&P”) as at December 31, 2017. In making its assessment, Management used the Committee of Sponsoring Organizations of the Treadway Commission Framework in Internal Control – Integrated Framework (2013) to evaluate the design and effectiveness of internal control over financial reporting. Based on our evaluation, Management has concluded that both ICFR and DC&P were effective as at December 31, 2017.

Management excluded the Deep Basin assets from its assessment of internal control over financial reporting as at December 31, 2017 because they were acquired by the Company through a business combination in 2017. As permitted by and in accordance with, National Instrument 52-109, “Certification of Disclosure in Issuers’ Annual and Interim Filings”, and guidance issued by the U.S. Securities and Exchange Commission, Management has limited the scope and design of ICFR and DC&P to exclude the controls, policies and procedures of the Deep Basin Assets. Such scope limitation is primarily due to the time required for Management to assess the ICFR and DC&P relating to the Deep Basin Assets in a manner consistent with our other operations.

Cenovus Energy Inc. 56 2017 Management’s Discussion and Analysis

Summary financial information related to the Deep Basin Assets included in the Consolidated Financial Statements is as follows:

($ millions)	May 17 -   December 31, 2017
Revenues	514
Operating Margin	207
Net Earnings (Loss)	(108)
As at	December 31, 2017
Current Assets	619
Non-Current Assets	6,075
Current Liabilities	364
Non-Current Liabilities	496

In addition, we acquired Deep Basin commitments of approximately $500 million, primarily consisting of transportation commitments on various pipelines.

The effectiveness of our ICFR, which excludes the Deep Basin assets, was audited as at December 31, 2017 by PricewaterhouseCoopers LLP, an independent firm of Chartered Professional Accountants, as stated in their Report of Independent Registered Public Accounting Firm, which is included in our audited Consolidated Financial Statements for the year ended December 31, 2017.

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

CORPORATE RESPONSIBILITY

We are committed to operating in a responsible manner and integrating our corporate responsibility principles in the way we conduct our business. Our Corporate Responsibility (“CR”) policy guides our activities in the areas of: Leadership, Corporate Governance and Business Practices, People, Environmental Performance, Stakeholder and Aboriginal Engagement, and Community Involvement and Investment.

We published our 2016 CR report in July 2017 to report on our management efforts and performance across the above noted areas within our CR policy, as well as other environment, social and governance topics that are important to our stakeholders. Our CR report also lists external recognition we received for our commitment to corporate responsibility, and is available on our website at cenovus.com.

OUTLOOK

We will continue to look for ways to increase our margins through strong operating performance and cost leadership, while delivering safe and reliable operations. Proactively managing our market access commitments and opportunities should assist with our goal of reaching a broader customer base to secure a higher sales price for our liquids production.

We have reduced the amount of capital needed to sustain our base business and expand our projects, which we believe will help to ensure our financial resilience.

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

Commodity Prices Underlying our Financial Results

Our crude oil pricing outlook is influenced by the following:

● We expect the general outlook for crude oil prices will be tied primarily to the supply response to the current price environment, the impact of potential supply disruptions, and the pace of growth in global demand as influenced by macro-economic events. Overall, we expect crude oil price volatility to continue and a modest price improvement in the next twelve months. OPEC’s ability to adhere to its current production cuts and the possibility of future production cuts, combined with annual increases in demand growth should support prices, constrained by the need to draw down surplus crude oil inventories and U.S. production growth;

● We anticipate the Brent-WTI differential will narrow after the impacts of severe weather related incidents dissipate and as a result of the U.S. exporting crude oil to overseas markets. Overall, the differential will likely be set by transportation costs; and

● We expect that the WTI-WCS differential will widen due to Canadian supply increasing due to the resolution of production outages, oil sands supply growth and transportation constraints, partially offset by the possibility of OPEC extending production cuts.

Cenovus Energy Inc. 57 2017 Management’s Discussion and Analysis

Natural gas prices are anticipated to improve in the first quarter of 2018 with a normal winter heating season and increased U.S. natural gas exports, partially offset by expected North American natural gas supply growth. However, mild weather occurred in the first few months of winter in 2017. If these trends continue, it will put downward pressure on prices.

Seasonal demand changes and refinery maintenance activity will result in fluctuations of refining crack spreads throughout 2018. The impact of potentially weaker refining crack spreads on refinery margins will be partially offset by the widening of the WTI-WCS differential, which increases the refinery feedstock cost advantage.

We expect the Canadian dollar to continue to be tied to a modest improvement in crude oil prices and the pace at which the U.S. Federal Reserve Board and the Bank of Canada raise benchmark lending rates relative to each other. The Bank of Canada raised its benchmark lending rate twice in 2017 and again in early 2018, marking a notable shift for Canada towards a tighter monetary policy.

Our exposure to the light/heavy price differentials is composed of both a global light/heavy component as well as Canadian transportation constraints. While we expect to see volatility in crude oil prices, we have the ability to partially mitigate the impact of swings in light/heavy price differentials through the following:

● Integration – having heavy oil refining capacity capable of processing Canadian heavy oil. From a value perspective, our refining business positions us to capture value from both the WTI-WCS differential for Canadian crude oil and the Brent-WTI differential from the sale of refined products;

● Financial hedge transactions – limiting the impact of fluctuations in upstream crude oil prices by entering into financial transactions that fix the WTI-WCS differential;

● Marketing arrangements – limiting the impact of fluctuations in upstream crude oil prices by entering into physical supply transactions with fixed price components directly with refiners; and

● Transportation commitments and arrangements – supporting transportation projects that move crude oil from our production areas to consuming markets, including tidewater markets.

Additional natural gas and NGLs production associated with the acquisition of the Deep Basin Assets will provide improved upstream integration for the fuel, solvent and blending requirements at our oil sands operations.

Cenovus Energy Inc. 58 2017 Management’s Discussion and Analysis

Key Priorities for 2018

Cost Reductions and Deleveraging

Our priorities in 2018 are to further reduce costs and deleverage our balance sheet while maintaining capital discipline. We remain focused on maintaining our financial resilience and flexibility while continuing to deliver safe and reliable operations, which remains a top priority.

Over the past three years, we have achieved significant improvements in our operating and sustaining capital costs. In 2018, we expect to realize additional capital, operating and general and administrative cost reductions across the Company. We expect to realize additional savings through continued improvements in areas such as drilling performance, development planning and optimized scheduling of oil sands well start-ups. Our ability to drive structural and sustainable cost and margin improvements will further support our business plan and financial resilience.

We are making some significant reductions to our non-rent general and administrative costs in 2018, the majority of which will come from workforce reductions, which we expect to be substantially completed by the end of the first quarter of 2018.

At December 31, 2017, through a combination of cash on hand and available capacity on our committed credit facility, we have approximately $5.1 billion of liquidity. We are currently marketing a package of non-core Deep Basin assets with production of approximately 15,000 BOE per day. We believe our liquidity position, proceeds from the asset sale and further cost reductions will help us reach our Net Debt to Adjusted EBITDA target of less than 2.0 times.

Disciplined Capital Investment

In 2018, we anticipate capital investment to be between $1.5 billion and $1.7 billion. We plan to direct the majority of our 2018 capital budget towards sustaining oil sands production, while supporting ongoing construction at the Christina Lake phase G expansion and a targeted drilling program in the Deep Basin. With integration remaining an important part of our overall strategy, capital investment is also allocated for scheduled maintenance and reliability work at the Refineries.

Market Access

Market access constraints for Canadian crude oil production continue to be a challenge. Our strategy is to maintain firm transportation commitments through a combination of pipelines, rail and marine access to support our growth plans, but leave capacity for optimization. We expect to supplement firm capacity with active blending, storage, sourcing and destination optimization to ensure we are maximizing the margin on every barrel we produce.

Cenovus Energy Inc. 59 2017 Management’s Discussion and Analysis

ADVISORY

Oil and Gas Information

The estimates of reserves were prepared effective December 31, 2017 by independent qualified reserves evaluators, based on the Canadian Oil and Gas Evaluation Handbook and in compliance with the requirements of National Instrument 51-101, Standards of Disclosure for Oil and Gas Activities. Estimates are presented using an average of three IQRE’s January 1, 2018 price forecast. For additional information about our reserves and other oil and gas information, see “Reserves Data and Other Oil and Gas Information” in our AIF for the year ended December 31, 2017.

Barrels of Oil Equivalent – natural gas volumes have been converted to barrels of oil equivalent (BOE) on the basis of six Mcf to one barrel (bbl). BOE may be misleading, particularly if used in isolation. A conversion ratio of one bbl to six Mcf is based on an energy equivalency conversion method primarily applicable at the burner tip and does not represent value equivalency at the wellhead. Given that the value ratio based on the current price of crude oil compared with natural gas is significantly different from the energy equivalency conversion ratio of 6:1, utilizing a conversion on a 6:1 basis is not an accurate reflection of value.

Forward-looking Information

This document contains certain forward-looking statements and forward-looking information (collectively referred to as “forward-looking information”) within the meaning of applicable securities legislation, including the U.S. Private Securities Litigation Reform Act of 1995, about our current expectations, estimates and projections about the future, based on certain assumptions made by us in light of our experience and perception of historical trends. Although we believe that the expectations represented by such forward looking information are reasonable, there can be no assurance that such expectations will prove to be correct.

Forward-looking information in this document is identified by words such as “anticipate”, “believe”, “expect”, “estimate”, “plan”, “forecast”, “future”, “target”, “position”, “project”, “committed”, “can be”, “pursue”, “capacity”, “could”, “should”, “will”, “focus”, “outlook”, “potential”, “priority”, “may”, “strategy”, “forward”, or similar expressions and includes suggestions of future outcomes, including statements about: our strategy and related milestones and schedules, including expected timing for oil sands expansion phases and associated expected production capacities; projections for 2018 and future years and our plans and strategies to realize such projections; forecast exchange rates and trends; our future opportunities for oil development; forecast operating and financial results, including forecast sales prices, costs and cash flows; targets for our Net Debt to Capitalization and Net Debt to Adjusted EBITDA ratios; our ability to satisfy payment obligations as they become due; priorities for our capital investment decisions; planned capital expenditures, including the amount, timing and financing thereof; expected future production, including the timing, stability or growth thereof; expected reserves; capacities, including for projects, transportation and refining; our ability to preserve our financial resilience and various plans and strategies with respect thereto; forecast cost savings and sustainability thereof; our priorities for 2018; future impact of regulatory measures; forecast commodity prices, differentials and trends and expected impact to Cenovus; potential impacts to Cenovus of various risks, including those related to commodity prices and the Acquisition; the potential effectiveness of our risk management strategies; new accounting standards, the timing for the adoption thereof by Cenovus, and anticipated impact on the Consolidated Financial Statements; expected impacts of the Acquisition; the availability and repayment of our credit facilities; potential asset sales and anticipated use of sales proceeds; expected impacts of the contingent payment related to the Acquisition; future use and development of technology; our ability to access and implement all technology necessary to efficiently and effectively operate our assets and achieve expected future cost reductions; and projected growth and projected shareholder return. Readers are cautioned not to place undue reliance on forward-looking information as our actual results may differ materially from those expressed or implied.

Developing forward-looking information involves reliance on a number of assumptions and consideration of certain risks and uncertainties, some of which are specific to Cenovus and others that apply to the industry generally. The factors or assumptions on which the forward-looking information is based include: forecast oil and natural gas, natural gas liquids, condensate and refined products prices and other assumptions inherent in Cenovus’s 2018 guidance, available at cenovus.com; our projected capital investment levels, the flexibility of our capital spending plans and the associated source of funding; the achievement of further cost reductions and sustainability thereof; expected condensate prices; estimates of quantities of oil, bitumen, natural gas and liquids from properties and other sources not currently classified as proved; future use and development of technology; our ability to obtain necessary regulatory and partner approvals; the successful and timely implementation of capital projects or stages thereof; our ability to generate sufficient cash flow to meet our current and future obligations; estimated abandonment and reclamation costs, including associated levies and regulations applicable thereto; achievement of expected impacts of the Acquisition; successful integration of the Deep Basin Assets; our ability to obtain and retain qualified staff and equipment in a timely and cost-efficient manner; our ability to access sufficient capital to pursue our development plans; our ability to complete asset sales, including with desired transaction metrics and the timelines we expect; forecast bitumen, crude oil, natural gas liquids, condensate and refined products prices, forecast inflation and other assumptions inherent in our current guidance set out below; expected impacts of the contingent payment to ConocoPhillips; alignment of realized Western Canadian Select (“WCS”) prices and WCS prices used to calculate the contingent payment to ConocoPhillips; our projected capital investment levels, the

Cenovus Energy Inc. 60 2017 Management’s Discussion and Analysis

flexibility of capital spending plans and the associated sources of funding; sustainability of achieved cost reductions, achievement of further cost reductions and sustainability thereof; our ability to access and implement all technology necessary to achieve expected future results; our ability to implement capital projects or stages thereof in a successful and timely manner; and other risks and uncertainties described from time to time in the filings we make with securities regulatory authorities.

2018 guidance, as updated December 13, 2017, assumes: Brent prices of US$55.00/bbl, WTI prices of US$52.00/bbl; WCS of US$37.00/bbl; NYMEX natural gas prices of US$3.00/MMBtu; AECO natural gas prices of $2.20/GJ; Chicago 3-2-1 crack spread of US$15.00/bbl; and an exchange rate of $0.78 US$/C$.

The risk factors and uncertainties that could cause our actual results to differ materially, include: possible failure by us to realize the anticipated benefits of and synergies from the Acquisition; possible failure to access or implement some or all of the technology necessary to efficiently and effectively operate our assets and achieve expected future results; volatility of and other assumptions regarding commodity prices; the effectiveness of our risk management program, including the impact of derivative financial instruments, the success of our hedging strategies and the sufficiency of our liquidity position; the accuracy of cost estimates; commodity prices, currency and interest rates; possible lack of alignment of realized WCS prices and WCS prices used to calculate the contingent payment to ConocoPhillips; product supply and demand; market competition, including from alternative energy sources; risks inherent in our marketing operations, including credit risks; exposure to counterparties and partners, including ability and willingness of such parties to satisfy contractual obligations in a timely manner; risks inherent in the operation of our crude-by-rail terminal, including health, safety and environmental risks; maintaining desirable ratios of Net Debt to Adjusted EBITDA as well as Net Debt to Capitalization; our ability to access various sources of debt and equity capital, generally, and on terms acceptable to us; our ability to finance growth and sustaining capital expenditures; changes in credit ratings applicable to us or any of our securities; changes to our dividend plans or strategy, including the dividend reinvestment plan; accuracy of our reserves, future production and future net revenue estimates; our ability to replace and expand oil and gas reserves; our ability to maintain our relationship with our partners and to successfully manage and operate our integrated business; reliability of our assets including in order to meet production targets; potential disruption or unexpected technical difficulties in developing new products and manufacturing processes; the occurrence of unexpected events such as fires, severe weather conditions, explosions, blow-outs, equipment failures, transportation incidents and other accidents or similar events; refining and marketing margins; inflationary pressures on operating costs, including labour, materials, natural gas and other energy sources used in oil sands processes; potential failure of products to achieve or maintain acceptance in the market; risks associated with fossil fuel industry reputation; unexpected cost increases or technical difficulties in constructing or modifying manufacturing or refining facilities; unexpected difficulties in producing, transporting or refining of bitumen and/or crude oil into petroleum and chemical products; risks associated with technology and its application to our business; risks associated with climate change; the timing and the costs of well and pipeline construction; our ability to secure adequate and cost-effective product transportation including sufficient pipeline, crude-by-rail, marine or alternate transportation, including to address any gaps caused by constraints in the pipeline system; availability of, and our ability to attract and retain, critical talent; possible failure to obtain and retain qualified staff and equipment in a timely and cost-efficient manner; changes in labour relationships; changes in the regulatory framework in any of the locations in which we operate, including changes to the regulatory approval process and land-use designations, royalty, tax, environmental, greenhouse gas, carbon, climate change and other laws or regulations, or changes to the interpretation of such laws and regulations, as adopted or proposed, the impact thereof and the costs associated with compliance; the expected impact and timing of various accounting pronouncements, rule changes and standards on our business, our financial results and our Consolidated Financial Statements; changes in general economic, market and business conditions; the political and economic conditions in the countries in which we operate or supply; the occurrence of unexpected events such as war, terrorist threats and the instability resulting therefrom; and risks associated with existing and potential future lawsuits and regulatory actions against us.

Statements relating to “reserves” are deemed to be forward looking information, as they involve the implied assessment, based on certain estimates and assumptions, that the reserves described exist in the quantities predicted or estimated, and can be profitably produced in the future.

Readers are cautioned that the foregoing lists are not exhaustive and are made as at the date hereof. Events or circumstances could cause our actual results to differ materially from those estimated or projected and expressed in, or implied by, the forward looking information. For a full discussion of our material risk factors, see “Risk Management and Risk Factors” in this MD&A for the period ended December 31, 2017, available on SEDAR at sedar.com, on EDGAR at sec.gov and on our website at cenovus.com.

Cenovus Energy Inc. 61 2017 Management’s Discussion and Analysis

ABBREVIATIONS

The following abbreviations have been used in this document:

Crude Oil		Natural Gas
bbl	Barrel	Mcf	thousand cubic feet
Mbbls/d	thousand barrels per day	MMcf	million cubic feet
MMbbls	million barrels	Bcf	billion cubic feet
BOE	barrel of oil equivalent	MMBtu	million British thermal units
MMBOE	million barrel of oil equivalent	GJ	gigajoule
WTI	West Texas Intermediate	AECO	Alberta Energy Company
WCS	Western Canadian Select	NYMEX	New York Mercantile Exchange
CDB	Christina Dilbit Blend
MSW	Mixed Sweet Blend

NETBACK RECONCILIATIONS

The following tables provide a reconciliation of the items comprising Netbacks to Operating Margin found in our Consolidated Financial Statements.

Total Production From Continuing Operations

Continuing Upstream Financial Results

				Per Consolidated Financial Statements								Adjustments									Basis of Netback Calculation
Year Ended December 31, 2017 ($ millions)				Oil Sands (1)			Deep Basin (1)		Continuing     Operations			Condensate			Inventory			Other			Continuing Operations
Gross Sales					7,362			555		7,917			(3,050	)		-			(45	)		4,822
Royalties					230			41		271			-			-			-			271
Transportation and Blending					3,704			56		3,760			(3,050	)		-			(1	)		709
Operating					934			250		1,184			-			-			(77	)		1,107
Production and Mineral Taxes					-			1		1			-			-			-			1
Netback					2,494			207		2,701			-			-			33			2,734
(Gain) Loss on Risk Management					307			-		307			-			-			-			307
Operating Margin					2,187			207		2,394			-			-			33			2,427
				Per Consolidated Financial Statements								Adjustments									Basis of Netback Calculation
Year Ended December 31, 2016 ($ millions)				Oil Sands (1)			Deep Basin (1)		Continuing Operations			Condensate			Inventory			Other			Continuing Operations
Gross Sales					2,929			-		2,929			(1,402	)		-			(2	)		1,525
Royalties					9			-		9			-			-			-			9
Transportation and Blending					1,721			-		1,721			(1,402	)		44			-			363
Operating					501			-		501			-			-			(4	)		497
Production and Mineral Taxes					-			-		-			-			-			-			-
Netback					698			-		698			-			(44	)		2			656
(Gain) Loss on Risk Management					(179	)		-		(179	)		-			-			-			(179	)
Operating Margin					877			-		877			-			(44	)		2			835
	Per Consolidated Financial Statements											Adjustments									Basis of Netback Calculation
Year Ended December 31, 2015 ($ millions)	Oil Sands (1)			Deep Basin (1)			Conventional (2)		Continuing Operations			Condensate			Inventory			Other			Continuing Operations
Gross Sales		3,030			-			61		3,091			(1,441	)		-			(8	)		1,642
Royalties		29			-			1		30			-			-			-			30
Transportation and Blending		1,815			-			1		1,816			(1,441	)		(38	)		-			337
Operating		531			-			3		534			-			-			(5	)		529
Production and Mineral Taxes		-			-			1		1			-			-			-			1
Netback		655			-			55		710			-			38			(3	)		745
(Gain) Loss on Risk Management		(404	)		-			-		(404	)		-			-			-			(404	)
Operating Margin		1,059			-			55		1,114			-			38			(3	)		1,149
				Per Interim Consolidated Financial Statements								Adjustments									Basis of Netback Calculation
Three Months Ended December 31, 2017 ($ millions)				Oil Sands (3)			Deep Basin (3)		Continuing       Operations			Condensate			Inventory			Other			Continuing Operations
Gross Sales					2,424			231		2,655			(990	)		-			(15	)		1,650
Royalties					113			20		133			-			-			-			133
Transportation and Blending					1,193			24		1,217			(990	)		(1	)		2			228
Operating					271			94		365			-			-			(15	)		350
Production and Mineral Taxes					-			1		1			-			-			-			1
Netback					847			92		939			-			1			(2	)		938
(Gain) Loss on Risk Management					235			-		235			-			-			-			235
Operating Margin					612			92		704			-			1			(2	)		703

Cenovus Energy Inc. 62 2017 Management’s Discussion and Analysis

	Per Interim Consolidated Financial Statements								Adjustments									Basis of Netback Calculation
Three Months Ended September 30, 2017 ($ millions)	Oil Sands (3)			Deep Basin (3)		Continuing Operations			Condensate			Inventory			Other			Continuing Operations
Gross Sales		2,210			200		2,410			(863	)		-			(19	)		1,528
Royalties		54			13		67			-			-			-			67
Transportation and Blending		1,066			22		1,088			(863	)		1			(1	)		225
Operating (4)		259			101		360			-			-			(9	)		351
Production and Mineral Taxes		-			-		-			-			-			-			-
Netback		831			64		895			-			(1	)		(9	)		885
(Gain) Loss on Risk Management		9			-		9			-			-			-			9
Operating Margin		822			64		886			-			(1	)		(9	)		876
	Per Interim Consolidated Financial Statements								Adjustments									Basis of Netback Calculation
Three Months Ended June 30, 2017 ($ millions)	Oil Sands (3)			Deep Basin (3)		Continuing Operations			Condensate			Inventory			Other			Continuing Operations
Gross Sales		1,666			124		1,790			(719	)		-			(6	)		1,065
Royalties		36			8		44			-			-			-			44
Transportation and Blending		879			10		889			(719	)		-			(2	)		168
Operating (5)		264			55		319			-			-			(52	)		267
Production and Mineral Taxes		-			-		-			-			-			-			-
Netback		487			51		538			-			-			48			586
(Gain) Loss on Risk Management		(14	)		-		(14	)		-			-			-			(14	)
Operating Margin		501			51		552			-			-			48			600
	Per Interim Consolidated Financial Statements								Adjustments									Basis of Netback Calculation
Three Months Ended March 31, 2017 ($ millions)	Oil Sands (3)			Deep Basin (3)		Continuing Operations			Condensate			Inventory			Other			Continuing Operations
Gross Sales		1,062			-		1,062			(478	)		-			(5	)		579
Royalties		27			-		27			-			-			-			27
Transportation and Blending		566			-		566			(478	)		-			-			88
Operating		140			-		140			-			-			(1	)		139
Production and Mineral Taxes		-			-		-			-			-			-			-
Netback		329			-		329			-			-			(4	)		325
(Gain) Loss on Risk Management		77			-		77			-			-			-			77
Operating Margin		252			-		252			-			-			(4	)		248

(1) Found in Note 1 of the Consolidated Financial Statements.

(2) Includes the results of operation for certain Conventional segment royalty interest assets disposed of in 2015.

(3) Found in Note 1 of the Interim Consolidated Financial Statements.

(4) As a result of measurement period adjustments related to the Acquisition, operating costs for the Oil Sands segment were increased by $2 million in the third quarter of 2017.

(5) As a result of measurement period adjustments related to the Acquisition, operating costs for the Oil Sands and Deep Basin segments were increased by $43 million and $4 million, respectively, in the second quarter of 2017.

Oil Sands

	Basis of Netback Calculation												Adjustments								Per Consolidated Financial Statements (1)
Year Ended December 31, 2017 ($ millions)	Foster Creek			Christina Lake			Total Crude Oil			Natural Gas			Condensate		Inventory			Other			Total Oil Sands
Gross Sales		1,945			2,345			4,290			8			3,050		-			14			7,362
Royalties		178			52			230			-			-		-			-			230
Transportation and Blending		387			266			653			-			3,050		-			1			3,704
Operating		465			403			868			9			-		-			57			934
Netback		915			1,624			2,539			(1	)		-		-			(44	)		2,494
(Gain) Loss on Risk Management		131			176			307			-			-		-			-			307
Operating Margin		784			1,448			2,232			(1	)		-		-			(44	)		2,187
	Basis of Netback Calculation												Adjustments								Per Consolidated Financial Statements (1)
Year Ended December 31, 2016 ($ millions)	Foster Creek			Christina Lake			Total         Crude Oil			Natural Gas			Condensate		Inventory			Other			Total Oil Sands
Gross Sales		773			736			1,509			16			1,402		-			2			2,929
Royalties		-			9			9			-			-		-			-			9
Transportation and Blending		225			137			362			1			1,402		(44	)		-			1,721
Operating		269			217			486			11			-		-			4			501
Netback		279			373			652			4			-		44			(2	)		698
(Gain) Loss on Risk Management		(90	)		(89	)		(179	)		-			-		-			-			(179	)
Operating Margin		369			462			831			4			-		44			(2	)		877

Cenovus Energy Inc. 63 2017 Management’s Discussion and Analysis

	Basis of Netback Calculation												Adjustments								Per Consolidated Financial Statements (1)
Year Ended December 31, 2015 ($ millions)	Foster Creek			Christina Lake			Total     Crude Oil			Natural Gas			Condensate		Inventory			Other			Total Oil Sands
Gross Sales		792			767			1,559			22			1,441		-			8			3,030
Royalties		11			18			29			-			-		-			-			29
Transportation and Blending		208			127			335			1			1,441		38			-			1,815
Operating		295			216			511			15			-		-			5			531
Netback		278			406			684			6			-		(38	)		3			655
(Gain) Loss on Risk Management		(202	)		(198	)		(400	)		(4	)		-		-			-			(404	)
Operating Margin		480			604			1,084			10			-		(38	)		3			1,059
	Basis of Netback Calculation												Adjustments								Per Interim Consolidated Financial Statements (2)
Three Months Ended December 31, 2017 ($ millions)	Foster Creek			Christina Lake			Total Crude Oil			Natural Gas			Condensate		Inventory			Other			Total Oil Sands
Gross Sales		626			804			1,430			1			990		-			3			2,424
Royalties		91			22			113			-			-		-			-			113
Transportation and Blending		106			96			202			-			990		1			-			1,193
Operating		137			123			260			3			-		-			8			271
Netback		292			563			855			(2	)		-		(1	)		(5	)		847
(Gain) Loss on Risk Management		98			137			235			-			-		-			-			235
Operating Margin		194			426			620			(2	)		-		(1	)		(5	)		612
	Basis of Netback Calculation												Adjustments								Per Interim Consolidated Financial Statements (2)
Three Months Ended September 30, 2017 ($ millions)	Foster Creek			Christina Lake			Total Crude Oil			Natural Gas			Condensate		Inventory			Other			Total Oil Sands
Gross Sales		603			737			1,340			1			863		-			6			2,210
Royalties		43			11			54			-			-		-			-			54
Transportation and Blending		126			79			205			-			863		(1	)		(1	)		1,066
Operating (3)		138			116			254			1			-		-			4			259
Netback		296			531			827			-			-		1			3			831
(Gain) Loss on Risk Management		2			7			9			-			-		-			-			9
Operating Margin		294			524			818			-			-		1			3			822
	Basis of Netback Calculation												Adjustments								Per Interim Consolidated Financial Statements (2)
Three Months Ended June 30, 2017 ($ millions)	Foster Creek			Christina Lake			Total Crude Oil			Natural Gas			Condensate		Inventory			Other			Total Oil Sands
Gross Sales		429			514			943			4			719		-			-			1,666
Royalties		24			12			36			-			-		-			-			36
Transportation and Blending		100			58			158			-			719		-			2			879
Operating (3)		119			99			218			2			-		-			44			264
Netback		186			345			531			2			-		-			(46	)		487
(Gain) Loss on Risk Management		(9	)		(5	)		(14	)		-			-		-			-			(14	)
Operating Margin		195			350			545			2			-		-			(46	)		501
	Basis of Netback Calculation												Adjustments								Per Interim Consolidated Financial Statements (2)
Three Months Ended March 31, 2017 ($ millions)	Foster Creek			Christina Lake			Total Crude Oil			Natural Gas			Condensate		Inventory			Other			Total Oil Sands
Gross Sales		287			290			577			2			478		-			5			1,062
Royalties		20			7			27			-			-		-			-			27
Transportation and Blending		55			33			88			-			478		-			-			566
Operating		71			65			136			3			-		-			1			140
Netback		141			185			326			(1	)		-		-			4			329
(Gain) Loss on Risk Management		40			37			77			-			-		-			-			77
Operating Margin		101			148			249			(1	)		-		-			4			252

(1) Found in Note 1 of the Consolidated Financial Statements.

(2) Found in Note 1 of the Interim Consolidated Financial Statements.

(3) As a result of measurement period adjustments related to the Acquisition, operating costs were increased by $43 million and $2 million in the second and third quarters of 2017, respectively.

Cenovus Energy Inc. 64 2017 Management’s Discussion and Analysis

Deep Basin

	Basis of Netback   Calculation		Adjustments		Per   Consolidated   Financial   Statements (1)
Year Ended December 31, 2017 ($ millions)		Total		Other		Total Deep Basin
Gross Sales		524		31		555
Royalties		41		-		41
Transportation and Blending		56		-		56
Operating		230		20		250
Production and Mineral Taxes		1		-		1
Netback		196		11		207
(Gain) Loss on Risk Management		-		-		-
Operating Margin		196		11		207
	Basis of Netback   Calculation		Adjustments		Per Interim   Consolidated   Financial   Statements (2)
Three Months Ended December 31, 2017 ($ millions)		Total		Other		Total Deep Basin
Gross Sales		219		12		231
Royalties		20		-		20
Transportation and Blending		26		(2)		24
Operating		87		7		94
Production and Mineral Taxes		1		-		1
Netback		85		7		92
(Gain) Loss on Risk Management		-		-		-
Operating Margin		85		7		92
	Basis of Netback   Calculation		Adjustments		Per Interim   Consolidated   Financial   Statements (2)
Three Months Ended September 30, 2017 ($ millions)		Total		Other		Total Deep Basin
Gross Sales		187		13		200
Royalties		13		-		13
Transportation and Blending		20		2		22
Operating		96		5		101
Production and Mineral Taxes		-		-		-
Netback		58		6		64
(Gain) Loss on Risk Management		-		-		-
Operating Margin		58		6		64
	Basis of Netback   Calculation		Adjustments		Per Interim   Consolidated   Financial   Statements (2)
Three Months Ended June 30, 2017 ($ millions)		Total		Other		Total Deep Basin
Gross Sales		118		6		124
Royalties		8		-		8
Transportation and Blending		10		-		10
Operating (3)		47		8		55
Production and Mineral Taxes		-		-		-
Netback		53		(2)		51
(Gain) Loss on Risk Management		-		-		-
Operating Margin		53		(2)		51

(1) Found in Note 1 of the Consolidated Financial Statements.

(2) Found in Note 1 of the Interim Consolidated Financial Statements.

(3) As a result of measurement period adjustments related to the Acquisition, operating costs were increased by $4 million in the second quarter of 2017.

Conventional (Discontinued Operations)

	Basis of Netback Calculation													Adjustments						Per  Consolidated  Financial  Statements(1)
Year Ended December 31, 2017 ($ millions)	Heavy Oil		Light & Medium		NGLs		Conventional Liquids		Natural Gas			Conventional		Condensate		Inventory		Other		Total  Conventional
Gross Sales		383		504		17		904		300			1,204		95		-		10		1,309
Royalties		51		107		2		160		14			174		-		-		-		174
Transportation and Blending		35		25		-		60		12			72		95		-		-		167
Operating		117		153		-		270		152			422		-		-		4		426
Production and Mineral Taxes		-		17		-		17		1			18		-		-		-		18
Netback		180		202		15		397		121			518		-		-		6		524
(Gain) Loss on Risk Management		14		23		-		37		(4	)		33		-		-		-		33
Operating Margin		166		179		15		360		125			485		-		-		6		491

Cenovus Energy Inc. 65 2017 Management’s Discussion and Analysis

	Basis of Netback Calculation												Adjustments						Per  Consolidated  Financial  Statements(1)
Year Ended December 31, 2016 ($ millions)	Heavy Oil		Light &  Medium		NGLs		Conventional  Liquids		Natural  Gas		Conventional		Condensate		Inventory		Other		Total  Conventional
Gross Sales		380		442		11		833		319		1,152		103		-		12		1,267
Royalties		35		88		2		125		14		139		-		-		-		139
Transportation and Blending		49		25		-		74		16		90		103		(7)		-		186
Operating		142		149		-		291		154		445		-		-		(1)		444
Production and Mineral Taxes		-		12		-		12		-		12		-		-		-		12
Netback		154		168		9		331		135		466		-		7		13		486
(Gain) Loss on Risk Management		(34)		(30)		-		(64)		-		(64)		-		-		6		(58)
Operating Margin		188		198		9		395		135		530		-		7		7		544
	Basis of Netback Calculation												Adjustments						Per  Consolidated  Financial  Statements(1)
Year Ended December 31, 2015 ($ millions)	Heavy Oil		Light &  Medium		NGLs		Conventional  Liquids		Natural  Gas		Conventional		Condensate		Inventory		Other		Total  Conventional
Gross Sales		507		528		13		1,048		435		1,483		142		-		23		1,648
Royalties		39		62		1		102		11		113		-		-		-		113
Transportation and Blending		44		31		-		75		17		92		142		(5)		-		229
Operating		206		180		-		386		177		563		-		-		(5)		558
Production and Mineral Taxes		-		15		-		15		2		17		-		-		-		17
Netback		218		240		12		470		228		698		-		5		28		731
(Gain) Loss on Risk Management		(88)		(76)		-		(164)		(55)		(219)		-		-		10		(209)
Operating Margin		306		316		12		634		283		917		-		5		18		940
	Basis of Netback Calculation												Adjustments						Per Interim  Consolidated  Financial  Statements(2)
Three Months Ended December 31, 2017 ($ millions)	Heavy Oil		Light &  Medium		NGLs		Conventional  Liquids		Natural  Gas		Conventional		Condensate		Inventory		Other		Total  Conventional
Gross Sales		40		107		4		151		53		204		8		-		6		218
Royalties		2		24		-		26		2		28		-		-		1		29
Transportation and Blending		3		5		-		8		2		10		8		-		-		18
Operating		14		32		-		46		35		81		-		-		2		83
Production and Mineral Taxes		-		4		-		4		-		4		-		-		-		4
Netback		21		42		4		67		14		81		-		-		3		84
(Gain) Loss on Risk Management		4		13		-		17		(3)		14		-		-		-		14
Operating Margin		17		29		4		50		17		67		-		-		3		70
	Basis of Netback Calculation												Adjustments						Per Interim  Consolidated  Financial  Statements(2)
Three Months Ended September 30, 2017 ($ millions)	Heavy Oil		Light &  Medium		NGLs		Conventional  Liquids		Natural  Gas		Conventional		Condensate		Inventory		Other		Total  Conventional
Gross Sales		111		131		4		246		62		308		22		-		1		331
Royalties		17		26		1		44		3		47		-		-		(2)		45
Transportation and Blending		13		7		-		20		3		23		22		-		(1)		44
Operating		35		44		-		79		39		118		-		-		-		118
Production and Mineral Taxes		-		4		-		4		-		4		-		-		-		4
Netback		46		50		3		99		17		116		-		-		4		120
(Gain) Loss on Risk Management		1		3		-		4		(1)		3		-		-		-		3
Operating Margin		45		47		3		95		18		113		-		-		4		117
	Basis of Netback Calculation												Adjustments						Per Interim  Consolidated  Financial  Statements(2)
Three Months Ended June 30, 2017 ($ millions)	Heavy Oil		Light &  Medium		NGLs		Conventional  Liquids		Natural  Gas		Conventional		Condensate		Inventory		Other		Total  Conventional
Gross Sales		119		138		4		261		90		351		32		-		3		386
Royalties		16		28		-		44		5		49		-		-		1		50
Transportation and Blending		11		7		-		18		3		21		32		-		1		54
Operating		37		39		-		76		37		113		-		-		2		115
Production and Mineral Taxes		-		5		-		5		-		5		-		-		-		5
Netback		55		59		4		118		45		163		-		-		(1)		162
(Gain) Loss on Risk Management		2		1		-		3		-		3		-		-		-		3
Operating Margin		53		58		4		115		45		160		-		-		(1)		159

Cenovus Energy Inc. 66 2017 Management’s Discussion and Analysis

	Basis of Netback Calculation												Adjustments						Per Interim Consolidated Financial Statements(2)
Three Months Ended March 31, 2017 ($ millions)	Heavy Oil		Light &     Medium		NGLs		Conventional Liquids		Natural             Gas		Conventional		Condensate		Inventory		Other		Total Conventional
Gross Sales		113		128		5		246		95		341		33		-		-		374
Royalties		16		29		1		46		4		50		-		-		-		50
Transportation and Blending		8		6		-		14		4		18		33		-		-		51
Operating		31		38		-		69		41		110		-		-		-		110
Production and Mineral Taxes		-		4		-		4		1		5		-		-		-		5
Netback		58		51		4		113		45		158		-		-		-		158
(Gain) Loss on Risk Management		7		6		-		13		-		13		-		-		-		13
Operating Margin		51		45		4		100		45		145		-		-		-		145

(1) Found in Note 11 of the Consolidated Financial Statements and includes operating results associated with our royalty interest assets sold in 2015 consisting of gross sales, royalties, transportation and blending expenses, operating expenses, and production and mineral taxes in the amount of $61 million, $1 million, $1 million, $3 million and $1 million, respectively.

(2) Found in Note 8 of the Interim Consolidated Financial Statements.

Total Production

Upstream Financial Results

	Per Consolidated Financial Statements									Adjustments									Basis of Netback Calculation
Year Ended December 31, 2017 ($ millions)	Continuing Operations (1)			Conventional (2)			Total Operations			Condensate			Inventory			Other			Total Operations
Gross Sales		7,917			1,309			9,226			(3,145	)		-			(55	)		6,026
Royalties		271			174			445			-			-			-			445
Transportation and Blending		3,760			167			3,927			(3,145	)		-			(2	)		780
Operating		1,184			426			1,610			-			-			(81	)		1,529
Production and Mineral Taxes		1			18			19			-			-			-			19
Netback		2,701			524			3,225			-			-			28			3,253
(Gain) Loss on Risk Management		307			33			340			-			-			-			340
Operating Margin		2,394			491			2,885			-			-			28			2,913
	Per Consolidated Financial Statements									Adjustments									Basis of Netback Calculation
Year Ended December 31, 2016 ($ millions)	Continuing Operations (1)			Conventional (2)			Total Operations			Condensate			Inventory			Other			Total Operations
Gross Sales		2,929			1,267			4,196			(1,505	)		-			(14	)		2,677
Royalties		9			139			148			-			-			-			148
Transportation and Blending		1,721			186			1,907			(1,505	)		51			-			453
Operating		501			444			945			-			-			(3	)		942
Production and Mineral Taxes		-			12			12			-			-			-			12
Netback		698			486			1,184			-			(51	)		(11	)		1,122
(Gain) Loss on Risk Management		(179	)		(58	)		(237	)		-			-			(6	)		(243	)
Operating Margin		877			544			1,421			-			(51	)		(5	)		1,365
	Per Consolidated Financial Statements									Adjustments									Basis of Netback Calculation
Year Ended December 31, 2015 ($ millions)	Continuing Operations (1)			Conventional (2)			Total Operations			Condensate			Inventory			Other			Total Operations
Gross Sales		3,091			1,648			4,739			(1,583	)		-			(31	)		3,125
Royalties		30			113			143			-			-			-			143
Transportation and Blending		1,816			229			2,045			(1,583	)		(33	)		-			429
Operating		534			558			1,092			-			-			-			1,092
Production and Mineral Taxes		1			17			18			-			-			-			18
Netback		710			731			1,441			-			33			(31	)		1,443
(Gain) Loss on Risk Management		(404	)		(209	)		(613	)		-			-			(10	)		(623	)
Operating Margin		1,114			940			2,054			-			33			(21	)		2,066
	Per Interim Consolidated Financial Statements									Adjustments									Basis of Netback Calculation
Three Months Ended December 31, 2017 ($ millions)	Continuing Operations (1)			Conventional (3)			Total Operations			Condensate			Inventory			Other			Total Operations
Gross Sales		2,655			218			2,873			(998	)		-			(21	)		1,854
Royalties		133			29			162			-			-			(1	)		161
Transportation and Blending		1,217			18			1,235			(998	)		(1	)		1			237
Operating		365			83			448			-			-			(17	)		431
Production and Mineral Taxes		1			4			5			-			-			-			5
Netback		939			84			1,023			-			1			(4	)		1,020
(Gain) Loss on Risk Management		235			14			249			-			-			-			249
Operating Margin		704			70			774			-			1			(4	)		771

Cenovus Energy Inc. 67 2017 Management’s Discussion and Analysis

	Per Interim Consolidated Financial Statements						Adjustments						Basis of   Netback       Calculation
Three Months Ended September 30, 2017 ($ millions)	Continuing   Operations (1)		Conventional (3)		Total         Operations		Condensate		Inventory		Other		Total         Operations
Gross Sales		2,410		331		2,741		(885)		-		(20)	1,836
Royalties		67		45		112		-		-		2	114
Transportation and Blending		1,088		44		1,132		(885)		1		-	248
Operating		360		118		478		-		-		(9)	469
Production and Mineral Taxes		-		4		4		-		-		-	4
Netback		895		120		1,015		-		(1)		(13)	1,001
(Gain) Loss on Risk Management		9		3		12		-		-		-	12
Operating Margin		886		117		1,003		-		(1)		(13)	989
	Per Interim Consolidated Financial Statements						Adjustments						Basis of   Netback   Calculation
Three Months Ended June 30, 2017 ($ millions)	Continuing   Operations (1)		Conventional (3)		Total   Operations		Condensate		Inventory		Other		Total   Operations
Gross Sales		1,790		386		2,176		(751)		-		(9)	1,416
Royalties		44		50		94		-		-		(1)	93
Transportation and Blending		889		54		943		(751)		-		(3)	189
Operating		319		115		434		-		-		(54)	380
Production and Mineral Taxes		-		5		5		-		-		-	5
Netback		538		162		700		-		-		49	749
(Gain) Loss on Risk Management		(14)		3		(11)		-		-		-	(11)
Operating Margin		552		159		711		-		-		49	760
	Per Interim Consolidated Financial Statements						Adjustments						Basis of   Netback   Calculation
Three Months Ended March 31, 2017 ($ millions)	Continuing   Operations (1)		Conventional (3)		Total           Operations		Condensate		Inventory		Other		Total   Operations
Gross Sales		1,062		374		1,436		(511)		-		(5)	920
Royalties		27		50		77		-		-		-	77
Transportation and Blending		566		51		617		(511)		-		-	106
Operating		140		110		250		-		-		(1)	249
Production and Mineral Taxes		-		5		5		-		-		-	5
Netback		329		158		487		-		-		(4)	483
(Gain) Loss on Risk Management		77		13		90		-		-		-	90
Operating Margin		252		145		397		-		-		(4)	393

(1) Continuing operations consist of the Oil Sands and Deep Basin segments.

(2) Classified as a discontinued operation, which can be found in Note 11 of the Consolidated Financial Statements.

(3) Classified as a discontinued operation, which can be found in Note 9 of the Interim Consolidated Financial Statements.

Cenovus Energy Inc. 68 2017 Management’s Discussion and Analysis

The following table provides the sales volumes used to calculate Netback.

Sales Volumes

			Twelve Months Ended December 31
(barrels per day, unless otherwise stated)			2017		2016		2015
Oil Sands
Foster Creek				121,806		69,647		64,467
Christina Lake				161,514		79,481		73,872
Total Oil Sands Crude Oil				283,320		149,128		138,339
Natural Gas (MMcf per day)				10		17		19
Deep Basin
Total Liquids				20,850		-		-
Natural Gas (MMcf per day)				316		-		-
Conventional Sales (BOE per day)				-		-		4,163
Sales From Continuing Operations (BOE per day)				358,476		151,962		145,669
Conventional (Discontinued Operations)
Heavy Oil				21,669		28,958		34,965
Light and Medium Oil				24,571		25,965		28,706
Natural Gas Liquids (“NGLs”)				1,073		1,065		1,149
Total Conventional Liquids				47,313		55,988		64,820
Natural Gas (MMcf per day)				333		377		412
Sales From Discontinued Operations (BOE per day)				102,792		118,821		133,537
Total Liquids Sales				351,483		205,116		205,706
Total Sales (BOE per day)				461,268		270,783		279,206
	Three Months Ended
(barrels per day, unless otherwise stated)	December 31, 2017		September 30, 2017		June 30, 2017		March 31, 2017
Oil Sands
Foster Creek		143,586		157,850		106,115		78,562
Christina Lake		193,734		206,338		154,431		89,919
Total Oil Sands Crude Oil		337,320		364,188		260,546		168,481
Natural Gas (MMcf per day)		7		6		12		15
Deep Basin
Total Liquids		33,147		32,864		16,894		-
Natural Gas (MMcf per day)		509		495		253		-
Sales From Continuing Operations (BOE per day)		456,455		480,512		321,526		170,981
Conventional (Discontinued Operations)
Heavy Oil		7,485		25,047		28,089		26,222
Light and Medium Oil		18,915		27,494		26,835		25,074
Natural Gas Liquids (“NGLs”)		913		1,201		1,132		1,047
Total Conventional Liquids		27,313		53,742		56,056		52,343
Natural Gas (MMcf per day)		279		350		355		348
Sales From Discontinued Operations (BOE per day)		73,775		112,079		115,235		110,343
Total Liquids Sales		397,780		450,794		333,496		220,824
Total Sales (BOE per day)		530,230		592,591		436,761		281,324

Cenovus Energy Inc. 69 2017 Management’s Discussion and Analysis

EX-99.3

Exhibit 99.3

Cenovus Energy Inc.

Consolidated Financial Statements

For the Year Ended December 31, 2017

(Canadian Dollars)

CONSOLIDATED FINANCIAL STATEMENTS

For the year ended December 31, 2017

TABLE OF CONTENTS

REPORT OF MANAGEMENT	3
REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM	4
CONSOLIDATED STATEMENTS OF EARNINGS (LOSS)	6
CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (LOSS)	7
CONSOLIDATED BALANCE SHEETS	8
CONSOLIDATED STATEMENTS OF SHAREHOLDERS’ EQUITY	9
CONSOLIDATED STATEMENTS OF CASH FLOWS	10
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS	11
1. DESCRIPTION OF BUSINESS AND SEGMENTED DISCLOSURES	11
2. BASIS OF PREPARATION AND STATEMENT OF COMPLIANCE	14
3. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES	14
4. CRITICAL ACCOUNTING JUDGMENTS AND KEY SOURCES OF ESTIMATION UNCERTAINTY	22
5. ACQUISITION	24
6. FINANCE COSTS	26
7. FOREIGN EXCHANGE (GAIN) LOSS, NET	27
8. DIVESTITURES	27
9. OTHER (INCOME) LOSS, NET	27
10. IMPAIRMENT CHARGES AND REVERSALS	27
11. ASSETS HELD FOR SALE AND DISCONTINUED OPERATIONS	30
12. INCOME TAXES	32
13. PER SHARE AMOUNTS	34
14. CASH AND CASH EQUIVALENTS	34
15. ACCOUNTS RECEIVABLE AND ACCRUED REVENUES	34
16. INVENTORIES	35
17. EXPLORATION AND EVALUATION ASSETS	35
18. PROPERTY, PLANT AND EQUIPMENT , NET	36
19. OTHER ASSETS	37
20. GOODWILL	37
21. ACCOUNTS PAYABLE AND ACCRUED LIABILITIES	37
22. CONTINGENT PAYMENT	37
23. LONG-TERM DEBT	38
24. DECOMMISSIONING LIABILITIES	39
25. OTHER LIABILITIES	40
26. PENSIONS AND OTHER POST-EMPLOYMENT BENEFITS	40
27. SHARE CAPITAL	43
28. ACCUMULATED OTHER COMPREHENSIVE INCOME (LOSS)	44
29. STOCK-BASED COMPENSATION PLANS	44
30. EMPLOYEE SALARIES AND BENEFIT EXPENSES	47
31. RELATED PARTY TRANSACTIONS	47
32. CAPITAL STRUCTURE	47
33. FINANCIAL INSTRUMENTS	49
34. RISK MANAGEMENT	51
35. SUPPLEMENTARY CASH FLOW INFORMATION	53
36. COMMITMENTS AND CONTINGENCIES	54

Cenovus Energy Inc. 2 For the year ended December 31, 2017

REPORT OF MANAGEMENT

Management’s Responsibility for the Consolidated Financial Statements

The accompanying Consolidated Financial Statements of Cenovus Energy Inc. are the responsibility of Management. The Consolidated Financial Statements have been prepared by Management in Canadian dollars in accordance with International Financial Reporting Standards as issued by the International Accounting Standards Board and include certain estimates that reflect Management’s best judgments.

The Board of Directors has approved the information contained in the Consolidated Financial Statements. The Board of Directors fulfills its responsibility regarding the financial statements mainly through its Audit Committee which is made up of four independent directors. The Audit Committee has a written mandate that complies with the current requirements of Canadian securities legislation and the United States Sarbanes – Oxley Act of 2002 and voluntarily complies, in principle, with the Audit Committee guidelines of the New York Stock Exchange. The Audit Committee meets with Management and the independent auditors on at least a quarterly basis to review and approve interim Consolidated Financial Statements and Management’s Discussion and Analysis prior to their public release as well as annually to review the annual Consolidated Financial Statements and Management’s Discussion and Analysis and recommend their approval to the Board of Directors.

Management’s Assessment of Internal Control over Financial Reporting

Management is also responsible for establishing and maintaining adequate internal control over financial reporting. The internal control system was designed to provide reasonable assurance to Management regarding the preparation and presentation of the Consolidated Financial Statements.

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

Management has assessed the design and effectiveness of internal control over financial reporting as at December 31, 2017. In making its assessment, Management has used the Committee of Sponsoring Organizations of the Treadway Commission (“COSO”) framework in Internal Control – Integrated Framework (2013) to evaluate the design and effectiveness of internal control over financial reporting. Based on our evaluation, Management has concluded that internal control over financial reporting was effective as at December 31, 2017.

Management excluded the Deep Basin assets from its assessment of internal control over financial reporting as at December 31, 2017 because they were acquired by the Company through a business combination in 2017. The Deep Basin total assets and total revenues excluded from Management’s assessment of internal control over financial reporting represents 16 percent and three percent, respectively, of the related Consolidated Financial Statement amounts as at and for the year ended December 31, 2017.

PricewaterhouseCoopers LLP, an independent firm of Chartered Professional Accountants, was appointed to audit and provide independent opinions on both the Consolidated Financial Statements and internal control over financial reporting as at December 31, 2017, as stated in their Report of Independent Registered Public Accounting Firm dated February 14, 2018. PricewaterhouseCoopers LLP has provided such opinions.

/s/ Alexander J. Pourbaix	/s/ Ivor M. Ruste
Alexander J. Pourbaix	Ivor M. Ruste
President &	Executive Vice-President &
Chief Executive Officer	Chief Financial Officer
Cenovus Energy Inc.	Cenovus Energy Inc.
February 14, 2018

Cenovus Energy Inc. 3 For the year ended December 31, 2017

REPORT OF INDEPENDENT REGISTERED PUBLIC

ACCOUNTING FIRM

To the Shareholders and Board of Directors of Cenovus Energy Inc.

Opinions on the Consolidated Financial Statements and Internal Control Over Financial Reporting

We have audited the accompanying Consolidated Balance Sheets of Cenovus Energy Inc. and its subsidiaries, (together the “Company”) as of December 31, 2017 and December 31, 2016, and the related Consolidated Statements of Earnings (Loss), Comprehensive Income (Loss), Shareholders’ Equity, and Cash Flows for each of the years in the three-year period ended December 31, 2017, including the related notes (collectively referred to as the “Consolidated Financial Statements”). We also have audited the Company’s internal control over financial reporting as of December 31, 2017, based on criteria established in Internal Control – Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission (“COSO”).

In our opinion, the Consolidated Financial Statements referred to above present fairly, in all material respects, the consolidated financial position of the Company as of December 31, 2017 and December 31, 2016 and its consolidated financial performance and its consolidated cash flows for each of the years in the three-year period ended December 31, 2017 in conformity with International Financial Reporting Standards as issued by the International Accounting Standards Board (“IFRS”). Also, in our opinion, the Company maintained, in all material respects, effective internal control over financial reporting as of December 31, 2017, based on criteria established in Internal Control - Integrated Framework (2013) issued by COSO.

Basis for Opinions

The Company’s Management is responsible for these Consolidated Financial Statements, for maintaining effective internal control over financial reporting, and for its assessment of the effectiveness of internal control over financial reporting, included in the accompanying Management’s Assessment of Internal Control over Financial Reporting. Our responsibility is to express opinions on the Company’s Consolidated Financial Statements and on the Company’s internal control over financial reporting based on our audits. We are a public accounting firm registered with the Public Company Accounting Oversight Board (United States) (“PCAOB”) and are required to be independent with respect to the Company in accordance with the U.S. federal securities laws and the applicable rules and regulations of the Securities and Exchange Commission and the PCAOB.

We conducted our audits in accordance with the standards of the PCAOB. Those standards require that we plan and perform the audits to obtain reasonable assurance about whether the Consolidated Financial Statements are free of material misstatement, whether due to error or fraud, and whether effective internal control over financial reporting was maintained in all material respects.

Our audits of the Consolidated Financial Statements included performing procedures to assess the risks of material misstatement of the Consolidated Financial Statements, whether due to error or fraud, and performing procedures that respond to those risks. Such procedures included examining, on a test basis, evidence regarding the amounts and disclosures in the Consolidated Financial Statements. Our audits also included evaluating the accounting principles used and significant estimates made by Management, as well as evaluating the overall presentation of the Consolidated Financial Statements. Our audit of internal control over financial reporting included obtaining an understanding of internal control over financial reporting, assessing the risk that a material weakness exists, and testing and evaluating the design and operating effectiveness of internal control based on the assessed risk. Our audits also included performing such other procedures as we considered necessary in the circumstances. We believe that our audits provide a reasonable basis for our opinions.

As described in Management’s Assessment of Internal Control over Financial Reporting, Management has excluded the Deep Basin assets from its assessment of internal control over financial reporting as of December 31, 2017 because it was acquired by the Company through a business combination in 2017. We have also excluded the Deep Basin assets from our audit of internal control over financial reporting. The Deep Basin total assets and total revenues excluded from Management’s assessment and our audit of internal control over financial reporting represent 16 percent and three percent, respectively, of the related Consolidated Financial Statement amounts as at and for the year ended December 31, 2017.

Cenovus Energy Inc. 4 For the year ended December 31, 2017

Definition and Limitations of Internal Control Over Financial Reporting

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

Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.

/s/ PricewaterhouseCoopers LLP

PricewaterhouseCoopers LLP

Chartered Professional Accountants

Calgary, Alberta, Canada

February 14, 2018

We have served as the Company’s auditor since 2008.

Cenovus Energy Inc. 5 For the year ended December 31, 2017

CONSOLIDATED STATEMENTS OF EARNINGS (LOSS)

For the years ended December 31,

($ millions, except per share amounts)

	Notes		2017			2016			2015
						(Restated) (1)			(Restated) (1)
Revenues		1
Gross Sales				17,314			11,015			11,559
Less: Royalties				271			9			30
				17,043			11,006			11,529
Expenses		1
Purchased Product				8,033			6,978			7,374
Transportation and Blending				3,748			1,715			1,814
Operating				1,949			1,239			1,281
Production and Mineral Taxes				1			-			1
(Gain) Loss on Risk Management		33		896			401			(252	)
Depreciation, Depletion and Amortization		18		1,838			931			993
Exploration Expense		17		888			2			67
General and Administrative				308			326			335
Finance Costs		6		645			390			381
Interest Income				(62	)		(52	)		(28	)
Foreign Exchange (Gain) Loss, Net		7		(812	)		(198	)		1,036
Revaluation (Gain)		5		(2,555	)		-			-
Transaction Costs		5		56			-			-
Re-measurement of Contingent Payment		5,22		(138	)		-			-
Research Costs				36			36			27
(Gain) Loss on Divestiture of Assets		8		1			6			(2,392	)
Other (Income) Loss, Net		9		(5	)		34			2
Earnings (Loss) From Continuing Operations Before Income Tax				2,216			(802	)		890
Income Tax Expense (Recovery)		12		(52	)		(343	)		(24	)
Net Earnings (Loss) From Continuing Operations				2,268			(459	)		914
Net Earnings (Loss) From Discontinued Operations		11		1,098			(86	)		(296	)
Net Earnings (Loss)				3,366			(545	)		618
Basic and Diluted Earnings (Loss) Per Share($)		13
Continuing Operations				2.06			(0.55	)		1.11
Discontinued Operations				0.99			(0.10	)		(0.36	)
Net Earnings (Loss) Per Share				3.05			(0.65	)		0.75

(1) The comparative periods have been restated to reflect discontinued operations as discussed in Notes 1 and 11.

See accompanying Notes to Consolidated Financial Statements.

Cenovus Energy Inc. 6 For the year ended December 31, 2017

CONSOLIDATED STATEMENTS OF COMPREHENSIVE

INCOME (LOSS)

For the years ended December 31,

($ millions)

	Notes		2017			2016			2015
Net Earnings (Loss)				3,366			(545	)		618
Other Comprehensive Income (Loss), Net of Tax		28
Items That Will Not be Reclassified to Profit or Loss:
Actuarial Gain (Loss) Relating to Pension and Other Post-Retirement Benefits				9			(3	)		20
Items That May be Reclassified to Profit or Loss:
Available for Sale Financial Assets – Change in Fair Value				(1	)		(2	)		6
Available for Sale Financial Assets – Reclassified to Profit or Loss				-			1			-
Foreign Currency Translation Adjustment				(275	)		(106	)		587
Total Other Comprehensive Income (Loss), Net of Tax				(267	)		(110	)		613
Comprehensive Income (Loss)				3,099			(655	)		1,231

See accompanying Notes to Consolidated Financial Statements.

Cenovus Energy Inc. 7 For the year ended December 31, 2017

CONSOLIDATED BALANCE SHEETS

As at December 31,

($ millions)

	Notes		2017		2016
Assets
Current Assets
Cash and Cash Equivalents		14		610		3,720
Accounts Receivable and Accrued Revenues		15		1,830		1,838
Income Tax Receivable				68		6
Inventories		16		1,389		1,237
Risk Management		33,34		63		21
Assets Held for Sale		11		1,048		-
Total Current Assets				5,008		6,822
Exploration and Evaluation Assets		1,17		3,673		1,585
Property, Plant and Equipment, Net		1,18		29,596		16,426
Income Tax Receivable				311		124
Risk Management		33,34		2		3
Other Assets		19		71		56
Goodwill		1,20		2,272		242
Total Assets				40,933		25,258
Liabilities and Shareholders’ Equity
Current Liabilities
Accounts Payable and Accrued Liabilities		21		2,635		2,266
Contingent Payment		22		38		-
Income Tax Payable				129		112
Risk Management		33,34		1,031		293
Liabilities Related to Assets Held for Sale		11		603		-
Total Current Liabilities				4,436		2,671
Long-Term Debt		23		9,513		6,332
Contingent Payment		22		168		-
Risk Management		33,34		20		22
Decommissioning Liabilities		24		1,029		1,847
Other Liabilities		25		173		211
Deferred Income Taxes		12		5,613		2,585
Total Liabilities				20,952		13,668
Shareholders’ Equity				19,981		11,590
Total Liabilities and Shareholders’ Equity				40,933		25,258
Commitments and Contingencies		36

See accompanying Notes to Consolidated Financial Statements.

Approved by the Board of Directors

/s/ Patrick D. Daniel	/s/ Colin Taylor
Patrick D. Daniel	Colin Taylor
Director	Director
Cenovus Energy Inc.	Cenovus Energy Inc.

Cenovus Energy Inc. 8 For the year ended December 31, 2017

CONSOLIDATED STATEMENTS OF SHAREHOLDERS’ EQUITY

($ millions)

	Share Capital		Paid in Surplus		Retained Earnings			AOCI (1)			Total
	(Note 27)		(Note 27)					(Note 28)
As at December 31, 2014		3,889		4,291		1,599			407			10,186
Net Earnings		-		-		618			-			618
Other Comprehensive Income		-		-		-			613			613
Total Comprehensive Income		-		-		618			613			1,231
Common Shares Issued for Cash		1,463		-		-			-			1,463
Common Shares Issued Pursuant to Dividend Reinvestment Plan		182		-		-			-			182
Stock-Based Compensation Expense		-		39		-			-			39
Dividends on Common Shares		-		-		(710	)		-			(710	)
As at December 31, 2015		5,534		4,330		1,507			1,020			12,391
Net Earnings (Loss)		-		-		(545	)		-			(545	)
Other Comprehensive Income (Loss)		-		-		-			(110	)		(110	)
Total Comprehensive Income (Loss)		-		-		(545	)		(110	)		(655	)
Stock-Based Compensation Expense		-		20		-			-			20
Dividends on Common Shares		-		-		(166	)		-			(166	)
As at December 31, 2016		5,534		4,350		796			910			11,590
Net Earnings (Loss)		-		-		3,366			-			3,366
Other Comprehensive Income (Loss)		-		-		-			(267	)		(267	)
Total Comprehensive Income (Loss)		-		-		3,366			(267	)		3,099
Common Shares Issued		5,506		-		-			-			5,506
Stock-Based Compensation Expense		-		11		-			-			11
Dividends on Common Shares		-		-		(225	)		-			(225	)
As at December 31, 2017		11,040		4,361		3,937			643			19,981

(1) Accumulated Other Comprehensive Income (Loss).

See accompanying Notes to Consolidated Financial Statements.

Cenovus Energy Inc. 9 For the year ended December 31, 2017

CONSOLIDATED STATEMENTS OF CASH FLOWS

For the years ended December 31,

($ millions)

	Notes		2017			2016			2015
Operating Activities
Net Earnings (Loss)				3,366			(545	)		618
Depreciation, Depletion and Amortization		18		2,030			1,498			2,114
Exploration Expense		17		890			2			138
Deferred Income Taxes		12		583			(209	)		(655	)
Unrealized (Gain) Loss on Risk Management		33		729			554			195
Unrealized Foreign Exchange (Gain) Loss		7		(857	)		(189	)		1,097
Revaluation (Gain)		5		(2,555	)		-			-
Re-measurement of Contingent Payment		22		(138	)		-			-
(Gain) Loss on Discontinuance		11		(1,285	)		-			-
(Gain) Loss on Divestiture of Assets		8		1			6			(2,392	)
Current Tax on Divestiture of Assets		8		-			-			391
Unwinding of Discount on Decommissioning Liabilities		24		128			130			126
Onerous Contract Provisions, Net of Cash Paid				(8	)		53			-
Other Asset Impairments		9		-			30			-
Other				30			93			59
Net Change in Other Assets and Liabilities				(107	)		(91	)		(107	)
Net Change in Non-Cash Working Capital				252			(471	)		(110	)
Cash From Operating Activities				3,059			861			1,474
Investing Activities
Acquisition, Net of Cash Acquired		5		(14,565	)		-			(84	)
Capital Expenditures – Exploration and Evaluation Assets		17		(147	)		(67	)		(138	)
Capital Expenditures – Property, Plant and Equipment		18		(1,523	)		(967	)		(1,576	)
Proceeds From Divestiture of Assets		8		3,210			8			3,344
Current Tax on Divestiture of Assets		8		-			-			(391	)
Net Change in Investments and Other				-			(1	)		3
Net Change in Non-Cash Working Capital				159			(52	)		(270	)
Cash From (Used in) Investing Activities				(12,866	)		(1,079	)		888
Net Cash Provided (Used) Before Financing Activities				(9,807	)		(218	)		2,362
Financing Activities		35
Net Issuance (Repayment) of Short-Term Borrowings		23		-			-			(25	)
Issuance of Long-Term Debt		23		3,842			-			-
Net Issuance (Repayment) of Revolving Long-Term Debt		23		32			-			-
Net Issuance of Debt Under Asset Sale Bridge Facility		23		3,569			-			-
Repayment of Debt Under Asset Sale Bridge Facility		23		(3,600	)		-			-
Common Shares Issued, Net of Issuance Costs		27		2,899			-			1,449
Dividends Paid on Common Shares		13		(225	)		(166	)		(528	)
Other				(2	)		(2	)		(2	)
Cash From (Used in) Financing Activities				6,515			(168	)		894
Foreign Exchange Gain (Loss) on Cash and Cash Equivalents Held in Foreign Currency				182			1			(34	)
Increase (Decrease) in Cash and Cash Equivalents				(3,110	)		(385	)		3,222
Cash and Cash Equivalents, Beginning of Year				3,720			4,105			883
Cash and Cash Equivalents, End of Year				610			3,720			4,105
Supplementary Cash Flow Information		35

See accompanying Notes to Consolidated Financial Statements.

Cenovus Energy Inc. 10 For the year ended December 31, 2017

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

All amounts in $ millions, unless otherwise indicated

For the year ended December  31, 2017

1. DESCRIPTION OF BUSINESS AND SEGMENTED DISCLOSURES

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

Cenovus is incorporated under the Canada Business Corporations Act and its shares are listed on the Toronto (“TSX”) and New York (“NYSE”) stock exchanges. The executive and registered office is located at 2600, 500 Centre Street S.E., Calgary, Alberta, Canada, T2G 1A6. Information on the Company’s basis of preparation for these Consolidated Financial Statements is found in Note 2.

On May 17, 2017, Cenovus acquired from ConocoPhillips Company and certain of its subsidiaries (collectively, “ConocoPhillips”) a 50 percent interest in FCCL Partnership (“FCCL”) and the majority of ConocoPhillips’ western Canadian conventional crude oil and natural gas assets (the “Deep Basin Assets”). This acquisition (the “Acquisition”) increased Cenovus’s interest in FCCL to 100 percent and expanded Cenovus’s operating areas to include more than three million net acres of land, exploration and production assets and related infrastructure and agreements in Alberta and British Columbia. The Acquisition had an effective date of January 1, 2017 (see Note 5).

Management has determined the operating segments based on information regularly reviewed for the purposes of decision making, allocating resources and assessing operational performance by Cenovus’s chief operating decision makers. The Company evaluates the financial performance of its operating segments primarily based on operating margin. The Company’s reportable segments are:

● Oil Sands, which includes the development and production of bitumen and natural gas in northeast Alberta. Cenovus’s bitumen assets include Foster Creek, Christina Lake and Narrows Lake as well as other projects in the early stages of development. The Company’s interest in certain of its operated oil sands properties, notably Foster Creek, Christina Lake and Narrows Lake, increased from 50 percent to 100 percent on May 17, 2017.

● Deep Basin, which includes approximately three million net acres of land primarily in the Elmworth-Wapiti, Kaybob-Edson, and Clearwater operating areas, rich in natural gas and NGLs. The assets reside in Alberta and British Columbia and include interests in numerous natural gas processing facilities. The Deep Basin Assets were acquired on May 17, 2017.

● Refining and Marketing, which is responsible for transporting, selling and refining crude oil into petroleum and chemical products. Cenovus jointly owns two refineries in the U.S. with the operator Phillips 66, an unrelated U.S. public company. In addition, Cenovus owns and operates a crude-by-rail terminal in Alberta. This segment coordinates Cenovus’s marketing and transportation initiatives to optimize product mix, delivery points, transportation commitments and customer diversification. The marketing of crude oil and natural gas sourced from Canada, including physical product sales that settle in the U.S., is considered to be undertaken by a Canadian business. U.S. sourced crude oil and natural gas purchases and sales are attributed to the U.S.

● Corporate and Eliminations, which primarily includes unrealized gains and losses recorded on derivative financial instruments, gains and losses on divestiture of assets, as well as other Cenovus-wide costs for general and administrative, financing activities and research costs. As financial instruments are settled, the realized gains and losses are recorded in the reportable segment to which the derivative instrument relates. Eliminations relate to sales and operating revenues, and purchased product between segments, recorded at transfer prices based on current market prices, and to unrealized intersegment profits in inventory. The Corporate and Eliminations segment is attributed to Canada, with the exception of unrealized risk management gains and losses, which have been attributed to the country in which the transacting entity resides.

In 2017, Cenovus disposed of the majority of the crude oil and natural gas assets in the Company’s Conventional segment. As such, the results of operations have been classified as a discontinued operation (see Note 11). This segment included the production of conventional crude oil, NGLs and natural gas in Alberta and Saskatchewan, including the heavy oil assets at Pelican Lake, the CO₂ enhanced oil recovery project at Weyburn and emerging tight oil opportunities. As at December 31, 2017, all Conventional assets were sold, except for the Company’s Suffield operations. The sale of the Suffield assets closed on January 5, 2018.

Cenovus Energy Inc. 11 For the year ended December 31, 2017

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

All amounts in $ millions, unless otherwise indicated

For the year ended December 31, 2017

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

A) Results of Operations – Segment and Operational Information

	Oil Sands								Deep Basin									Refining and Marketing
For the years ended December 31,	2017		2016			2015			2017			2016			2015			2017			2016			2015
Revenues
Gross Sales		7,362		2,929			3,030			555			-			-			9,852			8,439			8,805
Less: Royalties		230		9			29			41			-			-			-			-			-
		7,132		2,920			3,001			514			-			-			9,852			8,439			8,805
Expenses
Purchased Product		-		-			-			-			-			-			8,476			7,325			7,709
Transportation and Blending		3,704		1,721			1,815			56			-			-			-			-			-
Operating		934		501			531			250			-			-			772			742			754
Production and Mineral Taxes		-		-			-			1			-			-			-			-			-
(Gain) Loss on Risk Management		307		(179	)		(404	)		-			-			-			6			26			(43	)
Operating Margin		2,187		877			1,059			207			-			-			598			346			385
Depreciation, Depletion and Amortization		1,230		655			697			331			-			-			215			211			191
Exploration Expense		888		2			67			-			-			-			-			-			-
Segment Income (Loss)		69		220			295			(124	)		-			-			383			135			194
									Corporate and Eliminations									Consolidated
For the years ended December 31,									2017			2016			2015 (1)			2017			2016			2015
Revenues
Gross Sales										(455	)		(353	)		(276	)		17,314			11,015			11,559
Less: Royalties										-			-			1			271			9			30
										(455	)		(353	)		(277	)		17,043			11,006			11,529
Expenses
Purchased Product										(443	)		(347	)		(335	)		8,033			6,978			7,374
Transportation and Blending										(12	)		(6	)		(1	)		3,748			1,715			1,814
Operating										(7	)		(4	)		(4	)		1,949			1,239			1,281
Production and Mineral Taxes										-			-			1			1			-			1
(Gain) Loss on Risk Management										583			554			195			896			401			(252	)
Depreciation, Depletion and Amortization										62			65			105			1,838			931			993
Exploration Expense										-			-			-			888			2			67
Segment Income (Loss)										(638	)		(615	)		(238	)		(310	)		(260	)		251
General and Administrative										308			326			335			308			326			335
Finance Costs										645			390			381			645			390			381
Interest Income										(62	)		(52	)		(28	)		(62	)		(52	)		(28	)
Foreign Exchange (Gain) Loss, Net										(812	)		(198	)		1,036			(812	)		(198	)		1,036
Revaluation (Gain)										(2,555	)		-			-			(2,555	)		-			-
Transaction Costs										56			-			-			56			-			-
Re-measurement of Contingent Payment										(138	)		-			-			(138	)		-			-
Research Costs										36			36			27			36			36			27
(Gain) Loss on Divestiture of Assets										1			6			(2,392	)		1			6			(2,392	)
Other (Income) Loss, Net										(5	)		34			2			(5	)		34			2
										(2,526	)		542			(639	)		(2,526	)		542			(639	)
Earnings (Loss) From Continuing Operations Before Income Tax																			2,216			(802	)		890
Income Tax Expense (Recovery)																			(52	)		(343	)		(24	)
Net Earnings (Loss) From Continuing Operations																			2,268			(459	)		914

(1) The complete results for the 2017 and 2016 Conventional segment have been classified as a discontinued operation. For the 2015 comparative period, the results of operations for certain Conventional segment royalty interest assets disposed of in 2015 have been included in the Corporate and Eliminations segment due to their immaterial nature. The results of operations are as follows: revenues – $60 million, expenses – $5 million, operating margin – $55 million, depreciation, depletion and amortization – $27 million and segment income – $28 million.

Cenovus Energy Inc. 12 For the year ended December 31, 2017

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

All amounts in $ millions, unless otherwise indicated

For the year ended December 31, 2017

B) Revenues by Product

For the years ended December 31,	2017			2016			2015
Upstream
Crude Oil		7,184			2,902			2,971
Natural Gas (1)		235			16			22
NGLs		184			-			-
Other		43			2			8
Refining and Marketing		9,852			8,439			8,805
Corporate and Eliminations		(455	)		(353	)		(277	)
Revenues From Continuing Operations		17,043			11,006			11,529
(1)   In 2017, approximately 14 percent of the natural gas produced by Cenovus’s Deep Basin Assets was sold to ConocoPhillips resulting in gross sales of $32 million. C) Geographical Information
	Revenues
For the years ended December 31,	2017			2016			2015
Canada		9,723			4,978			4,729
United States		7,320			6,028			6,800
Consolidated		17,043			11,006			11,529
				Non-Current Assets (1)
As at December 31,				2017			2016
Canada (2)					31,756			14,130
United States					3,856			4,179
Consolidated					35,612			18,309

(1) Includes exploration and evaluation (“E&E”) assets, property, plant and equipment (“PP&E”), goodwill and other assets.

(2) Certain crude oil and natural gas properties of the Conventional and Deep Basin segments, which reside in Canada, have been reclassified as held for sale in 2017 in current assets. 2016 includes $3.1 billion related to the Conventional segment.

Export Sales

Sales of crude oil, NGLs and natural gas produced or purchased in Canada that have been delivered to customers outside of Canada were $1,713 million (2016 – $974 million; 2015 – $870 million).

Major Customers

In connection with the marketing and sale of Cenovus’s own and purchased crude oil, NGLs, natural gas and refined products for the year ended December 31, 2017, Cenovus had two customers (2016 – three; 2015 – three) that individually accounted for more than 10 percent of its consolidated gross sales. Sales to these customers, recognized as major international energy companies with investment grade credit ratings, were approximately $5,655 million and $1,964 million, respectively (2016 – $4,742 million, $1,623 million and $1,400 million; 2015 – $4,647 million, $1,705 million and $1,545 million), which are included in all of the Company’s operating segments.

D) Exploration and Evaluation Assets, Property, Plant and Equipment, Goodwill and Total Assets

	E&E				PP&E				Goodwill				Total Assets
As at December 31,	2017		2016		2017		2016		2017		2016		2017		2016
Oil Sands		617		1,564		22,320		8,798		2,272		242		26,799		11,112
Deep Basin		3,056		-		3,019		-		-		-		6,694		-
Conventional		-		21		-		3,080		-		-		644		3,196
Refining and Marketing		-		-		3,967		4,273		-		-		5,432		6,613
Corporate and Eliminations		-		-		290		275		-		-		1,364		4,337
Consolidated		3,673		1,585		29,596		16,426		2,272		242		40,933		25,258

Cenovus Energy Inc. 13 For the year ended December 31, 2017

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

All amounts in $ millions, unless otherwise indicated

For the year ended December 31, 2017

E) Capital Expenditures ⁽¹⁾

For the years ended December 31,	2017		2016		2015
Capital
Oil Sands		973		604		1,185
Deep Basin		225		-		-
Conventional		206		171		244
Refining and Marketing		180		220		248
Corporate		77		31		37
Capital Investment		1,661		1,026		1,714
Acquisition Capital
Oil Sands (2)		11,614		11		3
Deep Basin		6,774		-		-
Conventional		-		-		1
Refining and Marketing		-		-		83
Total Capital Expenditures		20,049		1,037		1,801

(1) Includes expenditures on PP&E, E&E assets and assets held for sale.

(2) In connection with the Acquisition discussed in Note 5, Cenovus was deemed to have disposed of its pre-existing interest in FCCL and re-acquired it at fair value as required by International Financial Reporting Standard 3, “Business Combinations” (“IFRS 3”), which is not reflected in the table above. The carrying value of the pre-existing interest was $9,081 million and the estimated fair value was $11,605 million as at May 17, 2017.

2. BASIS OF PREPARATION AND STATEMENT OF COMPLIANCE

In these Consolidated Financial Statements, unless otherwise indicated, all dollars are expressed in Canadian dollars. All references to C$ or $ are to Canadian dollars and references to US$ are to U.S. dollars.

These Consolidated Financial Statements have been prepared in accordance with International Financial Reporting Standards (“IFRS”) as issued by the International Accounting Standards Board (“IASB”) and interpretations of the International Financial Reporting Interpretations Committee (“IFRIC”). These Consolidated Financial Statements have been prepared in compliance with IFRS.

These Consolidated Financial Statements have been prepared on a historical cost basis, except as detailed in the Company’s accounting policies disclosed in Note 3.

These Consolidated Financial Statements were approved by the Board of Directors on February 14, 2018.

3. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

A) Principles of Consolidation

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

Interests in joint arrangements are classified as either joint operations or joint ventures, depending on the rights and obligations of the parties to the arrangement. Joint operations arise when the Company has rights to the assets and obligations for the liabilities of the arrangement. The Company’s Refining activities are conducted through the joint operation WRB Refining LP (“WRB”) and, accordingly, the accounts reflect the Company’s share of the assets, liabilities, revenues and expenses. Prior to May 17, 2017, FCCL was accounted for as a joint operation. Subsequent to the Acquisition, Cenovus controls FCCL, and accordingly, FCCL has been consolidated.

B) Foreign Currency Translation

Functional and Presentation Currency

The Company’s presentation currency is Canadian dollars. The accounts of the Company’s foreign operations that have a functional currency different from the Company’s presentation currency are translated into the Company’s presentation currency at period-end exchange rates for assets and liabilities, and using average rates over the period for revenues and expenses. Translation gains and losses relating to the foreign operations are recognized in other comprehensive income (“OCI”) as cumulative translation adjustments.

When the Company disposes of an entire interest in a foreign operation or loses control, joint control, or significant influence over a foreign operation, the foreign currency gains or losses accumulated in OCI related to the foreign

Cenovus Energy Inc. 14 For the year ended December 31, 2017

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

All amounts in $ millions, unless otherwise indicated

For the year ended December 31, 2017

operation are recognized in net earnings. When the Company disposes of part of an interest in a foreign operation that continues to be a subsidiary, a proportionate amount of gains and losses accumulated in OCI is allocated between controlling and non-controlling interests.

Transactions and Balances

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

C) Revenue Recognition

Revenues associated with the sales of Cenovus’s crude oil, NGLs, natural gas, and petroleum and refined products are recognized when the significant risks and rewards of ownership have been transferred to the customer, the sales price and costs can be measured reliably and it is probable that the economic benefits will flow to the Company. This is generally met when title passes from the Company to its customer. Revenues from the production of crude oil, NGLs and natural gas represent the Company’s share, net of royalty payments to governments and other mineral interest owners.

Processing income and revenue from fee-for-service hydrocarbon trans-loading services is recognized in the period the service is provided.

Purchases and sales of products that are entered into in contemplation of each other with the same counterparty are recorded on a net basis. Revenues associated with the services provided as agent are recorded as the services are provided.

D) Transportation and Blending

The costs associated with the transportation of crude oil, NGLs and natural gas, including the cost of diluent used in blending, are recognized when the product is sold.

E) Exploration Expense

Costs incurred prior to obtaining the legal right to explore (pre-exploration costs) are expensed in the period in which they are incurred as exploration expense.

Costs incurred after the legal right to explore is obtained are initially capitalized. If it is determined that the field/project/area is not technically feasible and commercially viable or if the Company decides not to continue the exploration and evaluation activity, the unrecoverable accumulated costs are expensed as exploration expense.

F) Employee Benefit Plans

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

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

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

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

● Service costs, including current service costs, past service costs, gains and losses on curtailments, and settlements, are recorded with pension benefit costs.

● Net interest is calculated by applying the same discount rate used to measure the defined benefit obligation at the beginning of the annual period to the net defined benefit asset or liability measured. Interest expense and interest income on net post-employment benefit liabilities and assets are recorded with pension benefit costs in operating, and general and administrative expenses, as well as PP&E and E&E assets.

● Remeasurements, composed of actuarial gains and losses, the effect of changes to the asset ceiling (excluding interest) and the return on plan assets (excluding interest income), are charged or credited to equity in OCI in the period in which they arise. Remeasurements are not reclassified to net earnings in subsequent periods.

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

Cenovus Energy Inc. 15 For the year ended December 31, 2017

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

All amounts in $ millions, unless otherwise indicated

For the year ended December 31, 2017

G) Income Taxes

Income taxes comprise current and deferred taxes. Income taxes are provided for on a non-discounted basis at amounts expected to be paid using the tax rates and laws that have been enacted or substantively enacted at the Consolidated Balance Sheet date.

Cenovus follows the liability method of accounting for income taxes, where deferred income taxes are recorded for the effect of any temporary difference between the accounting and income tax basis of an asset or liability, using the substantively enacted income tax rates expected to apply when the assets are realized or liabilities are settled. Deferred income tax balances are adjusted to reflect changes in income tax rates that are substantively enacted with the adjustment being recognized in net earnings in the period that the change occurs, except when it relates to items charged or credited directly to equity or OCI, in which case the deferred income tax is also recorded in equity or OCI, respectively.

Deferred income tax is provided on temporary differences arising from investments in subsidiaries except in the case where the timing of the reversal of the temporary difference is controlled by the Company and it is probable that the temporary difference will not reverse in the foreseeable future or when distributions can be made without incurring income taxes.

Deferred income tax assets are recognized only to the extent that it is probable that future taxable profit will be available against which the temporary differences can be utilized. Deferred income tax assets and liabilities are only offset where they arise within the same entity and tax jurisdiction. Deferred income tax assets and liabilities are presented as non-current.

H) Net Earnings per Share Amounts

Basic net earnings per share is computed by dividing net earnings by the weighted average number of common shares outstanding during the period. Diluted net earnings per share is calculated giving effect to the potential dilution that would occur if stock options or other contracts to issue common shares were exercised or converted to common shares. The treasury stock method is used to determine the dilutive effect of stock options and other dilutive instruments. The treasury stock method assumes that proceeds received from the exercise of in-the-money stock options are used to repurchase common shares at the average market price. For those contracts that may be settled in cash or in shares at the holder’s option, the more dilutive of cash settlement and share settlement is used in calculating diluted earnings per share.

I) Cash and Cash Equivalents

Cash and cash equivalents include short-term investments, such as money market deposits or similar type instruments, with a maturity of three months or less.

J) Inventories

Product inventories are valued at the lower of cost and net realizable value on a first-in, first-out or weighted average cost basis. The cost of inventory includes all costs incurred in the normal course of business to bring each product to its present location and condition. Net realizable value is the estimated selling price in the ordinary course of business less any expected selling costs. If the carrying amount exceeds net realizable value, a write-down is recognized. The write-down may be reversed in a subsequent period if circumstances which caused it no longer exist and the inventory is still on hand.

K) Exploration and Evaluation Assets

Costs incurred after the legal right to explore an area has been obtained, and before technical feasibility and commercial viability of the field/project/area have been established, are capitalized as E&E assets. These costs include license acquisition, geological and geophysical, drilling, sampling, decommissioning and other directly attributable internal costs. E&E assets are not depreciated and are carried forward until technical feasibility and commercial viability of the field/project/area is established or the assets are determined to be impaired. E&E costs are subject to regular technical, commercial and Management review to confirm the continued intent to develop the resources.

Once technical feasibility and commercial viability have been established, the carrying value of the E&E asset is tested for impairment. The carrying value, net of any impairment loss, is then reclassified as PP&E.

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

L) Property, Plant and Equipment

General

PP&E is stated at cost less accumulated depreciation, depletion and amortization (“DD&A”), and net of any impairment losses. Expenditures related to renewals or betterments that improve the productive capacity or extend the life of an asset are capitalized. Maintenance and repairs are expensed as incurred. Land is not depreciated.

Cenovus Energy Inc. 16 For the year ended December 31, 2017

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

All amounts in $ millions, unless otherwise indicated

For the year ended December 31, 2017

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

Development and Production Assets

Development and production assets are capitalized on an area-by-area basis and include all costs associated with the development and production of crude oil and natural gas properties, as well as any E&E expenditures incurred in finding reserves of crude oil, NGLs or natural gas transferred from E&E assets. Capitalized costs include directly attributable internal costs, decommissioning liabilities and, for qualifying assets, borrowing costs directly associated with the acquisition of, the exploration for, and the development of crude oil and natural gas reserves.

Costs accumulated within each area are depleted using the unit-of-production method based on estimated proved reserves determined using forward prices and costs. For the purpose of this calculation, natural gas is converted to crude oil on an energy equivalent basis. Costs subject to depletion include estimated future costs to be incurred in developing proved reserves.

Exchanges of development and production assets are measured at fair value unless the transaction lacks commercial substance or the fair value of neither the asset received, nor the asset given up, can be reliably measured. When fair value is not used, the carrying amount of the asset given up is used as the cost of the asset acquired.

Other Upstream Assets

Other upstream assets include information technology assets used to support the upstream business. These assets are depreciated on a straight-line basis over their useful lives of three years.

Refining Assets

The initial acquisition costs of refining PP&E are capitalized when incurred. Costs include the cost of constructing or otherwise acquiring the equipment or facilities, the cost of installing the asset and making it ready for its intended use, the associated decommissioning costs and, for qualifying assets, borrowing costs.

Refining assets are depreciated on a straight-line basis over the estimated service life of each component of the refinery. The major components are depreciated as follows:

●   Land improvements and buildings	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.

Other Assets

Costs associated with the crude-by-rail terminal, office furniture, fixtures, leasehold improvements, information technology and aircraft are carried at cost and depreciated on a straight-line basis over the estimated service lives of the assets, which range from three to 40 years.

The residual value, method of amortization and the useful lives of the assets are reviewed annually and adjusted on a prospective basis, if appropriate.

M) Impairment

Non-Financial Assets

PP&E and E&E assets are reviewed separately for indicators of impairment quarterly or when facts and circumstances suggest that the carrying amount may exceed its recoverable amount. Goodwill is tested for impairment at least annually.

If indicators of impairment exist, the recoverable amount of the cash-generating unit (“CGU”) is estimated as the greater of value-in-use (“VIU”) and fair value less costs of disposal (“FVLCOD”). VIU is estimated as the present value of the future cash flows expected to arise from the continuing use of a CGU or an asset. FVLCOD is determined by estimating the discounted after-tax future net cash flows. For Cenovus’s upstream assets, FVLCOD is based on the discounted after-tax cash flows of reserves and resources using forward prices and costs, consistent with Cenovus’s independent qualified reserves evaluators (“IQREs”), and may consider an evaluation of comparable asset transactions.

E&E assets are allocated to a related CGU containing development and production assets for the purposes of testing for impairment. Goodwill is allocated to the CGUs to which it contributes to the future cash flows.

If the recoverable amount of the CGU is less than the carrying amount, an impairment loss is recognized. An impairment loss is allocated first to reduce the carrying amount of any goodwill allocated to the CGU and then to reduce the carrying amounts of the other assets in the CGU. Goodwill impairments are not reversed.

Cenovus Energy Inc. 17 For the year ended December 31, 2017

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

All amounts in $ millions, unless otherwise indicated

For the year ended December 31, 2017

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. At inception, a leased asset within PP&E and a corresponding lease obligation are recognized. The leased asset is depreciated over the shorter of the estimated useful life of the asset or the lease term.

O) Business Combinations and Goodwill

Business combinations are accounted for using the acquisition method of accounting in which the identifiable assets acquired, liabilities assumed and non-controlling interest, if any, are recognized and measured at their fair value at the date of acquisition. Any excess of the purchase price plus any non-controlling interest over the fair value of the net assets acquired is recognized as goodwill. Any deficiency of the purchase price over the fair value of the net assets acquired is credited to net earnings.

At acquisition, goodwill is allocated to each of the CGUs to which it relates. Subsequent measurement of goodwill is at cost less any accumulated impairment losses.

Contingent consideration transferred in a business combination is measured at fair value on the date of acquisition and classified as a financial liability or equity. Contingent consideration classified as a liability is re-measured at fair value at each reporting date, with changes in fair value recognized in net earnings. Payments are classified as cash used in investing activities until the cumulative payments exceed the acquisition date fair value of the liability. Cumulative payments in excess of the acquisition date fair value are classified as cash used in operating activities. Contingent consideration classified as equity are not re-measured and settlements are accounted for within equity.

When a business combination is achieved in stages, the Company re-measures its pre-existing interest at the acquisition date fair value and recognizes the resulting gain or loss, if any, in net earnings.

P) Provisions

General

A provision is recognized if, as a result of a past event, the Company has a present obligation, legal or constructive, that can be estimated reliably, and it is more likely than not that an outflow of economic benefits will be required to settle the obligation. Where applicable, provisions are determined by discounting the expected future cash flows at a pre-tax credit-adjusted rate that reflects the current market assessments of the time value of money and the risks specific to the liability. The increase in the provision due to the passage of time is recognized as a finance cost in the Consolidated Statements of Earnings.

Cenovus Energy Inc. 18 For the year ended December 31, 2017

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

All amounts in $ millions, unless otherwise indicated

For the year ended December 31, 2017

Decommissioning Liabilities

Decommissioning liabilities include those legal or constructive obligations where the Company will be required to retire tangible long-lived assets such as producing well sites, upstream processing facilities, refining facilities and the crude-by-rail terminal. The amount recognized is the present value of estimated future expenditures required to settle the obligation using a credit-adjusted risk-free rate. A corresponding asset equal to the initial estimate of the liability is capitalized as part of the cost of the related long-lived asset. Changes in the estimated liability resulting from revisions to expected timing or future decommissioning costs are recognized as a change in the decommissioning liability and the related long-lived asset. The amount capitalized in PP&E is depreciated over the useful life of the related asset.

Actual expenditures incurred are charged against the accumulated liability.

Q) Share Capital

Common shares are classified as equity. Transaction costs directly attributable to the issue of common shares are recognized as a deduction from equity, net of any income taxes.

R) Stock-Based Compensation

Cenovus has a number of stock-based compensation plans which include stock options with associated net settlement rights (“NSRs”), stock options with associated tandem stock appreciation rights (“TSARs”), performance share units (“PSUs”), restricted share units (“RSUs”) and deferred share units (“DSUs”). Stock-based compensation costs are recorded in general and administrative expense, or E&E and PP&E when directly related to exploration or development activities.

Net Settlement Rights

NSRs are accounted for as equity instruments, which are measured at fair value on the grant date using the Black-Scholes-Merton valuation model and are not revalued at each reporting date. The fair value is recognized as stock-based compensation costs over the vesting period, with a corresponding increase recorded as paid in surplus in Shareholders’ Equity. On exercise, the cash consideration received by the Company and the associated paid in surplus are recorded as share capital.

Tandem Stock Appreciation Rights

TSARs are accounted for as liability instruments, which are measured at fair value at each period end using the Black-Scholes-Merton valuation model. The fair value is recognized as stock-based compensation costs over the vesting period. When options are settled for cash, the liability is reduced by the cash settlement paid. When options are settled for common shares, the cash consideration received by the Company and the previously recorded liability associated with the option are recorded as share capital.

Performance, Restricted and Deferred Share Units

PSUs, RSUs and DSUs are accounted for as liability instruments and are measured at fair value based on the market value of Cenovus’s common shares at each period end. The fair value is recognized as stock-based compensation costs over the vesting period. Fluctuations in the fair values are recognized as stock-based compensation costs in the period they occur.

S) Financial Instruments

The Company’s financial assets include cash and cash equivalents, accounts receivable and accrued revenues, risk management assets, investments in the equity of private companies and long-term receivables. The Company’s financial liabilities include accounts payable and accrued liabilities, contingent payment, risk management liabilities, short-term borrowings and long-term debt.

Financial instruments are recognized when the Company becomes a party to the contractual provisions of the instrument. Financial assets and liabilities are not offset unless the Company has the current legal right to offset and intends to settle on a net basis or settle the asset and liability simultaneously. A financial asset is derecognized when the rights to receive cash flows from the asset have expired or have been transferred and the Company has transferred substantially all the risks and rewards of ownership. A financial liability is derecognized when the obligation is discharged, cancelled or expired. When an existing financial liability is replaced by another from the same counterparty with substantially different terms, or the terms of an existing liability are substantially modified, this exchange or modification is treated as a derecognition of the original liability and the recognition of a new liability. The difference in the carrying amounts of the liabilities is recognized in the Consolidated Statements of Earnings.

Financial instruments are classified as either “fair value through profit and loss”, “loans and receivables”, “held-to-maturity investments”, “available for sale financial assets” or “financial liabilities measured at amortized cost”. The Company determines the classification of its financial instruments at initial recognition. Financial instruments are

Cenovus Energy Inc. 19 For the year ended December 31, 2017

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

All amounts in $ millions, unless otherwise indicated

For the year ended December 31, 2017

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. Derivative financial instruments are not used for speculative purposes.

The Company has classified its contingent payment as “fair value through profit or loss.”

Loans and Receivables

“Loans and receivables” are financial assets with fixed or determinable payments that are not quoted in an active market. After initial measurement, these assets are measured at amortized cost at the settlement date using the effective interest method of amortization. “Loans and receivables” comprise cash and cash equivalents, accounts receivable and accrued revenues, and long-term receivables. Gains and losses on “loans and receivables” are recognized in net earnings when the “loans and receivables” are derecognized or impaired.

Available for Sale Financial Assets

“Available for sale financial assets” are measured at fair value, with changes in fair value recognized in OCI. When an active market is non-existent, fair value is determined using valuation techniques. When fair value cannot be reliably measured, such assets are carried at cost. Available for sale financial assets comprise investments in the equity of private companies that the Company does not control or have significant influence over.

Financial Liabilities Measured at Amortized Cost

These financial liabilities are measured at amortized cost at the settlement date using the effective interest method of amortization. Financial liabilities measured at amortized cost comprise accounts payable and accrued liabilities, short-term borrowings and long-term debt. Long-term debt transaction costs, premiums and discounts are capitalized within long-term debt or as a prepayment and amortized using the effective interest method.

T) Reclassification

Certain information provided for prior years has been reclassified to conform to the presentation adopted in 2017.

U) Recent Accounting Pronouncements

New Accounting Standards and Interpretations not yet Adopted

A number of new accounting standards, amendments to accounting standards and interpretations are effective for annual periods beginning on or after January 1, 2018 and have not been applied in preparing the Consolidated Financial Statements for the year ended December 31, 2017. The standards applicable to Cenovus are as follows and will be adopted on their respective effective dates:

Financial Instruments

On July 24, 2014, the IASB issued the final version of IFRS 9, “Financial Instruments” (“IFRS 9”) to replace IAS 39, “Financial Instruments: Recognition and Measurement” (“IAS 39”).

IFRS 9 introduces a single approach to determine whether a financial asset is measured at amortized cost or fair value and replaces the multiple rules in IAS 39. The approach is based on how an entity manages its financial instruments in the context of its business model and the contractual cash flow characteristics of the financial assets. The IAS 39 measurement categories for financial assets will be replaced by fair value through profit or loss, fair value through other comprehensive income (“FVOCI”) and amortized cost. The standard eliminates the existing IAS 39 categories of held to maturity, loans and receivables and available for sale. Based on Management’s assessment, the change in categories will not have a material impact on the Consolidated Financial Statements. As

Cenovus Energy Inc. 20 For the year ended December 31, 2017

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

All amounts in $ millions, unless otherwise indicated

For the year ended December 31, 2017

at December 31, 2017, the Company has private equity investments classified as available for sale with a fair value of $37 million. Under IFRS 9, the Company has elected to measure these investments as FVOCI. As such, all fair value gains or losses will be recorded in OCI, impairments will not be recognized in net earnings and fair value gains or losses will not be recycled to net earnings on disposition.

IFRS 9 retains most of the IAS 39 requirements for financial liabilities. However, where the fair value option is applied to financial liabilities, the change in fair value resulting from an entity’s own credit risk is recorded in OCI rather than net earnings, unless this creates an accounting mismatch. Cenovus currently does not designate any financial liabilities as fair value through profit or loss; therefore, there will be no impact on the accounting for financial liabilities.

A new expected credit loss model for calculating impairment on financial assets replaces the incurred loss impairment model used in IAS 39. The new model will result in more timely recognition of expected credit losses. Management does not expect a material change to its impairment provision as at January 1, 2018.

In addition, IFRS 9 includes a simplified hedge accounting model, aligning hedge accounting more closely with risk management. Cenovus does not currently apply hedge accounting.

IFRS 9 must be adopted for years beginning on or after January 1, 2018. The Company will apply the new standard retrospectively and elect to use the practical expedients permitted under the standard. Comparative periods will not be restated.

Revenue Recognition

On May 28, 2014, the IASB issued IFRS 15, “Revenue From Contracts With Customers” (“IFRS 15”) replacing IAS 11, “Construction Contracts”, IAS 18, “Revenue” and several revenue-related interpretations. IFRS 15 establishes a single revenue recognition framework that applies to contracts with customers. The standard requires an entity to recognize revenue to reflect the transfer of goods and services for the amount it expects to receive, when control is transferred to the purchaser. Disclosure requirements have also been expanded.

Management has assessed the impact of applying the new standard on the Consolidated Financial Statements and has not identified any material differences from its current revenue recognition practice.

The adoption of IFRS 15 is mandatory for years beginning on or after January 1, 2018. The standard may be applied either retrospectively or using a modified retrospective approach. Cenovus intends to adopt the standard using the modified retrospective approach recognizing the cumulative impact of adoption in retained earnings as of January 1, 2018. Comparative periods will not be restated. The Company will apply IFRS 15 using the practical expedient in paragraph C5(a) of IFRS 15, under which the Company will not restate contracts that are completed contracts as at the date of adoption.

Leases

On January 13, 2016, the IASB issued IFRS 16, “Leases” (“IFRS 16”), which requires entities to recognize lease assets and lease obligations on the balance sheet. For lessees, IFRS 16 removes the classification of leases as either operating leases or finance leases, effectively treating all leases as finance leases. Certain short-term leases (less than 12 months) and leases of low-value assets are exempt from the requirements, and may continue to be treated as operating leases.

Lessors will continue with a dual lease classification model. Classification will determine how and when a lessor will recognize lease revenue, and what assets would be recorded.

IFRS 16 is effective for years beginning on or after January 1, 2019, with early adoption permitted if IFRS 15 has been adopted. The standard may be applied retrospectively or using a modified retrospective approach. The modified retrospective approach does not require restatement of prior period financial information as it recognizes the cumulative effect of applying the standard to prior periods as an adjustment to opening retained earnings. It is anticipated that the adoption of IFRS 16 will have a material impact on the Company’s Consolidated Balance Sheets due to material operating lease commitments. Cenovus will adopt IFRS 16 effective January 1, 2019. The Company intends to adopt the standard using the retrospective with cumulative effect approach and apply several of the practical expedients available.

Uncertain Tax Positions

In June 2017, the IASB issued International Financial Reporting Interpretation Committee 23, “Uncertainty Over Income Tax Treatments” (“IFRIC 23”). The interpretation provides clarity on how to account for a tax position when there is uncertainty over income tax treatments. In determining the likely resolution of the uncertain tax positions, a position may be considered separately or as a group. In addition, an assessment is required to determine the probability that the tax authority will accept the tax position taken in income tax filings. If the uncertain income tax treatment is unlikely to be accepted, the accounting tax position must reflect an appropriate level of uncertainty. An uncertain tax position may be reassessed if new information changes the original assessment. IFRIC 23 is

Cenovus Energy Inc. 21 For the year ended December 31, 2017

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

All amounts in $ millions, unless otherwise indicated

For the year ended December 31, 2017

effective for annual periods beginning on or after January 1, 2019 using either a modified or full retrospective approach. IFRIC 23 is not expected to have a significant impact on the Consolidated Financial Statements.

4. CRITICAL ACCOUNTING JUDGMENTS AND KEY SOURCES OF ESTIMATION UNCERTAINTY

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

A) Critical Judgments in Applying Accounting Policies

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

Joint Arrangements

The classification of a joint arrangement as either a joint operation or a joint venture requires judgment. Cenovus holds a 50 percent interest in WRB, a jointly controlled entity. It was determined that Cenovus has the rights to the assets and obligations for the liabilities of WRB. As a result, the joint arrangement is classified as a joint operation and the Company’s share of the assets, liabilities, revenues and expenses are recorded in the Consolidated Financial Statements.

Prior to May 17, 2017, Cenovus held a 50 percent interest in FCCL, which was jointly controlled with ConocoPhillips and met the definition of a joint operation under IFRS 11, “Joint Arrangements”. As such, Cenovus recognized its share of the assets, liabilities, revenues and expenses in its consolidated results. Subsequent to the Acquisition, Cenovus controls FCCL, as defined under IFRS 10, “Consolidated Financial Statements” (“IFRS 10”) and, accordingly, FCCL has been consolidated.

In determining the classification of its joint arrangements under IFRS 11, the Company considered the following:

● The intention of the transaction creating FCCL and WRB was to form an integrated North American heavy oil business. The integrated business was structured, initially on a tax neutral basis, through two partnerships due to the assets residing in different tax jurisdictions. Partnerships are “flow-through” entities which have a limited life.

● The partnership agreements require the partners (Cenovus and ConocoPhillips or Phillips 66 or respective subsidiaries) to make contributions if funds are insufficient to meet the obligations or liabilities of the partnerships. The past and future development of FCCL and WRB is dependent on funding from the partners by way of partnership notes payable and loans. The partnerships do not have any third-party borrowings.

● FCCL operated like most typical western Canadian working interest relationships where the operating partner takes product on behalf of the participants. WRB has a very similar structure modified only to account for the operating environment of the refining business.

● Cenovus and Phillips 66, as operators, either directly or through wholly-owned subsidiaries, provide marketing services, purchase necessary feedstock, and arrange for transportation and storage on the partners’ behalf as the agreements prohibit the partnerships from undertaking these roles themselves. In addition, the partnerships do not have employees and, as such, are not capable of performing these roles.

● In each arrangement, output is taken by one of the partners, indicating that the partners have rights to the economic benefits of the assets and the obligation for funding the liabilities of the arrangements.

Exploration and Evaluation Assets

The application of the Company’s accounting policy for E&E expenditures requires judgment in determining whether it is likely that future economic benefit exists when activities have not reached a stage where technical feasibility and commercial viability can be reasonably determined. Factors such as drilling results, future capital programs, future operating expenses, as well as estimated reserves and resources are considered. In addition, Management uses judgment to determine when E&E assets are reclassified to PP&E. In making this determination, various factors are considered, including the existence of reserves, and whether the appropriate approvals have been received from regulatory bodies and the Company’s internal approval process.

Cenovus Energy Inc. 22 For the year ended December 31, 2017

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

All amounts in $ millions, unless otherwise indicated

For the year ended December 31, 2017

Identification of Cash-Generating Units

CGUs are defined as the lowest level of integrated assets for which there are separately identifiable cash flows that are largely independent of cash flows from other assets or groups of assets. The classification of assets and allocation of corporate assets into CGUs requires significant judgment and interpretation. Factors considered in the classification include the integration between assets, shared infrastructures, the existence of common sales points, geography, geologic structure, and the manner in which Management monitors and makes decisions about its operations. The recoverability of the Company’s upstream, refining, crude-by-rail and corporate assets are assessed at the CGU level. As such, the determination of a CGU could have a significant impact on impairment losses and reversals.

B) Key Sources of Estimation Uncertainty

Critical accounting estimates are those estimates that require Management to make particularly subjective or complex judgments about matters that are inherently uncertain. Estimates and underlying assumptions are reviewed on an ongoing basis and any revisions to accounting estimates are recorded in the period in which the estimates are revised. The following are the key assumptions about the future and other key sources of estimation at the end of the reporting period that changes to could result in a material adjustment to the carrying amount of assets and liabilities within the next financial year.

Crude Oil and Natural Gas Reserves

There are a number of inherent uncertainties associated with estimating crude oil and natural gas reserves. Reserves estimates are dependent upon variables including the recoverable quantities of hydrocarbons, the cost of the development of the required infrastructure to recover the hydrocarbons, production costs, estimated selling price of the hydrocarbons produced, royalty payments and taxes. Changes in these variables could significantly impact the reserves estimates which would affect the impairment test fair value less costs to sell and DD&A expense of the Company’s crude oil and natural gas assets in the Oil Sands and Deep Basin segments. The Company’s reserves are evaluated annually and reported to the Company by its IQREs.

Recoverable Amounts

Determining the recoverable amount of a CGU or an individual asset requires the use of estimates and assumptions, which are subject to change as new information becomes available. For the Company’s upstream assets, these estimates include forward commodity prices, expected production volumes, quantity of reserves and resources, discount rates, future development and operating expenses, and income tax rates. Recoverable amounts for the Company’s refining assets and crude-by-rail terminal use assumptions such as throughput, forward commodity prices, operating expenses, transportation capacity, supply and demand conditions and income tax rates. Changes in assumptions used in determining the recoverable amount could affect the carrying value of the related assets.

Decommissioning Costs

Provisions are recorded for the future decommissioning and restoration of the Company’s upstream assets, refining assets and crude-by-rail terminal at the end of their economic lives. Management uses judgment to assess the existence and to estimate the future liability. The actual cost of decommissioning and restoration is uncertain and cost estimates may change in response to numerous factors including changes in legal requirements, technological advances, inflation and the timing of expected decommissioning and restoration. In addition, Management determines the appropriate discount rate at the end of each reporting period. This discount rate, which is credit-adjusted, is used to determine the present value of the estimated future cash outflows required to settle the obligation and may change in response to numerous market factors.

Fair Value of Assets Acquired and Liabilities Assumed in a Business Combination

The fair value of assets acquired and liabilities assumed in a business combination, including contingent consideration and goodwill, is estimated based on information available at the date of acquisition. Various valuation techniques are applied for measuring fair value including market comparables and discounted cash flows which rely on assumptions such as forward commodity prices, reserves and resources estimates, production costs, volatility, Canadian-U.S. foreign exchange rates and discount rates. Changes in these variables could significantly impact the carrying value of the net assets.

Income Tax Provisions

Tax regulations and legislation and the interpretations thereof in the various jurisdictions in which Cenovus operates are subject to change. There are usually a number of tax matters under review; therefore, income taxes are subject to measurement uncertainty.

Deferred income tax assets are recorded to the extent that it is probable that the deductible temporary differences will be recoverable in future periods. The recoverability assessment involves a significant amount of estimation

Cenovus Energy Inc. 23 For the year ended December 31, 2017

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

All amounts in $ millions, unless otherwise indicated

For the year ended December 31, 2017

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

5. ACQUISITION

FCCL and Deep Basin Acquisition

A) Summary of the Acquisition

On May 17, 2017, Cenovus acquired ConocoPhillips’ 50 percent interest in FCCL and the majority of ConocoPhillips’ Deep Basin Assets in Alberta and British Columbia (the “Acquisition”). The Acquisition provides Cenovus with control over the Company’s oil sands operations, doubles the Company’s oil sands production, and almost doubles the Company’s proved bitumen reserves. The Deep Basin Assets provide a second core operating area with more than three million net acres of land, exploration and production assets, and related infrastructure in Alberta and British Columbia.

The Acquisition has been accounted for using the acquisition method pursuant to IFRS 3. Under the acquisition method, assets and liabilities are recorded at their fair values on the date of acquisition and the total consideration is allocated to the tangible and intangible assets acquired and liabilities assumed. The excess of consideration given over the fair value of the net assets acquired has been recorded as goodwill.

B) Identifiable Assets Acquired and Liabilities Assumed

The final purchase price allocation is based on Management’s best estimate of fair value and has been retrospectively adjusted to reflect new information obtained between May 17, 2017 and December 31, 2017 about conditions that existed at the acquisition date. As a result of these adjustments, the final purchase price allocation includes an increase of $912 million to PP&E, $56 million to inventory, and $16 million to accounts receivable and accrued revenues, as well as an $822 million decrease to E&E assets. Goodwill from the Acquisition was reduced to $2,030 million and the revaluation gain increased to $2,555 million. These adjustments also resulted in a $9 million increase to the deferred income tax liability.

The following table summarizes the recognized amounts of assets acquired and liabilities assumed at the date of the Acquisition.

	Notes
100 Percent of the Identifiable Assets Acquired and Liabilities Assumed for FCCL
Cash			880
Accounts Receivable and Accrued Revenues			964
Inventories			345
E&E Assets		17	491
PP&E		18	22,717
Other Assets			27
Accounts Payable and Accrued Liabilities			(445	)
Decommissioning Liabilities		24	(277	)
Other Liabilities			(8	)
Deferred Income Taxes			(2,506	)
			22,188
Recognized Amounts of Identifiable Assets Acquired and Liabilities Assumed for Deep Basin
Accounts Receivable and Accrued Revenues			16
Inventories			14
E&E Assets		17	3,117
PP&E		18	3,600
Accounts Payable and Accrued Liabilities			(6	)
Decommissioning Liabilities		24	(667	)
			6,074
Total Identifiable Net Assets			28,262

The fair value of acquired accounts receivables and accrued revenues was $980 million. As at December 31, 2017, $964 million has been received and the remainder is expected to be collected.

Cenovus Energy Inc. 24 For the year ended December 31, 2017

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

All amounts in $ millions, unless otherwise indicated

For the year ended December 31, 2017

C) Total Consideration

Total consideration for the Acquisition consisted of US$10.6 billion in cash and 208 million Cenovus common shares plus closing adjustments. At the same time, Cenovus agreed to make certain quarterly contingent payments to ConocoPhillips during the five years subsequent to May 17, 2017 if crude oil prices exceed a specific threshold. The following table summarizes the fair value of the consideration:

Common Shares	2,579
Cash	15,005
	17,584
Estimated Contingent Payment (Note 22)	361
Total Consideration	17,945

At the date of closing, the Company issued 208 million common shares to ConocoPhillips that were accounted for at $12.40 per share, the estimated fair value for accounting purposes.

Consideration paid in cash was US$10.6 billion, before closing adjustments, and was financed through a bought-deal common share offering (see Note 27) and an offering in the United States for senior unsecured notes (see Note 23). In addition, Cenovus borrowed $3.6 billion under a committed asset sale bridge credit facility (see Note 23). The remainder of the cash purchase price was funded with cash on hand and a draw on Cenovus’s existing committed credit facility.

The estimated contingent payment related to oil sands production reflects that Cenovus agreed to make quarterly payments to ConocoPhillips during the five years subsequent to the closing date for quarters in which the average Western Canadian Select (“WCS”) crude oil price exceeds $52.00 per barrel during the quarter. The quarterly payment will be $6 million for each dollar that the WCS price exceeds $52.00 per barrel. There are no maximum payment terms.

The calculation of any contingent payment includes an adjustment mechanism related to certain significant production outages at Foster Creek and Christina Lake, which may reduce the amount of a contingent payment. The terms of the contingent payment agreement allow Cenovus to retain 80 percent to 85 percent of the WCS prices above $52.00 per barrel, based on gross production capacity at Foster Creek and Christina Lake at the time of the Acquisition. As production capacity increases with future expansions, the percentage of upside available to Cenovus will increase further.

The contingent payment is accounted for as a financial option. The fair value of $361 million on May 17, 2017 was estimated by calculating the present value of the future expected cash flows using an option pricing model, which assumes the probability distribution for WCS is based on the volatility of West Texas Intermediate (“WTI”) options, volatility of Canadian-U.S. foreign exchange rate options and WCS futures pricing, and discounted at a credit-adjusted risk-free rate of 2.9 percent. The contingent payment will be re-measured at fair value at each reporting date with changes in fair value recognized in net earnings (see Note 22).

D) Goodwill

Goodwill arising from the Acquisition has been recognized as follows:

	Notes
Total Purchase Consideration		4C	17,945
Fair Value of Pre-Existing 50 Percent Ownership Interest in FCCL			12,347
Fair Value of Identifiable Net Assets		4B	(28,262	)
Goodwill			2,030

Fair Value of Pre-Existing 50 Percent Ownership Interest in FCCL

Prior to the Acquisition, Cenovus’s 50 percent interest in FCCL was jointly controlled with ConocoPhillips and met the definition of a joint operation under IFRS 11 and as such Cenovus recognized its share of the assets, liabilities, revenues and expenses in its consolidated results. Subsequent to the Acquisition, Cenovus controls FCCL, as defined under IFRS 10 and, accordingly, FCCL has been consolidated from the date of acquisition. As required by IFRS 3, when an acquirer achieves control in stages, the previously held interest is re-measured to fair value at the acquisition date with any gain or loss recognized in net earnings. The acquisition-date fair value of the previously held interest was $12.3 billion and has been included in the measurement of the total consideration transferred. The carrying value of the FCCL assets was $9.7 billion. As a result, Cenovus recognized a non-cash revaluation gain of $2.6 billion ($1.9 billion, after-tax) on the re-measurement to fair value of its existing interest in FCCL.

Cenovus Energy Inc. 25 For the year ended December 31, 2017

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

All amounts in $ millions, unless otherwise indicated

For the year ended December 31, 2017

Goodwill was recorded in connection with deferred tax liabilities arising from the difference between the purchase price allocated to the FCCL assets and liabilities based on fair value and the tax basis of these assets and liabilities. In addition, the consideration paid for FCCL included a control premium, which resulted in a higher value compared to the fair value of the net assets acquired.

E) Acquisition-Related Costs

The Company incurred $56 million of Acquisition-related costs, excluding common share and debt issuance costs. These costs have been included in transaction costs in the Consolidated Statements of Earnings.

Debt issuance costs related to the Acquisition financing were $72 million. These costs are netted against the carrying amount of the debt and amortized using the effective interest method.

F) Transitional Services

Under the purchase and sales agreement, Cenovus and ConocoPhillips agreed to certain transitional services where ConocoPhillips provided certain day-to-day services required by Cenovus for a period of approximately nine months. These transactions were in the normal course of operations and have been measured at the exchange amounts.

Costs related to the transitional services of approximately $40 million were recorded in general and administrative expenses.

G) Revenue and Profit Contribution

The acquired business contributed revenues of $3.3 billion and net earnings of $172 million for the period from May 17, 2017 to December 31, 2017.

If the closing of the Acquisition had occurred on January 1, 2017, Cenovus’s consolidated pro forma revenue and net earnings for the twelve months ended December 31, 2017 would have been $19.0 billion and $3.5 billion, respectively. These amounts have been calculated using results from the acquired business and adjusting them for:

● Differences in accounting policies;

● Additional finance costs that would have been incurred if the amounts drawn on the Company’s committed asset sale bridge credit facility and the senior unsecured notes issued to fund the Acquisition had occurred on January 1, 2017;

● Additional DD&A that would have been charged assuming the fair value adjustments to PP&E and E&E assets had applied from January 1, 2017;

● Accretion on the decommissioning liability if it had been assumed on January 1, 2017; and

● The consequential tax effects.

This pro forma information is not necessarily indicative of the results that would have been obtained if the Acquisition had actually occurred on January 1, 2017.

Crude-by-Rail Terminal Acquisition

In August 2015, the Company completed the acquisition of a crude-by-rail terminal for cash consideration of $75 million, plus adjustments. The transaction was accounted for using the acquisition method of accounting. In connection with the acquisition, the Company assumed an associated decommissioning liability of $4 million, working capital of $1 million and net transportation commitments of $92 million. Transaction costs associated with the acquisition were expensed. These assets, related liabilities and results of operations are reported in the Refining and Marketing segment.

6. FINANCE COSTS

For the years ended December 31,	2017		2016		2015
Interest Expense – Short-Term Borrowings and Long-Term Debt		571		341		328
Unwinding of Discount on Decommissioning Liabilities (Note 24)		48		28		25
Other		26		21		28
		645		390		381

Cenovus Energy Inc. 26 For the year ended December 31, 2017

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

All amounts in $ millions, unless otherwise indicated

For the year ended December 31, 2017

7. FOREIGN EXCHANGE (GAIN) LOSS, NET

For the years ended December 31,	2017		2016		2015
Unrealized Foreign Exchange (Gain) Loss on Translation of:
U.S. Dollar Debt Issued From Canada		(665)		(196)		1,064
Other		(192)		7		33
Unrealized Foreign Exchange (Gain) Loss		(857)		(189)		1,097
Realized Foreign Exchange (Gain) Loss		45		(9)		(61)
		(812)		(198)		1,036

8. DIVESTITURES

In 2017, the Company completed the sale of the majority of its Conventional segment crude oil and natural gas properties for gross proceeds of $3.2 billion. A net gain of $1.3 billion was recorded on the divestitures. For further information see Note 11.

In 2016, the Company completed the sale of land to an unrelated third party for cash proceeds of $8 million, resulting in a loss of $5 million. The Company also sold equipment at a loss of $1 million. These assets, related liabilities and results of operations were reported in the Conventional segment.

In 2015, the Company completed the sale of Heritage Royalty Limited Partnership (“HRP”), a wholly-owned subsidiary, to a third party for gross cash proceeds of $3.3 billion, resulting in a gain of $2.4 billion. HRP was a royalty business consisting of royalty interest and mineral fee title lands in Alberta, Saskatchewan and Manitoba. These assets, related liabilities and results of operations were reported in the Conventional segment. In 2017, the remaining Conventional segment was classified as a discontinued operation.

The divestiture of HRP gave rise to a taxable gain for which the Company recognized a current tax expense of $391 million. The majority of HRP’s assets had been acquired at a nominal cost and, as such, had minimal benefit from tax depreciation in prior years. For this reason, the current tax expense associated with the divestiture was specifically identifiable; therefore, it was classified as an investing activity in the Consolidated Statements of Cash Flows.

In addition, the Company divested of an office building in 2015, recording a gain of $16 million.

9. OTHER (INCOME) LOSS, NET

As at December 31, 2016, due to the Government of Canada’s decision to reject the Northern Gateway Pipeline project, the Company wrote off $23 million of capitalized costs associated with its funding support unit in Northern Gateway Pipeline. In addition, $7 million of costs associated with termination were recorded and $7  million (2015 – $nil) of certain investments in private equity companies were written off.

10. IMPAIRMENT CHARGES AND REVERSALS

A) Cash-Generating Unit Net Impairments

On a quarterly basis, the Company assesses its CGUs for indicators of impairment or when facts and circumstances suggest the carrying amount may exceed its recoverable amount. Goodwill is tested for impairment at least annually.

2017 Upstream Impairments

As indicators of impairment were noted for the Company’s upstream assets due to a decline in forward commodity prices since the Acquisition, the Company tested its upstream CGUs for impairment. As at December 31, 2017, the Company determined that the carrying amount of the Clearwater CGU exceeded its recoverable amount, resulting in an impairment loss of $56 million. The impairment was recorded as additional DD&A in the Deep Basin segment. Future cash flows for the CGU declined due to lower forward crude oil prices and revisions to the development plan. As at December 31, 2017, the recoverable amount of the Clearwater CGU was estimated to be approximately $295 million.

Cenovus Energy Inc. 27 For the year ended December 31, 2017

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

All amounts in $ millions, unless otherwise indicated

For the year ended December 31, 2017

Key Assumptions

The recoverable amounts of Cenovus’s upstream CGUs were determined based on FVLCOD or an evaluation of comparable asset transactions. The fair values for producing properties were calculated based on discounted after-tax cash flows of proved and probable reserves using forward prices and cost estimates, prepared by Cenovus’s IQREs (Level 3). Key assumptions in the determination of future cash flows from reserves include crude oil and natural gas prices, costs to develop and the discount rate. All reserves have been evaluated as at December 31, 2017 by the IQREs.

Crude Oil, NGLs and Natural Gas Prices

The forward prices as at December 31, 2017, used to determine future cash flows from crude oil, NGLs and natural gas reserves were:

	2018		2019		2020		2021		2022		Average   Annual   Increase   Thereafter
WTI (US$/barrel)		57.50		60.90		64.13		68.33		71.19		2.1%
WCS (C$/barrel)		50.61		56.59		60.86		64.56		66.63		2.1%
Edmonton C5+ (C$/barrel)		72.41		74.90		77.07		81.07		83.32		2.1%
AECO (C$/Mcf) (1) (2)		2.43		2.77		3.19		3.48		3.67		2.0%

(1) Alberta Energy Company (“AECO”) natural gas.

(2) Assumes gas heating value of one million British Thermal Units per thousand cubic feet.

Discount and Inflation Rates

Discounted future cash flows are determined by applying a discount rate between 10 percent and 15 percent based on the individual characteristics of the CGU, and other economic and operating factors. Inflation is estimated at two percent.

For the purpose of impairment testing, goodwill is allocated to the CGU to which it relates. There were no goodwill impairments for the twelve months ended December 31, 2017.

Sensitivities

The sensitivity analysis below shows the impact that a change in the discount rate or forward commodity prices would have on impairment testing for the following CGUs:

	Increase (Decrease) to Impairment
	One Percent    Increase in    the Discount    Rate		One Percent    Decrease in    the Discount    Rate		Five Percent    Increase in    the Forward    Price    Estimates (1)		Five Percent     Decrease in    the Forward    Price    Estimates
Clearwater		27		(30)		(56)		65
Primrose		-		-		-		-
Christina Lake		-		-		-		-
Narrows Lake		312		-		-		333

(1) The $56 million represents the impairment loss as at December 31, 2017 that could be reversed in future periods.

2016 Net Upstream Impairments

As at December 31, 2016, the recoverable value of the Northern Alberta CGU was estimated to be $1.1 billion. Earlier in 2016 and 2015, impairment losses of $380 million and $184 million, respectively, were recorded primarily due to a decline in long-term heavy crude oil prices and a slowing of the development plan. In the fourth quarter of 2016, the Company reversed $400 million of impairment losses, net of the DD&A that would have been recorded had no impairments been recorded. The reversal arose due to the increase in the CGU’s estimated recoverable amount caused by an average reduction in expected future operating costs of five percent and lower future development costs, partially offset by a decline in estimated reserves. The impairment losses and subsequent reversal were recorded as DD&A in the Conventional segment, which has been classified as a discontinued operation (see Note 11). The Northern Alberta CGU included the Pelican Lake and Elk Point producing assets and other emerging assets in the exploration and evaluation stage.

As at December 31, 2016, the recoverable amount of the Suffield CGU PP&E was estimated to be $548 million. Earlier in 2016, an impairment loss of $65 million was recognized due to lower long-term forward natural gas and heavy crude oil prices. In the fourth quarter of 2016, the Company reversed the full amount of the impairment losses, net of the DD&A that would have been recorded had no impairment been recorded ($62 million). The reversal arose due to a decline in expected future royalties increasing the estimated recoverable amount of the CGU. The impairment loss and the subsequent reversal were recorded as DD&A in the Conventional segment,

Cenovus Energy Inc. 28 For the year ended December 31, 2017

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

All amounts in $ millions, unless otherwise indicated

For the year ended December 31, 2017

which has been classified as a discontinued operation (see Note 11). The Suffield CGU included production of natural gas and heavy crude oil in Alberta on the Canadian Forces Base.

There were no goodwill impairments for the twelve months ended December 31, 2016.

Key Assumptions

The fair values for producing properties were calculated based on discounted after-tax cash flows of proved and probable reserves using forward prices and cost estimates, prepared by Cenovus’s IQREs (Level 3). Future cash flows were estimated using a two percent inflation rate and discounted using a rate of 10 percent. Forward prices as at December 31, 2016 used to determine future cash flows from crude oil and natural gas reserves were:

	2017		2018		2019		2020		2021		Average   Annual   Increase   Thereafter
WTI (US$/barrel)		55.00		58.70		62.40		69.00		75.80		2.0	%
WCS (C$/barrel)		53.70		58.20		61.90		66.50		71.00		2.0	%
AECO (C$/Mcf) (1)		3.40		3.15		3.30		3.60		3.90		2.2	%

(1) Assumes gas heating value of one million British Thermal Units per thousand cubic feet.

2015 Upstream Impairments

As at December 31, 2015, the Company determined that the carrying amount of the Northern Alberta CGU exceeded its recoverable amount, resulting in an impairment loss of $184 million. The impairment was recorded as additional DD&A in the Conventional segment, which has been classified as a discontinued operation (see Note 11). Future cash flows for the CGU declined due to lower forward crude oil prices, a decline in reserves estimates and a slowing down of the development plan. This was partially offset by lower future development and operating costs.

The recoverable amount was determined using FVLCOD. The fair value of producing properties was calculated based on discounted after-tax cash flows of proved and probable reserves using forward prices and cost estimates, prepared by Cenovus’s IQREs (Level 3). Future cash flows were estimated using a two percent inflation rate and discounted using a rate of 10 percent. As at December 31, 2015, the recoverable amount of the Northern Alberta CGU was estimated to be approximately $1.5 billion.

There were no goodwill impairments for the twelve months ended December 31, 2015.

B) Asset Impairments and Writedowns

Exploration and Evaluation Assets

For the year ended December 31, 2017, Management wrotedown certain E&E assets, as their carrying values were not considered to be recoverable. As a result, $888 million of previously capitalized costs were recorded as exploration expense. These assets reside primarily in the Borealis CGU within the Oil Sands segment.

Management’s decision was based on a comprehensive review of spending to date, decisions to limit spending on these assets in recent years and the current business plan spending on the assets going forward. At this point, Management is not committing further material funding beyond that required to retain ownership of this significant resource. In addition, regulatory changes to the Oil Sands Royalty application process impact the economic viability of these projects.

In 2016, $2 million of previously capitalized E&E costs were written off and recorded as exploration expense in the Oil Sands segment.

In 2015, $138 million of previously capitalized E&E costs were written off and recorded as exploration expense. This writedown included $67 million and $71 million within the Oil Sands and Conventional segments, respectively.

Property, Plant and Equipment, Net

In 2017, the Company recorded an impairment loss of $21 million related to equipment that was written down to its recoverable amount. The impairment loss relates to the Oil Sands segment.

In 2016, the Company recorded an impairment loss of $20 million primarily related to equipment that was written down to its recoverable amount. This impairment was recorded as additional DD&A in the Conventional segment, which has been classified as a discontinued operation. The Company also recorded an impairment loss of $16 million related to preliminary engineering costs associated with a project that was cancelled and equipment that was written down to its recoverable amount. This impairment loss was recorded as additional DD&A in the Oil Sands segment. Leasehold improvements of $4 million were also written off and recorded as additional DD&A in the Corporate and Eliminations segment.

Cenovus Energy Inc. 29 For the year ended December 31, 2017

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

All amounts in $ millions, unless otherwise indicated

For the year ended December 31, 2017

In 2015, the Company impaired a sulphur recovery facility for $16 million, which was recorded as additional DD&A in the Oil Sands segment. The Company did not have future plans for the assets and did not believe it would recover the carrying amount through a sale.

11. ASSETS HELD FOR SALE AND DISCONTINUED OPERATIONS

In the second quarter of 2017, the Company announced its intention to divest of its Conventional segment which included its heavy oil assets at Pelican Lake, the carbon dioxide enhanced oil recovery project at Weyburn and conventional crude oil, natural gas and NGLs assets in the Suffield and Palliser areas in southern Alberta. The associated assets and liabilities were consequently presented as held for sale and the results of operations reported as a discontinued operation.

A) Results of Discontinued Operations

In 2017, the Company sold the majority of its Conventional segment assets for total gross cash proceeds of $3.2 billion before closing adjustments. Details of the asset sales are as follows.

Pelican Lake

On September 29, 2017, the Company completed the sale of its Pelican Lake heavy oil operations, as well as other miscellaneous assets in northern Alberta, for cash proceeds of $975 million before closing adjustments. A before-tax loss on discontinuance of $623 million was recorded on the sale.

Palliser

On December 7, 2017, Cenovus completed the sale of its Palliser crude oil and natural gas operations in southern Alberta for cash proceeds of $1.3 billion before closing adjustments. A before-tax gain on discontinuance of $1.6 billion was recorded on the sale.

Weyburn

On December 14, 2017, the Company completed the sale of its Weyburn assets in southern Saskatchewan for cash proceeds of $940 million before closing adjustments. A before-tax gain on discontinuance of $276 million was recorded on the sale.

Suffield

On September 25, 2017, Cenovus entered into an agreement to sell its Suffield crude oil and natural gas operations in southern Alberta for cash proceeds of $512 million, before closing adjustments. The sale closed on January 5, 2018. The Company anticipates a before-tax gain of approximately $350 million to be recorded in 2018. The agreement includes a deferred purchase price adjustment (“DPPA”) that could provide Cenovus with purchase price adjustments of up to $36 million if the average crude oil and natural gas prices meet certain thresholds over the next two years.

The DPPA is a two year agreement that commences on close. Under the purchase and sale agreement, Cenovus is entitled to receive cash for each month in which the average daily price of WTI is above US$55 per barrel or the price of Henry Hub natural gas is above US$3.50 per million British thermal units. Monthly cash payments are capped at $375 thousand and $1.125 million for crude oil and natural gas, respectively. The DPPA will be accounted for as a financial option and fair valued at each reporting date. The fair value of the DPPA on the date of close was $7 million.

Cenovus Energy Inc. 30 For the year ended December 31, 2017

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

All amounts in $ millions, unless otherwise indicated

For the year ended December 31, 2017

The following table presents the results of discontinued operations, including asset sales:

For the years ended December 31,	2017		2016			2015
Revenues
Gross Sales		1,309		1,267			1,648
Less: Royalties		174		139			113
		1,135		1,128			1,535
Expenses
Transportation and Blending		167		186			229
Operating		426		444			558
Production and Mineral Taxes		18		12			17
(Gain) Loss on Risk Management		33		(58	)		(209	)
Operating Margin		491		544			940
Depreciation, Depletion and Amortization		192		567			1,121
Exploration Expense		2		-			71
Finance Costs		80		102			101
Earnings (Loss) From Discontinued Operations Before Income Tax		217		(125	)		(353	)
Current Tax Expense (Recovery)		24		86			145
Deferred Tax Expense (Recovery)		33		(125	)		(202	)
After-tax Earnings (Loss) From Discontinued Operations		160		(86	)		(296	)
After-tax Gain (Loss) on Discontinuance (1)		938		-			-
Net Earnings (Loss) From Discontinued Operations		1,098		(86	)		(296	)
(1)   Net of deferred tax expense of $347 million in 2017. B) Cash Flows From Discontinued Operations Cash flows from discontinued operations reported in the Consolidated Statement of Cash Flows are:
For the years ended December 31,	2017		2016			2015
Cash From Operating Activities		448		435			778
Cash From (Used in) Investing Activities		2,993		(168	)		(243	)
Net Cash Flow		3,441		267			535

C) Assets and Liabilities Held for Sale

In the fourth quarter of 2017, the Company announced its intention to market for sale a package of non-core Deep Basin assets in the East Clearwater area and a portion of the West Clearwater assets. The assets have been classified as held for sale and recorded at the lesser of their carrying amount and their fair value less cost to sell. Assets and liabilities held for sale also include the Suffield operations, which were sold on January 5, 2018. No impairments were recorded on the assets held for sale as at December 31, 2017.

	E&E Assets		PP&E		Decommissioning Liabilities
As at December 31, 2017	(Note 17)		(Note 18)		(Note 24)
Conventional		-		568		454
Deep Basin		46		434		149
		46		1,002		603

Cenovus Energy Inc. 31 For the year ended December 31, 2017

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

All amounts in $ millions, unless otherwise indicated

For the year ended December 31, 2017

12. INCOME TAXES

The provision for income taxes is:

For the years ended December 31,	2017			2016			2015
Current Tax
Canada		(217	)		(260	)		441
United States		(38	)		1			(12	)
Current Tax Expense (Recovery)		(255	)		(259	)		429
Deferred Tax Expense (Recovery)		203			(84	)		(453	)
Tax Expense (Recovery) From Continuing Operations		(52	)		(343	)		(24	)

In 2017 and 2016, the Company recorded a current tax recovery due to the carryback of losses for income tax purposes and prior year adjustments. A deferred tax expense was recorded in 2017 due to the revaluation gain of our pre-existing interest in connection with the Acquisition, partially offset by a $275 million recovery from the reduction of the U.S. federal corporate income tax rate from 35 percent to 21 percent reducing the Company’s deferred income tax liability and the impact of E&E asset writedowns.

In 2015, the Company recorded a deferred tax recovery of $415 million arising from an adjustment to the tax basis of the refining assets. The increase in tax basis was a result of the Company’s partner recognizing a taxable gain on its interest in WRB which, due to an election filed with the U.S. tax authorities, was added to the tax basis of WRB’s assets. This was partially offset by an increase in the deferred tax expense as a result of a two percent increase in the Alberta corporate income tax rate.

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

For the years ended December 31,	2017			2016			2015
Earnings (Loss) From Continuing Operations Before Income Tax		2,216			(802	)		890
Canadian Statutory Rate		27.0%			27.0%			26.1%
Expected Income Tax Expense (Recovery) From Continuing Operations		598			(217	)		232
Effect of Taxes Resulting From:
Foreign Tax Rate Differential		(17	)		(46	)		(41	)
Non-Taxable Capital (Gains) Losses		(148	)		(26	)		137
Non-Recognition of Capital (Gains) Losses		(118	)		(26	)		135
Adjustments Arising From Prior Year Tax Filings		(41	)		(46	)		(55	)
(Recognition) of Previously Unrecognized Capital Losses		(68	)		-			(149	)
(Recognition) of U.S. Tax Basis		-			-			(415	)
Change in Statutory Rate		(275	)		-			114
Non-Deductible Expenses		(5	)		5			7
Other		22			13			11
Total Tax Expense (Recovery) From Continuing Operations		(52	)		(343	)		(24	)
Effective Tax Rate		(2.3)%			42.8%			(2.7)%

The analysis of deferred income tax liabilities and deferred income tax assets is as follows:

As at December 31,	2017			2016
Deferred Income Tax Liabilities
Deferred Tax Liabilities to be Settled Within 12 Months		186			6
Deferred Tax Liabilities to be Settled After More Than 12 Months		6,229			3,147
		6,415			3,153
Deferred Income Tax Assets
Deferred Tax Assets to be Recovered Within 12 Months		(374	)		(117	)
Deferred Tax Assets to be Recovered After More Than 12 Months		(428	)		(451	)
		(802	)		(568	)
Net Deferred Income Tax Liability		5,613			2,585

The deferred income tax assets and liabilities to be settled within 12 months represents Management’s estimate of the timing of the reversal of temporary differences and may not correlate to the current income tax expense of the subsequent year.

Cenovus Energy Inc. 32 For the year ended December 31, 2017

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

All amounts in $ millions, unless otherwise indicated

For the year ended December 31, 2017

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	PP&E			Timing of Partnership Items			Risk Management			Other			Total
As at December 31, 2015		3,052			-			82			17			3,151
Charged (Credited) to Earnings		118			-			(76	)		(16	)		26
Charged (Credited) to OCI		(24	)		-			-			-			(24	)
As at December 31, 2016		3,146			-			6			1			3,153
Charged (Credited) to Earnings		625			164			11			1			801
Charged (Credited) to Purchase Price Allocation		2,506			-			-			-			2,506
Charged (Credited) to OCI		(45	)		-			-			-			(45	)
As at December 31, 2017		6,232			164			17			2			6,415
Deferred Income Tax Assets	Unused Tax Losses			Timing of Partnership Items			Risk Management			Other			Total
As at December 31, 2015		(172	)		(36	)		(8	)		(119	)		(335	)
Charged (Credited) to Earnings		(102	)		36			(77	)		(92	)		(235	)
Charged (Credited) to OCI		4			-			-			(2	)		2
As at December 31, 2016		(270	)		-			(85	)		(213	)		(568	)
Charged (Credited) to Earnings		67			-			(198	)		(87	)		(218	)
Charged (Credited) to Share Capital		-			-			-			(28	)		(28	)
Charged (Credited) to OCI		12			-			-			-			12
As at December 31, 2017		(191	)		-			(283	)		(328	)		(802	)
Net Deferred Income Tax Liabilities													Total
Net Deferred Income Tax Liabilities as at December 31, 2015														2,816
Charged (Credited) to Earnings														(209	)
Charged (Credited) to OCI														(22	)
Net Deferred Income Tax Liabilities as at December 31, 2016														2,585
Charged (Credited) to Earnings														583
Charged (Credited) to Purchase Price Allocation														2,506
Charged (Credited) to Share Capital														(28	)
Charged (Credited) to OCI														(33	)
Net Deferred Income Tax Liabilities as at December 31, 2017														5,613

No deferred tax liability has been recognized as at December 31, 2017 on temporary differences associated with investments in subsidiaries and joint arrangements where the Company can control the timing of the reversal of the temporary difference and the reversal is not probable in the foreseeable future. In 2016, the Company had temporary differences of $7,457 million in respect of these investments where, on dissolution or sale, a tax liability might have existed. The Company has 100 percent control of that investment as of May 17, 2017.

The approximate amounts of tax pools available, including tax losses, are:

As at December 31,	2017		2016
Canada		8,317		4,273
United States		1,714		2,036
		10,031		6,309

As at December 31, 2017, the above tax pools included $73 million (2016 – $46 million) of Canadian non-capital losses and $593 million (2016 – $623 million) of U.S. federal net operating losses. These losses expire no earlier than 2025.

Also included in the December 31, 2017 tax pools are Canadian net capital losses totaling $8 million (2016 – $43 million), which are available for carry forward to reduce future capital gains. All of these net capital losses are unrecognized as a deferred income tax asset as at December 31, 2017 (2016 – $40 million). Recognition is dependent on future capital gains. The Company has not recognized $293 million (2016 – $730 million) of net capital losses associated with unrealized foreign exchange losses on its U.S. denominated debt.

Cenovus Energy Inc. 33 For the year ended December 31, 2017

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

All amounts in $ millions, unless otherwise indicated

For the year ended December 31, 2017

13. PER SHARE AMOUNTS

A) Net Earnings (Loss) Per Share — Basic and Diluted

For the years ended December 31,	2017		2016			2015
Earnings (Loss) From:
Continuing Operations		2,268		(459	)		914
Discontinued Operations		1,098		(86	)		(296	)
Net Earnings (Loss)		3,366		(545	)		618
Weighted Average Number of Shares (millions)		1,102.5		833.3			818.7
Basic and Diluted Earnings (Loss) Per Share From: ($)
Continuing Operations		2.06		(0.55	)		1.11
Discontinued Operations		0.99		(0.10	)		(0.36	)
Net Earnings (Loss) Per Share		3.05		(0.65	)		0.75

As at December 31, 2017, 43 million NSRs (2016 – 42 million) and 81 thousand TSARs (2016 – 3 million) were excluded from the diluted weighted average number of shares as their effect would have been anti-dilutive or their exercise prices exceed the market price of Cenovus’s common shares. These instruments could potentially dilute earnings per share in the future. For further information on the Company’s stock-based compensation plans, see Note 29.

B) Dividends Per Share

For the year ended December 31, 2017, the Company paid dividends of $225 million or $0.20 per share, all of which were paid in cash (2016 – $166 million or $0.20 per share, all of which were paid in cash; 2015 – $710 million or $0.8524 per share, including cash dividends of $528 million). The Cenovus Board of Directors declared a first quarter dividend of $0.05 per share, payable on March 29, 2018, to common shareholders of record as of March 15, 2018.

14. CASH AND CASH EQUIVALENTS

As at December 31,	2017		2016
Cash		547		542
Short-Term Investments		63		3,178
		610		3,720

15. ACCOUNTS RECEIVABLE AND ACCRUED REVENUES

As at December 31,	2017		2016
Accruals		1,379		1,606
Prepaids and Deposits		64		127
Partner Advances		94		-
Note Receivable From Partner (1)		-		50
Trade		193		29
Joint Operations Receivables		51		11
Other		49		15
		1,830		1,838

(1) Note receivable from partner was interest bearing at a rate of 1.6783 percent per annum.

Cenovus Energy Inc. 34 For the year ended December 31, 2017

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

All amounts in $ millions, unless otherwise indicated

For the year ended December 31, 2017

16. INVENTORIES

As at December 31,	2017		2016
Product
Refining and Marketing		894		1,006
Oil Sands		414		156
Deep Basin		2		-
Conventional		2		20
Parts and Supplies		77		55
		1,389		1,237

During the year ended December 31, 2017, approximately $12,856 million of produced and purchased inventory was recorded as an expense (2016 – $9,964 million; 2015 – $10,618 million).

17. EXPLORATION AND EVALUATION ASSETS

	Total
As at December 31, 2015		1,575
Additions		67
Transfers to PP&E (Note 18)		(49	)
Exploration Expense (Note 10)		(2	)
Change in Decommissioning Liabilities		(6	)
As at December 31, 2016		1,585
Additions		147
Acquisition (Note 5) (1)		3,608
Transfers to Assets Held for Sale (Note 11)		(316	)
Transfers to PP&E (Note 18)		(6	)
Exploration Expense (Notes 10 and 11)		(890	)
Change in Decommissioning Liabilities		5
Exchange Rate Movements and Other		19
Divestitures (1)		(479	)
As at December 31, 2017		3,673

(1) In connection with the Acquisition, Cenovus was deemed to have disposed of its pre-existing interest in FCCL and re-acquired it at fair value as required by IFRS 3.

Cenovus Energy Inc. 35 For the year ended December 31, 2017

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

All amounts in $ millions, unless otherwise indicated

For the year ended December 31, 2017

18. PROPERTY, PLANT AND EQUIPMENT, NET

	Upstream Assets
	Development & Production			Other         Upstream		Refining     Equipment			Other (1)			Total
COST
As at December 31, 2015		31,481			331		5,206			1,037			38,055
Additions		717			2		213			38			970
Transfers From E&E Assets (Note 17)		49			-		-			-			49
Change in Decommissioning Liabilities		(267	)		-		(8	)		-			(275	)
Exchange Rate Movements and Other		(16	)		-		(152	)		(1	)		(169	)
Divestitures (Note 8)		(23	)		-		-			-			(23	)
As at December 31, 2016		31,941			333		5,259			1,074			38,607
Additions		1,324			-		168			89			1,581
Acquisition (Note 5) (2)		26,317			-		-			-			26,317
Transfers From E&E Assets (Note 17)		6			-		-			-			6
Transfers to Assets Held for Sale (Note 11)		(19,719	)		-		-			-			(19,719	)
Change in Decommissioning Liabilities		(67	)		-		-			3			(64	)
Exchange Rate Movements and Other		(28	)		-		(364	)		1			(391	)
Divestitures (Note 8) (2)		(12,333	)		-		(2	)		-			(12,335	)
As at December 31, 2017		27,441			333		5,061			1,167			34,002
ACCUMULATED DEPRECIATION, DEPLETION AND AMORTIZATION
As at December 31, 2015		18,908			277		896			639			20,720
DD&A		1,173			31		205			66			1,475
Impairment Losses (Note 10)		481			-		-			4			485
Reversal of Impairment Losses (Note 10)		(462	)		-		-			-			(462	)
Exchange Rate Movements and Other		(4	)		-		(25	)		-			(29	)
Divestitures (Note 8)		(8	)		-		-			-			(8	)
As at December 31, 2016		20,088			308		1,076			709			22,181
DD&A		1,653			23		209			68			1,953
Impairment Losses (Note 10)		77			-		-			-			77
Transfers to Assets Held for Sale (Note 11)		(16,120	)		-		-			-			(16,120	)
Exchange Rate Movements and Other		17			-		(91	)		1			(73	)
Divestitures (Note 8) (2)		(3,611	)		-		(1	)		-			(3,612	)
As at December 31, 2017		2,104			331		1,193			778			4,406
CARRYING VALUE
As at December 31, 2015		12,573			54		4,310			398			17,335
As at December 31, 2016		11,853			25		4,183			365			16,426
As at December 31, 2017		25,337			2		3,868			389			29,596

(1) Includes crude-by-rail terminal, office furniture, fixtures, leasehold improvements, information technology and aircraft.

(2) In connection with the Acquisition, Cenovus was deemed to have disposed of its pre-existing interest in FCCL and re-acquired it at fair value as required by IFRS 3. The carrying value of the pre-existing interest in FCCL was $8,602 million.

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

As at December 31,	2017		2016
Development and Production		1,809		537
Refining Equipment		131		206
		1,940		743

Cenovus Energy Inc. 36 For the year ended December 31, 2017

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

All amounts in $ millions, unless otherwise indicated

For the year ended December 31, 2017

19. OTHER ASSETS

As at December 31,	2017		2016
Equity Investments		37		35
Long-Term Receivables		11		15
Prepaids		9		5
Other		14		1
		71		56

20. GOODWILL

As at December 31,	2017		2016
Carrying Value, Beginning of Year		242		242
Goodwill Recognized on Acquisition (Note 5)		2,030		-
Carrying Value, End of Year		2,272		242

The carrying amount of goodwill allocated to the Company’s exploration and production CGUs is:

As at December 31,	2017		2016
Primrose (Foster Creek) (1)		1,171		242
Christina Lake (1)		1,101		-
		2,272		242

(1) Goodwill recognized on the Acquisition reflects measurement period adjustments.

For the purposes of impairment testing, goodwill is allocated to the CGU to which it relates. The assumptions used to test Cenovus’s goodwill for impairment as at December 31, 2017 are consistent to those disclosed in Note 10.

21. ACCOUNTS PAYABLE AND ACCRUED LIABILITIES

As at December 31,	2017		2016
Accruals		2,006		1,927
Trade		337		105
Interest		86		72
Partner Advances		94		-
Note Payable to Partner (1)		-		50
Employee Long-Term Incentives		52		42
Onerous Contract Provisions		8		18
Joint Operations Payables		12		-
Other		40		52
		2,635		2,266

(1) Note payable to partner was interest bearing at a rate of 1.6783 percent per annum.

22. CONTINGENT PAYMENT

As at January 1, 2017	-
Initial Recognition on May 17, 2017 (Note 5)	361
Re-measurement (1)	(138	)
Liabilities Settled or Payable	(17	)
As at December 31, 2017	206
Less: Current Portion	38
Long-Term Portion	168

(1) Contingent payment is carried at fair value. Changes in fair value are recorded in net earnings.

In connection with the Acquisition (see Note 5), Cenovus agreed to make quarterly payments to ConocoPhillips during the five years subsequent to May 17, 2017 for quarters in which the average WCS crude oil price exceeds

Cenovus Energy Inc. 37 For the year ended December 31, 2017

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

All amounts in $ millions, unless otherwise indicated

For the year ended December 31, 2017

$52.00 per barrel during the quarter. The quarterly payment will be $6 million for each dollar that the WCS price exceeds $52.00 per barrel. The calculation includes an adjustment mechanism related to certain significant production outages at Foster Creek and Christina Lake which may reduce the amount of a contingent payment. As at December 31, 2017, $17 million is payable under this agreement.

23. LONG-TERM DEBT

As at December 31,	Notes		US$ Principal Amount		2017			2016
Revolving Term Debt (1)		A		-		-			-
Asset Sale Bridge Credit Facility		B		-		-			-
U.S. Dollar Denominated Unsecured Notes		C		7,650		9,597			6,378
Total Debt Principal						9,597			6,378
Debt Discounts and Transaction Costs						(84	)		(46	)
Long-Term Debt						9,513			6,332

(1) Revolving term debt may include Bankers’ Acceptances, London Interbank Offered Rate based loans, prime rate loans and U.S. base rate loans.

The weighted average interest rate on outstanding debt for the year ended December 31, 2017 was 4.9 percent (2016 – 5.3 percent).

A) Revolving Term Debt

On April 28, 2017, Cenovus amended its existing committed credit facility to increase the capacity of the facility by $0.5 billion to $4.5 billion and to extend the maturity dates. The committed credit facility consists of a $1.2 billion tranche maturing on November 30, 2020 and a $3.3 billion tranche maturing on November 30, 2021. Borrowings are available by way of Bankers’ Acceptances, LIBOR based loans, prime rate loans or U.S. base rate loans. As at December 31, 2017, there were no amounts drawn on Cenovus’s committed credit facility (2016 – $nil).

B) Asset Sale Bridge Credit Facility

In connection with the Acquisition, Cenovus borrowed $3.6 billion under a committed asset sale bridge credit facility. Net proceeds from the sale of the Company’s Conventional segment assets (see Note 11) and cash on hand were used to repay and retire the committed asset bridge credit facility prior to December 31, 2017.

C) Unsecured Notes

Unsecured notes are composed of:

	US$ Principal   Amount
As at December 31,			2017		2016
5.70% due October 15, 2019		1,300		1,631		1,746
3.00% due August 15, 2022		500		627		671
3.80% due September 15, 2023		450		565		604
4.25% due April 15, 2027		1,200		1,505		-
5.25% due June 15, 2037		700		878		-
6.75% due November 15, 2039		1,400		1,756		1,880
4.45% due September 15, 2042		750		941		1,007
5.20% due September 15, 2043		350		439		470
5.40% due June 15, 2047		1,000		1,255		-
		7,650		9,597		6,378

In connection with the Acquisition, the Company completed an offering in the U.S. on April 7, 2017 for US$2.9 billion of senior unsecured notes issued in three tranches, US$1.2 billion 4.25 percent senior unsecured notes due April 2027, US$700 million 5.25 percent senior unsecured notes due June 2037, and US$1.0 billion 5.40 percent senior unsecured notes due June 2047 (collectively, the “2017 Notes”). In the fourth quarter of 2017, the Company completed an exchange offer (“Exchange Offering”) whereby substantially all of the 2017 Notes were exchanged for notes registered under the Securities Act of 1933 with essentially the same terms and provisions as the 2017 Notes. The Exchange Offering has been treated as a modification for accounting purposes and not an extinguishment.

On October 10, 2017, Cenovus filed a base shelf prospectus that allows the Company to offer, from time to time, up to US$7.5 billion, or the equivalent in other currencies, of debt securities, common shares, preferred shares, subscription receipts, warrants, share purchase contracts and units in Canada, the U.S. and elsewhere where permitted by law. The base shelf prospectus is available to ConocoPhillips to offer, should they so choose from time

Cenovus Energy Inc. 38 For the year ended December 31, 2017

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

All amounts in $ millions, unless otherwise indicated

For the year ended December 31, 2017

to time, the common shares they acquired in connection with the Acquisition. The base shelf prospectus will expire in November 2019. Following the completion of the Exchange Offering and as at December 31, 2017, US$4.6 billion was available under the base shelf prospectus. Offerings under the base shelf prospectus are subject to market conditions.

As at December 31, 2017, the Company is in compliance with all of the terms of its debt agreements.

D) Mandatory Debt Payments

	US$ Principal   Amount		Total C$   Equivalent
2018		-		-
2019		1,300		1,631
2020		-		-
2021		-		-
2022		500		627
Thereafter		5,850		7,339
		7,650		9,597

24. DECOMMISSIONING LIABILITIES

The decommissioning provision represents the present value of the expected future costs associated with the retirement of upstream crude oil and natural gas assets, refining facilities and the crude-by-rail terminal. The aggregate carrying amount of the obligation is:

	2017			2016
Decommissioning Liabilities, Beginning of Year		1,847			2,052
Liabilities Incurred		20			11
Liabilities Acquired (Note 5) (1)		944			-
Liabilities Settled		(70	)		(51	)
Liabilities Divested (1)		(139	)		(1	)
Transfers to Liabilities Related to Assets Held for Sale (Note 11)		(1,621	)		-
Change in Estimated Future Cash Flows		(155	)		(423	)
Change in Discount Rate		76			131
Unwinding of Discount on Decommissioning Liabilities		128			130
Foreign Currency Translation		(1	)		(2	)
Decommissioning Liabilities, End of Year		1,029			1,847

(1) In connection with the Acquisition, Cenovus was deemed to have disposed of its pre-existing interest in FCCL and reacquired it at fair value as required by IFRS.

As at December 31, 2017, the undiscounted amount of estimated future cash flows required to settle the obligation is $3,360 million (2016 – $6,270 million), which has been discounted using a credit-adjusted risk-free rate of 5.3 percent (2016 – 5.9 percent). An inflation rate of two percent (2016 – two percent) was used to calculate the decommissioning provision. Most of these obligations are not expected to be paid for several years, or decades, and are expected to be funded from general resources at that time. The Company expects to settle approximately $40 million to $50 million of decommissioning liabilities over the next year. Revisions in estimated future cash flows resulted from lower cost estimates.

Sensitivities

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

	2017						2016
As at December 31,	Credit-Adjusted Risk-Free Rate			Inflation Rate			Credit-Adjusted Risk-Free Rate			Inflation Rate
One Percent Increase		(98	)		197			(248	)		327
One Percent Decrease		192			(103	)		317			(259	)

Cenovus Energy Inc. 39 For the year ended December 31, 2017

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

All amounts in $ millions, unless otherwise indicated

For the year ended December 31, 2017

25. OTHER LIABILITIES

As at December 31,	2017		2016
Employee Long-Term Incentives		43		72
Pension and Other Post-Employment Benefit Plan (Note 26)		62		71
Onerous Contract Provisions		37		35
Other		31		33
		173		211

26. PENSIONS AND OTHER POST-EMPLOYMENT BENEFITS

The Company provides employees with a pension that includes either a defined contribution or defined benefit component and other post-employment benefit plan. Most of the employees participate in the defined contribution pension. Starting in 2012, employees who meet certain criteria may move from the current defined contribution component to a defined benefit component for their future service.

The defined benefit pension provides pension benefits at retirement based on years of service and final average earnings. Future enrollment is limited to eligible employees who meet certain criteria. The Company’s OPEB provides certain retired employees with health care and dental benefits until age 65 and life insurance benefits.

The Company is required to file an actuarial valuation of its registered defined benefit pension with the provincial regulator at least every three years. The most recently filed valuation was dated December 31, 2014 and the next required actuarial valuation will be as at December 31, 2017.

A) Defined Benefit and OPEB Plan Obligation and Funded Status

Information related to defined benefit pension and OPEB plans, based on actuarial estimations, is:

	Pension Benefits						OPEB
As at December 31,	2017			2016			2017			2016
Defined Benefit Obligation
Defined Benefit Obligation, Beginning of Year		173			168			23			26
Current Service Costs		14			14			2			(3	)
Interest Costs (1)		7			7			1			1
Benefits Paid		(8	)		(25	)		(1	)		(1	)
Plan Participant Contributions		2			2			-			-
Past Service Costs – Curtailments		(6	)		-			(1	)		-
Remeasurements:
(Gains) Losses from Experience Adjustments		1			-			-			-
(Gains) Losses from Changes in Demographic Assumptions		-			-			(1	)		-
(Gains) Losses from Changes in Financial Assumptions		(2	)		7			(1	)		-
Defined Benefit Obligation, End of Year		181			173			22			23
Plan Assets
Fair Value of Plan Assets, Beginning of Year		125			128			-			-
Employer Contributions		9			14			-			-
Plan Participant Contributions		2			2			-			-
Benefits Paid		(8	)		(25	)		-			-
Interest Income (1)		4			3			-			-
Remeasurements:
Return on Plan Assets (Excluding Interest Income)		9			3			-			-
Fair Value of Plan Assets, End of Year		141			125			-			-
Pension and OPEB (Liability) (2)		(40	)		(48	)		(22	)		(23	)

(1) Based on the discount rate of the defined benefit obligation at the beginning of the year.

(2) Pension and OPEB liabilities are included in other liabilities on the Consolidated Balance Sheets.

In connection with the divestitures of the Company’s legacy Conventional assets, affected employees left the plans resulting in a curtailment gain.

Cenovus Energy Inc. 40 For the year ended December 31, 2017

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

All amounts in $ millions, unless otherwise indicated

For the year ended December 31, 2017

The weighted average duration of the defined benefit pension and OPEB obligations are 16 years and 10 years, respectively.

B) Pension and OPEB Costs

	Pension Benefits									OPEB
For the years ended December 31,	2017			2016			2015			2017			2016			2015
Defined Benefit Plan Cost
Current Service Costs		14			14			19			2			(3	)		3
Past Service Costs – Curtailments		(6	)		-			(5	)		(1	)		-			-
Net Settlement Costs		-			-			3			-			-			-
Net Interest Costs		3			4			6			1			1			1
Remeasurements:
Return on Plan Assets (Excluding Interest Income)		(9	)		(3	)		3			-			-			-
(Gains) Losses from Experience Adjustments		1			-			(3	)		-			-			-
(Gains) Losses from Changes in Demographic Assumptions		-			-			-			(1	)		-			-
(Gains) Losses from Changes in Financial Assumptions		(2	)		7			(28	)		(1	)		-			-
Defined Benefit Plan Cost (Recovery)		1			22			(5	)		-			(2	)		4
Defined Contribution Plan Cost		27			25			29			-			-			-
Total Plan Cost		28			47			24			-			(2	)		4

C) Investment Objectives and Fair Value of Plan Assets

The objective of the asset allocation is to manage the funded status of the plan at an appropriate level of risk, giving consideration to the security of the assets and the potential volatility of market returns and the resulting effect on both contribution requirements and pension expense. The long-term return is expected to achieve or exceed the return from a composite benchmark comprised of passive investments in appropriate market indices. The asset allocation structure is subject to diversification requirements and constraints which reduce risk by limiting exposure to individual equity investment and credit rating categories.

The allocation of assets between the various types of investment funds is monitored quarterly and is re-balanced as necessary. The asset allocation structure targets an investment of 50 to 75 percent in equity securities, 25 to 35 percent in fixed income assets, zero to 15 percent in real estate assets and zero to 10 percent in cash and cash equivalents.

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,	2017		2016
Equity Funds		89		73
Bond Funds		29		25
Non-Invested Assets		11		13
Real Estate Funds		9		9
Cash and Cash Equivalents		3		5
		141		125

Fair value of equities and bonds are based on the trading price of the underlying funds. The fair value of the non-invested assets is the discounted value of the expected future payments. The fair value of the real estate funds reflects the market value and the fund manager’s appraisal value of the assets.

Equity funds do not include any direct investments in Cenovus shares.

D) Funding

The defined benefit pension is funded in accordance with federal and provincial government pension legislation, where applicable. Contributions are made to trust funds administered by an independent trustee. The Company’s contributions to the defined benefit pension plan are based on the most recent actuarial valuation as at December 31, 2014, and direction of the Management Pension Committee and Human Resources and Compensation Committee of the Board of Directors.

Cenovus Energy Inc. 41 For the year ended December 31, 2017

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

All amounts in $ millions, unless otherwise indicated

For the year ended December 31, 2017

Employees participating in the defined benefit pension are required to contribute four percent of their pensionable earnings, up to an annual maximum, and the Company provides the balance of the funding necessary to ensure benefits will be fully provided for at retirement. The expected employer contributions for the year ended December 31, 2018 are $9 million for the defined benefit pension plan and $nil for the OPEB. The OPEB is funded on an as required basis.

E) Actuarial Assumptions and Sensitivities

Actuarial Assumptions

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

	Pension Benefits						OPEB
For the years ended December 31,	2017		2016		2015		2017		2016		2015
Discount Rate		3.50%		3.75%		4.00%		3.25%		3.75%		3.75%
Future Salary Growth Rate		3.81%		3.80%		3.80%		5.08%		5.15%		5.15%
Average Longevity (years)		88.0		87.9		88.3		88.0		87.9		88.3
Health Care Cost Trend Rate		N/A		N/A		N/A		6.00%		7.00%		7.00%

The discount rates are determined with reference to market yields on high quality corporate debt instruments of similar duration to the benefit obligations at the end of the reporting period.

Sensitivities

The sensitivity of the defined benefit and OPEB obligation to changes in relevant actuarial assumptions is:

	2017						2016
As at December 31,	Increase			Decrease			Increase			Decrease
One Percent Change:
Discount Rate		(28	)		36			(25	)		32
Future Salary Growth Rate		3			(3	)		3			(3	)
Health Care Cost Trend Rate		1			(1	)		2			(1	)
One Year Change in Assumed Life Expectancy		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.

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.

Cenovus Energy Inc. 42 For the year ended December 31, 2017

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

All amounts in $ millions, unless otherwise indicated

For the year ended December 31, 2017

27. SHARE CAPITAL

A) Authorized

Cenovus is authorized to issue an unlimited number of common shares and first and second preferred shares not exceeding, in aggregate, 20 percent of the number of issued and outstanding common shares. The first and second preferred shares may be issued in one or more series with rights and conditions to be determined by the Company’s Board of Directors prior to issuance and subject to the Company’s articles.

B) Issued and Outstanding

	2017				2016
As at December 31,	Number of   Common     Shares       (thousands)		Amount		Number of   Common   Shares       (thousands)		Amount
Outstanding, Beginning of Year		833,290		5,534		833,290		5,534
Common Shares Issued, Net of Issuance Costs and Tax		187,500		2,927		-		-
Common Shares Issued to ConocoPhillips (Note 5)		208,000		2,579		-		-
Outstanding, End of Year		1,228,790		11,040		833,290		5,534

In connection with the Acquisition (see Note 5), Cenovus closed a bought-deal common share financing on April 6, 2017 for 187.5 million common shares, raising gross proceeds of $3.0 billion ($2.9 billion net of $101 million of share issuance costs).

In addition, the Company issued 208 million common shares to ConocoPhillips on May 17, 2017 as partial consideration for the Acquisition. In relation to the share consideration, Cenovus and ConocoPhillips entered into an investor agreement, and a registration rights agreement which, among other things, restricted ConocoPhillips from selling or hedging its Cenovus common shares until after November 17, 2017. ConocoPhillips is also restricted from nominating new members to Cenovus’s Board of Directors and must vote its Cenovus common shares in accordance with Management’s recommendations or abstain from voting until such time ConocoPhillips owns 3.5 percent or less of the then outstanding common shares of Cenovus. As at December 31, 2017, ConocoPhillips continued to hold these common shares.

There were no preferred shares outstanding as at December 31, 2017 (2016 – nil).

As at December 31, 2017, there were 15 million (2016 – 12 million) common shares available for future issuance under the stock option plan.

C) Paid in Surplus

Cenovus’s paid in surplus reflects the Company’s retained earnings prior to the split of Encana Corporation (“Encana”) under the plan of arrangement into two independent energy companies, Encana and Cenovus (pre-arrangement earnings). In addition, paid in surplus includes stock-based compensation expense related to the Company’s NSRs discussed in Note 29A.

	Pre-Arrangement   Earnings		Stock-Based       Compensation		Total
As at December 31, 2015		4,086		244		4,330
Stock-Based Compensation Expense		-		20		20
As at December 31, 2016		4,086		264		4,350
Stock-Based Compensation Expense		-		11		11
As at December 31, 2017		4,086		275		4,361

Cenovus Energy Inc. 43 For the year ended December 31, 2017

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

All amounts in $ millions, unless otherwise indicated

For the year ended December 31, 2017

28. ACCUMULATED OTHER COMPREHENSIVE INCOME (LOSS)

	Defined Benefit Pension Plan			Foreign Currency Translation Adjustment			Available for Sale Financial Assets			Total
As at December 31, 2015		(10	)		1,014			16			1,020
Other Comprehensive Income (Loss), Before Tax		(4	)		(106	)		(4	)		(114	)
Income Tax		1			-			3			4
As at December 31, 2016		(13	)		908			15			910
Other Comprehensive Income (Loss), Before Tax		12			(275	)		(1	)		(264	)
Income Tax		(3	)		-			-			(3	)
As at December 31, 2017		(4	)		633			14			643

29. STOCK-BASED COMPENSATION PLANS

A) Employee Stock Option Plan

Cenovus has an Employee Stock Option Plan that provides employees with the opportunity to exercise an option to purchase a common share of the Company. Option exercise prices approximate the market price for the common shares on the date the options were issued. Options granted are exercisable at 30 percent of the number granted after one year, an additional 30 percent of the number granted after two years and are fully exercisable after three years. Options expire after seven years.

Options issued by the Company on or after February 24, 2011 have associated NSRs. The NSRs, in lieu of exercising the option, give the option holder the right to receive the number of common shares that could be acquired with the excess value of the market price of Cenovus’s common shares at the time of exercise over the exercise price of the option.

Options issued by the Company under the Employee Stock Option Plan prior to February 24, 2011 have associated TSARs. In lieu of exercising the options, the TSARs give the option holder the right to receive a cash payment equal to the excess of the market price of Cenovus’s common shares at the time of exercise over the exercise price of the option.

The TSARs and NSRs vest and expire under the same terms and conditions as the underlying options.

NSRs

The weighted average unit fair value of NSRs granted during the year ended December 31, 2017 was $3.10 before considering forfeitures, which are considered in determining total cost for the period. The fair value of each NSR was estimated on its grant date using the Black-Scholes-Merton valuation model with weighted average assumptions as follows:

Risk-Free Interest Rate	1.00%
Expected Dividend Yield	1.13%
Expected Volatility (1)	29.14%
Expected Life (years)	3.70

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

Cenovus Energy Inc. 44 For the year ended December 31, 2017

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

All amounts in $ millions, unless otherwise indicated

For the year ended December 31, 2017

The following tables summarize information related to the NSRs:

As at December 31, 2017							Number of   NSRs   (thousands)			Weighted   Average     Exercise   Price ($)
Outstanding, Beginning of Year								41,644			30.57
Granted								3,537			14.81
Exercised								-			-
Forfeited								(2,454	)		28.27
Outstanding, End of Year								42,727			29.40
	Outstanding NSRs						Exercisable NSRs
As at December 31, 2017 Range of Exercise Price ($)	Number of   NSRs       (thousands)		Weighted       Average     Remaining     Contractual   Life (years)		Weighted   Average   Exercise   Price ($)		Number of   NSRs   (thousands)			Weighted   Average   Exercise   Price($)
10.00 to 14.99		3,319		5.4		14.80		-			-
15.00 to 19.99		3,313		5.2		19.51		995			19.51
20.00 to 24.99		3,723		4.1		22.25		2,254			22.26
25.00 to 29.99		12,115		3.1		28.38		12,106			28.39
30.00 to 34.99		10,419		2.2		32.64		10,419			32.64
35.00 to 39.99		9,838		0.8		38.19		9,838			38.19
		42,727		2.8		29.40		35,612			31.70

TSARs

The Company had a liability of $nil as at December 31, 2017 (2016 – $nil) in the Consolidated Balance Sheets based on the fair value of each TSAR held by Cenovus employees. Fair value was estimated at the period-end date using the Black-Scholes-Merton valuation model with weighted average assumptions as follows:

Risk-Free Interest Rate	1.85%
Expected Dividend Yield	1.51%
Expected Volatility (1)	28.89%
Cenovus’s Common Share Price ($)	11.48

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

The intrinsic value of vested TSARs held by Cenovus employees as at December 31, 2017 was $nil (2016 – $nil).

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

As at December 31, 2017	Number of    TSARs         (thousands)		Weighted   Average   Exercise   Price ($)
Outstanding, Beginning of Year		3,373		26.66
Exercised for Cash Payment		-		-
Exercised as Options for Common Shares		-		-
Forfeited		(16)		29.19
Expired		(3,276)		26.48
Outstanding, End of Year		81		33.52

The market price of Cenovus’s common shares on the TSX as at December 31, 2017 was $11.48.

B) Performance Share Units

Cenovus has granted PSUs to certain employees under its Performance Share Unit Plan for Employees. PSUs are whole share units and entitle employees to receive, upon vesting, either a common share of Cenovus or a cash payment equal to the value of a Cenovus common share. For a portion of PSUs, the number of PSUs eligible for payment is determined over three years based on the units granted multiplied by 30 percent after year one, 30 percent after year two and 40 percent after year three. All PSUs are eligible to vest based on the Company achieving key pre-determined performance measures. PSUs vest after three years.

Cenovus Energy Inc. 45 For the year ended December 31, 2017

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

All amounts in $ millions, unless otherwise indicated

For the year ended December 31, 2017

The Company has recorded a liability of $37 million as at December 31, 2017 (2016 – $51 million) in the Consolidated Balance Sheets for PSUs based on the market value of Cenovus’s common shares at the end of the year. As PSUs are paid out upon vesting, the intrinsic value of vested PSUs was $nil as at December 31, 2017 and 2016.

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

As at December 31, 2017	Number    of PSUs    (thousands)
Outstanding, Beginning of Year		6,157
Granted		2,392
Vested and Paid Out		(451	)
Cancelled		(1,192	)
Units in Lieu of Dividends		112
Outstanding, End of Year		7,018

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 $41 million as at December 31, 2017 (2016 – $30 million) in the Consolidated Balance Sheets for RSUs based on the market value of Cenovus’s common shares at the end of the year. As RSUs are paid out upon vesting, the intrinsic value of vested RSUs was $nil as at December 31, 2017 and 2016.

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

As at December 31, 2017	Number    of RSUs    (thousands)
Outstanding, Beginning of Year		3,790
Granted		3,278
Vested and Paid Out		(101	)
Cancelled		(282	)
Units in Lieu of Dividends		100
Outstanding, End of Year		6,785

D) Deferred Share Units

Under two Deferred Share Unit Plans, Cenovus directors, officers and certain employees may receive DSUs, which are equivalent in value to a common share of the Company. Eligible employees have the option to convert either zero, 25 or 50 percent of their annual bonus award into DSUs. DSUs vest immediately, are redeemed in accordance with the terms of the agreement and expire on December 15 of the calendar year following the year of cessation of directorship or employment.

The Company has recorded a liability of $17 million as at December 31, 2017 (2016 – $32 million) in the Consolidated Balance Sheets for DSUs based on the market value of Cenovus’s common shares at the end of the year. The intrinsic value of vested DSUs equals the carrying value as DSUs vest at the time of grant.

The following table summarizes the information related to the DSUs held by Cenovus directors, officers and employees:

As at December 31, 2017	Number    of DSUs    (thousands)
Outstanding, Beginning of Year		1,598
Granted to Directors		136
Granted		93
Units in Lieu of Dividends		27
Redeemed		(414	)
Outstanding, End of Year		1,440

Cenovus Energy Inc. 46 For the year ended December 31, 2017

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

All amounts in $ millions, unless otherwise indicated

For the year ended December 31, 2017

E) Total Stock-Based Compensation

For the years ended December 31,	2017			2016			2015
NSRs		9			15			27
TSARs		-			(1	)		(5	)
PSUs		(7	)		13			(13	)
RSUs		3			13			6
DSUs		(11	)		7			(5	)
Stock-Based Compensation Expense (Recovery)		(6	)		47			10
Stock-Based Compensation Costs Capitalized		3			12			6
Total Stock-Based Compensation		(3	)		59			16
30. EMPLOYEE SALARIES AND BENEFIT EXPENSES
For the years ended December 31,	2017			2016			2015
Salaries, Bonuses and Other Short-Term Employee Benefits		606			500			534
Defined Contribution Pension Plan		19			16			19
Defined Benefit Pension Plan and OPEB		8			11			17
Stock-Based Compensation Expense (Note 29)		(6	)		47			10
Termination Benefits		19			19			43
		646			593			623
31. 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,	2017			2016			2015
Salaries, Director Fees and Short-Term Benefits		26			27			30
Post-Employment Benefits		4			4			5
Stock-Based Compensation		6			4			5
		36			35			40

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

32. CAPITAL STRUCTURE

Cenovus’s capital structure objectives remain unchanged from previous periods. Cenovus’s capital structure consists of shareholders’ equity plus Net Debt. Net Debt includes the Company’s short-term borrowings, and the current and long-term portions of long-term debt, net of cash and cash equivalents. Cenovus conducts its business and makes decisions consistent with that of an investment grade company. The Company’s objectives when managing its capital structure are to maintain financial flexibility, preserve access to capital markets, ensure its ability to finance internally generated growth and to fund potential acquisitions while maintaining the ability to meet the Company’s financial obligations as they come due.

Cenovus monitors its capital structure and financing requirements using, among other things, non-GAAP financial metrics consisting of Net Debt to Adjusted Earnings Before Interest, Taxes and DD&A (“Adjusted EBITDA”) and Net Debt to Capitalization. These metrics are used to steward Cenovus’s overall debt position as measures of Cenovus’s overall financial strength.

Over the long term, Cenovus targets a Net Debt to Adjusted EBITDA ratio of less than 2.0 times. At different points within the economic cycle, Cenovus expects this ratio may periodically be above the target. Cenovus also manages its Net Debt to Capitalization ratio to ensure compliance with the associated covenant as defined in its committed credit facility agreement.

Cenovus Energy Inc. 47 For the year ended December 31, 2017

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

All amounts in $ millions, unless otherwise indicated

For the year ended December 31, 2017

A) Net Debt to Adjusted EBITDA

As at December 31,	2017			2016			2015
Long-Term Debt		9,513			6,332			6,525
Less: Cash and Cash Equivalents		(610	)		(3,720	)		(4,105	)
Net Debt		8,903			2,612			2,420
Net Earnings (Loss)		3,366			(545	)		618
Add (Deduct):
Finance Costs		725			492			482
Interest Income		(62	)		(52	)		(28	)
Income Tax Expense (Recovery)		352			(382	)		(81	)
DD&A		2,030			1,498			2,114
E&E Impairment		890			2			138
Unrealized (Gain) Loss on Risk Management		729			554			195
Foreign Exchange (Gain) Loss, Net		(812	)		(198	)		1,036
Revaluation (Gain)		(2,555	)		-			-
Re-measurement of Contingent Payment		(138	)		-			-
(Gain) Loss on Discontinuance		(1,285	)		-			-
(Gain) Loss on Divestitures of Assets		1			6			(2,392	)
Other (Income) Loss, Net		(5	)		34			2
Adjusted EBITDA (1)		3,236			1,409			2,084
Net Debt to Adjusted EBITDA		2.8x			1.9x			1.2x
(1)   Calculated on a trailing twelve-month basis. Includes discontinued operations. B) Net Debt to Capitalization
As at December 31,	2017			2016			2015
Net Debt		8,903			2,612			2,420
Shareholders’ Equity		19,981			11,590			12,391
		28,884			14,202			14,811
Net Debt to Capitalization		31%			18%			16%

As at December 31, 2017, Cenovus’s Net Debt to Adjusted EBITDA is 2.8 times, which is above the Company’s target. However, it is important to note that Adjusted EBITDA is calculated on a rolling twelve month basis and as such, only includes the financial results from the Deep Basin Assets and the additional 50 percent of FCCL for the period May 17, 2017 to December 31, 2017. Net Debt is presented as at December 31, 2017; therefore, the ratio is burdened by the debt issued to finance the Acquisition. If Adjusted EBITDA reflected a full twelve months of earnings from the acquired assets, Cenovus’s Net Debt to Adjusted EBITDA ratio would be lower.

Cenovus’s objective is to maintain a high level of capital discipline and manage its capital structure to help ensure sufficient liquidity through all stages of the economic cycle. To ensure financial resilience, Cenovus may, among other actions, adjust capital and operating spending, draw down on its credit facility or repay existing debt, adjust dividends paid to shareholders, purchase shares for cancellation pursuant to normal course issuer bids, issue new debt, or issue new shares.

Cenovus has in place a committed credit facility that consists of a $1.2 billion tranche maturing on November 30, 2020 and a $3.3 billion tranche maturing on November 30, 2021. As at December 31, 2017, no amounts were drawn on its committed credit facility. Under the committed credit facility, the Company is required to maintain a debt to capitalization ratio, as defined in the agreement, not to exceed 65 percent. The Company is well below this limit.

In addition, the Company has in place a base shelf prospectus which expires in November 2019. As at December 31, 2017, US$4.6 billion remains available under the base shelf prospectus. Offerings under the base shelf prospectus are subject to market conditions.

As at December 31, 2017, Cenovus is in compliance with all of the terms of its debt agreements.

Cenovus Energy Inc. 48 For the year ended December 31, 2017

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

All amounts in $ millions, unless otherwise indicated

For the year ended December 31, 2017

33. FINANCIAL INSTRUMENTS

Cenovus’s financial assets and financial liabilities consist of cash and cash equivalents, accounts receivable and accrued revenues, accounts payable and accrued liabilities, risk management assets and liabilities, available for sale financial assets, long-term receivables, contingent payment, short-term borrowings and long-term debt. Risk management assets and liabilities arise from the use of derivative financial instruments.

A) Fair Value of Non-Derivative Financial Instruments

The fair values of cash and cash equivalents, accounts receivable and accrued revenues, accounts payable and accrued liabilities, and short-term borrowings approximate their carrying amount due to the short-term maturity of these instruments.

The fair values of long-term receivables approximate their carrying amount due to the specific non-tradeable nature of these instruments.

Long-term debt is carried at amortized cost. The estimated fair values of long-term borrowings have been determined based on period-end trading prices of long-term borrowings on the secondary market (Level 2). As at December 31, 2017, the carrying value of Cenovus’s debt was $9,513 million and the fair value was $10,061 million (2016 carrying value – $6,332 million; fair value – $6,539 million).

Available for sale financial assets comprise private equity investments. These assets are carried at fair value on the Consolidated Balance Sheets in other assets. Fair value is determined based on recent private placement transactions (Level 3) when available. The following table provides a reconciliation of changes in the fair value of available for sale financial assets:

As at December 31,	2017			2016
Fair Value, Beginning of Year		35			42
Net Acquisition of Investments		3			-
Change in Fair Value (1)		(1	)		(4	)
Impairment Losses (2)		-			(3	)
Fair Value, End of Year		37			35

(1) Changes in fair value on available for sale financial assets are recorded in OCI.

(2) Impairment losses on available for sale financial assets are reclassified from OCI to profit or loss.

B) Fair Value of Risk Management Assets and Liabilities

The Company’s risk management assets and liabilities consist of crude oil swaps and options, as well as condensate and interest rate swaps. Crude oil, condensate and, if entered, natural gas contracts are recorded at their estimated fair value based on the difference between the contracted price and the period-end forward price for the same commodity, using quoted market prices or the period-end forward price for the same commodity extrapolated to the end of the term of the contract (Level 2). The fair value of interest rate swaps are calculated using external valuation models which incorporate observable market data, including interest rate yield curves (Level 2).

Summary of Unrealized Risk Management Positions

	2017							2016
	Risk Management							Risk Management
As at December 31,	Asset		Liability		Net			Asset		Liability		Net
Crude Oil		63		1,031		(968	)		21		307		(286	)
Interest Rate		2		20		(18	)		3		8		(5	)
Total Fair Value		65		1,051		(986	)		24		315		(291	)

The following table presents the Company’s fair value hierarchy for risk management assets and liabilities carried at fair value:

As at December 31,	2017			2016
Level 2 – Prices Sourced From Observable Data or Market Corroboration		(986	)		(291)

Prices sourced from observable data or market corroboration refers to the fair value of contracts valued in part using active quotes and in part using observable, market-corroborated data.

Cenovus Energy Inc. 49 For the year ended December 31, 2017

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

All amounts in $ millions, unless otherwise indicated

For the year ended December 31, 2017

The following table provides a reconciliation of changes in the fair value of Cenovus’s risk management assets and liabilities:

As at December 31,	2017			2016
Fair Value of Contracts, Beginning of Year		(291	)		271
Fair Value of Contracts Realized During the Year (1)		200			(211	)
Change in Fair Value of Contracts in Place at Beginning of Year and Contracts Entered Into During the Year		(929	)		(343	)
Unamortized Premium on Put Options		16			-
Unrealized Foreign Exchange Gain (Loss) on U.S. Dollar Contracts		18			(8	)
Fair Value of Contracts, End of Year		(986	)		(291	)

(1) Includes a realized loss of $33 million (2016 – $58 million gain) related to the Conventional segment which is included in discontinued operations.

Financial assets and liabilities are offset only if Cenovus has the current legal right to offset and intends to settle on a net basis or settle the asset and liability simultaneously. Cenovus offsets risk management assets and liabilities when the counterparty, commodity, currency and timing of settlement are the same. No additional unrealized risk management positions are subject to an enforceable master netting arrangement or similar agreement that are not otherwise offset.

The following table provides a summary of the Company’s offsetting risk management positions:

	2017			2016
		Risk Management			Risk Management
As at December 31,	Asset	Liability	Net	Asset	Liability	Net
Recognized Risk Management Positions
Gross Amount	135	1,121	(986)	75	366	(291)
Amount Offset	(70)	(70)	-	(51)	(51)	-
Net Amount per Consolidated Financial Statements	65	1,051	(986)	24	315	(291)

The derivative liabilities do not have credit risk-related contingent features. Due to credit practices that limit transactions according to counterparties’ credit quality, the change in fair value through profit or loss attributable to changes in the credit risk of financial liabilities is immaterial.

Cenovus pledges cash collateral with respect to certain of these risk management contracts, which is not offset against the related financial liability. The amount of cash collateral required will vary daily over the life of these risk management contracts as commodity prices change. Additional cash collateral is required if, on a net basis, risk management payables exceed risk management receivables on a particular day. As at December 31, 2017, $26 million (2016 – $84 million) was pledged as collateral, of which $nil (2016 – $18 million) could have been withdrawn.

C) Fair Value of Contingent Payment

The contingent payment is carried at fair value on the Consolidated Balance Sheets. Fair value is estimated by calculating the present value of the future expected cash flows using an option pricing model (Level 3), which assumes the probability distribution for WCS is based on the volatility of WTI options, volatility of Canadian-U.S. foreign exchange rate options and WCS futures pricing, and discounted at a credit-adjusted risk-free rate of 3.3 percent. Fair value of the contingent payment has been calculated by Cenovus’s internal valuation team which consists of individuals who are knowledgeable and have experience in fair value techniques. As at December 31, 2017, the fair value of the contingent payment was estimated to be $206 million.

As at December 31, 2017, average WCS forward pricing for the remaining term of the contingent payment is US$35.51 per barrel or C$44.55 per barrel. The average volatility of WTI options and the Canadian-U.S. foreign exchange rates used to value the contingent payment was 20 percent and seven percent, respectively. Changes in the following inputs to the option pricing model, with fluctuations in all other variables held constant, could have resulted in unrealized gains (losses) impacting earnings before income tax as follows:

	Sensitivity Range	Increase			Decrease
WCS Forward Prices	± $5.00 per bbl		(167	)		111
WTI Option Volatility	± five percent		(95	)		85
U.S. to Canadian Dollar Foreign Exchange Rate Volatility	± five percent		2			(27	)

Cenovus Energy Inc. 50 For the year ended December 31, 2017

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

All amounts in $ millions, unless otherwise indicated

For the year ended December 31, 2017

D) Earnings Impact of (Gains) Losses From Risk Management Positions

For the years ended December 31,	2017		2016		2015
Realized (Gain) Loss (1)		167		(153)		(447)
Unrealized (Gain) Loss (2)		729		554		195
(Gain) Loss on Risk Management From Continuing Operations		896		401		(252)

(1) Realized gains and losses on risk management are recorded in the reportable segment to which the derivative instrument relates. Excludes realized risk management losses of $33 million in 2017 (2016 – $58 million gain; 2015 – $209 million gain) that were classified as discontinued operations.

(2) Unrealized gains and losses on risk management are recorded in the Corporate and Eliminations segment.

34. RISK MANAGEMENT

Cenovus is exposed to financial risks, including market risk related to commodity prices, foreign exchange rates, interest rates as well as credit risk and liquidity risk. To manage exposure to interest rate volatility, the Company entered into interest rate swap contracts related to expected future debt issuances. As at December 31, 2017, Cenovus had a notional amount of US$400 million in interest rate swaps. To mitigate the Company’s exposure to foreign exchange rate fluctuations, the Company periodically enters into foreign exchange contracts. No foreign exchange contracts were outstanding at December 31, 2017.

Net Fair Value of Risk Management Positions

As at December 31, 2017	Notional Volumes	Terms	Average Price	Fair Value Asset (Liability)
Crude Oil Contracts
Fixed Price Contracts
Brent Fixed Price	60,000 bbls/d	January – June 2018	US$53.34/bbl		(172	)
WTI Fixed Price	150,000 bbls/d	January – June 2018	US$48.91/bbl		(384	)
WTI Fixed Price	75,000 bbls/d	July – December 2018	US$49.32/bbl		(158	)
Brent Put Options	25,000 bbls/d	January – June 2018	US$53.00/bbl		1
Brent Collars	80,000 bbls/d	January – June 2018	US$49.54 –   US$59.86/bbl		(124	)
Brent Collars	75,000 bbls/d	July – December 2018	US$49.00 –   US$59.69/bbl		(110	)
WTI Collars	10,000 bbls/d	January – June 2018	US$45.30 –   US$62.77/bbl		(2	)
WCS Differential	16,300 bbls/d	January – March 2018	US$(13.11)/bbl		14
WCS Differential	14,800 bbls/d	April – June 2018	US$(14.05)/bbl		7
WCS Differential	10,500 bbls/d	January – December 2018	US$(14.52)/bbl		25
Other Financial Positions (1)					(65	)
Crude Oil Fair Value Position					(968	)
Interest Rate Swaps					(18	)
Total Fair Value					(986	)

(1) Other financial positions are part of ongoing operations to market the Company’s production.

A) Commodity Price Risk

Commodity price risk arises from the effect that fluctuations of forward commodity prices may have on the fair value or future cash flows of financial assets and liabilities. To partially mitigate exposure to commodity price risk, the Company has entered into various financial derivative instruments.

The use of these derivative instruments is governed under formal policies and is subject to limits established by the Board of Directors. The Company’s policy does not allow the use of derivative instruments for speculative purposes.

Crude Oil – The Company has used fixed price swaps, put options and costless collars to partially mitigate its exposure to the commodity price risk on its crude oil sales. In addition, Cenovus has entered into a number of transactions to help protect against widening light/heavy crude oil price differentials.

Condensate – The Company has used fixed price swaps to partially mitigate its exposure to the commodity price risk on its condensate purchases.

Cenovus Energy Inc. 51 For the year ended December 31, 2017

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

All amounts in $ millions, unless otherwise indicated

For the year ended December 31, 2017

Natural Gas – The Company may enter into transactions to partially mitigate its natural gas commodity price risk. To help protect against widening natural gas price differentials in various production areas, Cenovus may also enter into transactions to manage the price differentials between production areas and various sales points.

Sensitivities

The following table summarizes the sensitivity of the fair value of Cenovus’s risk management positions to fluctuations in commodity prices, with all other variables held constant. Management believes the fluctuations identified in the table below are a reasonable measure of volatility. The impact of fluctuating commodity prices and interest rates on the Company’s open risk management positions could have resulted in unrealized gains (losses) impacting earnings before income tax as follows:

As at December 31, 2017	Sensitivity Range	Increase			Decrease
Crude Oil Commodity Price	± US$5.00 per bbl Applied to Brent, WTI and Condensate Hedges		(529	)		507
Crude Oil Differential Price	± US$2.50 per bbl Applied to Differential Hedges Tied to Production		11			(11	)
As at December 31, 2016	Sensitivity Range	Increase			Decrease
Crude Oil Commodity Price	± US$5.00 per bbl Applied to Brent, WTI and Condensate Hedges		(198	)		193
Crude Oil Differential Price	± US$2.50 per bbl Applied to Differential Hedges Tied to Production		1			(1	)

B) Foreign Exchange Risk

Foreign exchange risk arises from changes in foreign exchange rates that may affect the fair value or future cash flows of Cenovus’s financial assets or liabilities. As Cenovus operates in North America, fluctuations in the exchange rate between the U.S./Canadian dollar can have a significant effect on reported results.

As disclosed in Note 7, Cenovus’s foreign exchange (gain) loss primarily includes unrealized foreign exchange gains and losses on the translation of the U.S. dollar debt issued from Canada. As at December 31, 2017, Cenovus had US$7,650 million in U.S. dollar debt issued from Canada (2016 – US$4,750 million). In respect of these financial instruments, the impact of changes in the U.S. to Canadian dollar exchange rate would have resulted in a change to the foreign exchange (gain) loss as follows:

For the years ended December 31,	2017			2016
$0.01 Increase in the U.S. to Canadian Dollar Foreign Exchange Rate		77			48
$0.01 Decrease in the U.S. to Canadian Dollar Foreign Exchange Rate		(77	)		(48	)

C) Interest Rate Risk

Interest rate risk arises from changes in market interest rates that may affect earnings, cash flows and valuations. Cenovus has the flexibility to partially mitigate its exposure to interest rate changes by maintaining a mix of both fixed and floating rate debt. In addition, to manage exposure to interest rate volatility, the Company entered into interest rate swap contracts. As at December 31, 2017, Cenovus had a notional amount of US$400 million (2016 – US$400 million) in interest rate swaps. In respect of these financial instruments, the impact of changes in the interest rate would have resulted in a change to unrealized gains (losses) impacting earnings before income tax as follows:

For the years ended December 31,	2017			2016
50 Basis Points Increase		44			45
50 Basis Points Decrease		(50	)		(52	)

As at December 31, 2017, the increase or decrease in net earnings for a one percent change in interest rates on floating rate debt amounts to $nil (2016 – $nil; 2015 – $nil). This assumes the amount of fixed and floating debt remains unchanged from the respective balance sheet dates.

D) Credit Risk

Credit risk arises from the potential that the Company may incur a financial loss if a counterparty to a financial instrument fails to meet its financial or performance obligations in accordance with agreed terms. Cenovus has in place a Credit Policy approved by the Audit Committee of the Board of Directors designed to ensure that its credit exposures are within an acceptable risk level as determined by the Company’s Enterprise Risk Management Policy. The Credit Policy outlines the roles and responsibilities related to credit risk, sets a framework for how credit exposures will be measured, monitored and mitigated, and sets parameters around credit concentration limits.

Cenovus assesses the credit risk of new counterparties and continues risk-based monitoring of all counterparties on an ongoing basis. A substantial portion of Cenovus’s accounts receivable are with customers in the oil and gas industry and are subject to normal industry credit risks. Cenovus’s exposure to its counterparties is within credit policy tolerances.

Cenovus Energy Inc. 52 For the year ended December 31, 2017

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

All amounts in $ millions, unless otherwise indicated

For the year ended December 31, 2017

As at December 31, 2017 and 2016, substantially all of the Company’s accounts receivable were less than 60 days. As at December 31, 2017, 89 percent (2016 – 90 percent) of Cenovus’s accounts receivable and financial derivative credit exposures are with investment grade counterparties. As at December 31, 2017, Cenovus had three counterparties (2016 – three counterparties) whose net settlement position individually accounted for more than 10 percent of the fair value of the outstanding in-the-money net financial and physical contracts. The 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 the Company will not be able to meet all of its financial obligations as they become due. Liquidity risk also includes the risk of not being able to liquidate assets in a timely manner at a reasonable price. Cenovus manages its liquidity risk through the active management of cash and debt and by maintaining appropriate access to credit, which may be impacted by the Company’s credit ratings. As disclosed in Note 32, over the long term, Cenovus targets a Net Debt to Adjusted EBITDA of less than 2.0 times to manage the Company’s overall debt position.

Cenovus manages its liquidity risk by ensuring that it has access to multiple sources of capital including: cash and cash equivalents, cash from operating activities, undrawn credit facility capacity and availability under its shelf prospectus. As at December 31, 2017, Cenovus had $610 million in cash and cash equivalents, and $4.5 billion available on its committed credit facility. In addition, Cenovus has unused capacity of US$4.6 billion under a base shelf prospectus, the availability of which is dependent on market conditions.

Undiscounted cash outflows relating to financial liabilities are:

As at December 31, 2017	Less than 1 Year		Years 2 and 3		Years 4 and 5		Thereafter		Total
Accounts Payable and Accrued Liabilities		2,635		-		-		-		2,635
Risk Management Liabilities (1)		1,031		20		-		-		1,051
Long-Term Debt (2)		494		2,527		1,429		13,309		17,759
Other		-		21		11		16		48
As at December 31, 2016	Less than 1 Year		Years 2 and 3		Years 4 and 5		Thereafter		Total
Accounts Payable and Accrued Liabilities		2,266		-		-		-		2,266
Risk Management Liabilities (1)		293		22		-		-		315
Long-Term Debt (2)		339		2,662		1,150		7,550		11,701
Other		-		25		8		16		49

(1) Risk management liabilities subject to master netting agreements.

(2) Principal and interest, including current portion.

35. SUPPLEMENTARY CASH FLOW INFORMATION

For the years ended December 31,	2017		2016		2015
Interest Paid		538		350		330
Interest Received		31		32		19
Income Taxes Paid		12		11		933

Cenovus Energy Inc. 53 For the year ended December 31, 2017

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

All amounts in $ millions, unless otherwise indicated

For the year ended December 31, 2017

The following table provides a reconciliation of cash flows arising from financing activities:

	Dividends Payable			Current Portion of Long-Term Debt			Long-Term Debt			Share     Capital
As at December 31, 2015		-			-			6,525			5,534
Changes From Financing Cash Flows:
Dividends Paid		(166	)		-			-			-
Non-Cash Changes:
Dividends Declared		166			-			-			-
Unrealized Foreign Exchange (Gain) Loss (Note 7)		-			-			(196	)		-
Amortization of Debt Discounts		-			-			3			-
As at December 31, 2016		-			-			6,332			5,534
Changes From Financing Cash Flows:
Issuance of Long-Term Debt		-			-			3,842			-
Net Issuance (Repayment) of Revolving Long-Term Debt		-			-			32			-
Issuance of Debt Under Asset Sale Bridge Facility		-			892			2,677			-
(Repayment) of Debt Under Asset Sale Bridge Facility		-			(900	)		(2,700	)		-
Common Shares Issued, Net of Issuance Costs		-			-			-			2,899
Dividends Paid		(225	)		-			-			-
Non-Cash Changes:
Common Shares Issued to ConocoPhillips		-			-			-			2,579
Deferred Taxes on Share Issuance Costs		-			-			-			28
Dividends Declared		225			-			-			-
Unrealized Foreign Exchange (Gain) Loss		-			-			(697	)		-
Finance Costs		-			8			28			-
Other		-			-			(1	)		-
As at December 31, 2017		-			-			9,513			11,040

36. COMMITMENTS AND CONTINGENCIES

A) Commitments

Future payments for the Company’s commitments are below. A commitment is an enforceable and legally binding agreement to make a payment in the future for the purchase of goods and services. These items exclude amounts recorded in the Consolidated Balance Sheets.

As at December 31, 2017	1 Year		2 Years		3 Years		4 Years		5 Years		Thereafter		Total
Transportation and Storage (1)		899		886		919		1,123		1,223		13,260		18,310
Operating Leases (Building Leases) (2)		155		146		142		141		140		2,305		3,029
Capital Commitments		16		2		-		-		-		-		18
Other Long-Term Commitments		109		39		32		28		25		122		355
Total Payments (3)		1,179		1,073		1,093		1,292		1,388		15,687		21,712
Fixed Price Product Sales		-		-		-		-		-		-		-
As at December 31, 2016	1 Year		2 Years		3 Years		4 Years		5 Years		Thereafter		Total
Transportation and Storage (1)		682		711		722		1,031		1,239		21,875		26,260
Operating Leases (Building Leases) (2)		101		146		146		145		142		2,465		3,145
Product Purchases		70		-		-		-		-		-		70
Capital Commitments		23		3		-		-		-		-		26
Other Long-Term Commitments		80		27		26		15		15		108		271
Total Payments (3)		956		887		894		1,191		1,396		24,448		29,772
Fixed Price Product Sales		3		-		-		-		-		-		3

(1) Includes transportation commitments of $9 billion (2016 – $19 billion) that are subject to regulatory approval or have been approved, but are not yet in service.

(2) Excludes committed payment for which a provision has been provided.

(3) For 2017, contracts undertaken on behalf of WRB are reflected at Cenovus’s 50 percent interest. For 2016, contracts undertaken on behalf of FCCL and WRB are reflected at Cenovus’s 50 percent interest.

Cenovus Energy Inc. 54 For the year ended December 31, 2017

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

All amounts in $ millions, unless otherwise indicated

For the year ended December 31, 2017

Commitments for various pipeline transportation arrangements decreased $8.0 billion from 2016 primarily due to pipeline project cancellations, partially offset by incremental commitments included with the Acquisition and newly executed transportation agreements. Terms are up to 20 years subsequent to the date of commencement.

As at December 31, 2017, there were outstanding letters of credit aggregating $376 million issued as security for performance under certain contracts (2016 – $258 million).

In addition to the above, Cenovus’s commitments related to its risk management program are disclosed in Note 34.

B) Contingencies

Legal Proceedings

Cenovus is involved in a limited number of legal claims associated with the normal course of operations. Cenovus believes that any liabilities that might arise from such matters, to the extent not provided for, are not likely to have a material effect on its Consolidated Financial Statements.

Decommissioning Liabilities

Cenovus is responsible for the retirement of long-lived assets at the end of their useful lives. Cenovus has recorded a liability of $1,029 million, based on current legislation and estimated costs, related to its upstream properties, refining facilities and midstream facilities. Actual costs may differ from those estimated due to changes in legislation and changes in costs.

Income Tax Matters

The tax regulations and legislation and interpretations thereof in the various jurisdictions in which Cenovus operates are continually changing. As a result, there are usually a number of tax matters under review. Management believes that the provision for taxes is adequate.

Contingent Payment

In connection with the Acquisition, Cenovus agreed to make quarterly payments to ConocoPhillips during the five years subsequent to May 17, 2017 for quarters in which the average WCS crude oil price exceeds $52.00 per barrel during the quarter. As at December 31, 2017, the estimated fair value of the contingent payment was $206 million (see Note 22).

Cenovus Energy Inc. 55 For the year ended December 31, 2017

EX-99.4

Exhibit 99.4

Cenovus Energy Inc.

Supplementary Information – Oil and Gas Activities (unaudited)

For the Year Ended December 31, 2017

(Canadian Dollars)

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 and 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 after royalty 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 disclosed are effective December 31, 2017, and were prepared by the independent, qualified reserves evaluators McDaniel & Associates Consultants Ltd. and GLJ Petroleum Consultants Ltd. There are significant differences between reserves evaluated under the SEC requirements and those presented in the Company’s Annual Information Form filed under National Instrument 51-101 “Standards of Disclosure for Oil and Gas Activities” (“NI 51-101”). NI 51-101 requires disclosure of before royalties reserves and the associated values using forecasted prices and costs.

The reserves presented 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, natural gas liquids 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, natural gas liquids 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, sales, 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 rates. Canadian reserves, as presented on a net basis, assume royalty rates in existence at the time the estimates were made.

Subsequent to December 31, 2017 the Company has closed the sale of its Suffield property, resulting in the disposition of 64.0 million barrels of oil equivalent, comprised of approximately 80 percent natural gas and 20 percent crude oil.

The reserves data contained herein is dated February 13, 2018 with an effective date of December 31, 2017.

2  

Cenovus Energy Inc. Supplementary Information – Oil and Gas Activities (unaudited)

OIL AND GAS RESERVES INFORMATION

All of Cenovus’s reserves are located in Alberta and British Columbia, Canada.

Net Proved Reserves (Cenovus Share After Royalties)^(1)(2)(3)

Average Fiscal-Year Prices

	Bitumen (MMbbls)(3)		Natural Gas Liquids (MMbbls)(3)(4)		Crude Oil (MMbbls)(3)(4)		Natural Gas (Bcf)(3)		Total   (MMBOE)(3)
2016
Beginning of year		1,953		1		189		539		2,233
Revisions and improved recovery		(128)		-		(45)		8		(172)
Extensions and discoveries		134		-		-		-		134
Purchase of reserves in place		-		-		-		-		-
Sale of reserves in place		-		-		-		-		-
Production		(54)		-		(18)		(141)		(95)
End of year		1,905		1		126		406		2,100
Developed		307		1		114		405		490
Undeveloped		1,598		-		12		1		1,610
Total		1,905		1		126		406		2,100
2017
Beginning of year		1,905		1		126		406		2,100
Revisions and improved recovery		73		-		5		102		95
Extensions and discoveries		129		1		-		33		135
Purchase of reserves in place		1,959		85		12		1,559		2,316
Sale of reserves in place		-		(1)		(104)		(73)		(117)
Production		(100)		(6)		(15)		(233)		(160)
End of year		3,966		80		24		1,794		4,369
Developed		664		51		23		1,390		970
Undeveloped		3,302		29		1		404		3,399
Total		3,966		80		24		1,794		4,369

  (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) “Million barrels” is abbreviated as MMbbls, “billion cubic feet” is abbreviated as Bcf, and “million barrel of oil equivalent” is abbreviated as MMBOE.

  (4) Natural gas liquids and crude oil have been presented separately to conform to the presentation adopted in 2017.

Changes to Reserves

The explanation of significant year-over-year changes in the Company’s net proved reserves for the year ended December 31, 2016 and December 31, 2017 is set forth below.

Year ended December 31, 2016

The changes to the Company’s net proved bitumen reserves in 2016 are explained as follows:

• Revisions and improved recovery: The year-over-year decrease in average bitumen price rendered 235 million barrels of reserves at the Company’s Narrows Lake property uneconomic. The decrease was partially offset by increased reserves of 122 million barrels, which resulted from reduced royalty rates caused by lower WTI benchmark prices, at the Company’s Foster Creek and Christina Lake properties. The remaining difference is due to negative technical revisions.

• Extensions and discoveries: In 2016, the Alberta Energy Regulator approved a development area expansion at the Company’s Christina Lake property, which increased the Company’s proved reserves by 134 million barrels.

The changes to the Company’s net proved crude oil reserves in 2016 are explained as follows:

• Revisions and improved recovery: Crude oil reserves decreased in 2016 primarily due to lower year-over-year average prices, which rendered 46 million barrels of proved crude oil reserves at the Company’s Pelican Lake property uneconomic, offset by positive technical revisions.

3  

Cenovus Energy Inc. Supplementary Information – Oil and Gas Activities (unaudited)

Year ended December 31, 2017

The changes to the Company’s net proved bitumen reserves in 2017 are explained as follows:

• Purchase of reserves in place: The Company concluded a material transaction to acquire its partner’s 50 percent interest in the Christina Lake, Foster Creek, and Narrows Lake properties (“FCCL”), increasing net proved reserves by 1,959 million barrels.

• Revisions and improved recovery: The year-over-year increase in average bitumen price restored economic viability to the Narrows Lake project, increasing reserves by 243 million barrels. The increase was partially offset by decreased reserves of 144 million barrels, which resulted from increased royalty rates caused by higher WTI benchmark prices at the Company’s Foster Creek and Christina Lake properties. The remaining difference is attributable to technical revisions.

• Extensions and discoveries: In 2017, the Alberta Energy Regulator approved development area expansions at the Foster Creek and Narrows Lake properties, increasing the Company’s net proved reserves by 129 million barrels.

The changes to the Company’s net proved reserves of crude oil, natural gas liquids, and natural gas in 2017 are as follows:

• Purchase of reserves in place: The Company acquired significant assets in Alberta and British Columbia (the “Deep Basin Assets”). This added 12 million barrels of crude oil, 85 million barrels of natural gas liquids, and 1,559 billion cubic feet of natural gas reserves.

• Sale of reserves in place: The Company sold its Palliser, Pelican Lake and Saskatchewan properties, reducing its net proved reserves of crude oil and natural gas by 104 million barrels and 73 billion cubic feet, respectively.

• Revisions and improved recovery: Improved performance at Suffield and Athabasca Gas identified net proved natural gas reserves additions of 102 billion cubic feet. The Suffield property has subsequently been sold in early 2018.

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 net 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, natural gas liquids 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 and Natural Gas Liquids								Natural Gas
	WTI(1) Cushing          Oklahoma (US$/bbl)		WCS(2)     (C$/bbl)		Edmonton MSW(3) (C$/bbl)		Edmonton   C5+   (C$/bbl)		Henry Hub Louisiana         (US$/MMBtu)		AECO(4)        (C$/MMBtu)
2017		51.34		50.69		63.70		68.10		2.98		2.31
2016		42.75		37.98		52.06		55.32		2.49		2.17

(1) WTI is an abbreviation for West Texas Intermediate.

(2) WCS is an abbreviation for Western Canadian Select.

(3) MSW is an abbreviation for Mixed Sweet Blend.

(4) AECO is an abbreviation for Alberta Energy Company Operations.

4  

Cenovus Energy Inc. Supplementary Information – Oil and Gas Activities (unaudited)

Standardized Measure of Discounted Future Net Cash Flows Relating to Proved Oil and Gas Reserves

($ millions)	2017		2016
Future cash inflows		147,064	49,119
Less future:
Production costs		48,064	24,121
Development costs		22,850	11,293
Decommissioning liability payments		2,464	2,882
Income taxes		17,713	1,966
Future net cash flows		55,973	8,857
Less 10 percent annual discount for estimated timing of cash flows		36,263	5,225
Discounted future net cash flows		19,710	3,632

Changes in Standardized Measure of Discounted Future Net Cash Flows Relating to Proved Oil and Gas Reserves

($ millions)	2017			2016
Balance, beginning of year		3,632		6,026
Changes resulting from:
Sales of oil and gas produced during the period		(2,885	)	(1,421)
Extensions, discoveries and improved recovery, net of related costs		826		285
Purchases of proved reserves in place		13,819		-
Sales of proved reserves in place		(571	)	-
Net change in prices and production costs		8,060		(3,895)
Revisions to quantity estimates		1,293		(750)
Accretion of discount		420		746
Previously estimated development costs incurred net of change in future development costs		(5	)	1,536
Asset Retirement Obligation		77		175
Other		277		58
Net change in income taxes		(5,233	)	872
Balance, end of year		19,710		3,632

OTHER FINANCIAL INFORMATION

Results of Operations

($ millions)	2017		2016
Oil and gas sales to external customers, net of royalties, transportation and blending and realized risk management		4,071	2,031
Intersegment sales		443	347
		4,514	2,378
Less:
Operating costs, production and mineral taxes, and accretion of decommissioning liabilities		1,755	1,085
Depreciation, depletion and amortization		1,753	1,222
Exploration expense		890	2
Operating income		116	69
Income taxes		31	19
Results of operations		85	50

Capitalized Costs ⁽¹⁾

($ millions)	2017		2016
Proved oil and gas properties		28,776	32,274
Unproved oil and gas properties (2)		3,719	1,585
Total capital cost (3)		32,495	33,859
Accumulated depreciation, depletion and amortization		2,435	20,396
Net capitalized costs		30,060	13,463

  (1) In connection with the acquisition of Cenovus’s partner’s 50 percent interest in FCCL, Cenovus was deemed to have disposed of its pre-existing interest (net capitalized cost of $9.7 billion) and re-acquired it at fair value ($12.3 billion) as required by IFRS 3, “Business Combinations” effectively resetting accumulated depreciation, depletion and amortization to zero.

  (2) Unproved oil and gas properties include exploration and evaluation assets for which no proved reserves have been recognized.

  (3) Includes assets held for sale.

5  

Cenovus Energy Inc. Supplementary Information – Oil and Gas Activities (unaudited)

Costs Incurred

($ millions)	2017		2016
Acquisitions
Unproved(1)		3,372	11
Proved(2)(3)		15,016	-
Total acquisitions		18,388	11
Exploration costs		147	35
Development costs		1,257	738
Total costs incurred		19,792	784

  (1) An unproved property is a property to which no proved or probable reserves have been specifically attributed.

  (2) A proved property is a property to which proved and probable reserves have been specifically attributed.

  (3) Asset retirement costs are included in the year of acquisition.

6  

Cenovus Energy Inc. Supplementary Information – Oil and Gas Activities (unaudited)

EX-99.5

Exhibit 99.5

Certification of Chief Executive Officer

Pursuant to Rule 13a-14(a) or 15d-14(a) of the Securities Exchange Act of 1934

I, Alex J. Pourbaix, certify that:

1. I have reviewed this annual report on Form 40-F of Cenovus Energy Inc.;

2. Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;

3. Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the issuer as of, and for, the periods presented in this report;

4. The issuer’s other certifying officer(s) and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the issuer and have:

(a) Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the issuer, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;

(b) Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, 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;

(c) Evaluated the effectiveness of the issuer’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and

(d) Disclosed in this report any change in the issuer’s internal control over financial reporting that occurred during the period covered by the annual report that has materially affected, or is reasonably likely to materially affect, the issuer’s internal control over financial reporting; and

5. The issuer’s other certifying officer(s) and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the issuer’s auditors and the audit committee of the issuer’s board of directors (or persons performing the equivalent functions):

(a) All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the issuer’s ability to record, process, summarize and report financial information; and

(b) Any fraud, whether or not material, that involves management or other employees who have a significant role in the issuer’s internal control over financial reporting.

Date: February 15, 2018

/s/ Alex J. Pourbaix

Alex J. Pourbaix

President & Chief Executive Officer

(Principal Executive Officer)

EX-99.6

Exhibit 99.6

Certification of Chief Financial Officer

Pursuant to Rule 13a-14(a) or 15d-14(a) of the Securities Exchange Act of 1934

I, Ivor M. Ruste, certify that:

1. I have reviewed this annual report on Form 40-F of Cenovus Energy Inc.;

2. Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;

3. Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the issuer as of, and for, the periods presented in this report;

4. The issuer’s other certifying officer(s) and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the issuer and have:

(a) Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the issuer, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;

(b) Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, 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;

(c) Evaluated the effectiveness of the issuer’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and

(d) Disclosed in this report any change in the issuer’s internal control over financial reporting that occurred during the period covered by the annual report that has materially affected, or is reasonably likely to materially affect, the issuer’s internal control over financial reporting; and

5. The issuer’s other certifying officer(s) and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the issuer’s auditors and the audit committee of the issuer’s board of directors (or persons performing the equivalent functions):

(a) All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the issuer’s ability to record, process, summarize and report financial information; and

(b) Any fraud, whether or not material, that involves management or other employees who have a significant role in the issuer’s internal control over financial reporting.

Date: February 15, 2018

/s/ Ivor M. Ruste

Ivor M. Ruste

Executive Vice-President & Chief Financial Officer

(Principal Financial Officer)

EX-99.7

Exhibit 99.7

Certification Pursuant to 18 U.S.C. Section 1350, As Adopted

Pursuant to Section 906 of the Sarbanes Oxley Act of 2002

In connection with the annual report of Cenovus Energy Inc. (the “Company”) on Form 40–F for the year ended December 31, 2017, as filed with the Securities and Exchange Commission on the date hereof (the “Report”), I, Alex J. Pourbaix, President & Chief Executive Officer of the Company, certify, pursuant to 18 U.S.C. section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002, that to the best of my knowledge:

1. The Report fully complies with the requirements of section 13(a) or 15(d) of the Securities Exchange Act of 1934; and

2. The information contained in the Report fairly presents, in all material respects, the financial condition and results of operations of the Company.

Date: February 15, 2018

By:	/s/ Alex J. Pourbaix
	Alex J. Pourbaix
	President & Chief Executive Officer

EX-99.8

Exhibit 99.8

Certification Pursuant to 18 U.S.C. Section 1350, As Adopted

Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002

In connection with the annual report of Cenovus Energy Inc. (the “Company”) on Form 40–F for the year ended December 31, 2017, as filed with the Securities and Exchange Commission on the date hereof (the “Report”), I, Ivor M. Ruste, Executive Vice-President & Chief Financial Officer of the Company, certify, pursuant to 18 U.S.C. section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002, that to the best of my knowledge:

1. The Report fully complies with the requirements of section 13(a) or 15(d) of the Securities Exchange Act of 1934; and

2. The information contained in the Report fairly presents, in all material respects, the financial condition and results of operations of the Company.

Date: February 15, 2018

By:	/s/ Ivor M. Ruste
	Ivor M. Ruste
	Executive Vice-President & Chief Financial Officer

EX-99.9

Exhibit 99.9

CONSENT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

We hereby consent to the inclusion in this Annual Report on Form 40-F for the year ended December 31, 2017 of Cenovus Energy Inc. of our report dated February 14, 2018, relating to the consolidated financial statements, and the effectiveness of internal control over financial reporting, which appears in this Annual Report.

We also consent to the incorporation by reference in the Registration Statements on Form S-8 (File No. 333-163397), Form F-3D (File No. 333-202165), and Form F-10 (File No. 333-220700) of Cenovus Energy Inc. of our report dated February 14, 2018 referred to above. We also consent to reference to us under the heading “Interests of Experts,” which appears in the Annual Information Form included in the Exhibit incorporated by reference in this Annual Report on Form 40-F, which is incorporated by reference in such Registration Statements.

/s/ PricewaterhouseCoopers LLP

Calgary, Alberta

February 15, 2018

EX-99.10

Exhibit 99.10

CONSENT OF INDEPENDENT PETROLEUM ENGINEER

We hereby consent to the use and reference to our name and reports evaluating a portion of Cenovus Energy Inc. oil and gas reserves data, including estimates of proved reserves and probable reserves and related future net revenue as at December 31, 2017, estimated using forecast prices and costs, and the information derived from our reports, as described or incorporated by reference in Cenovus Energy Inc.’s annual report on Form 40-F for the year ended December 31, 2017 and Cenovus Energy Inc.’s registration statements on Form S-8 (File No. 333-163397), Form F-3D (File No. 333-202165) and Form F-10 (File No. 333-220700), filed with the United States Securities and Exchange Commission pursuant to the Securities Exchange Act of 1934, as amended or the Securities Act of 1933, as amended, as applicable.

  MCDANIEL & ASSOCIATES CONSULTANTS LTD.

  /s/ M. J. Verney

  M. J. Verney, P. Eng.

  Vice President 

  Calgary, Alberta

  February 15, 2018

EX-99.11

Exhibit 99.11

CONSENT OF INDEPENDENT PETROLEUM ENGINEER

We hereby consent to the use and reference to our name and report evaluating a portion of Cenovus Energy Inc. oil and gas reserves data, including estimates of proved reserves and probable reserves and related future net revenue as at December 31, 2017, estimated using forecast prices and costs, and the information derived from our reports, as described or incorporated by reference in Cenovus Energy Inc.’s annual report on Form 40-F for the year ended December 31, 2017 and Cenovus Energy Inc.’s registration statements on Form S-8 (File No. 333-163397), Form F-3D (File No. 333-202165) and Form F-10 (File No. 333-220700), filed with the United States Securities and Exchange Commission pursuant to the Securities Exchange Act of 1934, as amended or the Securities Act of 1933, as amended, as applicable.

GLJ PETROLEUM CONSULTANTS LTD.

/s/ Keith M. Braaten

Keith M. Braaten, P.Eng.

President & CEO

Calgary, Alberta

February 15, 2018

EX-99.12

Exhibit 99.12

Code of Business Conduct

& Ethics

March 1, 2017

This Code of Business Conduct & Ethics (“Code”) reflects Cenovus’s commitment to conducting our business ethically, legally and safely while we pursue progressive and innovative approaches to developing energy resources. At Cenovus, we can be trusted to do what we say. We are a company that conducts its business with respect. This Code will be used to identify and manage ethical situations and to provide guidance in making ethical business decisions so that our staff can fulfill these commitments. Staff should review and be familiar with the Code’s supporting policies and practices.

Compliance with Laws and Regulations

As employees, contractors and directors, we comply with the laws, rules and regulations of Canada, the United States and any other countries in which Cenovus operates. We comply with the requirements of applicable securities regulatory authorities and stock exchanges.

Corporate Opportunities

Our employees, contractors and directors are prohibited from taking opportunities, using Cenovus property or information or their position with Cenovus for personal gain or competing with Cenovus, based on information discovered through the use of corporate property, information or position.

Conflicts of Interest

Our employees, contractors and directors avoid situations where personal interests could conflict, or appear to conflict, with duties and responsibilities or the interests of Cenovus. A conflict of interest may occur where involvement in any activity, with or without the involvement of a related party, prevents the proper performance of employee, contractor and director duties for Cenovus, or creates, or appears to create, a situation where judgment or ability to act in the best interests of Cenovus is affected. The

Compliance with Laws and Regulations	1
Corporate Opportunities	1
Conflicts of Interest	1
Fraud and other Similar Irregularities	2
Confidentiality and Disclosure	2
Safety, Environment and
Corporate Responsibility	3
Acceptable Use of Cenovus’s
Systems and Assets	3
Inducements and Gifts	4
Political Activities	4
Lobbying Activities	4
Fair Dealing	4
Acquisition and Supply of
Goods and Services	5
Company Records	5
Accuracy of Books and Records	5
Accounting, Auditing or
Disclosure Concerns	5
Human Rights and Harassment	6
Observance of the Code	6
Reporting Violations of the Code	6
Whistleblower Protection	6
Waivers and Amendments	7

Conflict of Interest Practice provides further guidance and examples regarding conflict of interest situations.

When faced with an actual or potential conflict of interest, our employees follow the procedures outlined in the Conflict of Interest Practice and contractors review and follow the provisions of their written contracts. Our officers and directors follow obligations that are set out in relevant statutes and company by-laws and inform the Chair of the Board of Directors of any such conflict. Our commitment is to ensure that employees and contractors are not involved in any decision or operation related to a conflict and that officers or directors are not involved in any decision or operation related to a conflict. This is the commitment of our employees, our Executive Team and our Board of Directors.

Fraud and other Similar Irregularities

At Cenovus, we are committed to protecting the revenue, property, information and other assets of the company and our shareholders from any attempt, either by the public, contractors, agents or our own employees, to gain financial or other benefit by deceit, in the course of our business.

Our employees, contractors and directors must not, under any circumstances, misappropriate funds, property or other assets, or knowingly assist another individual to do so. Similarly, our employees, contractors and directors are not to use, borrow, loan, take, transfer or convert any assets that do not belong to them, or use them for the benefit of themselves or anyone other than the rightful owners, and are not to knowingly assist another individual to do so.

Our employees, contractors and directors will only claim those expenses that are eligible for reimbursement under Cenovus’s expense guidelines and will not use the corporate credit card for personal expenses other than in accordance with Cenovus’s credit card guidelines.

We have zero-tolerance for fraudulent activities and fully investigate any suspected acts of fraud, misappropriation or other similar irregularity. Cenovus will pursue every reasonable effort, including court-ordered restitution, to obtain recovery of Cenovus’s losses from the offender or other appropriate sources.

Any employee or contractor who has knowledge of an occurrence of fraud, or has reason to suspect that a fraud has occurred, must immediately notify their supervisor or Cenovus representative or may report their suspicions in accordance with the Investigations Practice or to the Integrity Helpline.

Confidentiality and Disclosure

Confidential information includes all non-public information that might be of use to competitors, or harmful to Cenovus or its customers, if disclosed. Confidential or proprietary information and Cenovus’s intellectual property must not be disclosed without proper safeguards, or specific authorization given to do so, or such disclosure is legally mandated. Knowledge of confidential information about another company gained in the course of work duties at Cenovus must be protected in the same manner as confidential information about Cenovus.

Our employees, contractors and directors must not violate or infringe the intellectual property rights or breach any obligations relating to the confidential information of Cenovus or of others. The Intellectual Property Practice provides further guidance regarding the use and protection of intellectual property at Cenovus.

Employees, contractors and directors must not speak on behalf of Cenovus unless authorized to do so and should refer to the Policy on Disclosure, Confidentiality and Employee Trading.

Taking advantage of, or benefiting from, information obtained at work that is not available to the public is not permitted. Friends, relatives and associates must not benefit from such information. Where insider information is known and not yet publicly disclosed, employees, contractors and directors must avoid acquiring or disposing of any business interest, including publicly traded securities, whether directly or through another person.

If an employee or contractor is not sure whether information has been publicly disclosed, they should consult with a member of Cenovus’s Legal group for guidance before engaging in any transaction in any securities of Cenovus. Officers

Cenovus Energy Inc. • Code of Business Conduct & Ethics

March 1, 2017 • Page 2 of 7

and directors should consult on such matters with the persons listed in the Restricted Trading and Insider Guidelines for guidance before engaging in any transaction in any Cenovus securities. All securities transactions are subject to the Policy on Disclosure, Confidentiality and Employee Trading and if applicable, the Restricted Trading and Insider Guidelines.

These confidentiality obligations remain in effect even beyond termination of employment, service agreements or Board of Directors appointments with Cenovus or its affiliates.

Safety, Environment and Corporate Responsibility

We are safety and environmentally focused at Cenovus. In all our activities and operations, staff are required to:

• Act in a manner consistent with our Safety Commitments, Life-Saving Rules, Environmental Commitments and Corporate Responsibility Policy

• Complete health and safety training commensurate with the degree of risk associated with the activity or operation they are engaged in or as required by the company

• Continuously identify and eliminate or manage health, safety and environment risks associated with our activities and operations

• Comply with all applicable health, safety and environment related laws and regulations, and company policies and practices

Acceptable Use of Cenovus’s Systems and Assets

Cenovus’s corporate information, data, information system assets, office equipment, tools, vehicles, supplies, facilities and services are provided for authorized business purposes. Our employees, contractors, and directors have an obligation to use these assets in accordance with fundamental principles of reasonable and acceptable use and are not permitted to engage in unacceptable use of those assets.

Acceptable use is demonstrated when each individual:

• Consistently ensures the confidentiality, integrity and availability of Cenovus’s information

• Takes acceptable measures to protect Cenovus’s rights and property ownership of information system assets

Personal use is considered reasonable if it:

• Involves appropriate content

• Does not put Cenovus at risk of violating the copyrights on any materials

• Is in alignment with regional laws, legislation, and Cenovus values

• Occurs for short periods of time and does not interfere with day-to-day responsibilities of Cenovus staff

Unacceptable use (whether personal or business) includes when an individual acts so as to:

• Defame, slander, harass, annoy or cause needless anxiety to another person or another organization

• Conduct any illegal or unethical activity

• Conduct any activity that could adversely affect Cenovus or Cenovus’s reputation

• Intentionally transmit viruses or transmit virus warnings to any recipient other than the Service Desk

• Make excessive or inappropriate use of non-business-related Internet sites, chat rooms, blogs, discussion rooms, or social networking sites (e.g. Facebook, MySpace, Twitter) for personal reasons

• Replace personal assets (e.g. home telephone land line or personal PC)

• Exchange any of the following types of content:

• Personal commercial, advertising or political material

• Pictures, jokes or content that conflict with this Code

• Chain letters

Cenovus Energy Inc. • Code of Business Conduct & Ethics

March 1, 2017 • Page 3 of 7

• Obscene or sexually explicit messages, pictures, cartoons or jokes

• Ethnic, religious, gender-related, disability-related or racial slurs

• Confidential, sensitive or proprietary information to unauthorized recipients

• Material that could damage Cenovus’s image or reputation

Cenovus’s information system assets and other assets must not be used for personal commercial ventures.

Cenovus staff should also consult the Records and Information Management Policy and the Information Security Practice website for further guidance related to acceptable use of Cenovus’s systems and assets.

Inducements and Gifts

At Cenovus, we do not accept or give gifts, favours, personal advantages, services payments, loans, or benefits of any kind, other than those of nominal value that can be made as a generally accepted business practice. The Acceptance of Gifts Guideline provides further guidance regarding gift-giving and receiving and should be referred to and or written approval from Cenovus leaders should be requested. Gift-giving practices may vary among different cultures, and therefore local gift practices and guidelines will be considered when addressing these issues.

We do not tolerate soliciting, accepting, or paying bribes or other illicit payments for any purpose. Situations must be avoided where judgment might be influenced by, or appears to be influenced by such unlawful or unethical behavior. Payment or acceptance of any “kickbacks” from a contractor or other external party is strictly prohibited.

Illicit or improper payments to public officials are strictly prohibited. Cenovus is subject to and abides by the Corruption of Foreign Public Officials Act (Canada), the Foreign Corrupt Practices Act (U.S.A.), and equivalent legislation in other countries in which Cenovus operates. Staff must comply with any associated practices. Non-compliance could have serious ramifications for Cenovus and for staff.

Political Activities

Cenovus does not participate in improper intervention in political processes and does not make financial contributions or contributions in kind (e.g. properties, materials or services) to political parties, committees or their representatives.

At Cenovus, our employees, contractors and directors may choose to become involved in political activities as long as they undertake these activities on their own behalf and may, on a personal level, give to any political party or candidate. Reimbursement by the company is prohibited.

Lobbying Activities

We comply with all applicable lobbying legislation including the Lobbying Act (Canada), the Lobbyists Act (Alberta), The Lobbyists Act (Saskatchewan) and the Lobbyists Registration Act (British Columbia) which impose reporting requirements on lobbying communications with certain officers and employees of the Government of Canada, the Government of Alberta and the Government of British Columbia (known in Canada as “Public Office Holders” or “POHs”). Employees must not have communications with a POH unless they have been registered by Cenovus, except where otherwise permitted by the applicable legislation.

Fair Dealing

Our employees, contractors and directors endeavour to deal fairly with Cenovus’s customers, contractors, industry partners, employees and any other stakeholders, and to not take unfair advantage of anyone through manipulation, concealment, abuse of privileged information, misrepresentation of material facts, or any other unfair-dealing practice.

Cenovus Energy Inc. • Code of Business Conduct & Ethics

March 1, 2017 • Page 4 of 7

Acquisition and Supply of Goods and Services

It is the responsibility of all Cenovus employees and contractors involved in the acquisition of goods and services to act in a financially responsible and ethical manner.

Employees are required to:

• Acquire goods and services through company defined practices and guidelines

• Ensure the necessary parties are involved in the process, and that required approvals are obtained for agreements, contracts and purchasing activities

• Support the principle of company-wide buying power to achieve security of supply, reduction in total cost of ownership, and the best supply arrangements to meet the needs of Cenovus

• Engage with the supplier community in a manner that is fair and aligned with the Cenovus Values and Work Principles (e.g., safety focused, local and aboriginal, environmentally focused, and innovation focused suppliers)

• Ensure that engagement of suppliers and contractors is conducted in a manner that avoids conflicts of interest or perceived conflicts of interest (as described earlier in this Code)

All employees are required to ensure suppliers and contractors are managed in accordance with the above and any associated practices.

Company Records

Records must be kept and maintained to fulfill relevant legal requirements. Recording and reporting information, including information related to operations, environment, health, safety, training, human resources and financial matters, must be done honestly, accurately and with care.

Accuracy of Books and Records

At Cenovus we understand that the books and records of Cenovus must reflect in reasonable detail its transactions in a timely, fair and accurate manner to, among other things, permit the preparation of accurate financial statements in accordance with International Financial Reporting Standards and maintain recorded accountability for assets and liabilities. The accuracy of asset and liability records must be maintained by comparing the records to the existing assets and liabilities at reasonable intervals, and taking appropriate action with respect to any differences.

All business transactions that employees, contractors and directors have participated in must be properly authorized, properly recorded and supported by accurate documentation in reasonable detail.

Accounting, Auditing or Disclosure Concerns

Cenovus is required to provide full, fair, accurate, timely and understandable disclosure in reports and documents that are filed with, or submitted to, the U.S. Securities and Exchange Commission, the Alberta Securities Commission and other Canadian securities regulatory authorities, the Toronto Stock Exchange and the New York Stock Exchange, as well as in other public communications made by Cenovus. All employees and contractors responsible for the preparation of Cenovus’s public disclosures, or who provide information as part of the process, ensure that disclosures are prepared and information is provided honestly, accurately and in compliance with the various Cenovus disclosure controls and procedures.

All employees, contractors and directors have a duty to submit any good faith questions and concerns regarding questionable accounting, auditing or disclosure matters or controls. Submissions about these or similar matters should be reported in accordance with the Investigations Practice.

To the extent that potential violations involve Cenovus’s accounting, internal accounting controls or auditing matters (including questionable accounting or auditing matters), investigations under this Code will be overseen by, and be the

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March 1, 2017 • Page 5 of 7

ultimate responsibility of, the Audit Committee of the Board of Directors.

No information may be concealed from Cenovus’s external auditors, internal auditors, the Board of Directors, or the Audit Committee of the Board of Directors. It is illegal to fraudulently influence, coerce, manipulate or mislead an external auditor who is auditing Cenovus’s financial statements.

Human Rights and Harassment

We do not tolerate unlawful workplace conduct, including discrimination, intimidation or harassment. We are committed to maintaining a positive workplace where all staff adheres to relevant human rights legislation and acts ethically, honestly and treats all others we come in contact with during our work with dignity, fairness and respect. Any form of unlawful harassment or discrimination based on age, gender, race, color, religion, creed, national or ethnic origin, citizenship, linguistic or cultural background, marital or family status, sexual orientation or physical or mental disability will not be tolerated.

Observance of the Code

All employees and directors are personally accountable for learning, endorsing and promoting this Code and applying it to their own conduct and field of work. All employees and directors are asked to review this Code, to confirm on a regular basis, through written or electronic declaration, that they understand their individual responsibilities and to acknowledge they conform to the requirements of the Code.

Contractors are expected to develop and enforce with their staff, policies and/or practices that are consistent with this Code and its associated requirements and to acknowledge their compliance in writing.

Employees or contractors with questions about this Code or specific situations are encouraged to refer the matter to their supervisor or leader or the persons listed in any referenced policy or practice, as applicable. Applicable resource groups such as internal legal counsel or Human Resources may also be contacted. Officers and directors with questions about this Code or specific situations are encouraged to refer the matter to the Chief Executive Officer or the Chair of the Board of Directors or the persons listed in any referenced policy or practice, as applicable.

Reporting Violations of the Code

Individuals are strongly encouraged to report business conduct concerns or violations of this Code to their supervisor, Cenovus representative, Human Resources Business Partner, to a member of the Investigations Committee or to the Integrity Helpline.

If an investigation is required, it will be conducted in accordance with Cenovus’s Investigations Practice. The Investigations Practice outlines how a report will be treated once it is made, protection for complainants and the consequences of violating this Code.

Violation of this Code and its associated guidelines may result in disciplinary action up to and including termination of employment or contract for services.

Whistleblower Protection

Retaliation against individuals (whether employees, contractors or other third parties) who report violations of this Code will not be tolerated. Every supervisor has the responsibility to create an environment in which staff can raise business conduct concerns or violations under this Code without fear of retaliation.

No adverse action will be taken against individuals making a good faith report of a business conduct concern or violation under this Code, whether or not the report ultimately proves to be well founded. Good faith does not mean that the individual reporting the concern or violation has to be right; but it does mean that the individual believes he/she is providing truthful and accurate information.

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March 1, 2017 • Page 6 of 7

Any individual who believes retaliation has occurred should contact the Integrity Helpline immediately.

We will not tolerate reports that are not made in good faith, such as reports intentionally providing false information or made maliciously to harm the company or another employee or contractor. Disciplinary action, up to and including termination of employment or services, may be taken against an employee or contractor knowingly making false reports.

Waivers and Amendments

Waivers of this Code for employees or contractors may be granted only by a Vice-President in limited, exceptional circumstances. Any waiver of this Code for officers or directors may only be made by the Board of Directors and will be promptly disclosed to shareholders to the extent required by law, rule, regulation or stock exchange requirement.

Amendments to this Code will be publicly disclosed to the extent required by law, rule, regulation or stock exchange requirement.

Cenovus Energy Inc. • Code of Business Conduct & Ethics

March 1, 2017 • Page 7 of 7

XML

Document and Entity Information	12 Months Ended
	Dec. 31, 2017 shares
Document And Entity Information [Abstract]
Document Type	40-F
Amendment Flag	false
Document Period End Date	Dec. 31, 2017
Document Fiscal Year Focus	2017
Document Fiscal Period Focus	FY
Trading Symbol	CVE
Entity Registrant Name	CENOVUS ENERGY INC.
Entity Central Index Key	0001475260
Current Fiscal Year End Date	--12-31
Entity Current Reporting Status	Yes
Entity Common Stock, Shares Outstanding	1,228,789,845

XML

Consolidated Statements of Earnings (Loss) - CAD CAD in Millions	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016	[1]	Dec. 31, 2015	[1]
Revenues
Gross Sales	CAD 17,314	CAD 11,015		CAD 11,559
Less: Royalties	271	9		30
Revenue	17,043	11,006		11,529
Expenses
Purchased Product	8,033	6,978		7,374
Transportation and Blending	3,748	1,715		1,814
Operating	1,949	1,239		1,281
Production and Mineral Taxes	1			1
(Gain) Loss on Risk Management	896	401		(252)
Depreciation, Depletion and Amortization	1,838	931		993
Exploration Expense	888	2		67
General and Administrative	308	326		335
Finance Costs	645	390		381
Interest Income	(62)	(52)		(28)
Foreign Exchange (Gain) Loss, Net	(812)	(198)		1,036
Revaluation (Gain)	(2,555)
Transaction Costs	56
Re-measurement of Contingent Payment	(138)
Research Costs	36	36		27
(Gain) Loss on Divestiture of Assets	1	6		(2,392)
Other (Income) Loss, Net	(5)	34		2
Earnings (Loss) From Continuing Operations Before Income Tax	2,216	(802)		890
Income Tax Expense (Recovery)	(52)	(343)		(24)
Net Earnings (Loss) From Continuing Operations	2,268	(459)		914
Net Earnings (Loss) From Discontinued Operations	1,098	(86)		(296)
Net Earnings (Loss)	CAD 3,366	CAD (545)		CAD 618
Basic and Diluted Earnings (Loss) Per Share ($)
Continuing Operations	CAD 2.06	CAD (0.55)		CAD 1.11
Discontinued Operations	0.99	(0.10)		(0.36)
Net Earnings (Loss) Per Share	CAD 3.05	CAD (0.65)		CAD 0.75

[1] The comparative periods have been restated to reflect discontinued operations as discussed in Notes 1 and 11.

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Consolidated Statements of Comprehensive Income (Loss) - CAD CAD in Millions	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016		Dec. 31, 2015
Statement Of Comprehensive Income [Abstract]
Net Earnings (Loss)	CAD 3,366	CAD (545)	[1]	CAD 618	[1]
Items That Will Not be Reclassified to Profit or Loss:
Actuarial Gain (Loss) Relating to Pension and Other Post-Retirement Benefits	9	(3)		20
Items That May be Reclassified to Profit or Loss:
Available for Sale Financial Assets – Change in Fair Value	(1)	(2)		6
Available for Sale Financial Assets – Reclassified to Profit or Loss		1
Foreign Currency Translation Adjustment	(275)	(106)		587
Total Other Comprehensive Income (Loss), Net of Tax	(267)	(110)		613
Comprehensive Income (Loss)	CAD 3,099	CAD (655)		CAD 1,231

[1] The comparative periods have been restated to reflect discontinued operations as discussed in Notes 1 and 11.

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Consolidated Balance Sheets - CAD CAD in Millions	Dec. 31, 2017	Dec. 31, 2016
Current Assets
Cash and Cash Equivalents	CAD 610	CAD 3,720
Accounts Receivable and Accrued Revenues	1,830	1,838
Income Tax Receivable	68	6
Inventories	1,389	1,237
Risk Management	63	21
Assets Held for Sale	1,048
Total Current Assets	5,008	6,822
Exploration and Evaluation Assets	3,673	1,585
Property, Plant and Equipment, Net	29,596	16,426
Income Tax Receivable	311	124
Risk Management	2	3
Other Assets	71	56
Goodwill	2,272	242
Total Assets	40,933	25,258
Current Liabilities
Accounts Payable and Accrued Liabilities	2,635	2,266
Contingent Payment	38
Income Tax Payable	129	112
Risk Management	1,031	293
Liabilities Related to Assets Held for Sale	603
Total Current Liabilities	4,436	2,671
Long-Term Debt	9,513	6,332
Contingent Payment	168
Risk Management	20	22
Decommissioning Liabilities	1,029	1,847
Other Liabilities	173	211
Deferred Income Taxes	5,613	2,585
Total Liabilities	20,952	13,668
Shareholders’ Equity	19,981	11,590
Total Liabilities and Shareholders’ Equity	40,933	25,258
Commitments and Contingencies

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Consolidated Statements of Shareholders' Equity - CAD CAD in Millions	Total		Share Capital [Member]	Paid in Surplus [Member]	Retained Earnings [Member]	AOCI [Member]	[1]
Beginning balance at Dec. 31, 2014	CAD 10,186		CAD 3,889	CAD 4,291	CAD 1,599	CAD 407
Net Earnings (Loss)	618	[2]			618
Other Comprehensive Income (Loss)	613					613
Comprehensive Income (Loss)	1,231				618	613
Common Shares Issued for Cash	1,463		1,463
Common Shares Issued Pursuant to Dividend Reinvestment Plan	182		182
Stock-Based Compensation Expense	39			39
Dividends on Common Shares	(710)				(710)
Ending balance at Dec. 31, 2015	12,391		5,534	4,330	1,507	1,020
Net Earnings (Loss)	(545)	[2]			(545)
Other Comprehensive Income (Loss)	(110)					(110)
Comprehensive Income (Loss)	(655)				(545)	(110)
Stock-Based Compensation Expense	20			20
Dividends on Common Shares	(166)				(166)
Ending balance at Dec. 31, 2016	11,590		5,534	4,350	796	910
Net Earnings (Loss)	3,366				3,366
Other Comprehensive Income (Loss)	(267)					(267)
Comprehensive Income (Loss)	3,099				3,366	(267)
Common Shares Issued for Cash	5,506		5,506
Stock-Based Compensation Expense	11			11
Dividends on Common Shares	(225)				(225)
Ending balance at Dec. 31, 2017	CAD 19,981		CAD 11,040	CAD 4,361	CAD 3,937	CAD 643

[1] Accumulated Other Comprehensive Income (Loss).

[2] The comparative periods have been restated to reflect discontinued operations as discussed in Notes 1 and 11.

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Consolidated Statements of Cash Flows - CAD CAD in Millions	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016		Dec. 31, 2015
Operating Activities
Net Earnings (Loss)	CAD 3,366	CAD (545)	[1]	CAD 618	[1]
Depreciation, Depletion and Amortization	2,030	1,498		2,114
Exploration Expense	890	2		138
Deferred Income Taxes	583	(209)		(655)
Unrealized (Gain) Loss on Risk Management	729	554		195
Unrealized Foreign Exchange (Gain) Loss	(857)	(189)		1,097
Revaluation (Gain)	(2,555)
Re-measurement of Contingent Payment	(138)
(Gain) Loss on Discontinuance	(1,285)
(Gain) Loss on Divestiture of Assets	1	6		(2,392)
Current Tax on Divestiture of Assets				391
Unwinding of Discount on Decommissioning Liabilities	128	130		126
Onerous Contract Provisions, Net of Cash Paid	(8)	53
Other Asset Impairments		30
Other	30	93		59
Net Change in Other Assets and Liabilities	(107)	(91)		(107)
Net Change in Non-Cash Working Capital	252	(471)		(110)
Cash From Operating Activities	3,059	861		1,474
Investing Activities
Acquisition, Net of Cash Acquired	(14,565)			(84)
Capital Expenditures – Exploration and Evaluation Assets	(147)	(67)		(138)
Capital Expenditures – Property, Plant and Equipment	(1,523)	(967)		(1,576)
Proceeds From Divestiture of Assets	3,210	8		3,344
Current Tax on Divestiture of Assets				(391)
Net Change in Investments and Other		(1)		3
Net Change in Non-Cash Working Capital	159	(52)		(270)
Cash From (Used in) Investing Activities	(12,866)	(1,079)		888
Net Cash Provided (Used) Before Financing Activities	(9,807)	(218)		2,362
Financing Activities
Net Issuance (Repayment) of Short-Term Borrowings				(25)
Issuance of Long-Term Debt	3,842
Net Issuance (Repayment) of Revolving Long-Term Debt	32
Net Issuance of Debt Under Asset Sale Bridge Facility	3,569
Repayment of Debt Under Asset Sale Bridge Facility	(3,600)
Common Shares Issued, Net of Issuance Costs	2,899			1,449
Dividends Paid on Common Shares	(225)	(166)		(528)
Other	(2)	(2)		(2)
Cash From (Used in) Financing Activities	6,515	(168)		894
Foreign Exchange Gain (Loss) on Cash and Cash Equivalents Held in Foreign Currency	182	1		(34)
Increase (Decrease) in Cash and Cash Equivalents	(3,110)	(385)		3,222
Cash and Cash Equivalents, Beginning of Year	3,720	4,105		883
Cash and Cash Equivalents, End of Year	CAD 610	CAD 3,720		CAD 4,105

[1] The comparative periods have been restated to reflect discontinued operations as discussed in Notes 1 and 11.

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Description of Business and Segmented Disclosures

12 Months Ended

Dec. 31, 2017

Disclosure Of Reportable Segments [Abstract]

Description of Business and Segmented Disclosures

1. DESCRIPTION OF BUSINESS AND SEGMENTED DISCLOSURES

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

Cenovus is incorporated under the Canada Business Corporations Act and its shares are listed on the Toronto (“TSX”) and New York (“NYSE”) stock exchanges. The executive and registered office is located at 2600, 500 Centre Street S.E., Calgary, Alberta, Canada, T2G 1A6. Information on the Company’s basis of preparation for these Consolidated Financial Statements is found in Note 2.

On May 17, 2017, Cenovus acquired from ConocoPhillips Company and certain of its subsidiaries (collectively, “ConocoPhillips”) a 50 percent interest in FCCL Partnership (“FCCL”) and the majority of ConocoPhillips’ western Canadian conventional crude oil and natural gas assets (the “Deep Basin Assets”). This acquisition (the “Acquisition”) increased Cenovus’s interest in FCCL to 100 percent and expanded Cenovus’s operating areas to include more than three million net acres of land, exploration and production assets and related infrastructure and agreements in Alberta and British Columbia. The Acquisition had an effective date of January 1, 2017 (see Note 5).

Management has determined the operating segments based on information regularly reviewed for the purposes of decision making, allocating resources and assessing operational performance by Cenovus’s chief operating decision makers. The Company evaluates the financial performance of its operating segments primarily based on operating margin. The Company’s reportable segments are:

Oil Sands, which includes the development and production of bitumen and natural gas in northeast Alberta. Cenovus’s bitumen assets include Foster Creek, Christina Lake and Narrows Lake as well as other projects in the early stages of development. The Company’s interest in certain of its operated oil sands properties, notably Foster Creek, Christina Lake and Narrows Lake, increased from 50 percent to 100 percent on May 17, 2017.

Deep Basin, which includes approximately three million net acres of land primarily in the Elmworth-Wapiti, Kaybob-Edson, and Clearwater operating areas, rich in natural gas and NGLs. The assets reside in Alberta and British Columbia and include interests in numerous natural gas processing facilities. The Deep Basin Assets were acquired on May 17, 2017.

Refining and Marketing, which is responsible for transporting, selling and refining crude oil into petroleum and chemical products. Cenovus jointly owns two refineries in the U.S. with the operator Phillips 66, an unrelated U.S. public company. In addition, Cenovus owns and operates a crude-by-rail terminal in Alberta. This segment coordinates Cenovus’s marketing and transportation initiatives to optimize product mix, delivery points, transportation commitments and customer diversification. The marketing of crude oil and natural gas sourced from Canada, including physical product sales that settle in the U.S., is considered to be undertaken by a Canadian business. U.S. sourced crude oil and natural gas purchases and sales are attributed to the U.S.

Corporate and Eliminations, which primarily includes unrealized gains and losses recorded on derivative financial instruments, gains and losses on divestiture of assets, as well as other Cenovus-wide costs for general and administrative, financing activities and research costs. As financial instruments are settled, the realized gains and losses are recorded in the reportable segment to which the derivative instrument relates. Eliminations relate to sales and operating revenues, and purchased product between segments, recorded at transfer prices based on current market prices, and to unrealized intersegment profits in inventory. The Corporate and Eliminations segment is attributed to Canada, with the exception of unrealized risk management gains and losses, which have been attributed to the country in which the transacting entity resides.

In 2017, Cenovus disposed of the majority of the crude oil and natural gas assets in the Company’s Conventional segment. As such, the results of operations have been classified as a discontinued operation (see Note 11). This segment included the production of conventional crude oil, NGLs and natural gas in Alberta and Saskatchewan, including the heavy oil assets at Pelican Lake, the CO₂ enhanced oil recovery project at Weyburn and emerging tight oil opportunities. As at December 31, 2017, all Conventional assets were sold, except for the Company’s Suffield operations. The sale of the Suffield assets closed on January 5, 2018.

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

A) Results of Operations – Segment and Operational Information

	Oil Sands				Deep Basin				Refining and Marketing
For the years ended December 31,	2017	2016	2015	2017		2016	2015	2017		2016	2015
Revenues
Gross Sales	7,362	2,929	3,030	555		-	-	9,852		8,439	8,805
Less: Royalties	230	9	29	41		-	-	-		-	-
	7,132	2,920	3,001	514		-	-	9,852		8,439	8,805
Expenses
Purchased Product	-	-	-	-		-	-	8,476		7,325	7,709
Transportation and Blending	3,704	1,721	1,815	56		-	-	-		-	-
Operating	934	501	531	250		-	-	772		742	754
Production and Mineral Taxes	-	-	-	1		-	-	-		-	-
(Gain) Loss on Risk Management	307	(179)	(404)	-		-	-	6		26	(43)
Operating Margin	2,187	877	1,059	207		-	-	598		346	385
Depreciation, Depletion and Amortization	1,230	655	697	331		-	-	215		211	191
Exploration Expense	888	2	67	-		-	-	-		-	-
Segment Income (Loss)	69	220	295	(124)		-	-	383		135	194

	Corporate and Eliminations			Consolidated
For the years ended December 31,	2017	2016	2015 (1)	2017	2016	2015
Revenues
Gross Sales	(455)	(353)	(276)	17,314	11,015	11,559
Less: Royalties	-	-	1	271	9	30
	(455)	(353)	(277)	17,043	11,006	11,529
Expenses
Purchased Product	(443)	(347)	(335)	8,033	6,978	7,374
Transportation and Blending	(12)	(6)	(1)	3,748	1,715	1,814
Operating	(7)	(4)	(4)	1,949	1,239	1,281
Production and Mineral Taxes	-	-	1	1	-	1
(Gain) Loss on Risk Management	583	554	195	896	401	(252)
Depreciation, Depletion and Amortization	62	65	105	1,838	931	993
Exploration Expense	-	-	-	888	2	67
Segment Income (Loss)	(638)	(615)	(238)	(310)	(260)	251
General and Administrative	308	326	335	308	326	335
Finance Costs	645	390	381	645	390	381
Interest Income	(62)	(52)	(28)	(62)	(52)	(28)
Foreign Exchange (Gain) Loss, Net	(812)	(198)	1,036	(812)	(198)	1,036
Revaluation (Gain)	(2,555)	-	-	(2,555)	-	-
Transaction Costs	56	-	-	56	-	-
Re-measurement of Contingent Payment	(138)	-	-	(138)	-	-
Research Costs	36	36	27	36	36	27
(Gain) Loss on Divestiture of Assets	1	6	(2,392)	1	6	(2,392)
Other (Income) Loss, Net	(5)	34	2	(5)	34	2
	(2,526)	542	(639)	(2,526)	542	(639)
Earnings (Loss) From Continuing Operations Before Income Tax				2,216	(802)	890
Income Tax Expense (Recovery)				(52)	(343)	(24)
Net Earnings (Loss) From Continuing Operations				2,268	(459)	914

(1) The complete results for the 2017 and 2016 Conventional segment have been classified as a discontinued operation. For the 2015 comparative period, the results of operations for certain Conventional segment royalty interest assets disposed of in 2015 have been included in the Corporate and Eliminations segment due to their immaterial nature. The results of operations are as follows: revenues – $60 million, expenses – $5 million, operating margin – $55 million, depreciation, depletion and amortization – $27 million and segment income – $28 million.

B) Revenues by Product

For the years ended December 31,	2017	2016	2015
Upstream
Crude Oil	7,184	2,902	2,971
Natural Gas (1)	235	16	22
NGLs	184	-	-
Other	43	2	8
Refining and Marketing	9,852	8,439	8,805
Corporate and Eliminations	(455)	(353)	(277)
Revenues From Continuing Operations	17,043	11,006	11,529

(1) In 2017, approximately 14 percent of the natural gas produced by Cenovus’s Deep Basin Assets was sold to ConocoPhillips resulting in gross sales of $32 million.

C) Geographical Information

	Revenues
For the years ended December 31,	2017	2016	2015
Canada	9,723	4,978	4,729
United States	7,320	6,028	6,800
Consolidated	17,043	11,006	11,529

	Non-Current Assets (1)
As at December 31,	2017	2016
Canada (2)	31,756	14,130
United States	3,856	4,179
Consolidated	35,612	18,309

(1) Includes exploration and evaluation (“E&E”) assets, property, plant and equipment (“PP&E”), goodwill and other assets.

(2) Certain crude oil and natural gas properties of the Conventional and Deep Basin segments, which reside in Canada, have been reclassified as held for sale in 2017 in current assets. 2016 includes $3.1 billion related to the Conventional segment.

Export Sales

Sales of crude oil, NGLs and natural gas produced or purchased in Canada that have been delivered to customers outside of Canada were $1,713 million (2016 – $974 million; 2015 – $870 million).

Major Customers

In connection with the marketing and sale of Cenovus’s own and purchased crude oil, NGLs, natural gas and refined products for the year ended December 31, 2017, Cenovus had two customers (2016 – three; 2015 – three) that individually accounted for more than 10 percent of its consolidated gross sales. Sales to these customers, recognized as major international energy companies with investment grade credit ratings, were approximately $5,655 million and $1,964 million, respectively (2016 – $4,742 million, $1,623 million and $1,400 million; 2015 – $4,647 million, $1,705 million and $1,545 million), which are included in all of the Company’s operating segments.

D) Exploration and Evaluation Assets, Property, Plant and Equipment, Goodwill and Total Assets

	E&E		PP&E		Goodwill		Total Assets
As at December 31,	2017	2016	2017	2016	2017	2016	2017	2016
Oil Sands	617	1,564	22,320	8,798	2,272	242	26,799	11,112
Deep Basin	3,056	-	3,019	-	-	-	6,694	-
Conventional	-	21	-	3,080	-	-	644	3,196
Refining and Marketing	-	-	3,967	4,273	-	-	5,432	6,613
Corporate and Eliminations	-	-	290	275	-	-	1,364	4,337
Consolidated	3,673	1,585	29,596	16,426	2,272	242	40,933	25,258

E) Capital Expenditures ⁽¹⁾

For the years ended December 31,	2017	2016	2015
Capital
Oil Sands	973	604	1,185
Deep Basin	225	-	-
Conventional	206	171	244
Refining and Marketing	180	220	248
Corporate	77	31	37
Capital Investment	1,661	1,026	1,714
Acquisition Capital
Oil Sands (2)	11,614	11	3
Deep Basin	6,774	-	-
Conventional	-	-	1
Refining and Marketing	-	-	83
Total Capital Expenditures	20,049	1,037	1,801

(1) Includes expenditures on PP&E, E&E assets and assets held for sale.

(2) In connection with the Acquisition discussed in Note 5, Cenovus was deemed to have disposed of its pre-existing interest in FCCL and re-acquired it at fair value as required by International Financial Reporting Standard 3, “Business Combinations” (“IFRS 3”), which is not reflected in the table above. The carrying value of the pre-existing interest was $9,081 million and the estimated fair value was $11,605 million as at May 17, 2017.

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Basis of Preparation and Statement of Compliance

12 Months Ended

Dec. 31, 2017

Basis Of Preparation And Statement Of Compliance [Abstract]

Basis of Preparation and Statement of Compliance

2. BASIS OF PREPARATION AND STATEMENT OF COMPLIANCE

In these Consolidated Financial Statements, unless otherwise indicated, all dollars are expressed in Canadian dollars. All references to C$ or $ are to Canadian dollars and references to US$ are to U.S. dollars.

These Consolidated Financial Statements have been prepared in accordance with International Financial Reporting Standards (“IFRS”) as issued by the International Accounting Standards Board (“IASB”) and interpretations of the International Financial Reporting Interpretations Committee (“IFRIC”). These Consolidated Financial Statements have been prepared in compliance with IFRS.

These Consolidated Financial Statements have been prepared on a historical cost basis, except as detailed in the Company’s accounting policies disclosed in Note 3.

These Consolidated Financial Statements were approved by the Board of Directors on February 14, 2018.

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Summary of Significant Accounting Policies

12 Months Ended

Dec. 31, 2017

Disclosure Of Summary Of Significant Accounting Policies [Abstract]

Summary of Significant Accounting Policies

3. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

A) Principles of Consolidation

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

Interests in joint arrangements are classified as either joint operations or joint ventures, depending on the rights and obligations of the parties to the arrangement. Joint operations arise when the Company has rights to the assets and obligations for the liabilities of the arrangement. The Company’s Refining activities are conducted through the joint operation WRB Refining LP (“WRB”) and, accordingly, the accounts reflect the Company’s share of the assets, liabilities, revenues and expenses. Prior to May 17, 2017, FCCL was accounted for as a joint operation. Subsequent to the Acquisition, Cenovus controls FCCL, and accordingly, FCCL has been consolidated.

B) Foreign Currency Translation

Functional and Presentation Currency

The Company’s presentation currency is Canadian dollars. The accounts of the Company’s foreign operations that have a functional currency different from the Company’s presentation currency are translated into the Company’s presentation currency at period-end exchange rates for assets and liabilities, and using average rates over the period for revenues and expenses. Translation gains and losses relating to the foreign operations are recognized in other comprehensive income (“OCI”) as cumulative translation adjustments.

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

Transactions and Balances

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

C) Revenue Recognition

Revenues associated with the sales of Cenovus’s crude oil, NGLs, natural gas, and petroleum and refined products are recognized when the significant risks and rewards of ownership have been transferred to the customer, the sales price and costs can be measured reliably and it is probable that the economic benefits will flow to the Company. This is generally met when title passes from the Company to its customer. Revenues from the production of crude oil, NGLs and natural gas represent the Company’s share, net of royalty payments to governments and other mineral interest owners.

Processing income and revenue from fee-for-service hydrocarbon trans-loading services is recognized in the period the service is provided.

Purchases and sales of products that are entered into in contemplation of each other with the same counterparty are recorded on a net basis. Revenues associated with the services provided as agent are recorded as the services are provided.

D) Transportation and Blending

The costs associated with the transportation of crude oil, NGLs and natural gas, including the cost of diluent used in blending, are recognized when the product is sold.

E) Exploration Expense

Costs incurred prior to obtaining the legal right to explore (pre-exploration costs) are expensed in the period in which they are incurred as exploration expense.

Costs incurred after the legal right to explore is obtained are initially capitalized. If it is determined that the field/project/area is not technically feasible and commercially viable or if the Company decides not to continue the exploration and evaluation activity, the unrecoverable accumulated costs are expensed as exploration expense.

F) Employee Benefit Plans

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

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

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

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

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

• Net interest is calculated by applying the same discount rate used to measure the defined benefit obligation at the beginning of the annual period to the net defined benefit asset or liability measured. Interest expense and interest income on net post-employment benefit liabilities and assets are recorded with pension benefit costs in operating, and general and administrative expenses, as well as PP&E and E&E assets.

• Remeasurements, composed of actuarial gains and losses, the effect of changes to the asset ceiling (excluding interest) and the return on plan assets (excluding interest income), are charged or credited to equity in OCI in the period in which they arise. Remeasurements are not reclassified to net earnings in subsequent periods.

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

G) Income Taxes

Income taxes comprise current and deferred taxes. Income taxes are provided for on a non-discounted basis at amounts expected to be paid using the tax rates and laws that have been enacted or substantively enacted at the Consolidated Balance Sheet date.

Cenovus follows the liability method of accounting for income taxes, where deferred income taxes are recorded for the effect of any temporary difference between the accounting and income tax basis of an asset or liability, using the substantively enacted income tax rates expected to apply when the assets are realized or liabilities are settled. Deferred income tax balances are adjusted to reflect changes in income tax rates that are substantively enacted with the adjustment being recognized in net earnings in the period that the change occurs, except when it relates to items charged or credited directly to equity or OCI, in which case the deferred income tax is also recorded in equity or OCI, respectively.

Deferred income tax is provided on temporary differences arising from investments in subsidiaries except in the case where the timing of the reversal of the temporary difference is controlled by the Company and it is probable that the temporary difference will not reverse in the foreseeable future or when distributions can be made without incurring income taxes.

Deferred income tax assets are recognized only to the extent that it is probable that future taxable profit will be available against which the temporary differences can be utilized. Deferred income tax assets and liabilities are only offset where they arise within the same entity and tax jurisdiction. Deferred income tax assets and liabilities are presented as non-current.

H) Net Earnings per Share Amounts

Basic net earnings per share is computed by dividing net earnings by the weighted average number of common shares outstanding during the period. Diluted net earnings per share is calculated giving effect to the potential dilution that would occur if stock options or other contracts to issue common shares were exercised or converted to common shares. The treasury stock method is used to determine the dilutive effect of stock options and other dilutive instruments. The treasury stock method assumes that proceeds received from the exercise of in-the-money stock options are used to repurchase common shares at the average market price. For those contracts that may be settled in cash or in shares at the holder’s option, the more dilutive of cash settlement and share settlement is used in calculating diluted earnings per share.

I) Cash and Cash Equivalents

Cash and cash equivalents include short-term investments, such as money market deposits or similar type instruments, with a maturity of three months or less.

J) Inventories

Product inventories are valued at the lower of cost and net realizable value on a first-in, first-out or weighted average cost basis. The cost of inventory includes all costs incurred in the normal course of business to bring each product to its present location and condition. Net realizable value is the estimated selling price in the ordinary course of business less any expected selling costs. If the carrying amount exceeds net realizable value, a write-down is recognized. The write-down may be reversed in a subsequent period if circumstances which caused it no longer exist and the inventory is still on hand.

K) Exploration and Evaluation Assets

Costs incurred after the legal right to explore an area has been obtained, and before technical feasibility and commercial viability of the field/project/area have been established, are capitalized as E&E assets. These costs include license acquisition, geological and geophysical, drilling, sampling, decommissioning and other directly attributable internal costs. E&E assets are not depreciated and are carried forward until technical feasibility and commercial viability of the field/project/area is established or the assets are determined to be impaired. E&E costs are subject to regular technical, commercial and Management review to confirm the continued intent to develop the resources.

Once technical feasibility and commercial viability have been established, the carrying value of the E&E asset is tested for impairment. The carrying value, net of any impairment loss, is then reclassified as PP&E.

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

L) Property, Plant and Equipment

General

PP&E is stated at cost less accumulated depreciation, depletion and amortization (“DD&A”), and net of any impairment losses. Expenditures related to renewals or betterments that improve the productive capacity or extend the life of an asset are capitalized. Maintenance and repairs are expensed as incurred. Land is not depreciated.

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

Development and Production Assets

Development and production assets are capitalized on an area-by-area basis and include all costs associated with the development and production of crude oil and natural gas properties, as well as any E&E expenditures incurred in finding reserves of crude oil, NGLs or natural gas transferred from E&E assets. Capitalized costs include directly attributable internal costs, decommissioning liabilities and, for qualifying assets, borrowing costs directly associated with the acquisition of, the exploration for, and the development of crude oil and natural gas reserves.

Costs accumulated within each area are depleted using the unit-of-production method based on estimated proved reserves determined using forward prices and costs. For the purpose of this calculation, natural gas is converted to crude oil on an energy equivalent basis. Costs subject to depletion include estimated future costs to be incurred in developing proved reserves.

Exchanges of development and production assets are measured at fair value unless the transaction lacks commercial substance or the fair value of neither the asset received, nor the asset given up, can be reliably measured. When fair value is not used, the carrying amount of the asset given up is used as the cost of the asset acquired.

Other Upstream Assets

Other upstream assets include information technology assets used to support the upstream business. These assets are depreciated on a straight-line basis over their useful lives of three years.

Refining Assets

The initial acquisition costs of refining PP&E are capitalized when incurred. Costs include the cost of constructing or otherwise acquiring the equipment or facilities, the cost of installing the asset and making it ready for its intended use, the associated decommissioning costs and, for qualifying assets, borrowing costs.

Refining assets are depreciated on a straight-line basis over the estimated service life of each component of the refinery. The major components are depreciated as follows:

Land improvements and buildings	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.

Other Assets

Costs associated with the crude-by-rail terminal, office furniture, fixtures, leasehold improvements, information technology and aircraft are carried at cost and depreciated on a straight-line basis over the estimated service lives of the assets, which range from three to 40 years.

The residual value, method of amortization and the useful lives of the assets are reviewed annually and adjusted on a prospective basis, if appropriate.

M) Impairment

Non-Financial Assets

PP&E and E&E assets are reviewed separately for indicators of impairment quarterly or when facts and circumstances suggest that the carrying amount may exceed its recoverable amount. Goodwill is tested for impairment at least annually.

If indicators of impairment exist, the recoverable amount of the cash-generating unit (“CGU”) is estimated as the greater of value-in-use (“VIU”) and fair value less costs of disposal (“FVLCOD”). VIU is estimated as the present value of the future cash flows expected to arise from the continuing use of a CGU or an asset. FVLCOD is determined by estimating the discounted after-tax future net cash flows. For Cenovus’s upstream assets, FVLCOD is based on the discounted after-tax cash flows of reserves and resources using forward prices and costs, consistent with Cenovus’s independent qualified reserves evaluators (“IQREs”), and may consider an evaluation of comparable asset transactions.

E&E assets are allocated to a related CGU containing development and production assets for the purposes of testing for impairment. Goodwill is allocated to the CGUs to which it contributes to the future cash flows.

If the recoverable amount of the CGU is less than the carrying amount, an impairment loss is recognized. An impairment loss is allocated first to reduce the carrying amount of any goodwill allocated to the CGU and then to reduce the carrying amounts of the other assets in the CGU. Goodwill impairments are not reversed.

Impairment losses on PP&E and E&E assets are recognized in the Consolidated Statements of Earnings as additional DD&A and exploration expense, respectively.

Impairment losses recognized in prior periods, other than goodwill impairments, are assessed at each reporting date for any indicators that the impairment losses may no longer exist or may have decreased. In the event that an impairment loss reverses, the carrying amount of the asset is increased to the revised estimate of its recoverable amount, but only to the extent that the carrying amount does not exceed the amount that would have been determined had no impairment loss been recognized on the asset in prior periods. The amount of the reversal is recognized in net earnings.

Financial Assets

At each reporting date, the Company assesses whether there are any indicators that its financial assets are impaired. An impairment loss is only recognized if there is objective evidence of impairment, the loss event has an impact on future cash flows and the loss can be reliably estimated.

Evidence of impairment may include default or delinquency by a debtor or indicators that the debtor may enter bankruptcy. For equity securities, a significant or prolonged decline in the fair value of the security below cost is evidence that the assets are impaired.

An impairment loss on a financial asset carried at amortized cost is calculated as the difference between the amortized cost and the present value of the future cash flows discounted at the asset’s original effective interest rate. The carrying amount of the asset is reduced through the use of an allowance account. Impairment losses on financial assets carried at amortized cost are reversed through net earnings in subsequent periods if the amount of the loss decreases.

N) Leases

Leases in which substantially all of the risks and rewards of ownership are retained by the lessor are classified as operating leases. Operating lease payments are recognized as an expense on a straight-line basis over the lease term.

Leases where the Company assumes substantially all the risks and rewards of ownership are classified as finance leases. At inception, a leased asset within PP&E and a corresponding lease obligation are recognized. The leased asset is depreciated over the shorter of the estimated useful life of the asset or the lease term.

O) Business Combinations and Goodwill

Business combinations are accounted for using the acquisition method of accounting in which the identifiable assets acquired, liabilities assumed and non-controlling interest, if any, are recognized and measured at their fair value at the date of acquisition. Any excess of the purchase price plus any non-controlling interest over the fair value of the net assets acquired is recognized as goodwill. Any deficiency of the purchase price over the fair value of the net assets acquired is credited to net earnings.

At acquisition, goodwill is allocated to each of the CGUs to which it relates. Subsequent measurement of goodwill is at cost less any accumulated impairment losses.

Contingent consideration transferred in a business combination is measured at fair value on the date of acquisition and classified as a financial liability or equity. Contingent consideration classified as a liability is re-measured at fair value at each reporting date, with changes in fair value recognized in net earnings. Payments are classified as cash used in investing activities until the cumulative payments exceed the acquisition date fair value of the liability. Cumulative payments in excess of the acquisition date fair value are classified as cash used in operating activities. Contingent consideration classified as equity are not re-measured and settlements are accounted for within equity.

When a business combination is achieved in stages, the Company re-measures its pre-existing interest at the acquisition date fair value and recognizes the resulting gain or loss, if any, in net earnings.

P) Provisions

General

A provision is recognized if, as a result of a past event, the Company has a present obligation, legal or constructive, that can be estimated reliably, and it is more likely than not that an outflow of economic benefits will be required to settle the obligation. Where applicable, provisions are determined by discounting the expected future cash flows at a pre-tax credit-adjusted rate that reflects the current market assessments of the time value of money and the risks specific to the liability. The increase in the provision due to the passage of time is recognized as a finance cost in the Consolidated Statements of Earnings.

Decommissioning Liabilities

Decommissioning liabilities include those legal or constructive obligations where the Company will be required to retire tangible long-lived assets such as producing well sites, upstream processing facilities, refining facilities and the crude-by-rail terminal. The amount recognized is the present value of estimated future expenditures required to settle the obligation using a credit-adjusted risk-free rate. A corresponding asset equal to the initial estimate of the liability is capitalized as part of the cost of the related long-lived asset. Changes in the estimated liability resulting from revisions to expected timing or future decommissioning costs are recognized as a change in the decommissioning liability and the related long-lived asset. The amount capitalized in PP&E is depreciated over the useful life of the related asset.

Actual expenditures incurred are charged against the accumulated liability.

Q) Share Capital

Common shares are classified as equity. Transaction costs directly attributable to the issue of common shares are recognized as a deduction from equity, net of any income taxes.

R) Stock-Based Compensation

Cenovus has a number of stock-based compensation plans which include stock options with associated net settlement rights (“NSRs”), stock options with associated tandem stock appreciation rights (“TSARs”), performance share units (“PSUs”), restricted share units (“RSUs”) and deferred share units (“DSUs”). Stock-based compensation costs are recorded in general and administrative expense, or E&E and PP&E when directly related to exploration or development activities.

Net Settlement Rights

NSRs are accounted for as equity instruments, which are measured at fair value on the grant date using the Black-Scholes-Merton valuation model and are not revalued at each reporting date. The fair value is recognized as stock-based compensation costs over the vesting period, with a corresponding increase recorded as paid in surplus in Shareholders’ Equity. On exercise, the cash consideration received by the Company and the associated paid in surplus are recorded as share capital.

Tandem Stock Appreciation Rights

TSARs are accounted for as liability instruments, which are measured at fair value at each period end using the Black-Scholes-Merton valuation model. The fair value is recognized as stock-based compensation costs over the vesting period. When options are settled for cash, the liability is reduced by the cash settlement paid. When options are settled for common shares, the cash consideration received by the Company and the previously recorded liability associated with the option are recorded as share capital.

Performance, Restricted and Deferred Share Units

PSUs, RSUs and DSUs are accounted for as liability instruments and are measured at fair value based on the market value of Cenovus’s common shares at each period end. The fair value is recognized as stock-based compensation costs over the vesting period. Fluctuations in the fair values are recognized as stock-based compensation costs in the period they occur.

S) Financial Instruments

The Company’s financial assets include cash and cash equivalents, accounts receivable and accrued revenues, risk management assets, investments in the equity of private companies and long-term receivables. The Company’s financial liabilities include accounts payable and accrued liabilities, contingent payment, risk management liabilities, short-term borrowings and long-term debt.

Financial instruments are recognized when the Company becomes a party to the contractual provisions of the instrument. Financial assets and liabilities are not offset unless the Company has the current legal right to offset and intends to settle on a net basis or settle the asset and liability simultaneously. A financial asset is derecognized when the rights to receive cash flows from the asset have expired or have been transferred and the Company has transferred substantially all the risks and rewards of ownership. A financial liability is derecognized when the obligation is discharged, cancelled or expired. When an existing financial liability is replaced by another from the same counterparty with substantially different terms, or the terms of an existing liability are substantially modified, this exchange or modification is treated as a derecognition of the original liability and the recognition of a new liability. The difference in the carrying amounts of the liabilities is recognized in the Consolidated Statements of Earnings.

Financial instruments are classified as either “fair value through profit and loss”, “loans and receivables”, “held-to-maturity investments”, “available for sale financial assets” or “financial liabilities measured at amortized cost”. The Company determines the classification of its financial instruments at initial recognition. Financial instruments are initially measured at fair value except in the case of “financial liabilities measured at amortized cost”, which are initially measured at fair value net of directly attributable transaction costs.

As required by IFRS, the Company characterizes its fair value measurements into a three-level hierarchy depending on the degree to which the inputs are observable, as follows:

• Level 1 inputs are quoted prices in active markets for identical assets and liabilities;

• Level 2 inputs are inputs, other than quoted prices included within Level 1, that are observable for the asset or liability either directly or indirectly; and

• Level 3 inputs are unobservable inputs for the asset or liability.

Fair Value Through Profit or Loss

Financial assets and financial liabilities at “fair value through profit or loss” are either “held-for-trading” or have been “designated at fair value through profit or loss.” In both cases, the financial assets and financial liabilities are measured at fair value with changes in fair value recognized in net earnings.

Risk management assets and liabilities are derivative financial instruments classified as “held-for-trading” unless designated for hedge accounting. Derivative instruments that do not qualify as hedges, or are not designated as hedges, are recorded using mark-to-market accounting whereby instruments are recorded in the Consolidated Balance Sheets as either an asset or liability with changes in fair value recognized in net earnings as a (gain) loss on risk management. Derivative financial instruments are not used for speculative purposes.

The Company has classified its contingent payment as “fair value through profit or loss.”

Loans and Receivables

“Loans and receivables” are financial assets with fixed or determinable payments that are not quoted in an active market. After initial measurement, these assets are measured at amortized cost at the settlement date using the effective interest method of amortization. “Loans and receivables” comprise cash and cash equivalents, accounts receivable and accrued revenues, and long-term receivables. Gains and losses on “loans and receivables” are recognized in net earnings when the “loans and receivables” are derecognized or impaired.

Available for Sale Financial Assets

“Available for sale financial assets” are measured at fair value, with changes in fair value recognized in OCI. When an active market is non-existent, fair value is determined using valuation techniques. When fair value cannot be reliably measured, such assets are carried at cost. Available for sale financial assets comprise investments in the equity of private companies that the Company does not control or have significant influence over.

Financial Liabilities Measured at Amortized Cost

These financial liabilities are measured at amortized cost at the settlement date using the effective interest method of amortization. Financial liabilities measured at amortized cost comprise accounts payable and accrued liabilities, short-term borrowings and long-term debt. Long-term debt transaction costs, premiums and discounts are capitalized within long-term debt or as a prepayment and amortized using the effective interest method.

T) Reclassification

Certain information provided for prior years has been reclassified to conform to the presentation adopted in 2017.

U) Recent Accounting Pronouncements

New Accounting Standards and Interpretations not yet Adopted

A number of new accounting standards, amendments to accounting standards and interpretations are effective for annual periods beginning on or after January 1, 2018 and have not been applied in preparing the Consolidated Financial Statements for the year ended December 31, 2017. The standards applicable to Cenovus are as follows and will be adopted on their respective effective dates:

Financial Instruments

On July 24, 2014, the IASB issued the final version of IFRS 9, “Financial Instruments” (“IFRS 9”) to replace IAS 39, “Financial Instruments: Recognition and Measurement” (“IAS 39”).

IFRS 9 introduces a single approach to determine whether a financial asset is measured at amortized cost or fair value and replaces the multiple rules in IAS 39. The approach is based on how an entity manages its financial instruments in the context of its business model and the contractual cash flow characteristics of the financial assets. The IAS 39 measurement categories for financial assets will be replaced by fair value through profit or loss, fair value through other comprehensive income (“FVOCI”) and amortized cost. The standard eliminates the existing IAS 39 categories of held to maturity, loans and receivables and available for sale. Based on Management’s assessment, the change in categories will not have a material impact on the Consolidated Financial Statements. As at December 31, 2017, the Company has private equity investments classified as available for sale with a fair value of $37 million. Under IFRS 9, the Company has elected to measure these investments as FVOCI. As such, all fair value gains or losses will be recorded in OCI, impairments will not be recognized in net earnings and fair value gains or losses will not be recycled to net earnings on disposition.

IFRS 9 retains most of the IAS 39 requirements for financial liabilities. However, where the fair value option is applied to financial liabilities, the change in fair value resulting from an entity’s own credit risk is recorded in OCI rather than net earnings, unless this creates an accounting mismatch. Cenovus currently does not designate any financial liabilities as fair value through profit or loss; therefore, there will be no impact on the accounting for financial liabilities.

A new expected credit loss model for calculating impairment on financial assets replaces the incurred loss impairment model used in IAS 39. The new model will result in more timely recognition of expected credit losses. Management does not expect a material change to its impairment provision as at January 1, 2018.

In addition, IFRS 9 includes a simplified hedge accounting model, aligning hedge accounting more closely with risk management. Cenovus does not currently apply hedge accounting.

IFRS 9 must be adopted for years beginning on or after January 1, 2018. The Company will apply the new standard retrospectively and elect to use the practical expedients permitted under the standard. Comparative periods will not be restated.

Revenue Recognition

On May 28, 2014, the IASB issued IFRS 15, “Revenue From Contracts With Customers” (“IFRS 15”) replacing IAS 11, “Construction Contracts”, IAS 18, “Revenue” and several revenue-related interpretations. IFRS 15 establishes a single revenue recognition framework that applies to contracts with customers. The standard requires an entity to recognize revenue to reflect the transfer of goods and services for the amount it expects to receive, when control is transferred to the purchaser. Disclosure requirements have also been expanded.

Management has assessed the impact of applying the new standard on the Consolidated Financial Statements and has not identified any material differences from its current revenue recognition practice.

The adoption of IFRS 15 is mandatory for years beginning on or after January 1, 2018. The standard may be applied either retrospectively or using a modified retrospective approach. Cenovus intends to adopt the standard using the modified retrospective approach recognizing the cumulative impact of adoption in retained earnings as of January 1, 2018. Comparative periods will not be restated. The Company will apply IFRS 15 using the practical expedient in paragraph C5(a) of IFRS 15, under which the Company will not restate contracts that are completed contracts as at the date of adoption.

Leases

On January 13, 2016, the IASB issued IFRS 16, “Leases” (“IFRS 16”), which requires entities to recognize lease assets and lease obligations on the balance sheet. For lessees, IFRS 16 removes the classification of leases as either operating leases or finance leases, effectively treating all leases as finance leases. Certain short-term leases (less than 12 months) and leases of low-value assets are exempt from the requirements, and may continue to be treated as operating leases.

Lessors will continue with a dual lease classification model. Classification will determine how and when a lessor will recognize lease revenue, and what assets would be recorded.

IFRS 16 is effective for years beginning on or after January 1, 2019, with early adoption permitted if IFRS 15 has been adopted. The standard may be applied retrospectively or using a modified retrospective approach. The modified retrospective approach does not require restatement of prior period financial information as it recognizes the cumulative effect of applying the standard to prior periods as an adjustment to opening retained earnings. It is anticipated that the adoption of IFRS 16 will have a material impact on the Company’s Consolidated Balance Sheets due to material operating lease commitments. Cenovus will adopt IFRS 16 effective January 1, 2019. The Company intends to adopt the standard using the retrospective with cumulative effect approach and apply several of the practical expedients available.

Uncertain Tax Positions

In June 2017, the IASB issued International Financial Reporting Interpretation Committee 23, “Uncertainty Over Income Tax Treatments” (“IFRIC 23”). The interpretation provides clarity on how to account for a tax position when there is uncertainty over income tax treatments. In determining the likely resolution of the uncertain tax positions, a position may be considered separately or as a group. In addition, an assessment is required to determine the probability that the tax authority will accept the tax position taken in income tax filings. If the uncertain income tax treatment is unlikely to be accepted, the accounting tax position must reflect an appropriate level of uncertainty. An uncertain tax position may be reassessed if new information changes the original assessment. IFRIC 23 is effective for annual periods beginning on or after January 1, 2019 using either a modified or full retrospective approach. IFRIC 23 is not expected to have a significant impact on the Consolidated Financial Statements.

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Critical Accounting Judgments and Key Sources of Estimation Uncertainty

12 Months Ended

Dec. 31, 2017

Disclosure Of Accounting Judgements And Estimates [Abstract]

Critical Accounting Judgments and Key Sources of Estimation Uncertainty

4. CRITICAL ACCOUNTING JUDGMENTS AND KEY SOURCES OF ESTIMATION UNCERTAINTY

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

A) Critical Judgments in Applying Accounting Policies

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

Joint Arrangements

The classification of a joint arrangement as either a joint operation or a joint venture requires judgment. Cenovus holds a 50 percent interest in WRB, a jointly controlled entity. It was determined that Cenovus has the rights to the assets and obligations for the liabilities of WRB. As a result, the joint arrangement is classified as a joint operation and the Company’s share of the assets, liabilities, revenues and expenses are recorded in the Consolidated Financial Statements.

Prior to May 17, 2017, Cenovus held a 50 percent interest in FCCL, which was jointly controlled with ConocoPhillips and met the definition of a joint operation under IFRS 11, “Joint Arrangements”. As such, Cenovus recognized its share of the assets, liabilities, revenues and expenses in its consolidated results. Subsequent to the Acquisition, Cenovus controls FCCL, as defined under IFRS 10, “Consolidated Financial Statements” (“IFRS 10”) and, accordingly, FCCL has been consolidated.

In determining the classification of its joint arrangements under IFRS 11, the Company considered the following:

• The intention of the transaction creating FCCL and WRB was to form an integrated North American heavy oil business. The integrated business was structured, initially on a tax neutral basis, through two partnerships due to the assets residing in different tax jurisdictions. Partnerships are “flow-through” entities which have a limited life.

• The partnership agreements require the partners (Cenovus and ConocoPhillips or Phillips 66 or respective subsidiaries) to make contributions if funds are insufficient to meet the obligations or liabilities of the partnerships. The past and future development of FCCL and WRB is dependent on funding from the partners by way of partnership notes payable and loans. The partnerships do not have any third-party borrowings.

• FCCL operated like most typical western Canadian working interest relationships where the operating partner takes product on behalf of the participants. WRB has a very similar structure modified only to account for the operating environment of the refining business.

• Cenovus and Phillips 66, as operators, either directly or through wholly-owned subsidiaries, provide marketing services, purchase necessary feedstock, and arrange for transportation and storage on the partners’ behalf as the agreements prohibit the partnerships from undertaking these roles themselves. In addition, the partnerships do not have employees and, as such, are not capable of performing these roles.

• In each arrangement, output is taken by one of the partners, indicating that the partners have rights to the economic benefits of the assets and the obligation for funding the liabilities of the arrangements.

Exploration and Evaluation Assets

The application of the Company’s accounting policy for E&E expenditures requires judgment in determining whether it is likely that future economic benefit exists when activities have not reached a stage where technical feasibility and commercial viability can be reasonably determined. Factors such as drilling results, future capital programs, future operating expenses, as well as estimated reserves and resources are considered. In addition, Management uses judgment to determine when E&E assets are reclassified to PP&E. In making this determination, various factors are considered, including the existence of reserves, and whether the appropriate approvals have been received from regulatory bodies and the Company’s internal approval process.

Identification of Cash-Generating Units

CGUs are defined as the lowest level of integrated assets for which there are separately identifiable cash flows that are largely independent of cash flows from other assets or groups of assets. The classification of assets and allocation of corporate assets into CGUs requires significant judgment and interpretation. Factors considered in the classification include the integration between assets, shared infrastructures, the existence of common sales points, geography, geologic structure, and the manner in which Management monitors and makes decisions about its operations. The recoverability of the Company’s upstream, refining, crude-by-rail and corporate assets are assessed at the CGU level. As such, the determination of a CGU could have a significant impact on impairment losses and reversals.

B) Key Sources of Estimation Uncertainty

Critical accounting estimates are those estimates that require Management to make particularly subjective or complex judgments about matters that are inherently uncertain. Estimates and underlying assumptions are reviewed on an ongoing basis and any revisions to accounting estimates are recorded in the period in which the estimates are revised. The following are the key assumptions about the future and other key sources of estimation at the end of the reporting period that changes to could result in a material adjustment to the carrying amount of assets and liabilities within the next financial year.

Crude Oil and Natural Gas Reserves

There are a number of inherent uncertainties associated with estimating crude oil and natural gas reserves. Reserves estimates are dependent upon variables including the recoverable quantities of hydrocarbons, the cost of the development of the required infrastructure to recover the hydrocarbons, production costs, estimated selling price of the hydrocarbons produced, royalty payments and taxes. Changes in these variables could significantly impact the reserves estimates which would affect the impairment test fair value less costs to sell and DD&A expense of the Company’s crude oil and natural gas assets in the Oil Sands and Deep Basin segments. The Company’s reserves are evaluated annually and reported to the Company by its IQREs.

Recoverable Amounts

Determining the recoverable amount of a CGU or an individual asset requires the use of estimates and assumptions, which are subject to change as new information becomes available. For the Company’s upstream assets, these estimates include forward commodity prices, expected production volumes, quantity of reserves and resources, discount rates, future development and operating expenses, and income tax rates. Recoverable amounts for the Company’s refining assets and crude-by-rail terminal use assumptions such as throughput, forward commodity prices, operating expenses, transportation capacity, supply and demand conditions and income tax rates. Changes in assumptions used in determining the recoverable amount could affect the carrying value of the related assets.

Decommissioning Costs

Provisions are recorded for the future decommissioning and restoration of the Company’s upstream assets, refining assets and crude-by-rail terminal at the end of their economic lives. Management uses judgment to assess the existence and to estimate the future liability. The actual cost of decommissioning and restoration is uncertain and cost estimates may change in response to numerous factors including changes in legal requirements, technological advances, inflation and the timing of expected decommissioning and restoration. In addition, Management determines the appropriate discount rate at the end of each reporting period. This discount rate, which is credit-adjusted, is used to determine the present value of the estimated future cash outflows required to settle the obligation and may change in response to numerous market factors.

Fair Value of Assets Acquired and Liabilities Assumed in a Business Combination

The fair value of assets acquired and liabilities assumed in a business combination, including contingent consideration and goodwill, is estimated based on information available at the date of acquisition. Various valuation techniques are applied for measuring fair value including market comparables and discounted cash flows which rely on assumptions such as forward commodity prices, reserves and resources estimates, production costs, volatility, Canadian-U.S. foreign exchange rates and discount rates. Changes in these variables could significantly impact the carrying value of the net assets.

Income Tax Provisions

Tax regulations and legislation and the interpretations thereof in the various jurisdictions in which Cenovus operates are subject to change. There are usually a number of tax matters under review; therefore, income taxes are subject to measurement uncertainty.

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

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Acquisition

12 Months Ended

Dec. 31, 2017

Disclosure Of Business Combinations [Abstract]

Acquisition

5. ACQUISITION

FCCL and Deep Basin Acquisition

A) Summary of the Acquisition

On May 17, 2017, Cenovus acquired ConocoPhillips’ 50 percent interest in FCCL and the majority of ConocoPhillips’ Deep Basin Assets in Alberta and British Columbia (the “Acquisition”). The Acquisition provides Cenovus with control over the Company’s oil sands operations, doubles the Company’s oil sands production, and almost doubles the Company’s proved bitumen reserves. The Deep Basin Assets provide a second core operating area with more than three million net acres of land, exploration and production assets, and related infrastructure in Alberta and British Columbia.

The Acquisition has been accounted for using the acquisition method pursuant to IFRS 3. Under the acquisition method, assets and liabilities are recorded at their fair values on the date of acquisition and the total consideration is allocated to the tangible and intangible assets acquired and liabilities assumed. The excess of consideration given over the fair value of the net assets acquired has been recorded as goodwill.

B) Identifiable Assets Acquired and Liabilities Assumed

The final purchase price allocation is based on Management’s best estimate of fair value and has been retrospectively adjusted to reflect new information obtained between May 17, 2017 and December 31, 2017 about conditions that existed at the acquisition date. As a result of these adjustments, the final purchase price allocation includes an increase of $912 million to PP&E, $56 million to inventory, and $16 million to accounts receivable and accrued revenues, as well as an $822 million decrease to E&E assets. Goodwill from the Acquisition was reduced to $2,030 million and the revaluation gain increased to $2,555 million. These adjustments also resulted in a $9 million increase to the deferred income tax liability.

The following table summarizes the recognized amounts of assets acquired and liabilities assumed at the date of the Acquisition.

	Notes
100 Percent of the Identifiable Assets Acquired and Liabilities Assumed for FCCL
Cash		880
Accounts Receivable and Accrued Revenues		964
Inventories		345
E&E Assets	17	491
PP&E	18	22,717
Other Assets		27
Accounts Payable and Accrued Liabilities		(445)
Decommissioning Liabilities	24	(277)
Other Liabilities		(8)
Deferred Income Taxes		(2,506)
		22,188
Recognized Amounts of Identifiable Assets Acquired and Liabilities Assumed for Deep Basin
Accounts Receivable and Accrued Revenues		16
Inventories		14
E&E Assets	17	3,117
PP&E	18	3,600
Accounts Payable and Accrued Liabilities		(6)
Decommissioning Liabilities	24	(667)
		6,074
Total Identifiable Net Assets		28,262

The fair value of acquired accounts receivables and accrued revenues was $980 million. As at December 31, 2017, $964 million has been received and the remainder is expected to be collected.

C) Total Consideration

Total consideration for the Acquisition consisted of US$10.6 billion in cash and 208 million Cenovus common shares plus closing adjustments. At the same time, Cenovus agreed to make certain quarterly contingent payments to ConocoPhillips during the five years subsequent to May 17, 2017 if crude oil prices exceed a specific threshold. The following table summarizes the fair value of the consideration:

Common Shares	2,579
Cash	15,005
	17,584
Estimated Contingent Payment (Note 22)	361
Total Consideration	17,945

At the date of closing, the Company issued 208 million common shares to ConocoPhillips that were accounted for at $12.40 per share, the estimated fair value for accounting purposes.

Consideration paid in cash was US$10.6 billion, before closing adjustments, and was financed through a bought-deal common share offering (see Note 27) and an offering in the United States for senior unsecured notes (see Note 23). In addition, Cenovus borrowed $3.6 billion under a committed asset sale bridge credit facility (see Note 23). The remainder of the cash purchase price was funded with cash on hand and a draw on Cenovus’s existing committed credit facility.

The estimated contingent payment related to oil sands production reflects that Cenovus agreed to make quarterly payments to ConocoPhillips during the five years subsequent to the closing date for quarters in which the average Western Canadian Select (“WCS”) crude oil price exceeds $52.00 per barrel during the quarter. The quarterly payment will be $6 million for each dollar that the WCS price exceeds $52.00 per barrel. There are no maximum payment terms.

The calculation of any contingent payment includes an adjustment mechanism related to certain significant production outages at Foster Creek and Christina Lake, which may reduce the amount of a contingent payment. The terms of the contingent payment agreement allow Cenovus to retain 80 percent to 85 percent of the WCS prices above $52.00 per barrel, based on gross production capacity at Foster Creek and Christina Lake at the time of the Acquisition. As production capacity increases with future expansions, the percentage of upside available to Cenovus will increase further.

The contingent payment is accounted for as a financial option. The fair value of $361 million on May 17, 2017 was estimated by calculating the present value of the future expected cash flows using an option pricing model, which assumes the probability distribution for WCS is based on the volatility of West Texas Intermediate (“WTI”) options, volatility of Canadian-U.S. foreign exchange rate options and WCS futures pricing, and discounted at a credit-adjusted risk-free rate of 2.9 percent. The contingent payment will be re-measured at fair value at each reporting date with changes in fair value recognized in net earnings (see Note 22).

D) Goodwill

Goodwill arising from the Acquisition has been recognized as follows:

	Notes
Total Purchase Consideration	4C	17,945
Fair Value of Pre-Existing 50 Percent Ownership Interest in FCCL		12,347
Fair Value of Identifiable Net Assets	4B	(28,262)
Goodwill		2,030

Fair Value of Pre-Existing 50 Percent Ownership Interest in FCCL

Prior to the Acquisition, Cenovus’s 50 percent interest in FCCL was jointly controlled with ConocoPhillips and met the definition of a joint operation under IFRS 11 and as such Cenovus recognized its share of the assets, liabilities, revenues and expenses in its consolidated results. Subsequent to the Acquisition, Cenovus controls FCCL, as defined under IFRS 10 and, accordingly, FCCL has been consolidated from the date of acquisition. As required by IFRS 3, when an acquirer achieves control in stages, the previously held interest is re-measured to fair value at the acquisition date with any gain or loss recognized in net earnings. The acquisition-date fair value of the previously held interest was $12.3 billion and has been included in the measurement of the total consideration transferred. The carrying value of the FCCL assets was $9.7 billion. As a result, Cenovus recognized a non-cash revaluation gain of $2.6 billion ($1.9 billion, after-tax) on the re-measurement to fair value of its existing interest in FCCL.

Goodwill was recorded in connection with deferred tax liabilities arising from the difference between the purchase price allocated to the FCCL assets and liabilities based on fair value and the tax basis of these assets and liabilities. In addition, the consideration paid for FCCL included a control premium, which resulted in a higher value compared to the fair value of the net assets acquired.

E) Acquisition-Related Costs

The Company incurred $56 million of Acquisition-related costs, excluding common share and debt issuance costs. These costs have been included in transaction costs in the Consolidated Statements of Earnings.

Debt issuance costs related to the Acquisition financing were $72 million. These costs are netted against the carrying amount of the debt and amortized using the effective interest method.

F) Transitional Services

Under the purchase and sales agreement, Cenovus and ConocoPhillips agreed to certain transitional services where ConocoPhillips provided certain day-to-day services required by Cenovus for a period of approximately nine months. These transactions were in the normal course of operations and have been measured at the exchange amounts.

Costs related to the transitional services of approximately $40 million were recorded in general and administrative expenses.

G) Revenue and Profit Contribution

The acquired business contributed revenues of $3.3 billion and net earnings of $172 million for the period from May 17, 2017 to December 31, 2017.

If the closing of the Acquisition had occurred on January 1, 2017, Cenovus’s consolidated pro forma revenue and net earnings for the twelve months ended December 31, 2017 would have been $19.0 billion and $3.5 billion, respectively. These amounts have been calculated using results from the acquired business and adjusting them for:

Differences in accounting policies;

• Additional finance costs that would have been incurred if the amounts drawn on the Company’s committed asset sale bridge credit facility and the senior unsecured notes issued to fund the Acquisition had occurred on January 1, 2017;

• Additional DD&A that would have been charged assuming the fair value adjustments to PP&E and E&E assets had applied from January 1, 2017;

• Accretion on the decommissioning liability if it had been assumed on January 1, 2017; and

• The consequential tax effects.

This pro forma information is not necessarily indicative of the results that would have been obtained if the Acquisition had actually occurred on January 1, 2017.

Crude-by-Rail Terminal Acquisition

In August 2015, the Company completed the acquisition of a crude-by-rail terminal for cash consideration of $75 million, plus adjustments. The transaction was accounted for using the acquisition method of accounting. In connection with the acquisition, the Company assumed an associated decommissioning liability of $4 million, working capital of $1 million and net transportation commitments of $92 million. Transaction costs associated with the acquisition were expensed. These assets, related liabilities and results of operations are reported in the Refining and Marketing segment.

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Finance Costs

12 Months Ended

Dec. 31, 2017

Finance Costs [Abstract]

Finance Costs

6. FINANCE COSTS

For the years ended December 31,	2017	2016	2015
Interest Expense – Short-Term Borrowings and Long-Term Debt	571	341	328
Unwinding of Discount on Decommissioning Liabilities (Note 24)	48	28	25
Other	26	21	28
	645	390	381

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Foreign Exchange (Gain) Loss, Net

12 Months Ended

Dec. 31, 2017

Foreign Exchange Gains Losses [Abstract]

Foreign Exchange (Gain) Loss, Net

7. FOREIGN EXCHANGE (GAIN) LOSS, NET

For the years ended December 31,	2017	2016	2015
Unrealized Foreign Exchange (Gain) Loss on Translation of:
U.S. Dollar Debt Issued From Canada	(665)	(196)	1,064
Other	(192)	7	33
Unrealized Foreign Exchange (Gain) Loss	(857)	(189)	1,097
Realized Foreign Exchange (Gain) Loss	45	(9)	(61)
	(812)	(198)	1,036

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Divestitures

12 Months Ended

Dec. 31, 2017

Gains Losses On Disposals Of Noncurrent Assets [Abstract]

Divestitures

8. DIVESTITURES

In 2017, the Company completed the sale of the majority of its Conventional segment crude oil and natural gas properties for gross proceeds of $3.2 billion. A net gain of $1.3 billion was recorded on the divestitures. For further information see Note 11.

In 2016, the Company completed the sale of land to an unrelated third party for cash proceeds of $8 million, resulting in a loss of $5 million. The Company also sold equipment at a loss of $1 million. These assets, related liabilities and results of operations were reported in the Conventional segment.

In 2015, the Company completed the sale of Heritage Royalty Limited Partnership (“HRP”), a wholly-owned subsidiary, to a third party for gross cash proceeds of $3.3 billion, resulting in a gain of $2.4 billion. HRP was a royalty business consisting of royalty interest and mineral fee title lands in Alberta, Saskatchewan and Manitoba. These assets, related liabilities and results of operations were reported in the Conventional segment. In 2017, the remaining Conventional segment was classified as a discontinued operation.

The divestiture of HRP gave rise to a taxable gain for which the Company recognized a current tax expense of $391 million. The majority of HRP’s assets had been acquired at a nominal cost and, as such, had minimal benefit from tax depreciation in prior years. For this reason, the current tax expense associated with the divestiture was specifically identifiable; therefore, it was classified as an investing activity in the Consolidated Statements of Cash Flows.

In addition, the Company divested of an office building in 2015, recording a gain of $16 million.

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Other (Income) Loss, Net

12 Months Ended

Dec. 31, 2017

Other Gains Losses [Abstract]

Other (Income) Loss, Net

9. OTHER (INCOME) LOSS, NET

As at December 31, 2016, due to the Government of Canada’s decision to reject the Northern Gateway Pipeline project, the Company wrote off $23 million of capitalized costs associated with its funding support unit in Northern Gateway Pipeline. In addition, $7 million of costs associated with termination were recorded and $7 million (2015 – $nil) of certain investments in private equity companies were written off.

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Impairment Charges and Reversals

12 Months Ended

Dec. 31, 2017

Disclosure Of Impairment Loss Recognised Or Reversed [Abstract]

Impairment Charges and Reversals

10. IMPAIRMENT CHARGES AND REVERSALS

A) Cash-Generating Unit Net Impairments

On a quarterly basis, the Company assesses its CGUs for indicators of impairment or when facts and circumstances suggest the carrying amount may exceed its recoverable amount. Goodwill is tested for impairment at least annually.

2017 Upstream Impairments

As indicators of impairment were noted for the Company’s upstream assets due to a decline in forward commodity prices since the Acquisition, the Company tested its upstream CGUs for impairment. As at December 31, 2017, the Company determined that the carrying amount of the Clearwater CGU exceeded its recoverable amount, resulting in an impairment loss of $56 million. The impairment was recorded as additional DD&A in the Deep Basin segment. Future cash flows for the CGU declined due to lower forward crude oil prices and revisions to the development plan. As at December 31, 2017, the recoverable amount of the Clearwater CGU was estimated to be approximately $295 million.

Key Assumptions

The recoverable amounts of Cenovus’s upstream CGUs were determined based on FVLCOD or an evaluation of comparable asset transactions. The fair values for producing properties were calculated based on discounted after-tax cash flows of proved and probable reserves using forward prices and cost estimates, prepared by Cenovus’s IQREs (Level 3). Key assumptions in the determination of future cash flows from reserves include crude oil and natural gas prices, costs to develop and the discount rate. All reserves have been evaluated as at December 31, 2017 by the IQREs.

Crude Oil, NGLs and Natural Gas Prices

The forward prices as at December 31, 2017, used to determine future cash flows from crude oil, NGLs and natural gas reserves were:

	2018	2019	2020	2021	2022	Average Annual Increase Thereafter
WTI (US$/barrel)	57.50	60.90	64.13	68.33	71.19	2.1%
WCS (C$/barrel)	50.61	56.59	60.86	64.56	66.63	2.1%
Edmonton C5+ (C$/barrel)	72.41	74.90	77.07	81.07	83.32	2.1%
AECO (C$/Mcf) (1) (2)	2.43	2.77	3.19	3.48	3.67	2.0%

(1) Alberta Energy Company (“AECO”) natural gas.

(2) Assumes gas heating value of one million British Thermal Units per thousand cubic feet.

Discount and Inflation Rates

Discounted future cash flows are determined by applying a discount rate between 10 percent and 15 percent based on the individual characteristics of the CGU, and other economic and operating factors. Inflation is estimated at two percent.

For the purpose of impairment testing, goodwill is allocated to the CGU to which it relates. There were no goodwill impairments for the twelve months ended December 31, 2017.

Sensitivities

The sensitivity analysis below shows the impact that a change in the discount rate or forward commodity prices would have on impairment testing for the following CGUs:

	Increase (Decrease) to Impairment
	One Percent Increase in the Discount Rate	One Percent Decrease in the Discount Rate	Five Percent Increase in the Forward Price Estimates (1)	Five Percent Decrease in the Forward Price Estimates
Clearwater	27	(30)	(56)	65
Primrose	-	-	-	-
Christina Lake	-	-	-	-
Narrows Lake	312	-	-	333

(1) The $56 million represents the impairment loss as at December 31, 2017 that could be reversed in future periods.

2016 Net Upstream Impairments

As at December 31, 2016, the recoverable value of the Northern Alberta CGU was estimated to be $1.1 billion. Earlier in 2016 and 2015, impairment losses of $380 million and $184 million, respectively, were recorded primarily due to a decline in long-term heavy crude oil prices and a slowing of the development plan. In the fourth quarter of 2016, the Company reversed $400 million of impairment losses, net of the DD&A that would have been recorded had no impairments been recorded. The reversal arose due to the increase in the CGU’s estimated recoverable amount caused by an average reduction in expected future operating costs of five percent and lower future development costs, partially offset by a decline in estimated reserves. The impairment losses and subsequent reversal were recorded as DD&A in the Conventional segment, which has been classified as a discontinued operation (see Note 11). The Northern Alberta CGU included the Pelican Lake and Elk Point producing assets and other emerging assets in the exploration and evaluation stage.

As at December 31, 2016, the recoverable amount of the Suffield CGU PP&E was estimated to be $548 million. Earlier in 2016, an impairment loss of $65 million was recognized due to lower long-term forward natural gas and heavy crude oil prices. In the fourth quarter of 2016, the Company reversed the full amount of the impairment losses, net of the DD&A that would have been recorded had no impairment been recorded ($62 million). The reversal arose due to a decline in expected future royalties increasing the estimated recoverable amount of the CGU. The impairment loss and the subsequent reversal were recorded as DD&A in the Conventional segment, which has been classified as a discontinued operation (see Note 11). The Suffield CGU included production of natural gas and heavy crude oil in Alberta on the Canadian Forces Base.

There were no goodwill impairments for the twelve months ended December 31, 2016.

Key Assumptions

The fair values for producing properties were calculated based on discounted after-tax cash flows of proved and probable reserves using forward prices and cost estimates, prepared by Cenovus’s IQREs (Level 3). Future cash flows were estimated using a two percent inflation rate and discounted using a rate of 10 percent. Forward prices as at December 31, 2016 used to determine future cash flows from crude oil and natural gas reserves were:

	2017	2018	2019	2020	2021	Average Annual Increase Thereafter
WTI (US$/barrel)	55.00	58.70	62.40	69.00	75.80	2.0%
WCS (C$/barrel)	53.70	58.20	61.90	66.50	71.00	2.0%
AECO (C$/Mcf) (1)	3.40	3.15	3.30	3.60	3.90	2.2%

(1) Assumes gas heating value of one million British Thermal Units per thousand cubic feet.

2015 Upstream Impairments

As at December 31, 2015, the Company determined that the carrying amount of the Northern Alberta CGU exceeded its recoverable amount, resulting in an impairment loss of $184 million. The impairment was recorded as additional DD&A in the Conventional segment, which has been classified as a discontinued operation (see Note 11). Future cash flows for the CGU declined due to lower forward crude oil prices, a decline in reserves estimates and a slowing down of the development plan. This was partially offset by lower future development and operating costs.

The recoverable amount was determined using FVLCOD. The fair value of producing properties was calculated based on discounted after-tax cash flows of proved and probable reserves using forward prices and cost estimates, prepared by Cenovus’s IQREs (Level 3). Future cash flows were estimated using a two percent inflation rate and discounted using a rate of 10 percent. As at December 31, 2015, the recoverable amount of the Northern Alberta CGU was estimated to be approximately $1.5 billion.

There were no goodwill impairments for the twelve months ended December 31, 2015.

B) Asset Impairments and Writedowns

Exploration and Evaluation Assets

For the year ended December 31, 2017, Management wrotedown certain E&E assets, as their carrying values were not considered to be recoverable. As a result, $888 million of previously capitalized costs were recorded as exploration expense. These assets reside primarily in the Borealis CGU within the Oil Sands segment.

Management’s decision was based on a comprehensive review of spending to date, decisions to limit spending on these assets in recent years and the current business plan spending on the assets going forward. At this point, Management is not committing further material funding beyond that required to retain ownership of this significant resource. In addition, regulatory changes to the Oil Sands Royalty application process impact the economic viability of these projects.

In 2016, $2 million of previously capitalized E&E costs were written off and recorded as exploration expense in the Oil Sands segment.

In 2015, $138 million of previously capitalized E&E costs were written off and recorded as exploration expense. This writedown included $67 million and $71 million within the Oil Sands and Conventional segments, respectively.

Property, Plant and Equipment, Net

In 2017, the Company recorded an impairment loss of $21 million related to equipment that was written down to its recoverable amount. The impairment loss relates to the Oil Sands segment.

In 2016, the Company recorded an impairment loss of $20 million primarily related to equipment that was written down to its recoverable amount. This impairment was recorded as additional DD&A in the Conventional segment, which has been classified as a discontinued operation. The Company also recorded an impairment loss of $16 million related to preliminary engineering costs associated with a project that was cancelled and equipment that was written down to its recoverable amount. This impairment loss was recorded as additional DD&A in the Oil Sands segment. Leasehold improvements of $4 million were also written off and recorded as additional DD&A in the Corporate and Eliminations segment.

In 2015, the Company impaired a sulphur recovery facility for $16 million, which was recorded as additional DD&A in the Oil Sands segment. The Company did not have future plans for the assets and did not believe it would recover the carrying amount through a sale.

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Held for Sales Assets and Discontinued Operations

12 Months Ended

Dec. 31, 2017

Disclosure Of Noncurrent Assets Held For Sale And Discontinued Operations [Abstract]

Assets Held for Sale and Discontinued Operations

11. ASSETS HELD FOR SALE AND DISCONTINUED OPERATIONS

In the second quarter of 2017, the Company announced its intention to divest of its Conventional segment which included its heavy oil assets at Pelican Lake, the carbon dioxide enhanced oil recovery project at Weyburn and conventional crude oil, natural gas and NGLs assets in the Suffield and Palliser areas in southern Alberta. The associated assets and liabilities were consequently presented as held for sale and the results of operations reported as a discontinued operation.

A) Results of Discontinued Operations

In 2017, the Company sold the majority of its Conventional segment assets for total gross cash proceeds of $3.2 billion before closing adjustments. Details of the asset sales are as follows.

Pelican Lake

On September 29, 2017, the Company completed the sale of its Pelican Lake heavy oil operations, as well as other miscellaneous assets in northern Alberta, for cash proceeds of $975 million before closing adjustments. A before-tax loss on discontinuance of $623 million was recorded on the sale.

Palliser

On December 7, 2017, Cenovus completed the sale of its Palliser crude oil and natural gas operations in southern Alberta for cash proceeds of $1.3 billion before closing adjustments. A before-tax gain on discontinuance of $1.6 billion was recorded on the sale.

Weyburn

On December 14, 2017, the Company completed the sale of its Weyburn assets in southern Saskatchewan for cash proceeds of $940 million before closing adjustments. A before-tax gain on discontinuance of $276 million was recorded on the sale.

Suffield

On September 25, 2017, Cenovus entered into an agreement to sell its Suffield crude oil and natural gas operations in southern Alberta for cash proceeds of $512 million, before closing adjustments. The sale closed on January 5, 2018. The Company anticipates a before-tax gain of approximately $350 million to be recorded in 2018. The agreement includes a deferred purchase price adjustment (“DPPA”) that could provide Cenovus with purchase price adjustments of up to $36 million if the average crude oil and natural gas prices meet certain thresholds over the next two years.

The DPPA is a two year agreement that commences on close. Under the purchase and sale agreement, Cenovus is entitled to receive cash for each month in which the average daily price of WTI is above US$55 per barrel or the price of Henry Hub natural gas is above US$3.50 per million British thermal units. Monthly cash payments are capped at $375 thousand and $1.125 million for crude oil and natural gas, respectively. The DPPA will be accounted for as a financial option and fair valued at each reporting date. The fair value of the DPPA on the date of close was $7 million.

The following table presents the results of discontinued operations, including asset sales:

For the years ended December 31,	2017	2016	2015
Revenues
Gross Sales	1,309	1,267	1,648
Less: Royalties	174	139	113
	1,135	1,128	1,535
Expenses
Transportation and Blending	167	186	229
Operating	426	444	558
Production and Mineral Taxes	18	12	17
(Gain) Loss on Risk Management	33	(58)	(209)
Operating Margin	491	544	940
Depreciation, Depletion and Amortization	192	567	1,121
Exploration Expense	2	-	71
Finance Costs	80	102	101
Earnings (Loss) From Discontinued Operations Before Income Tax	217	(125)	(353)
Current Tax Expense (Recovery)	24	86	145
Deferred Tax Expense (Recovery)	33	(125)	(202)
After-tax Earnings (Loss) From Discontinued Operations	160	(86)	(296)
After-tax Gain (Loss) on Discontinuance (1)	938	-	-
Net Earnings (Loss) From Discontinued Operations	1,098	(86)	(296)

(1) Net of deferred tax expense of $347 million in 2017.

B) Cash Flows From Discontinued Operations

Cash flows from discontinued operations reported in the Consolidated Statement of Cash Flows are:

For the years ended December 31,	2017	2016	2015
Cash From Operating Activities	448	435	778
Cash From (Used in) Investing Activities	2,993	(168)	(243)
Net Cash Flow	3,441	267	535

C) Assets and Liabilities Held for Sale

In the fourth quarter of 2017, the Company announced its intention to market for sale a package of non-core Deep Basin assets in the East Clearwater area and a portion of the West Clearwater assets. The assets have been classified as held for sale and recorded at the lesser of their carrying amount and their fair value less cost to sell. Assets and liabilities held for sale also include the Suffield operations, which were sold on January 5, 2018. No impairments were recorded on the assets held for sale as at December 31, 2017.

		E&E Assets	PP&E	Decommissioning Liabilities
As at December 31, 2017		(Note 17)	(Note 18)	(Note 24)
Conventional	-		568	454
Deep Basin	46		434	149
	46		1,002	603

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Income Taxes

12 Months Ended

Dec. 31, 2017

Disclosure Of Income Tax Expense Continuing Operations [Abstract]

Income Taxes

12. INCOME TAXES

The provision for income taxes is:

For the years ended December 31,	2017	2016	2015
Current Tax
Canada	(217)	(260)	441
United States	(38)	1	(12)
Current Tax Expense (Recovery)	(255)	(259)	429
Deferred Tax Expense (Recovery)	203	(84)	(453)
Tax Expense (Recovery) From Continuing Operations	(52)	(343)	(24)

In 2017 and 2016, the Company recorded a current tax recovery due to the carryback of losses for income tax purposes and prior year adjustments. A deferred tax expense was recorded in 2017 due to the revaluation gain of our pre-existing interest in connection with the Acquisition, partially offset by a $275 million recovery from the reduction of the U.S. federal corporate income tax rate from 35 percent to 21 percent reducing the Company’s deferred income tax liability and the impact of E&E asset writedowns.

In 2015, the Company recorded a deferred tax recovery of $415 million arising from an adjustment to the tax basis of the refining assets. The increase in tax basis was a result of the Company’s partner recognizing a taxable gain on its interest in WRB which, due to an election filed with the U.S. tax authorities, was added to the tax basis of WRB’s assets. This was partially offset by an increase in the deferred tax expense as a result of a two percent increase in the Alberta corporate income tax rate.

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

For the years ended December 31,	2017	2016	2015
Earnings (Loss) From Continuing Operations Before Income Tax	2,216	(802)	890
Canadian Statutory Rate	27.0%	27.0%	26.1%
Expected Income Tax Expense (Recovery) From Continuing Operations	598	(217)	232
Effect of Taxes Resulting From:
Foreign Tax Rate Differential	(17)	(46)	(41)
Non-Taxable Capital (Gains) Losses	(148)	(26)	137
Non-Recognition of Capital (Gains) Losses	(118)	(26)	135
Adjustments Arising From Prior Year Tax Filings	(41)	(46)	(55)
(Recognition) of Previously Unrecognized Capital Losses	(68)	-	(149)
(Recognition) of U.S. Tax Basis	-	-	(415)
Change in Statutory Rate	(275)	-	114
Non-Deductible Expenses	(5)	5	7
Other	22	13	11
Total Tax Expense (Recovery) From Continuing Operations	(52)	(343)	(24)
Effective Tax Rate	(2.3)%	42.8%	(2.7)%

The analysis of deferred income tax liabilities and deferred income tax assets is as follows:

As at December 31,	2017	2016
Deferred Income Tax Liabilities
Deferred Tax Liabilities to be Settled Within 12 Months	186	6
Deferred Tax Liabilities to be Settled After More Than 12 Months	6,229	3,147
	6,415	3,153
Deferred Income Tax Assets
Deferred Tax Assets to be Recovered Within 12 Months	(374)	(117)
Deferred Tax Assets to be Recovered After More Than 12 Months	(428)	(451)
	(802)	(568)
Net Deferred Income Tax Liability	5,613	2,585

The deferred income tax assets and liabilities to be settled within 12 months represents Management’s estimate of the timing of the reversal of temporary differences and may not correlate to the current income tax expense of the subsequent year.

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	PP&E		Timing of Partnership Items		Risk Management	Other	Total
As at December 31, 2015	3,052		-		82	17	3,151
Charged (Credited) to Earnings	118		-		(76)	(16)	26
Charged (Credited) to OCI	(24)		-		-	-	(24)
As at December 31, 2016	3,146		-		6	1	3,153
Charged (Credited) to Earnings	625		164		11	1	801
Charged (Credited) to Purchase Price Allocation	2,506		-		-	-	2,506
Charged (Credited) to OCI	(45)		-		-	-	(45)
As at December 31, 2017	6,232		164		17	2	6,415
Deferred Income Tax Assets	Unused Tax Losses	Timing of Partnership Items		Risk Management		Other	Total
As at December 31, 2015	(172)	(36)		(8)		(119)	(335)
Charged (Credited) to Earnings	(102)	36		(77)		(92)	(235)
Charged (Credited) to OCI	4	-		-		(2)	2
As at December 31, 2016	(270)	-		(85)		(213)	(568)
Charged (Credited) to Earnings	67	-		(198)		(87)	(218)
Charged (Credited) to Share Capital	-	-		-		(28)	(28)
Charged (Credited) to OCI	12	-		-		-	12
As at December 31, 2017	(191)	-		(283)		(328)	(802)

Net Deferred Income Tax Liabilities	Total
Net Deferred Income Tax Liabilities as at December 31, 2015	2,816
Charged (Credited) to Earnings	(209)
Charged (Credited) to OCI	(22)
Net Deferred Income Tax Liabilities as at December 31, 2016	2,585
Charged (Credited) to Earnings	583
Charged (Credited) to Purchase Price Allocation	2,506
Charged (Credited) to Share Capital	(28)
Charged (Credited) to OCI	(33)
Net Deferred Income Tax Liabilities as at December 31, 2017	5,613

No deferred tax liability has been recognized as at December 31, 2017 on temporary differences associated with investments in subsidiaries and joint arrangements where the Company can control the timing of the reversal of the temporary difference and the reversal is not probable in the foreseeable future. In 2016, the Company had temporary differences of $7,457 million in respect of these investments where, on dissolution or sale, a tax liability might have existed. The Company has 100 percent control of that investment as of May 17, 2017.

The approximate amounts of tax pools available, including tax losses, are:

As at December 31,	2017	2016
Canada	8,317	4,273
United States	1,714	2,036
	10,031	6,309

As at December 31, 2017, the above tax pools included $73 million (2016 – $46 million) of Canadian non-capital losses and $593 million (2016 – $623 million) of U.S. federal net operating losses. These losses expire no earlier than 2025.

Also included in the December 31, 2017 tax pools are Canadian net capital losses totaling $8 million (2016 – $43 million), which are available for carry forward to reduce future capital gains. All of these net capital losses are unrecognized as a deferred income tax asset as at December 31, 2017 (2016 – $40 million). Recognition is dependent on future capital gains. The Company has not recognized $293 million (2016 – $730 million) of net capital losses associated with unrealized foreign exchange losses on its U.S. denominated debt.

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Per Share Amounts

12 Months Ended

Dec. 31, 2017

Earnings Per Share [Abstract]

Per Share Amounts

13. PER SHARE AMOUNTS

A) Net Earnings (Loss) Per Share — Basic and Diluted

For the years ended December 31,	2017	2016	2015
Earnings (Loss) From:
Continuing Operations	2,268	(459)	914
Discontinued Operations	1,098	(86)	(296)
Net Earnings (Loss)	3,366	(545)	618
Weighted Average Number of Shares(millions)	1,102.5	833.3	818.7
Basic and Diluted Earnings (Loss) Per Share From:($)
Continuing Operations	2.06	(0.55)	1.11
Discontinued Operations	0.99	(0.10)	(0.36)
Net Earnings (Loss) Per Share	3.05	(0.65)	0.75

As at December 31, 2017, 43 million NSRs (2016 – 42 million) and 81 thousand TSARs (2016 – 3 million) were excluded from the diluted weighted average number of shares as their effect would have been anti-dilutive or their exercise prices exceed the market price of Cenovus’s common shares. These instruments could potentially dilute earnings per share in the future. For further information on the Company’s stock-based compensation plans, see Note 29.

B) Dividends Per Share

For the year ended December 31, 2017, the Company paid dividends of $225 million or $0.20 per share, all of which were paid in cash (2016 – $166 million or $0.20 per share, all of which were paid in cash; 2015 – $710 million or $0.8524 per share, including cash dividends of $528 million). The Cenovus Board of Directors declared a first quarter dividend of $0.05 per share, payable on March 29, 2018, to common shareholders of record as of March 15, 2018.

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Cash and Cash Equivalents

12 Months Ended

Dec. 31, 2017

Cash And Cash Equivalents [Abstract]

Cash and Cash Equivalents

14. CASH AND CASH EQUIVALENTS

As at December 31,	2017	2016
Cash	547	542
Short-Term Investments	63	3,178
	610	3,720

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Accounts Receivable and Accrued Revenues

12 Months Ended

Dec. 31, 2017

Trade And Other Current Receivables [Abstract]

Accounts Receivable and Accrued Revenues

15. ACCOUNTS RECEIVABLE AND ACCRUED REVENUES

As at December 31,	2017	2016
Accruals	1,379	1,606
Prepaids and Deposits	64	127
Partner Advances	94	-
Note Receivable From Partner (1)	-	50
Trade	193	29
Joint Operations Receivables	51	11
Other	49	15
	1,830	1,838

(1) Note receivable from partner was interest bearing at a rate of 1.6783 percent per annum.

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Inventories

12 Months Ended

Dec. 31, 2017

Classes Of Inventories [Abstract]

Inventories

16. INVENTORIES

As at December 31,	2017	2016
Product
Refining and Marketing	894	1,006
Oil Sands	414	156
Deep Basin	2	-
Conventional	2	20
Parts and Supplies	77	55
	1,389	1,237

During the year ended December 31, 2017, approximately $12,856 million of produced and purchased inventory was recorded as an expense (2016 – $9,964 million; 2015 – $10,618 million).

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Exploration and Evaluation Assets

12 Months Ended

Dec. 31, 2017

Disclosure Of Exploration And Evaluation Assets [Abstract]

Exploration and Evaluation Assets

17. EXPLORATION AND EVALUATION ASSETS

	Total
As at December 31, 2015	1,575
Additions	67
Transfers to PP&E (Note 18)	(49)
Exploration Expense (Note 10)	(2)
Change in Decommissioning Liabilities	(6)
As at December 31, 2016	1,585
Additions	147
Acquisition (Note 5) (1)	3,608
Transfers to Assets Held for Sale (Note 11)	(316)
Transfers to PP&E (Note 18)	(6)
Exploration Expense (Notes 10 and 11)	(890)
Change in Decommissioning Liabilities	5
Exchange Rate Movements and Other	19
Divestitures (1)	(479)
As at December 31, 2017	3,673

(1) In connection with the Acquisition, Cenovus was deemed to have disposed of its pre-existing interest in FCCL and re-acquired it at fair value as required by IFRS 3.

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Property, Plant and Equipment, Net

12 Months Ended

Dec. 31, 2017

Disclosure Of Property Plant And Equipment [Abstract]

Property, Plant and Equipment, Net

18. PROPERTY, PLANT AND EQUIPMENT, NET

	Upstream Assets
	Development & Production	Other Upstream	Refining Equipment	Other (1)	Total
COST
As at December 31, 2015	31,481	331	5,206	1,037	38,055
Additions	717	2	213	38	970
Transfers From E&E Assets (Note 17)	49	-	-	-	49
Change in Decommissioning Liabilities	(267)	-	(8)	-	(275)
Exchange Rate Movements and Other	(16)	-	(152)	(1)	(169)
Divestitures (Note 8)	(23)	-	-	-	(23)
As at December 31, 2016	31,941	333	5,259	1,074	38,607
Additions	1,324	-	168	89	1,581
Acquisition (Note 5) (2)	26,317	-	-	-	26,317
Transfers From E&E Assets (Note 17)	6	-	-	-	6
Transfers to Assets Held for Sale (Note 11)	(19,719)	-	-	-	(19,719)
Change in Decommissioning Liabilities	(67)	-	-	3	(64)
Exchange Rate Movements and Other	(28)	-	(364)	1	(391)
Divestitures (Note 8) (2)	(12,333)	-	(2)	-	(12,335)
As at December 31, 2017	27,441	333	5,061	1,167	34,002
ACCUMULATED DEPRECIATION, DEPLETION AND AMORTIZATION
As at December 31, 2015	18,908	277	896	639	20,720
DD&A	1,173	31	205	66	1,475
Impairment Losses (Note 10)	481	-	-	4	485
Reversal of Impairment Losses (Note 10)	(462)	-	-	-	(462)
Exchange Rate Movements and Other	(4)	-	(25)	-	(29)
Divestitures (Note 8)	(8)	-	-	-	(8)
As at December 31, 2016	20,088	308	1,076	709	22,181
DD&A	1,653	23	209	68	1,953
Impairment Losses (Note 10)	77	-	-	-	77
Transfers to Assets Held for Sale (Note 11)	(16,120)	-	-	-	(16,120)
Exchange Rate Movements and Other	17	-	(91)	1	(73)
Divestitures (Note 8) (2)	(3,611)	-	(1)	-	(3,612)
As at December 31, 2017	2,104	331	1,193	778	4,406
CARRYING VALUE
As at December 31, 2015	12,573	54	4,310	398	17,335
As at December 31, 2016	11,853	25	4,183	365	16,426
As at December 31, 2017	25,337	2	3,868	389	29,596

(1) Includes crude-by-rail terminal, office furniture, fixtures, leasehold improvements, information technology and aircraft.

(2) In connection with the Acquisition, Cenovus was deemed to have disposed of its pre-existing interest in FCCL and re-acquired it at fair value as required by IFRS 3. The carrying value of the pre-existing interest in FCCL was $8,602 million.

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

As at December 31,	2017	2016
Development and Production	1,809	537
Refining Equipment	131	206
	1,940	743

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Other Assets

12 Months Ended

Dec. 31, 2017

Other Noncurrent Assets [Abstract]

Other Assets

19. OTHER ASSETS

As at December 31,	2017	2016
Equity Investments	37	35
Long-Term Receivables	11	15
Prepaids	9	5
Other	14	1
	71	56

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Goodwill

12 Months Ended

Dec. 31, 2017

Goodwill [Abstract]

Goodwill

20. GOODWILL

As at December 31,	2017	2016
Carrying Value, Beginning of Year	242	242
Goodwill Recognized on Acquisition (Note 5)	2,030	-
Carrying Value, End of Year	2,272	242

The carrying amount of goodwill allocated to the Company’s exploration and production CGUs is:

As at December 31,	2017	2016
Primrose (Foster Creek) (1)	1,171	242
Christina Lake (1)	1,101	-
	2,272	242

(1) Goodwill recognized on the Acquisition reflects measurement period adjustments.

For the purposes of impairment testing, goodwill is allocated to the CGU to which it relates. The assumptions used to test Cenovus’s goodwill for impairment as at December 31, 2017 are consistent to those disclosed in Note 10.

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Accounts Payable and Accrued Liabilities

12 Months Ended

Dec. 31, 2017

Trade And Other Current Payables [Abstract]

Accounts Payable and Accrued Liabilities

21. ACCOUNTS PAYABLE AND ACCRUED LIABILITIES

As at December 31,	2017	2016
Accruals	2,006	1,927
Trade	337	105
Interest	86	72
Partner Advances	94	-
Note Payable to Partner (1)	-	50
Employee Long-Term Incentives	52	42
Onerous Contract Provisions	8	18
Joint Operations Payables	12	-
Other	40	52
	2,635	2,266

(1) Note payable to partner was interest bearing at a rate of 1.6783 percent per annum.

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Contingent Payment

12 Months Ended

Dec. 31, 2017

Disclosure Of Contingent Liabilities In Business Combination [Abstract]

Contingent Payment

22. CONTINGENT PAYMENT

As at January 1, 2017	-
Initial Recognition on May 17, 2017 (Note 5)	361
Re-measurement (1)	(138)
Liabilities Settled or Payable	(17)
As at December 31, 2017	206
Less: Current Portion	38
Long-Term Portion	168

(1) Contingent payment is carried at fair value. Changes in fair value are recorded in net earnings.

In connection with the Acquisition (see Note 5), Cenovus agreed to make quarterly payments to ConocoPhillips during the five years subsequent to May 17, 2017 for quarters in which the average WCS crude oil price exceeds $52.00 per barrel during the quarter. The quarterly payment will be $6 million for each dollar that the WCS price exceeds $52.00 per barrel. The calculation includes an adjustment mechanism related to certain significant production outages at Foster Creek and Christina Lake which may reduce the amount of a contingent payment. As at December 31, 2017, $17 million is payable under this agreement.

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Long-term Debt

12 Months Ended

Dec. 31, 2017

Borrowings [Abstract]

Long-Term Debt

23. LONG-TERM DEBT

As at December 31,	Notes	US$ Principal Amount	2017	2016
Revolving Term Debt (1)	A	-	-	-
Asset Sale Bridge Credit Facility	B	-	-	-
U.S. Dollar Denominated Unsecured Notes	C	7,650	9,597	6,378
Total Debt Principal			9,597	6,378
Debt Discounts and Transaction Costs			(84)	(46)
Long-Term Debt			9,513	6,332

(1) Revolving term debt may include Bankers’ Acceptances, London Interbank Offered Rate based loans, prime rate loans and U.S. base rate loans.

The weighted average interest rate on outstanding debt for the year ended December 31, 2017 was 4.9 percent (2016 – 5.3 percent).

A) Revolving Term Debt

On April 28, 2017, Cenovus amended its existing committed credit facility to increase the capacity of the facility by $0.5 billion to $4.5 billion and to extend the maturity dates. The committed credit facility consists of a $1.2 billion tranche maturing on November 30, 2020 and a $3.3 billion tranche maturing on November 30, 2021. Borrowings are available by way of Bankers’ Acceptances, LIBOR based loans, prime rate loans or U.S. base rate loans. As at December 31, 2017, there were no amounts drawn on Cenovus’s committed credit facility (2016 – $nil).

B) Asset Sale Bridge Credit Facility

In connection with the Acquisition, Cenovus borrowed $3.6 billion under a committed asset sale bridge credit facility. Net proceeds from the sale of the Company’s Conventional segment assets (see Note 11) and cash on hand were used to repay and retire the committed asset bridge credit facility prior to December 31, 2017.

C) Unsecured Notes

Unsecured notes are composed of:

	US$ Principal Amount
As at December 31,		2017	2016
5.70% due October 15, 2019	1,300	1,631	1,746
3.00% due August 15, 2022	500	627	671
3.80% due September 15, 2023	450	565	604
4.25% due April 15, 2027	1,200	1,505	-
5.25% due June 15, 2037	700	878	-
6.75% due November 15, 2039	1,400	1,756	1,880
4.45% due September 15, 2042	750	941	1,007
5.20% due September 15, 2043	350	439	470
5.40% due June 15, 2047	1,000	1,255	-
	7,650	9,597	6,378

In connection with the Acquisition, the Company completed an offering in the U.S. on April 7, 2017 for US$2.9 billion of senior unsecured notes issued in three tranches, US$1.2 billion 4.25 percent senior unsecured notes due April 2027, US$700 million 5.25 percent senior unsecured notes due June 2037, and US$1.0 billion 5.40 percent senior unsecured notes due June 2047 (collectively, the “2017 Notes”). In the fourth quarter of 2017, the Company completed an exchange offer (“Exchange Offering”) whereby substantially all of the 2017 Notes were exchanged for notes registered under the Securities Act of 1933 with essentially the same terms and provisions as the 2017 Notes. The Exchange Offering has been treated as a modification for accounting purposes and not an extinguishment.

On October 10, 2017, Cenovus filed a base shelf prospectus that allows the Company to offer, from time to time, up to US$7.5 billion, or the equivalent in other currencies, of debt securities, common shares, preferred shares, subscription receipts, warrants, share purchase contracts and units in Canada, the U.S. and elsewhere where permitted by law. The base shelf prospectus is available to ConocoPhillips to offer, should they so choose from time to time, the common shares they acquired in connection with the Acquisition. The base shelf prospectus will expire in November 2019. Following the completion of the Exchange Offering and as at December 31, 2017, US$4.6 billion was available under the base shelf prospectus. Offerings under the base shelf prospectus are subject to market conditions.

As at December 31, 2017, the Company is in compliance with all of the terms of its debt agreements.

D) Mandatory Debt Payments

	US$ Principal Amount	Total C$ Equivalent
2018	-	-
2019	1,300	1,631
2020	-	-
2021	-	-
2022	500	627
Thereafter	5,850	7,339
	7,650	9,597

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Decommissioning Liabilities

12 Months Ended

Dec. 31, 2017

Provision For Decommissioning Restoration And Rehabilitation Costs [Abstract]

Decommissioning Liabilities

24. DECOMMISSIONING LIABILITIES

The decommissioning provision represents the present value of the expected future costs associated with the retirement of upstream crude oil and natural gas assets, refining facilities and the crude-by-rail terminal. The aggregate carrying amount of the obligation is:

	2017	2016
Decommissioning Liabilities, Beginning of Year	1,847	2,052
Liabilities Incurred	20	11
Liabilities Acquired (Note 5) (1)	944	-
Liabilities Settled	(70)	(51)
Liabilities Divested (1)	(139)	(1)
Transfers to Liabilities Related to Assets Held for Sale (Note 11)	(1,621)	-
Change in Estimated Future Cash Flows	(155)	(423)
Change in Discount Rate	76	131
Unwinding of Discount on Decommissioning Liabilities	128	130
Foreign Currency Translation	(1)	(2)
Decommissioning Liabilities, End of Year	1,029	1,847

(1) In connection with the Acquisition, Cenovus was deemed to have disposed of its pre-existing interest in FCCL and reacquired it at fair value as required by IFRS.

As at December 31, 2017, the undiscounted amount of estimated future cash flows required to settle the obligation is $3,360 million (2016 – $6,270 million), which has been discounted using a credit-adjusted risk-free rate of 5.3 percent (2016 – 5.9 percent). An inflation rate of two percent (2016 – two percent) was used to calculate the decommissioning provision. Most of these obligations are not expected to be paid for several years, or decades, and are expected to be funded from general resources at that time.The Company expects to settle approximately $40 million to $50 million of decommissioning liabilities over the next year. Revisions in estimated future cash flows resulted from lower cost estimates.

Sensitivities

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

	2017		2016
As at December 31,	Credit-Adjusted Risk-Free Rate	Inflation Rate	Credit-Adjusted Risk-Free Rate	Inflation Rate
One Percent Increase	(98)	197	(248)	327
One Percent Decrease	192	(103)	317	(259)

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Other Liabilities

12 Months Ended

Dec. 31, 2017

Disclosure Of Other Liabilities [Abstract]

Other Liabilities

25. OTHER LIABILITIES

As at December 31,	2017	2016
Employee Long-Term Incentives	43	72
Pension and Other Post-Employment Benefit Plan (Note 26)	62	71
Onerous Contract Provisions	37	35
Other	31	33
	173	211

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Pensions and Other Post-Employment Benefits

12 Months Ended

Dec. 31, 2017

Pension Plans [Abstract]

Pensions and Other Post-Employment Benefits

26. PENSIONS AND OTHER POST-EMPLOYMENT BENEFITS

The Company provides employees with a pension that includes either a defined contribution or defined benefit component and other post-employment benefit plan. Most of the employees participate in the defined contribution pension. Starting in 2012, employees who meet certain criteria may move from the current defined contribution component to a defined benefit component for their future service.

The defined benefit pension provides pension benefits at retirement based on years of service and final average earnings. Future enrollment is limited to eligible employees who meet certain criteria. The Company’s OPEB provides certain retired employees with health care and dental benefits until age 65 and life insurance benefits.

The Company is required to file an actuarial valuation of its registered defined benefit pension with the provincial regulator at least every three years. The most recently filed valuation was dated December 31, 2014 and the next required actuarial valuation will be as at December 31, 2017.

A) Defined Benefit and OPEB Plan Obligation and Funded Status

Information related to defined benefit pension and OPEB plans, based on actuarial estimations, is:

	Pension Benefits		OPEB
As at December 31,	2017	2016	2017	2016
Defined Benefit Obligation
Defined Benefit Obligation, Beginning of Year	173	168	23	26
Current Service Costs	14	14	2	(3)
Interest Costs (1)	7	7	1	1
Benefits Paid	(8)	(25)	(1)	(1)
Plan Participant Contributions	2	2	-	-
Past Service Costs – Curtailments	(6)	-	(1)	-
Remeasurements:
(Gains) Losses from Experience Adjustments	1	-	-	-
(Gains) Losses from Changes in Demographic Assumptions	-	-	(1)	-
(Gains) Losses from Changes in Financial Assumptions	(2)	7	(1)	-
Defined Benefit Obligation, End of Year	181	173	22	23
Plan Assets
Fair Value of Plan Assets, Beginning of Year	125	128	-	-
Employer Contributions	9	14	-	-
Plan Participant Contributions	2	2	-	-
Benefits Paid	(8)	(25)	-	-
Interest Income (1)	4	3	-	-
Remeasurements:
Return on Plan Assets (Excluding Interest Income)	9	3	-	-
Fair Value of Plan Assets, End of Year	141	125	-	-
Pension and OPEB (Liability) (2)	(40)	(48)	(22)	(23)

(1) Based on the discount rate of the defined benefit obligation at the beginning of the year.

(2) Pension and OPEB liabilities are included in other liabilities on the Consolidated Balance Sheets.

In connection with the divestitures of the Company’s legacy Conventional assets, affected employees left the plans resulting in a curtailment gain.

The weighted average duration of the defined benefit pension and OPEB obligations are 16 years and 10 years, respectively.

B) Pension and OPEB Costs

	Pension Benefits			OPEB
For the years ended December 31,	2017	2016	2015	2017	2016	2015
Defined Benefit Plan Cost
Current Service Costs	14	14	19	2	(3)	3
Past Service Costs – Curtailments	(6)	-	(5)	(1)	-	-
Net Settlement Costs	-	-	3	-	-	-
Net Interest Costs	3	4	6	1	1	1
Remeasurements:
Return on Plan Assets (Excluding Interest Income)	(9)	(3)	3	-	-	-
(Gains) Losses from Experience Adjustments	1	-	(3)	-	-	-
(Gains) Losses from Changes in Demographic Assumptions	-	-	-	(1)	-	-
(Gains) Losses from Changes in Financial Assumptions	(2)	7	(28)	(1)	-	-
Defined Benefit Plan Cost (Recovery)	1	22	(5)	-	(2)	4
Defined Contribution Plan Cost	27	25	29	-	-	-
Total Plan Cost	28	47	24	-	(2)	4

C) Investment Objectives and Fair Value of Plan Assets

The objective of the asset allocation is to manage the funded status of the plan at an appropriate level of risk, giving consideration to the security of the assets and the potential volatility of market returns and the resulting effect on both contribution requirements and pension expense. The long-term return is expected to achieve or exceed the return from a composite benchmark comprised of passive investments in appropriate market indices. The asset allocation structure is subject to diversification requirements and constraints which reduce risk by limiting exposure to individual equity investment and credit rating categories.

The allocation of assets between the various types of investment funds is monitored quarterly and is re-balanced as necessary. The asset allocation structure targets an investment of 50 to 75 percent in equity securities, 25 to 35 percent in fixed income assets, zero to 15 percent in real estate assets and zero to 10 percent in cash and cash equivalents.

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,	2017	2016
Equity Funds	89	73
Bond Funds	29	25
Non-Invested Assets	11	13
Real Estate Funds	9	9
Cash and Cash Equivalents	3	5
	141	125

Fair value of equities and bonds are based on the trading price of the underlying funds. The fair value of the non-invested assets is the discounted value of the expected future payments. The fair value of the real estate funds reflects the market value and the fund manager’s appraisal value of the assets.

Equity funds do not include any direct investments in Cenovus shares.

D) Funding

The defined benefit pension is funded in accordance with federal and provincial government pension legislation, where applicable. Contributions are made to trust funds administered by an independent trustee. The Company’s contributions to the defined benefit pension plan are based on the most recent actuarial valuation as at December 31, 2014, and direction of the Management Pension Committee and Human Resources and Compensation Committee of the Board of Directors.

Employees participating in the defined benefit pension are required to contribute four percent of their pensionable earnings, up to an annual maximum, and the Company provides the balance of the funding necessary to ensure benefits will be fully provided for at retirement. The expected employer contributions for the year ended December 31, 2018 are $9 million for the defined benefit pension plan and $nil for the OPEB. The OPEB is funded on an as required basis.

E) Actuarial Assumptions and Sensitivities

Actuarial Assumptions

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

	Pension Benefits			OPEB
For the years ended December 31,	2017	2016	2015	2017	2016	2015
Discount Rate	3.50%	3.75%	4.00%	3.25%	3.75%	3.75%
Future Salary Growth Rate	3.81%	3.80%	3.80%	5.08%	5.15%	5.15%
Average Longevity (years)	88.0	87.9	88.3	88.0	87.9	88.3
Health Care Cost Trend Rate	N/A	N/A	N/A	6.00%	7.00%	7.00%

The discount rates are determined with reference to market yields on high quality corporate debt instruments of similar duration to the benefit obligations at the end of the reporting period.

Sensitivities

The sensitivity of the defined benefit and OPEB obligation to changes in relevant actuarial assumptions is:

	2017		2016
As at December 31,	Increase	Decrease	Increase	Decrease
One Percent Change:
Discount Rate	(28)	36	(25)	32
Future Salary Growth Rate	3	(3)	3	(3)
Health Care Cost Trend Rate	1	(1)	2	(1)
One Year Change in Assumed Life Expectancy	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.

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.

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Share Capital

12 Months Ended

Dec. 31, 2017

Disclosure Of Share Capital Reserves And Other Equity Interest [Abstract]

Share Capital

27. SHARE CAPITAL

A) Authorized

Cenovus is authorized to issue an unlimited number of common shares and first and second preferred shares not exceeding, in aggregate, 20 percent of the number of issued and outstanding common shares. The first and second preferred shares may be issued in one or more series with rights and conditions to be determined by the Company’s Board of Directors prior to issuance and subject to the Company’s articles.

B) Issued and Outstanding

	2017		2016
As at December 31,	Number of Common Shares (thousands)	Amount	Number of Common Shares (thousands)	Amount
Outstanding, Beginning of Year	833,290	5,534	833,290	5,534
Common Shares Issued, Net of Issuance Costs and Tax	187,500	2,927	-	-
Common Shares Issued to ConocoPhillips (Note 5)	208,000	2,579	-	-
Outstanding, End of Year	1,228,790	11,040	833,290	5,534

In connection with the Acquisition (see Note 5), Cenovus closed a bought-deal common share financing on April 6, 2017 for 187.5 million common shares, raising gross proceeds of $3.0 billion ($2.9 billion net of $101 million of share issuance costs).

In addition, the Company issued 208 million common shares to ConocoPhillips on May 17, 2017 as partial consideration for the Acquisition. In relation to the share consideration, Cenovus and ConocoPhillips entered into an investor agreement, and a registration rights agreement which, among other things, restricted ConocoPhillips from selling or hedging its Cenovus common shares until after November 17, 2017. ConocoPhillips is also restricted from nominating new members to Cenovus’s Board of Directors and must vote its Cenovus common shares in accordance with Management’s recommendations or abstain from voting until such time ConocoPhillips owns 3.5 percent or less of the then outstanding common shares of Cenovus. As at December 31, 2017, ConocoPhillips continued to hold these common shares.

There were no preferred shares outstanding as at December 31, 2017 (2016 – nil).

As at December 31, 2017, there were 15 million (2016 – 12 million) common shares available for future issuance under the stock option plan.

C) Paid in Surplus

Cenovus’s paid in surplus reflects the Company’s retained earnings prior to the split of Encana Corporation (“Encana”) under the plan of arrangement into two independent energy companies, Encana and Cenovus (pre-arrangement earnings). In addition, paid in surplus includes stock-based compensation expense related to the Company’s NSRs discussed in Note 29A.

	Pre-Arrangement Earnings	Stock-Based Compensation	Total
As at December 31, 2015	4,086	244	4,330
Stock-Based Compensation Expense	-	20	20
As at December 31, 2016	4,086	264	4,350
Stock-Based Compensation Expense	-	11	11
As at December 31, 2017	4,086	275	4,361

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Accumulated Other Comprehensive Income (Loss)

12 Months Ended

Dec. 31, 2017

Disclosure Of Accumulated Other Comprehensive Income Loss [Abstract]

Accumulated Other Comprehensive Income (Loss)

28. ACCUMULATED OTHER COMPREHENSIVE INCOME (LOSS)

	Defined Benefit Pension Plan	Foreign Currency Translation Adjustment	Available for Sale Financial Assets	Total
As at December 31, 2015	(10)	1,014	16	1,020
Other Comprehensive Income (Loss), Before Tax	(4)	(106)	(4)	(114)
Income Tax	1	-	3	4
As at December 31, 2016	(13)	908	15	910
Other Comprehensive Income (Loss), Before Tax	12	(275)	(1)	(264)
Income Tax	(3)	-	-	(3)
As at December 31, 2017	(4)	633	14	643

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Stock-Based Compensation Plans

12 Months Ended

Dec. 31, 2017

Disclosure Of Terms And Conditions Of Sharebased Payment Arrangement [Abstract]

Stock-Based Compensation Plans

29. STOCK-BASED COMPENSATION PLANS

A) Employee Stock Option Plan

Cenovus has an Employee Stock Option Plan that provides employees with the opportunity to exercise an option to purchase a common share of the Company. Option exercise prices approximate the market price for the common shares on the date the options were issued. Options granted are exercisable at 30 percent of the number granted after one year, an additional 30 percent of the number granted after two years and are fully exercisable after three years. Options expire after seven years.

Options issued by the Company on or after February 24, 2011 have associated NSRs. The NSRs, in lieu of exercising the option, give the option holder the right to receive the number of common shares that could be acquired with the excess value of the market price of Cenovus’s common shares at the time of exercise over the exercise price of the option.

Options issued by the Company under the Employee Stock Option Plan prior to February 24, 2011 have associated TSARs. In lieu of exercising the options, the TSARs give the option holder the right to receive a cash payment equal to the excess of the market price of Cenovus’s common shares at the time of exercise over the exercise price of the option.

The TSARs and NSRs vest and expire under the same terms and conditions as the underlying options.

NSRs

The weighted average unit fair value of NSRs granted during the year ended December 31, 2017 was $3.10 before considering forfeitures, which are considered in determining total cost for the period. The fair value of each NSR was estimated on its grant date using the Black-Scholes-Merton valuation model with weighted average assumptions as follows:

Risk-Free Interest Rate	1.00%
Expected Dividend Yield	1.13%
Expected Volatility (1)	29.14%
Expected Life (years)	3.70

(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, 2017	Number of NSRs (thousands)	Weighted Average Exercise Price ($)
Outstanding, Beginning of Year	41,644	30.57
Granted	3,537	14.81
Exercised	-	-
Forfeited	(2,454)	28.27
Outstanding, End of Year	42,727	29.40

	Outstanding NSRs			Exercisable NSRs
As at December 31, 2017 Range of Exercise Price($)	Number of NSRs (thousands)	Weighted Average Remaining Contractual Life (years)	Weighted Average Exercise Price($)	Number of NSRs (thousands)	Weighted Average Exercise Price($)
10.00 to 14.99	3,319	5.4	14.80	-	-
15.00 to 19.99	3,313	5.2	19.51	995	19.51
20.00 to 24.99	3,723	4.1	22.25	2,254	22.26
25.00 to 29.99	12,115	3.1	28.38	12,106	28.39
30.00 to 34.99	10,419	2.2	32.64	10,419	32.64
35.00 to 39.99	9,838	0.8	38.19	9,838	38.19
	42,727	2.8	29.40	35,612	31.70

TSARs

The Company had a liability of $nil as at December 31, 2017 (2016 – $nil) in the Consolidated Balance Sheets based on the fair value of each TSAR held by Cenovus employees. Fair value was estimated at the period-end date using the Black-Scholes-Merton valuation model with weighted average assumptions as follows:

Risk-Free Interest Rate	1.85%
Expected Dividend Yield	1.51%
Expected Volatility (1)	28.89%
Cenovus’s Common Share Price ($)	11.48

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

The intrinsic value of vested TSARs held by Cenovus employees as at December 31, 2017 was $nil (2016 – $nil).

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

As at December 31, 2017	Number of TSARs (thousands)	Weighted Average Exercise Price ($)
Outstanding, Beginning of Year	3,373	26.66
Exercised for Cash Payment	-	-
Exercised as Options for Common Shares	-	-
Forfeited	(16)	29.19
Expired	(3,276)	26.48
Outstanding, End of Year	81	33.52

The market price of Cenovus’s common shares on the TSX as at December 31, 2017 was $11.48.

B) Performance Share Units

Cenovus has granted PSUs to certain employees under its Performance Share Unit Plan for Employees. PSUs are whole share units and entitle employees to receive, upon vesting, either a common share of Cenovus or a cash payment equal to the value of a Cenovus common share. For a portion of PSUs, the number of PSUs eligible for payment is determined over three years based on the units granted multiplied by 30 percent after year one, 30 percent after year two and 40 percent after year three. All PSUs are eligible to vest based on the Company achieving key pre-determined performance measures. PSUs vest after three years.

The Company has recorded a liability of $37 million as at December 31, 2017 (2016 – $51 million) in the Consolidated Balance Sheets for PSUs based on the market value of Cenovus’s common shares at the end of the year. As PSUs are paid out upon vesting, the intrinsic value of vested PSUs was $nil as at December 31, 2017 and 2016.

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

As at December 31, 2017	Number of PSUs (thousands)
Outstanding, Beginning of Year	6,157
Granted	2,392
Vested and Paid Out	(451)
Cancelled	(1,192)
Units in Lieu of Dividends	112
Outstanding, End of Year	7,018

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 $41 million as at December 31, 2017 (2016 – $30 million) in the Consolidated Balance Sheets for RSUs based on the market value of Cenovus’s common shares at the end of the year. As RSUs are paid out upon vesting, the intrinsic value of vested RSUs was $nil as at December 31, 2017 and 2016.

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

As at December 31, 2017	Number of RSUs (thousands)
Outstanding, Beginning of Year	3,790
Granted	3,278
Vested and Paid Out	(101)
Cancelled	(282)
Units in Lieu of Dividends	100
Outstanding, End of Year	6,785

D) Deferred Share Units

Under two Deferred Share Unit Plans, Cenovus directors, officers and certain employees may receive DSUs, which are equivalent in value to a common share of the Company. Eligible employees have the option to convert either zero, 25 or 50 percent of their annual bonus award into DSUs. DSUs vestimmediately, are redeemed in accordance with the terms of the agreement and expire on December 15 of the calendar year following the year of cessation of directorship or employment.

The Company has recorded a liability of $17 million as at December 31, 2017 (2016 – $32 million) in the Consolidated Balance Sheets for DSUs based on the market value of Cenovus’s common shares at the end of the year. The intrinsic value of vested DSUs equals the carrying value as DSUs vest at the time of grant.

The following table summarizes the information related to the DSUs held by Cenovus directors, officers and employees:

As at December 31, 2017	Number of DSUs (thousands)
Outstanding, Beginning of Year	1,598
Granted to Directors	136
Granted	93
Units in Lieu of Dividends	27
Redeemed	(414)
Outstanding, End of Year	1,440

E) Total Stock-Based Compensation

For the years ended December 31,	2017	2016	2015
NSRs	9	15	27
TSARs	-	(1)	(5)
PSUs	(7)	13	(13)
RSUs	3	13	6
DSUs	(11)	7	(5)
Stock-Based Compensation Expense (Recovery)	(6)	47	10
Stock-Based Compensation Costs Capitalized	3	12	6
Total Stock-Based Compensation	(3)	59	16

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Employee Salaries and Benefit Expenses

12 Months Ended

Dec. 31, 2017

Disclosure Of Salaries And Employee Benefits [Abstract]

Employee Salaries and Benefit Expenses

30. EMPLOYEE SALARIES AND BENEFIT EXPENSES

For the years ended December 31,	2017	2016	2015
Salaries, Bonuses and Other Short-Term Employee Benefits	606	500	534
Defined Contribution Pension Plan	19	16	19
Defined Benefit Pension Plan and OPEB	8	11	17
Stock-Based Compensation Expense (Note 29)	(6)	47	10
Termination Benefits	19	19	43
	646	593	623

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Related Party Transactions

12 Months Ended

Dec. 31, 2017

Disclosure Of Transactions Between Related Parties [Abstract]

Related Party Transactions

31. 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,	2017	2016	2015
Salaries, Director Fees and Short-Term Benefits	26	27	30
Post-Employment Benefits	4	4	5
Stock-Based Compensation	6	4	5
	36	35	40

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

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Capital Structure

12 Months Ended

Dec. 31, 2017

Disclosure Of Objectives Policies And Processes For Managing Capital [Abstract]

Capital Structure

32. CAPITAL STRUCTURE

Cenovus’s capital structure objectives remain unchanged from previous periods. Cenovus’s capital structure consists of shareholders’ equity plus Net Debt. Net Debt includes the Company’s short-term borrowings, and the current and long-term portions of long-term debt, net of cash and cash equivalents. Cenovus conducts its business and makes decisions consistent with that of an investment grade company. The Company’s objectives when managing its capital structure are to maintain financial flexibility, preserve access to capital markets, ensure its ability to finance internally generated growth and to fund potential acquisitions while maintaining the ability to meet the Company’s financial obligations as they come due.

Cenovus monitors its capital structure and financing requirements using, among other things, non-GAAP financial metrics consisting of Net Debt to Adjusted Earnings Before Interest, Taxes and DD&A (“Adjusted EBITDA”) and Net Debt to Capitalization. These metrics are used to steward Cenovus’s overall debt position as measures of Cenovus’s overall financial strength.

Over the long term, Cenovus targets a Net Debt to Adjusted EBITDA ratio of less than 2.0 times. At different points within the economic cycle, Cenovus expects this ratio may periodically be above the target. Cenovus also manages its Net Debt to Capitalization ratio to ensure compliance with the associated covenant as defined in its committed credit facility agreement.

A) Net Debt to Adjusted EBITDA

As at December 31,	2017	2016	2015
Long-Term Debt	9,513	6,332	6,525
Less: Cash and Cash Equivalents	(610)	(3,720)	(4,105)
Net Debt	8,903	2,612	2,420
Net Earnings (Loss)	3,366	(545)	618
Add (Deduct):
Finance Costs	725	492	482
Interest Income	(62)	(52)	(28)
Income Tax Expense (Recovery)	352	(382)	(81)
DD&A	2,030	1,498	2,114
E&E Impairment	890	2	138
Unrealized (Gain) Loss on Risk Management	729	554	195
Foreign Exchange (Gain) Loss, Net	(812)	(198)	1,036
Revaluation (Gain)	(2,555)	-	-
Re-measurement of Contingent Payment	(138)	-	-
(Gain) Loss on Discontinuance	(1,285)	-	-
(Gain) Loss on Divestitures of Assets	1	6	(2,392)
Other (Income) Loss, Net	(5)	34	2
Adjusted EBITDA (1)	3,236	1,409	2,084
Net Debt to Adjusted EBITDA	2.8x	1.9x	1.2x

(1) Calculated on a trailing twelve-month basis. Includes discontinued operations.

B) Net Debt to Capitalization

As at December 31,	2017	2016	2015
Net Debt	8,903	2,612	2,420
Shareholders’ Equity	19,981	11,590	12,391
	28,884	14,202	14,811
Net Debt to Capitalization	31%	18%	16%

As at December 31, 2017, Cenovus’s Net Debt to Adjusted EBITDA is 2.8 times, which is above the Company’s target. However, it is important to note that Adjusted EBITDA is calculated on a rolling twelve month basis and as such, only includes the financial results from the Deep Basin Assets and the additional 50 percent of FCCL for the period May 17, 2017 to December 31, 2017. Net Debt is presented as at December 31, 2017; therefore, the ratio is burdened by the debt issued to finance the Acquisition. If Adjusted EBITDA reflected a full twelve months of earnings from the acquired assets, Cenovus’s Net Debt to Adjusted EBITDA ratio would be lower.

Cenovus’s objective is to maintain a high level of capital discipline and manage its capital structure to help ensure sufficient liquidity through all stages of the economic cycle. To ensure financial resilience, Cenovus may, among other actions, adjust capital and operating spending, draw down on its credit facility or repay existing debt, adjust dividends paid to shareholders, purchase shares for cancellation pursuant to normal course issuer bids, issue new debt, or issue new shares.

Cenovus has in place a committed credit facility that consists of a $1.2 billion tranche maturing on November 30, 2020 and a $3.3 billion tranche maturing on November 30, 2021. As at December 31, 2017, no amounts were drawn on its committed credit facility. Under the committed credit facility, the Company is required to maintain a debt to capitalization ratio, as defined in the agreement, not to exceed 65 percent. The Company is well below this limit.

In addition, the Company has in place a base shelf prospectus which expires in November 2019. As at December 31, 2017, US$4.6 billion remains available under the base shelf prospectus. Offerings under the base shelf prospectus are subject to market conditions.

As at December 31, 2017, Cenovus is in compliance with all of the terms of its debt agreements.

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Financial Instruments

12 Months Ended

Dec. 31, 2017

Disclosure Of Financial Instruments [Abstract]

Financial Instruments

33. FINANCIAL INSTRUMENTS

Cenovus’s financial assets and financial liabilities consist of cash and cash equivalents, accounts receivable and accrued revenues, accounts payable and accrued liabilities, risk management assets and liabilities, available for sale financial assets, long-term receivables, contingent payment, short-term borrowings and long-term debt. Risk management assets and liabilities arise from the use of derivative financial instruments.

A) Fair Value of Non-Derivative Financial Instruments

The fair values of cash and cash equivalents, accounts receivable and accrued revenues, accounts payable and accrued liabilities, and short-term borrowings approximate their carrying amount due to the short-term maturity of these instruments.

The fair values of long-term receivables approximate their carrying amount due to the specific non-tradeable nature of these instruments.

Long-term debt is carried at amortized cost. The estimated fair values of long-term borrowings have been determined based on period-end trading prices of long-term borrowings on the secondary market (Level 2). As at December 31, 2017, the carrying value of Cenovus’s debt was $9,513 million and the fair value was $10,061 million (2016 carrying value – $6,332 million; fair value – $6,539 million).

Available for sale financial assets comprise private equity investments. These assets are carried at fair value on the Consolidated Balance Sheets in other assets. Fair value is determined based on recent private placement transactions (Level 3) when available. The following table provides a reconciliation of changes in the fair value of available for sale financial assets:

As at December 31,	2017	2016
Fair Value, Beginning of Year	35	42
Net Acquisition of Investments	3	-
Change in Fair Value (1)	(1)	(4)
Impairment Losses (2)	-	(3)
Fair Value, End of Year	37	35

(1) Changes in fair value on available for sale financial assets are recorded in OCI.

(2) Impairment losses on available for sale financial assets are reclassified from OCI to profit or loss.

B) Fair Value of Risk Management Assets and Liabilities

The Company’s risk management assets and liabilities consist of crude oil swaps and options, as well as condensate and interest rate swaps. Crude oil, condensate and, if entered, natural gas contracts are recorded at their estimated fair value based on the difference between the contracted price and the period-end forward price for the same commodity, using quoted market prices or the period-end forward price for the same commodity extrapolated to the end of the term of the contract (Level 2). The fair value of interest rate swaps are calculated using external valuation models which incorporate observable market data, including interest rate yield curves (Level 2).

Summary of Unrealized Risk Management Positions

	2017			2016
	Risk Management			Risk Management
As at December 31,	Asset	Liability	Net	Asset	Liability	Net
Crude Oil	63	1,031	(968)	21	307	(286)
Interest Rate	2	20	(18)	3	8	(5)
Total Fair Value	65	1,051	(986)	24	315	(291)

The following table presents the Company’s fair value hierarchy for risk management assets and liabilities carried at fair value:

As at December 31,	2017	2016
Level 2 – Prices Sourced From Observable Data or Market Corroboration	(986)	(291)

Prices sourced from observable data or market corroboration refers to the fair value of contracts valued in part using active quotes and in part using observable, market-corroborated data.

The following table provides a reconciliation of changes in the fair value of Cenovus’s risk management assets and liabilities:

As at December 31,	2017	2016
Fair Value of Contracts, Beginning of Year	(291)		271
Fair Value of Contracts Realized During the Year (1)	200		(211)
Change in Fair Value of Contracts in Place at Beginning of Year and Contracts Entered Into During the Year	(929)		(343)
Unamortized Premium on Put Options	16		-
Unrealized Foreign Exchange Gain (Loss) on U.S. Dollar Contracts	18		(8)
Fair Value of Contracts, End of Year	(986)		(291)

(1) Includes a realized loss of $33 million (2016 – $58 million gain) related to the Conventional segment which is included in discontinued operations.

Financial assets and liabilities are offset only if Cenovus has the current legal right to offset and intends to settle on a net basis or settle the asset and liability simultaneously. Cenovus offsets risk management assets and liabilities when the counterparty, commodity, currency and timing of settlement are the same. No additional unrealized risk management positions are subject to an enforceable master netting arrangement or similar agreement that are not otherwise offset.

The following table provides a summary of the Company’s offsetting risk management positions:

	2017			2016
	Risk Management			Risk Management
As at December 31,	Asset	Liability	Net	Asset	Liability	Net
Recognized Risk Management Positions
Gross Amount	135	1,121	(986)	75	366	(291)
Amount Offset	(70)	(70)	-	(51)	(51)	-
Net Amount per Consolidated Financial  Statements	65	1,051	(986)	24	315	(291)

The derivative liabilities do not have credit risk-related contingent features. Due to credit practices that limit transactions according to counterparties’ credit quality, the change in fair value through profit or loss attributable to changes in the credit risk of financial liabilities is immaterial.

Cenovus pledges cash collateral with respect to certain of these risk management contracts, which is not offset against the related financial liability. The amount of cash collateral required will vary daily over the life of these risk management contracts as commodity prices change. Additional cash collateral is required if, on a net basis, risk management payables exceed risk management receivables on a particular day. As at December 31, 2017, $26 million (2016 – $84 million) was pledged as collateral, of which $nil (2016 – $18 million) could have been withdrawn.

C) Fair Value of Contingent Payment

The contingent payment is carried at fair value on the Consolidated Balance Sheets. Fair value is estimated by calculating the present value of the future expected cash flows using an option pricing model (Level 3), which assumes the probability distribution for WCS is based on the volatility of WTI options, volatility of Canadian-U.S. foreign exchange rate options and WCS futures pricing, and discounted at a credit-adjusted risk-free rate of 3.3 percent. Fair value of the contingent payment has been calculated by Cenovus’s internal valuation team which consists of individuals who are knowledgeable and have experience in fair value techniques. As at December 31, 2017, the fair value of the contingent payment was estimated to be $206 million.

As at December 31, 2017, average WCS forward pricing for the remaining term of the contingent payment is US$35.51 per barrel or C$44.55 per barrel. The average volatility of WTI options and the Canadian-U.S. foreign exchange rates used to value the contingent payment was 20 percent and seven percent, respectively. Changes in the following inputs to the option pricing model, with fluctuations in all other variables held constant, could have resulted in unrealized gains (losses) impacting earnings before income tax as follows:

	Sensitivity Range	Increase	Decrease
WCS Forward Prices	± $5.00 per bbl	(167)	111
WTI Option Volatility	± five percent	(95)	85
U.S. to Canadian Dollar Foreign Exchange Rate Volatility	± five percent	2	(27)

D) Earnings Impact of (Gains) Losses From Risk Management Positions

For the years ended December 31,	2017	2016	2015
Realized (Gain) Loss (1)	167	(153)	(447)
Unrealized (Gain) Loss (2)	729	554	195
(Gain) Loss on Risk Management From Continuing Operations	896	401	(252)

(1) Realized gains and losses on risk management are recorded in the reportable segment to which the derivative instrument relates. Excludes realized risk management losses of $33 million in 2017 (2016 – $58 million gain; 2015 – $209 million gain) that were classified as discontinued operations.

(2) Unrealized gains and losses on risk management are recorded in the Corporate and Eliminations segment.

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Risk Management

12 Months Ended

Dec. 31, 2017

Description Of Objectives Policies And Processes For Managing Risk [Abstract]

Risk Management

34. RISK MANAGEMENT

Cenovus is exposed to financial risks, including market risk related to commodity prices, foreign exchange rates, interest rates as well as credit risk and liquidity risk. To manage exposure to interest rate volatility, the Company entered into interest rate swap contracts related to expected future debt issuances. As at December 31, 2017, Cenovus had a notional amount of US$400 million in interest rate swaps. To mitigate the Company’s exposure to foreign exchange rate fluctuations, the Company periodically enters into foreign exchange contracts. No foreign exchange contracts were outstanding at December 31, 2017.

Net Fair Value of Risk Management Positions

As at December 31, 2017	Notional Volumes	Terms	Average Price	Fair Value Asset (Liability)
Crude Oil Contracts
Fixed Price Contracts
Brent Fixed Price	60,000 bbls/d	January – June 2018	US$53.34/bbl	(172)
WTI Fixed Price	150,000 bbls/d	January – June 2018	US$48.91/bbl	(384)
WTI Fixed Price	75,000 bbls/d	July – December 2018	US$49.32/bbl	(158)
Brent Put Options	25,000 bbls/d	January – June 2018	US$53.00/bbl	1
Brent Collars	80,000 bbls/d	January – June 2018	US$49.54 – US$59.86/bbl	(124)
Brent Collars	75,000 bbls/d	July – December 2018	US$49.00 – US$59.69/bbl	(110)
WTI Collars	10,000 bbls/d	January – June 2018	US$45.30 – US$62.77/bbl	(2)
WCS Differential	16,300 bbls/d	January – March 2018	US$(13.11)/bbl	14
WCS Differential	14,800 bbls/d	April – June 2018	US$(14.05)/bbl	7
WCS Differential	10,500 bbls/d	January – December 2018	US$(14.52)/bbl	25
Other Financial Positions (1)				(65)
Crude Oil Fair Value Position				(968)
Interest Rate Swaps				(18)
Total Fair Value				(986)

(1) Other financial positions are part of ongoing operations to market the Company’s production.

A) Commodity Price Risk

Commodity price risk arises from the effect that fluctuations of forward commodity prices may have on the fair value or future cash flows of financial assets and liabilities. To partially mitigate exposure to commodity price risk, the Company has entered into various financial derivative instruments.

The use of these derivative instruments is governed under formal policies and is subject to limits established by the Board of Directors. The Company’s policy does not allow the use of derivative instruments for speculative purposes.

Crude Oil – The Company has used fixed price swaps, put options and costless collars to partially mitigate its exposure to the commodity price risk on its crude oil sales. In addition, Cenovus has entered into a number of transactions to help protect against widening light/heavy crude oil price differentials.

Condensate – The Company has used fixed price swaps to partially mitigate its exposure to the commodity price risk on its condensate purchases.

Natural Gas – The Company may enter into transactions to partially mitigate its natural gas commodity price risk. To help protect against widening natural gas price differentials in various production areas, Cenovus may also enter into transactions to manage the price differentials between production areas and various sales points.

Sensitivities

The following table summarizes the sensitivity of the fair value of Cenovus’s risk management positions to fluctuations in commodity prices, with all other variables held constant. Management believes the fluctuations identified in the table below are a reasonable measure of volatility. The impact of fluctuating commodity prices and interest rates on the Company’s open risk management positions could have resulted in unrealized gains (losses) impacting earnings before income tax as follows:

As at December 31, 2017	Sensitivity Range	Increase	Decrease
Crude Oil Commodity Price	± US$5.00 per bbl Applied to Brent, WTI and Condensate Hedges	(529)	507
Crude Oil Differential Price	± US$2.50 per bbl Applied to Differential Hedges Tied to Production	11	(11)

As at December 31, 2016	Sensitivity Range	Increase	Decrease
Crude Oil Commodity Price	± US$5.00 per bbl Applied to Brent, WTI and Condensate Hedges	(198)	193
Crude Oil Differential Price	± US$2.50 per bbl Applied to Differential Hedges Tied to Production	1	(1)

B) Foreign Exchange Risk

Foreign exchange risk arises from changes in foreign exchange rates that may affect the fair value or future cash flows of Cenovus’s financial assets or liabilities. As Cenovus operates in North America, fluctuations in the exchange rate between the U.S./Canadian dollar can have a significant effect on reported results.

As disclosed in Note 7, Cenovus’s foreign exchange (gain) loss primarily includes unrealized foreign exchange gains and losses on the translation of the U.S. dollar debt issued from Canada. As at December 31, 2017, Cenovus had US$7,650 million in U.S. dollar debt issued from Canada (2016 – US$4,750 million). In respect of these financial instruments, the impact of changes in the U.S. to Canadian dollar exchange rate would have resulted in a change to the foreign exchange (gain) loss as follows:

For the years ended December 31,	2017	2016
$0.01 Increase in the U.S. to Canadian Dollar Foreign Exchange Rate	77	48
$0.01 Decrease in the U.S. to Canadian Dollar Foreign Exchange Rate	(77)	(48)

C) Interest Rate Risk

Interest rate risk arises from changes in market interest rates that may affect earnings, cash flows and valuations. Cenovus has the flexibility to partially mitigate its exposure to interest rate changes by maintaining a mix of both fixed and floating rate debt. In addition, to manage exposure to interest rate volatility, the Company entered into interest rate swap contracts. As at December 31, 2017, Cenovus had a notional amount of US$400 million (2016 – US$400 million) in interest rate swaps. In respect of these financial instruments, the impact of changes in the interest rate would have resulted in a change to unrealized gains (losses) impacting earnings before income tax as follows:

For the years ended December 31,	2017	2016
50 Basis Points Increase	44	45
50 Basis Points Decrease	(50)	(52)

As at December 31, 2017, the increase or decrease in net earnings for a one percent change in interest rates on floating rate debt amounts to $nil (2016 – $nil; 2015 – $nil). This assumes the amount of fixed and floating debt remains unchanged from the respective balance sheet dates.

D) Credit Risk

Credit risk arises from the potential that the Company may incur a financial loss if a counterparty to a financial instrument fails to meet its financial or performance obligations in accordance with agreed terms. Cenovus has in place a Credit Policy approved by the Audit Committee of the Board of Directors designed to ensure that its credit exposures are within an acceptable risk level as determined by the Company’s Enterprise Risk Management Policy. The Credit Policy outlines the roles and responsibilities related to credit risk, sets a framework for how credit exposures will be measured, monitored and mitigated, and sets parameters around credit concentration limits.

Cenovus assesses the credit risk of new counterparties and continues risk-based monitoring of all counterparties on an ongoing basis. A substantial portion of Cenovus’s accounts receivable are with customers in the oil and gas industry and are subject to normal industry credit risks. Cenovus’s exposure to its counterparties is within credit policy tolerances.

As at December 31, 2017 and 2016, substantially all of the Company’s accounts receivable were less than 60 days. As at December 31, 2017, 89 percent (2016 – 90 percent) of Cenovus’s accounts receivable and financial derivative credit exposures are with investment grade counterparties. As at December 31, 2017, Cenovus had three counterparties (2016 – three counterparties) whose net settlement position individually accounted for more than 10 percent of the fair value of the outstanding in-the-money net financial and physical contracts. The 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 the Company will not be able to meet all of its financial obligations as they become due. Liquidity risk also includes the risk of not being able to liquidate assets in a timely manner at a reasonable price. Cenovus manages its liquidity risk through the active management of cash and debt and by maintaining appropriate access to credit, which may be impacted by the Company’s credit ratings. As disclosed in Note 32, over the long term, Cenovus targets a Net Debt to Adjusted EBITDA of less than 2.0 times to manage the Company’s overall debt position.

Cenovus manages its liquidity risk by ensuring that it has access to multiple sources of capital including: cash and cash equivalents, cash from operating activities, undrawn credit facility capacity and availability under its shelf prospectus. As at December 31, 2017, Cenovus had $610 million in cash and cash equivalents, and $4.5 billion available on its committed credit facility. In addition, Cenovus has unused capacity of US$4.6 billion under a base shelf prospectus, the availability of which is dependent on market conditions.

Undiscounted cash outflows relating to financial liabilities are:

As at December 31, 2017	Less than 1 Year	Years 2 and 3	Years 4 and 5	Thereafter	Total
Accounts Payable and Accrued Liabilities	2,635	-	-	-	2,635
Risk Management Liabilities (1)	1,031	20	-	-	1,051
Long-Term Debt (2)	494	2,527	1,429	13,309	17,759
Other	-	21	11	16	48

As at December 31, 2016	Less than 1 Year	Years 2 and 3	Years 4 and 5	Thereafter	Total
Accounts Payable and Accrued Liabilities	2,266	-	-	-	2,266
Risk Management Liabilities (1)	293	22	-	-	315
Long-Term Debt (2)	339	2,662	1,150	7,550	11,701
Other	-	25	8	16	49

(1) Risk management liabilities subject to master netting agreements.

(2) Principal and interest, including current portion.

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Supplementary Cash Flow Information

12 Months Ended

Dec. 31, 2017

Disclosure Of Supplementary Cash Flow Information [Abstract]

Supplementary Cash Flow Information

35. SUPPLEMENTARY CASH FLOW INFORMATION

For the years ended December 31,	2017	2016	2015
Interest Paid	538	350	330
Interest Received	31	32	19
Income Taxes Paid	12	11	933

The following table provides a reconciliation of cash flows arising from financing activities:

	Dividends Payable	Current Portion of Long-Term Debt	Long-Term Debt	Share Capital
As at December 31, 2015	-	-	6,525	5,534
Changes From Financing Cash Flows:
Dividends Paid	(166)	-	-	-
Non-Cash Changes:
Dividends Declared	166	-	-	-
Unrealized Foreign Exchange (Gain) Loss (Note 7)	-	-	(196)	-
Amortization of Debt Discounts	-	-	3	-
As at December 31, 2016	-	-	6,332	5,534
Changes From Financing Cash Flows:
Issuance of Long-Term Debt	-	-	3,842	-
Net Issuance (Repayment) of Revolving Long-Term Debt	-	-	32	-
Issuance of Debt Under Asset Sale Bridge Facility	-	892	2,677	-
(Repayment) of Debt Under Asset Sale Bridge Facility	-	(900)	(2,700)	-
Common Shares Issued, Net of Issuance Costs	-	-	-	2,899
Dividends Paid	(225)	-	-	-
Non-Cash Changes:
Common Shares Issued to ConocoPhillips	-	-	-	2,579
Deferred Taxes on Share Issuance Costs	-	-	-	28
Dividends Declared	225	-	-	-
Unrealized Foreign Exchange (Gain) Loss	-	-	(697)	-
Finance Costs	-	8	28	-
Other	-	-	(1)	-
As at December 31, 2017	-	-	9,513	11,040

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Commitments and Contingencies

12 Months Ended

Dec. 31, 2017

Commitments And Contingencies Abstract

Commitments and Contingencies

36. COMMITMENTS AND CONTINGENCIES

A) Commitments

Future payments for the Company’s commitments are below. A commitment is an enforceable and legally binding agreement to make a payment in the future for the purchase of goods and services. These items exclude amounts recorded in the Consolidated Balance Sheets.

As at December 31, 2017	1 Year	2 Years	3 Years	4 Years	5 Years	Thereafter	Total
Transportation and Storage (1)	899	886	919	1,123	1,223	13,260	18,310
Operating Leases (Building Leases) (2)	155	146	142	141	140	2,305	3,029
Capital Commitments	16	2	-	-	-	-	18
Other Long-Term Commitments	109	39	32	28	25	122	355
Total Payments (3)	1,179	1,073	1,093	1,292	1,388	15,687	21,712
Fixed Price Product Sales	-	-	-	-	-	-	-

As at December 31, 2016	1 Year	2 Years	3 Years	4 Years	5 Years	Thereafter	Total
Transportation and Storage (1)	682	711	722	1,031	1,239	21,875	26,260
Operating Leases (Building Leases) (2)	101	146	146	145	142	2,465	3,145
Product Purchases	70	-	-	-	-	-	70
Capital Commitments	23	3	-	-	-	-	26
Other Long-Term Commitments	80	27	26	15	15	108	271
Total Payments (3)	956	887	894	1,191	1,396	24,448	29,772
Fixed Price Product Sales	3	-	-	-	-	-	3

(1) Includes transportation commitments of $9 billion (2016 – $19 billion) that are subject to regulatory approval or have been approved, but are not yet in service.

(2) Excludes committed payment for which a provision has been provided.

(3) For 2017, contracts undertaken on behalf of WRB are reflected at Cenovus’s 50 percent interest. For 2016, contracts undertaken on behalf of FCCL and WRB are reflected at Cenovus’s 50 percent interest.

Commitments for various pipeline transportation arrangements decreased $8.0 billion from 2016 primarily due to pipeline project cancellations, partially offset by incremental commitments included with the Acquisition and newly executed transportation agreements. Terms are up to 20 years subsequent to the date of commencement.

As at December 31, 2017, there were outstanding letters of credit aggregating $376 million issued as security for performance under certain contracts (2016 – $258 million).

In addition to the above, Cenovus’s commitments related to its risk management program are disclosed in Note 34.

B) Contingencies

Legal Proceedings

Cenovus is involved in a limited number of legal claims associated with the normal course of operations. Cenovus believes that any liabilities that might arise from such matters, to the extent not provided for, are not likely to have a material effect on its Consolidated Financial Statements.

Decommissioning Liabilities

Cenovus is responsible for the retirement of long-lived assets at the end of their useful lives. Cenovus has recorded a liability of $1,029 million, based on current legislation and estimated costs, related to its upstream properties, refining facilities and midstream facilities. Actual costs may differ from those estimated due to changes in legislation and changes in costs.

Income Tax Matters

The tax regulations and legislation and interpretations thereof in the various jurisdictions in which Cenovus operates are continually changing. As a result, there are usually a number of tax matters under review. Management believes that the provision for taxes is adequate.

Contingent Payment

In connection with the Acquisition, Cenovus agreed to make quarterly payments to ConocoPhillips during the five years subsequent to May 17, 2017 for quarters in which the average WCS crude oil price exceeds $52.00 per barrel during the quarter. As at December 31, 2017, the estimated fair value of the contingent payment was $206 million (see Note 22).

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Summary of Significant Accounting Policies (Policies)

12 Months Ended

Dec. 31, 2017

Disclosure Of Summary Of Significant Accounting Policies [Abstract]

Principles of Consolidation

A) Principles of Consolidation

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

Interests in joint arrangements are classified as either joint operations or joint ventures, depending on the rights and obligations of the parties to the arrangement. Joint operations arise when the Company has rights to the assets and obligations for the liabilities of the arrangement. The Company’s Refining activities are conducted through the joint operation WRB Refining LP (“WRB”) and, accordingly, the accounts reflect the Company’s share of the assets, liabilities, revenues and expenses. Prior to May 17, 2017, FCCL was accounted for as a joint operation. Subsequent to the Acquisition, Cenovus controls FCCL, and accordingly, FCCL has been consolidated.

Foreign Currency Translation

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.

Revenue Recognition

C) Revenue Recognition

Revenues associated with the sales of Cenovus’s crude oil, NGLs, natural gas, and petroleum and refined products are recognized when the significant risks and rewards of ownership have been transferred to the customer, the sales price and costs can be measured reliably and it is probable that the economic benefits will flow to the Company. This is generally met when title passes from the Company to its customer. Revenues from the production of crude oil, NGLs and natural gas represent the Company’s share, net of royalty payments to governments and other mineral interest owners.

Processing income and revenue from fee-for-service hydrocarbon trans-loading services is recognized in the period the service is provided.

Purchases and sales of products that are entered into in contemplation of each other with the same counterparty are recorded on a net basis. Revenues associated with the services provided as agent are recorded as the services are provided.

Transportation and Blending

D) Transportation and Blending

The costs associated with the transportation of crude oil, NGLs and natural gas, including the cost of diluent used in blending, are recognized when the product is sold.

Exploration Expense

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.

Employee Benefit Plans

F) Employee Benefit Plans

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

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

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

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

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

• Net interest is calculated by applying the same discount rate used to measure the defined benefit obligation at the beginning of the annual period to the net defined benefit asset or liability measured. Interest expense and interest income on net post-employment benefit liabilities and assets are recorded with pension benefit costs in operating, and general and administrative expenses, as well as PP&E and E&E assets.

• Remeasurements, composed of actuarial gains and losses, the effect of changes to the asset ceiling (excluding interest) and the return on plan assets (excluding interest income), are charged or credited to equity in OCI in the period in which they arise. Remeasurements are not reclassified to net earnings in subsequent periods.

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

Income Taxes

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.

Net Earnings per Share Amounts

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.

Cash and Cash Equivalents

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.

Inventories

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.

Exploration and Evaluation Assets

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.

Property, Plant and Equipment

L) Property, Plant and Equipment

General

PP&E is stated at cost less accumulated depreciation, depletion and amortization (“DD&A”), and net of any impairment losses. Expenditures related to renewals or betterments that improve the productive capacity or extend the life of an asset are capitalized. Maintenance and repairs are expensed as incurred. Land is not depreciated.

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

Development and Production Assets

Development and production assets are capitalized on an area-by-area basis and include all costs associated with the development and production of crude oil and natural gas properties, as well as any E&E expenditures incurred in finding reserves of crude oil, NGLs or natural gas transferred from E&E assets. Capitalized costs include directly attributable internal costs, decommissioning liabilities and, for qualifying assets, borrowing costs directly associated with the acquisition of, the exploration for, and the development of crude oil and natural gas reserves.

Costs accumulated within each area are depleted using the unit-of-production method based on estimated proved reserves determined using forward prices and costs. For the purpose of this calculation, natural gas is converted to crude oil on an energy equivalent basis. Costs subject to depletion include estimated future costs to be incurred in developing proved reserves.

Exchanges of development and production assets are measured at fair value unless the transaction lacks commercial substance or the fair value of neither the asset received, nor the asset given up, can be reliably measured. When fair value is not used, the carrying amount of the asset given up is used as the cost of the asset acquired.

Other Upstream Assets

Other upstream assets include information technology assets used to support the upstream business. These assets are depreciated on a straight-line basis over their useful lives of three years.

Refining Assets

The initial acquisition costs of refining PP&E are capitalized when incurred. Costs include the cost of constructing or otherwise acquiring the equipment or facilities, the cost of installing the asset and making it ready for its intended use, the associated decommissioning costs and, for qualifying assets, borrowing costs.

Refining assets are depreciated on a straight-line basis over the estimated service life of each component of the refinery. The major components are depreciated as follows:

Land improvements and buildings	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.

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.

Impairment

M) Impairment

Non-Financial Assets

PP&E and E&E assets are reviewed separately for indicators of impairment quarterly or when facts and circumstances suggest that the carrying amount may exceed its recoverable amount. Goodwill is tested for impairment at least annually.

If indicators of impairment exist, the recoverable amount of the cash-generating unit (“CGU”) is estimated as the greater of value-in-use (“VIU”) and fair value less costs of disposal (“FVLCOD”). VIU is estimated as the present value of the future cash flows expected to arise from the continuing use of a CGU or an asset. FVLCOD is determined by estimating the discounted after-tax future net cash flows. For Cenovus’s upstream assets, FVLCOD is based on the discounted after-tax cash flows of reserves and resources using forward prices and costs, consistent with Cenovus’s independent qualified reserves evaluators (“IQREs”), and may consider an evaluation of comparable asset transactions.

E&E assets are allocated to a related CGU containing development and production assets for the purposes of testing for impairment. Goodwill is allocated to the CGUs to which it contributes to the future cash flows.

If the recoverable amount of the CGU is less than the carrying amount, an impairment loss is recognized. An impairment loss is allocated first to reduce the carrying amount of any goodwill allocated to the CGU and then to reduce the carrying amounts of the other assets in the CGU. Goodwill impairments are not reversed.

Impairment losses on PP&E and E&E assets are recognized in the Consolidated Statements of Earnings as additional DD&A and exploration expense, respectively.

Impairment losses recognized in prior periods, other than goodwill impairments, are assessed at each reporting date for any indicators that the impairment losses may no longer exist or may have decreased. In the event that an impairment loss reverses, the carrying amount of the asset is increased to the revised estimate of its recoverable amount, but only to the extent that the carrying amount does not exceed the amount that would have been determined had no impairment loss been recognized on the asset in prior periods. The amount of the reversal is recognized in net earnings.

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.

Leases

N) Leases

Leases in which substantially all of the risks and rewards of ownership are retained by the lessor are classified as operating leases. Operating lease payments are recognized as an expense on a straight-line basis over the lease term.

Leases where the Company assumes substantially all the risks and rewards of ownership are classified as finance leases. At inception, a leased asset within PP&E and a corresponding lease obligation are recognized. The leased asset is depreciated over the shorter of the estimated useful life of the asset or the lease term.

Business Combinations and Goodwill

O) Business Combinations and Goodwill

Business combinations are accounted for using the acquisition method of accounting in which the identifiable assets acquired, liabilities assumed and non-controlling interest, if any, are recognized and measured at their fair value at the date of acquisition. Any excess of the purchase price plus any non-controlling interest over the fair value of the net assets acquired is recognized as goodwill. Any deficiency of the purchase price over the fair value of the net assets acquired is credited to net earnings.

At acquisition, goodwill is allocated to each of the CGUs to which it relates. Subsequent measurement of goodwill is at cost less any accumulated impairment losses.

Contingent consideration transferred in a business combination is measured at fair value on the date of acquisition and classified as a financial liability or equity. Contingent consideration classified as a liability is re-measured at fair value at each reporting date, with changes in fair value recognized in net earnings. Payments are classified as cash used in investing activities until the cumulative payments exceed the acquisition date fair value of the liability. Cumulative payments in excess of the acquisition date fair value are classified as cash used in operating activities. Contingent consideration classified as equity are not re-measured and settlements are accounted for within equity.

When a business combination is achieved in stages, the Company re-measures its pre-existing interest at the acquisition date fair value and recognizes the resulting gain or loss, if any, in net earnings.

Provisions

P) Provisions

General

A provision is recognized if, as a result of a past event, the Company has a present obligation, legal or constructive, that can be estimated reliably, and it is more likely than not that an outflow of economic benefits will be required to settle the obligation. Where applicable, provisions are determined by discounting the expected future cash flows at a pre-tax credit-adjusted rate that reflects the current market assessments of the time value of money and the risks specific to the liability. The increase in the provision due to the passage of time is recognized as a finance cost in the Consolidated Statements of Earnings.

Decommissioning Liabilities

Decommissioning liabilities include those legal or constructive obligations where the Company will be required to retire tangible long-lived assets such as producing well sites, upstream processing facilities, refining facilities and the crude-by-rail terminal. The amount recognized is the present value of estimated future expenditures required to settle the obligation using a credit-adjusted risk-free rate. A corresponding asset equal to the initial estimate of the liability is capitalized as part of the cost of the related long-lived asset. Changes in the estimated liability resulting from revisions to expected timing or future decommissioning costs are recognized as a change in the decommissioning liability and the related long-lived asset. The amount capitalized in PP&E is depreciated over the useful life of the related asset.

Actual expenditures incurred are charged against the accumulated liability.

Share Capital

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.

Stock-Based Compensation

R) Stock-Based Compensation

Cenovus has a number of stock-based compensation plans which include stock options with associated net settlement rights (“NSRs”), stock options with associated tandem stock appreciation rights (“TSARs”), performance share units (“PSUs”), restricted share units (“RSUs”) and deferred share units (“DSUs”). Stock-based compensation costs are recorded in general and administrative expense, or E&E and PP&E when directly related to exploration or development activities.

Net Settlement Rights

NSRs are accounted for as equity instruments, which are measured at fair value on the grant date using the Black-Scholes-Merton valuation model and are not revalued at each reporting date. The fair value is recognized as stock-based compensation costs over the vesting period, with a corresponding increase recorded as paid in surplus in Shareholders’ Equity. On exercise, the cash consideration received by the Company and the associated paid in surplus are recorded as share capital.

Tandem Stock Appreciation Rights

TSARs are accounted for as liability instruments, which are measured at fair value at each period end using the Black-Scholes-Merton valuation model. The fair value is recognized as stock-based compensation costs over the vesting period. When options are settled for cash, the liability is reduced by the cash settlement paid. When options are settled for common shares, the cash consideration received by the Company and the previously recorded liability associated with the option are recorded as share capital.

Performance, Restricted and Deferred Share Units

PSUs, RSUs and DSUs are accounted for as liability instruments and are measured at fair value based on the market value of Cenovus’s common shares at each period end. The fair value is recognized as stock-based compensation costs over the vesting period. Fluctuations in the fair values are recognized as stock-based compensation costs in the period they occur.

Financial Instruments

S) Financial Instruments

The Company’s financial assets include cash and cash equivalents, accounts receivable and accrued revenues, risk management assets, investments in the equity of private companies and long-term receivables. The Company’s financial liabilities include accounts payable and accrued liabilities, contingent payment, risk management liabilities, short-term borrowings and long-term debt.

Financial instruments are recognized when the Company becomes a party to the contractual provisions of the instrument. Financial assets and liabilities are not offset unless the Company has the current legal right to offset and intends to settle on a net basis or settle the asset and liability simultaneously. A financial asset is derecognized when the rights to receive cash flows from the asset have expired or have been transferred and the Company has transferred substantially all the risks and rewards of ownership. A financial liability is derecognized when the obligation is discharged, cancelled or expired. When an existing financial liability is replaced by another from the same counterparty with substantially different terms, or the terms of an existing liability are substantially modified, this exchange or modification is treated as a derecognition of the original liability and the recognition of a new liability. The difference in the carrying amounts of the liabilities is recognized in the Consolidated Statements of Earnings.

Financial instruments are classified as either “fair value through profit and loss”, “loans and receivables”, “held-to-maturity investments”, “available for sale financial assets” or “financial liabilities measured at amortized cost”. The Company determines the classification of its financial instruments at initial recognition. Financial instruments are initially measured at fair value except in the case of “financial liabilities measured at amortized cost”, which are initially measured at fair value net of directly attributable transaction costs.

As required by IFRS, the Company characterizes its fair value measurements into a three-level hierarchy depending on the degree to which the inputs are observable, as follows:

• Level 1 inputs are quoted prices in active markets for identical assets and liabilities;

• Level 2 inputs are inputs, other than quoted prices included within Level 1, that are observable for the asset or liability either directly or indirectly; and

• Level 3 inputs are unobservable inputs for the asset or liability.

Fair Value Through Profit or Loss

Financial assets and financial liabilities at “fair value through profit or loss” are either “held-for-trading” or have been “designated at fair value through profit or loss.” In both cases, the financial assets and financial liabilities are measured at fair value with changes in fair value recognized in net earnings.

Risk management assets and liabilities are derivative financial instruments classified as “held-for-trading” unless designated for hedge accounting. Derivative instruments that do not qualify as hedges, or are not designated as hedges, are recorded using mark-to-market accounting whereby instruments are recorded in the Consolidated Balance Sheets as either an asset or liability with changes in fair value recognized in net earnings as a (gain) loss on risk management. Derivative financial instruments are not used for speculative purposes.

The Company has classified its contingent payment as “fair value through profit or loss.”

Loans and Receivables

“Loans and receivables” are financial assets with fixed or determinable payments that are not quoted in an active market. After initial measurement, these assets are measured at amortized cost at the settlement date using the effective interest method of amortization. “Loans and receivables” comprise cash and cash equivalents, accounts receivable and accrued revenues, and long-term receivables. Gains and losses on “loans and receivables” are recognized in net earnings when the “loans and receivables” are derecognized or impaired.

Available for Sale Financial Assets

“Available for sale financial assets” are measured at fair value, with changes in fair value recognized in OCI. When an active market is non-existent, fair value is determined using valuation techniques. When fair value cannot be reliably measured, such assets are carried at cost. Available for sale financial assets comprise investments in the equity of private companies that the Company does not control or have significant influence over.

Financial Liabilities Measured at Amortized Cost

These financial liabilities are measured at amortized cost at the settlement date using the effective interest method of amortization. Financial liabilities measured at amortized cost comprise accounts payable and accrued liabilities, short-term borrowings and long-term debt. Long-term debt transaction costs, premiums and discounts are capitalized within long-term debt or as a prepayment and amortized using the effective interest method.

Reclassification

T) Reclassification

Certain information provided for prior years has been reclassified to conform to the presentation adopted in 2017.

Recent Accounting Pronouncements

U) Recent Accounting Pronouncements

New Accounting Standards and Interpretations not yet Adopted

A number of new accounting standards, amendments to accounting standards and interpretations are effective for annual periods beginning on or after January 1, 2018 and have not been applied in preparing the Consolidated Financial Statements for the year ended December 31, 2017. The standards applicable to Cenovus are as follows and will be adopted on their respective effective dates:

Financial Instruments

On July 24, 2014, the IASB issued the final version of IFRS 9, “Financial Instruments” (“IFRS 9”) to replace IAS 39, “Financial Instruments: Recognition and Measurement” (“IAS 39”).

IFRS 9 introduces a single approach to determine whether a financial asset is measured at amortized cost or fair value and replaces the multiple rules in IAS 39. The approach is based on how an entity manages its financial instruments in the context of its business model and the contractual cash flow characteristics of the financial assets. The IAS 39 measurement categories for financial assets will be replaced by fair value through profit or loss, fair value through other comprehensive income (“FVOCI”) and amortized cost. The standard eliminates the existing IAS 39 categories of held to maturity, loans and receivables and available for sale. Based on Management’s assessment, the change in categories will not have a material impact on the Consolidated Financial Statements. As at December 31, 2017, the Company has private equity investments classified as available for sale with a fair value of $37 million. Under IFRS 9, the Company has elected to measure these investments as FVOCI. As such, all fair value gains or losses will be recorded in OCI, impairments will not be recognized in net earnings and fair value gains or losses will not be recycled to net earnings on disposition.

IFRS 9 retains most of the IAS 39 requirements for financial liabilities. However, where the fair value option is applied to financial liabilities, the change in fair value resulting from an entity’s own credit risk is recorded in OCI rather than net earnings, unless this creates an accounting mismatch. Cenovus currently does not designate any financial liabilities as fair value through profit or loss; therefore, there will be no impact on the accounting for financial liabilities.

A new expected credit loss model for calculating impairment on financial assets replaces the incurred loss impairment model used in IAS 39. The new model will result in more timely recognition of expected credit losses. Management does not expect a material change to its impairment provision as at January 1, 2018.

In addition, IFRS 9 includes a simplified hedge accounting model, aligning hedge accounting more closely with risk management. Cenovus does not currently apply hedge accounting.

IFRS 9 must be adopted for years beginning on or after January 1, 2018. The Company will apply the new standard retrospectively and elect to use the practical expedients permitted under the standard. Comparative periods will not be restated.

Revenue Recognition

On May 28, 2014, the IASB issued IFRS 15, “Revenue From Contracts With Customers” (“IFRS 15”) replacing IAS 11, “Construction Contracts”, IAS 18, “Revenue” and several revenue-related interpretations. IFRS 15 establishes a single revenue recognition framework that applies to contracts with customers. The standard requires an entity to recognize revenue to reflect the transfer of goods and services for the amount it expects to receive, when control is transferred to the purchaser. Disclosure requirements have also been expanded.

Management has assessed the impact of applying the new standard on the Consolidated Financial Statements and has not identified any material differences from its current revenue recognition practice.

The adoption of IFRS 15 is mandatory for years beginning on or after January 1, 2018. The standard may be applied either retrospectively or using a modified retrospective approach. Cenovus intends to adopt the standard using the modified retrospective approach recognizing the cumulative impact of adoption in retained earnings as of January 1, 2018. Comparative periods will not be restated. The Company will apply IFRS 15 using the practical expedient in paragraph C5(a) of IFRS 15, under which the Company will not restate contracts that are completed contracts as at the date of adoption.

Leases

On January 13, 2016, the IASB issued IFRS 16, “Leases” (“IFRS 16”), which requires entities to recognize lease assets and lease obligations on the balance sheet. For lessees, IFRS 16 removes the classification of leases as either operating leases or finance leases, effectively treating all leases as finance leases. Certain short-term leases (less than 12 months) and leases of low-value assets are exempt from the requirements, and may continue to be treated as operating leases.

Lessors will continue with a dual lease classification model. Classification will determine how and when a lessor will recognize lease revenue, and what assets would be recorded.

IFRS 16 is effective for years beginning on or after January 1, 2019, with early adoption permitted if IFRS 15 has been adopted. The standard may be applied retrospectively or using a modified retrospective approach. The modified retrospective approach does not require restatement of prior period financial information as it recognizes the cumulative effect of applying the standard to prior periods as an adjustment to opening retained earnings. It is anticipated that the adoption of IFRS 16 will have a material impact on the Company’s Consolidated Balance Sheets due to material operating lease commitments. Cenovus will adopt IFRS 16 effective January 1, 2019. The Company intends to adopt the standard using the retrospective with cumulative effect approach and apply several of the practical expedients available.

Uncertain Tax Positions

In June 2017, the IASB issued International Financial Reporting Interpretation Committee 23, “Uncertainty Over Income Tax Treatments” (“IFRIC 23”). The interpretation provides clarity on how to account for a tax position when there is uncertainty over income tax treatments. In determining the likely resolution of the uncertain tax positions, a position may be considered separately or as a group. In addition, an assessment is required to determine the probability that the tax authority will accept the tax position taken in income tax filings. If the uncertain income tax treatment is unlikely to be accepted, the accounting tax position must reflect an appropriate level of uncertainty. An uncertain tax position may be reassessed if new information changes the original assessment. IFRIC 23 is effective for annual periods beginning on or after January 1, 2019 using either a modified or full retrospective approach. IFRIC 23 is not expected to have a significant impact on the Consolidated Financial Statements.

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Description of Business and Segmented Disclosures (Tables)

12 Months Ended

Dec. 31, 2017

Disclosure Of Reportable Segments [Abstract]

Schedule of Segment and Operational Information

A) Results of Operations – Segment and Operational Information

	Oil Sands				Deep Basin				Refining and Marketing
For the years ended December 31,	2017	2016	2015	2017		2016	2015	2017		2016	2015
Revenues
Gross Sales	7,362	2,929	3,030	555		-	-	9,852		8,439	8,805
Less: Royalties	230	9	29	41		-	-	-		-	-
	7,132	2,920	3,001	514		-	-	9,852		8,439	8,805
Expenses
Purchased Product	-	-	-	-		-	-	8,476		7,325	7,709
Transportation and Blending	3,704	1,721	1,815	56		-	-	-		-	-
Operating	934	501	531	250		-	-	772		742	754
Production and Mineral Taxes	-	-	-	1		-	-	-		-	-
(Gain) Loss on Risk Management	307	(179)	(404)	-		-	-	6		26	(43)
Operating Margin	2,187	877	1,059	207		-	-	598		346	385
Depreciation, Depletion and Amortization	1,230	655	697	331		-	-	215		211	191
Exploration Expense	888	2	67	-		-	-	-		-	-
Segment Income (Loss)	69	220	295	(124)		-	-	383		135	194

	Corporate and Eliminations			Consolidated
For the years ended December 31,	2017	2016	2015 (1)	2017	2016	2015
Revenues
Gross Sales	(455)	(353)	(276)	17,314	11,015	11,559
Less: Royalties	-	-	1	271	9	30
	(455)	(353)	(277)	17,043	11,006	11,529
Expenses
Purchased Product	(443)	(347)	(335)	8,033	6,978	7,374
Transportation and Blending	(12)	(6)	(1)	3,748	1,715	1,814
Operating	(7)	(4)	(4)	1,949	1,239	1,281
Production and Mineral Taxes	-	-	1	1	-	1
(Gain) Loss on Risk Management	583	554	195	896	401	(252)
Depreciation, Depletion and Amortization	62	65	105	1,838	931	993
Exploration Expense	-	-	-	888	2	67
Segment Income (Loss)	(638)	(615)	(238)	(310)	(260)	251
General and Administrative	308	326	335	308	326	335
Finance Costs	645	390	381	645	390	381
Interest Income	(62)	(52)	(28)	(62)	(52)	(28)
Foreign Exchange (Gain) Loss, Net	(812)	(198)	1,036	(812)	(198)	1,036
Revaluation (Gain)	(2,555)	-	-	(2,555)	-	-
Transaction Costs	56	-	-	56	-	-
Re-measurement of Contingent Payment	(138)	-	-	(138)	-	-
Research Costs	36	36	27	36	36	27
(Gain) Loss on Divestiture of Assets	1	6	(2,392)	1	6	(2,392)
Other (Income) Loss, Net	(5)	34	2	(5)	34	2
	(2,526)	542	(639)	(2,526)	542	(639)
Earnings (Loss) From Continuing Operations Before Income Tax				2,216	(802)	890
Income Tax Expense (Recovery)				(52)	(343)	(24)
Net Earnings (Loss) From Continuing Operations				2,268	(459)	914

(1) The complete results for the 2017 and 2016 Conventional segment have been classified as a discontinued operation. For the 2015 comparative period, the results of operations for certain Conventional segment royalty interest assets disposed of in 2015 have been included in the Corporate and Eliminations segment due to their immaterial nature. The results of operations are as follows: revenues – $60 million, expenses – $5 million, operating margin – $55 million, depreciation, depletion and amortization – $27 million and segment income – $28 million.

Schedule of Revenues by Product

B) Revenues by Product

For the years ended December 31,	2017	2016	2015
Upstream
Crude Oil	7,184	2,902	2,971
Natural Gas (1)	235	16	22
NGLs	184	-	-
Other	43	2	8
Refining and Marketing	9,852	8,439	8,805
Corporate and Eliminations	(455)	(353)	(277)
Revenues From Continuing Operations	17,043	11,006	11,529

(1) In 2017, approximately 14 percent of the natural gas produced by Cenovus’s Deep Basin Assets was sold to ConocoPhillips resulting in gross sales of $32 million.

Schedule of Geographical Information

C) Geographical Information

	Revenues
For the years ended December 31,	2017	2016	2015
Canada	9,723	4,978	4,729
United States	7,320	6,028	6,800
Consolidated	17,043	11,006	11,529

	Non-Current Assets (1)
As at December 31,	2017	2016
Canada (2)	31,756	14,130
United States	3,856	4,179
Consolidated	35,612	18,309

(1) Includes exploration and evaluation (“E&E”) assets, property, plant and equipment (“PP&E”), goodwill and other assets.

(2) Certain crude oil and natural gas properties of the Conventional and Deep Basin segments, which reside in Canada, have been reclassified as held for sale in 2017 in current assets. 2016 includes $3.1 billion related to the Conventional segment.

Schedule of Exploration and Evaluation Assets, Property, Plant and Equipment, Goodwill and Total Assets

D) Exploration and Evaluation Assets, Property, Plant and Equipment, Goodwill and Total Assets

	E&E		PP&E		Goodwill		Total Assets
As at December 31,	2017	2016	2017	2016	2017	2016	2017	2016
Oil Sands	617	1,564	22,320	8,798	2,272	242	26,799	11,112
Deep Basin	3,056	-	3,019	-	-	-	6,694	-
Conventional	-	21	-	3,080	-	-	644	3,196
Refining and Marketing	-	-	3,967	4,273	-	-	5,432	6,613
Corporate and Eliminations	-	-	290	275	-	-	1,364	4,337
Consolidated	3,673	1,585	29,596	16,426	2,272	242	40,933	25,258

Schedule of Capital Expenditures

E) Capital Expenditures ⁽¹⁾

For the years ended December 31,	2017	2016	2015
Capital
Oil Sands	973	604	1,185
Deep Basin	225	-	-
Conventional	206	171	244
Refining and Marketing	180	220	248
Corporate	77	31	37
Capital Investment	1,661	1,026	1,714
Acquisition Capital
Oil Sands (2)	11,614	11	3
Deep Basin	6,774	-	-
Conventional	-	-	1
Refining and Marketing	-	-	83
Total Capital Expenditures	20,049	1,037	1,801

(1) Includes expenditures on PP&E, E&E assets and assets held for sale.

(2) In connection with the Acquisition discussed in Note 5, Cenovus was deemed to have disposed of its pre-existing interest in FCCL and re-acquired it at fair value as required by International Financial Reporting Standard 3, “Business Combinations” (“IFRS 3”), which is not reflected in the table above. The carrying value of the pre-existing interest was $9,081 million and the estimated fair value was $11,605 million as at May 17, 2017.

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Acquisition (Tables)

12 Months Ended

Dec. 31, 2017

Disclosure Of Business Combinations [Line Items]

Additional Recognition of Goodwill Explanatory

Goodwill arising from the Acquisition has been recognized as follows:

	Notes
Total Purchase Consideration	4C	17,945
Fair Value of Pre-Existing 50 Percent Ownership Interest in FCCL		12,347
Fair Value of Identifiable Net Assets	4B	(28,262)
Goodwill		2,030

FCCL Partnership and Deep Basin [Member]

Disclosure Of Business Combinations [Line Items]

Summary of Identifiable Assets Acquired and Liabilities Assumed

The following table summarizes the recognized amounts of assets acquired and liabilities assumed at the date of the Acquisition.

	Notes
100 Percent of the Identifiable Assets Acquired and Liabilities Assumed for FCCL
Cash		880
Accounts Receivable and Accrued Revenues		964
Inventories		345
E&E Assets	17	491
PP&E	18	22,717
Other Assets		27
Accounts Payable and Accrued Liabilities		(445)
Decommissioning Liabilities	24	(277)
Other Liabilities		(8)
Deferred Income Taxes		(2,506)
		22,188
Recognized Amounts of Identifiable Assets Acquired and Liabilities Assumed for Deep Basin
Accounts Receivable and Accrued Revenues		16
Inventories		14
E&E Assets	17	3,117
PP&E	18	3,600
Accounts Payable and Accrued Liabilities		(6)
Decommissioning Liabilities	24	(667)
		6,074
Total Identifiable Net Assets		28,262

ConocoPhillips Company and Certain of its Subsidiaries [Member]

Disclosure Of Business Combinations [Line Items]

Summary of Fair Value of the Consideration

The following table summarizes the fair value of the consideration

Common Shares	2,579
Cash	15,005
	17,584
Estimated Contingent Payment (Note 22)	361
Total Consideration	17,945

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Finance Costs (Tables)

12 Months Ended

Dec. 31, 2017

Finance Costs [Abstract]

Schedule of Finance Cost

For the years ended December 31,	2017	2016	2015
Interest Expense – Short-Term Borrowings and Long-Term Debt	571	341	328
Unwinding of Discount on Decommissioning Liabilities (Note 24)	48	28	25
Other	26	21	28
	645	390	381

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Foreign Exchange (Gain) Loss, Net (Tables)

12 Months Ended

Dec. 31, 2017

Foreign Exchange Gains Losses [Abstract]

Schedule of Foreign Exchange Gain Loss Net

For the years ended December 31,	2017	2016	2015
Unrealized Foreign Exchange (Gain) Loss on Translation of:
U.S. Dollar Debt Issued From Canada	(665)	(196)	1,064
Other	(192)	7	33
Unrealized Foreign Exchange (Gain) Loss	(857)	(189)	1,097
Realized Foreign Exchange (Gain) Loss	45	(9)	(61)
	(812)	(198)	1,036

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Impairment Charges and Reversals (Tables)

12 Months Ended

Dec. 31, 2017

Disclosure Of Impairment Loss Recognised Or Reversed [Abstract]

Summary of Forward Prices Used to Determine Future Cash Flows

The forward prices as at December 31, 2017, used to determine future cash flows from crude oil, NGLs and natural gas reserves were:

	2018	2019	2020	2021	2022	Average Annual Increase Thereafter
WTI (US$/barrel)	57.50	60.90	64.13	68.33	71.19	2.1%
WCS (C$/barrel)	50.61	56.59	60.86	64.56	66.63	2.1%
Edmonton C5+ (C$/barrel)	72.41	74.90	77.07	81.07	83.32	2.1%
AECO (C$/Mcf) (1) (2)	2.43	2.77	3.19	3.48	3.67	2.0%

(1) Alberta Energy Company (“AECO”) natural gas.

(2) Assumes gas heating value of one million British Thermal Units per thousand cubic feet.

Forward prices as at December 31, 2016 used to determine future cash flows from crude oil and natural gas reserves were:

	2017	2018	2019	2020	2021	Average Annual Increase Thereafter
WTI (US$/barrel)	55.00	58.70	62.40	69.00	75.80	2.0%
WCS (C$/barrel)	53.70	58.20	61.90	66.50	71.00	2.0%
AECO (C$/Mcf) (1)	3.40	3.15	3.30	3.60	3.90	2.2%

(1) Assumes gas heating value of one million British Thermal Units per thousand cubic feet.

Summary of Increase (Decrease) to Impairment

The sensitivity analysis below shows the impact that a change in the discount rate or forward commodity prices would have on impairment testing for the following CGUs:

	Increase (Decrease) to Impairment
	One Percent Increase in the Discount Rate	One Percent Decrease in the Discount Rate	Five Percent Increase in the Forward Price Estimates (1)	Five Percent Decrease in the Forward Price Estimates
Clearwater	27	(30)	(56)	65
Primrose	-	-	-	-
Christina Lake	-	-	-	-
Narrows Lake	312	-	-	333

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Held for Sales Assets and Discontinued Operations (Tables)

12 Months Ended

Dec. 31, 2017

Disclosure Of Noncurrent Assets Held For Sale And Discontinued Operations [Abstract]

Results of Discontinued Operations

The following table presents the results of discontinued operations, including asset sales:

For the years ended December 31,	2017	2016	2015
Revenues
Gross Sales	1,309	1,267	1,648
Less: Royalties	174	139	113
	1,135	1,128	1,535
Expenses
Transportation and Blending	167	186	229
Operating	426	444	558
Production and Mineral Taxes	18	12	17
(Gain) Loss on Risk Management	33	(58)	(209)
Operating Margin	491	544	940
Depreciation, Depletion and Amortization	192	567	1,121
Exploration Expense	2	-	71
Finance Costs	80	102	101
Earnings (Loss) From Discontinued Operations Before Income Tax	217	(125)	(353)
Current Tax Expense (Recovery)	24	86	145
Deferred Tax Expense (Recovery)	33	(125)	(202)
After-tax Earnings (Loss) From Discontinued Operations	160	(86)	(296)
After-tax Gain (Loss) on Discontinuance (1)	938	-	-
Net Earnings (Loss) From Discontinued Operations	1,098	(86)	(296)

Summary of Cash Flows from Discontinued Operations

Cash flows from discontinued operations reported in the Consolidated Statement of Cash Flows are:

For the years ended December 31,	2017	2016	2015
Cash From Operating Activities	448	435	778
Cash From (Used in) Investing Activities	2,993	(168)	(243)
Net Cash Flow	3,441	267	535

Summary of Assets and Liabilities Held for Sale

The assets have been classified as held for sale and recorded at the lesser of their carrying amount and their fair value less cost to sell. Assets and liabilities held for sale also include the Suffield operations, which were sold on January 5, 2018. No impairments were recorded on the assets held for sale as at December 31, 2017.

		E&E Assets	PP&E	Decommissioning Liabilities
As at December 31, 2017		(Note 17)	(Note 18)	(Note 24)
Conventional	-		568	454
Deep Basin	46		434	149
	46		1,002	603

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Income Taxes (Tables)

12 Months Ended

Dec. 31, 2017

Disclosure Of Income Taxes Continuing Operations [Abstract]

Provision for Income Taxes

The provision for income taxes is:

For the years ended December 31,	2017	2016	2015
Current Tax
Canada	(217)	(260)	441
United States	(38)	1	(12)
Current Tax Expense (Recovery)	(255)	(259)	429
Deferred Tax Expense (Recovery)	203	(84)	(453)
Tax Expense (Recovery) From Continuing Operations	(52)	(343)	(24)

Reconciliation of Income Taxes Calculated at Statutory Rate

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

For the years ended December 31,	2017	2016	2015
Earnings (Loss) From Continuing Operations Before Income Tax	2,216	(802)	890
Canadian Statutory Rate	27.0%	27.0%	26.1%
Expected Income Tax Expense (Recovery) From Continuing Operations	598	(217)	232
Effect of Taxes Resulting From:
Foreign Tax Rate Differential	(17)	(46)	(41)
Non-Taxable Capital (Gains) Losses	(148)	(26)	137
Non-Recognition of Capital (Gains) Losses	(118)	(26)	135
Adjustments Arising From Prior Year Tax Filings	(41)	(46)	(55)
(Recognition) of Previously Unrecognized Capital Losses	(68)	-	(149)
(Recognition) of U.S. Tax Basis	-	-	(415)
Change in Statutory Rate	(275)	-	114
Non-Deductible Expenses	(5)	5	7
Other	22	13	11
Total Tax Expense (Recovery) From Continuing Operations	(52)	(343)	(24)
Effective Tax Rate	(2.3)%	42.8%	(2.7)%

Deferred Income Tax Liabilities and Deferred Income Tax Assets

The analysis of deferred income tax liabilities and deferred income tax assets is as follows:

As at December 31,	2017	2016
Deferred Income Tax Liabilities
Deferred Tax Liabilities to be Settled Within 12 Months	186	6
Deferred Tax Liabilities to be Settled After More Than 12 Months	6,229	3,147
	6,415	3,153
Deferred Income Tax Assets
Deferred Tax Assets to be Recovered Within 12 Months	(374)	(117)
Deferred Tax Assets to be Recovered After More Than 12 Months	(428)	(451)
	(802)	(568)
Net Deferred Income Tax Liability	5,613	2,585

Schedule of Movement in Deferred Income Tax Liabilities and Assets

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	PP&E		Timing of Partnership Items		Risk Management	Other	Total
As at December 31, 2015	3,052		-		82	17	3,151
Charged (Credited) to Earnings	118		-		(76)	(16)	26
Charged (Credited) to OCI	(24)		-		-	-	(24)
As at December 31, 2016	3,146		-		6	1	3,153
Charged (Credited) to Earnings	625		164		11	1	801
Charged (Credited) to Purchase Price Allocation	2,506		-		-	-	2,506
Charged (Credited) to OCI	(45)		-		-	-	(45)
As at December 31, 2017	6,232		164		17	2	6,415
Deferred Income Tax Assets	Unused Tax Losses	Timing of Partnership Items		Risk Management		Other	Total
As at December 31, 2015	(172)	(36)		(8)		(119)	(335)
Charged (Credited) to Earnings	(102)	36		(77)		(92)	(235)
Charged (Credited) to OCI	4	-		-		(2)	2
As at December 31, 2016	(270)	-		(85)		(213)	(568)
Charged (Credited) to Earnings	67	-		(198)		(87)	(218)
Charged (Credited) to Share Capital	-	-		-		(28)	(28)
Charged (Credited) to OCI	12	-		-		-	12
As at December 31, 2017	(191)	-		(283)		(328)	(802)

Net Deferred Income Tax Liabilities	Total
Net Deferred Income Tax Liabilities as at December 31, 2015	2,816
Charged (Credited) to Earnings	(209)
Charged (Credited) to OCI	(22)
Net Deferred Income Tax Liabilities as at December 31, 2016	2,585
Charged (Credited) to Earnings	583
Charged (Credited) to Purchase Price Allocation	2,506
Charged (Credited) to Share Capital	(28)
Charged (Credited) to OCI	(33)
Net Deferred Income Tax Liabilities as at December 31, 2017	5,613

Schedule of Amounts of Tax Pools Available, Including Tax Losses

The approximate amounts of tax pools available, including tax losses, are:

As at December 31,	2017	2016
Canada	8,317	4,273
United States	1,714	2,036
	10,031	6,309

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Per Share Amounts (Tables)

12 Months Ended

Dec. 31, 2017

Earnings Per Share [Abstract]

Schedule Representing Per Share Amounts

A) Net Earnings (Loss) Per Share — Basic and Diluted

For the years ended December 31,	2017	2016	2015
Earnings (Loss) From:
Continuing Operations	2,268	(459)	914
Discontinued Operations	1,098	(86)	(296)
Net Earnings (Loss)	3,366	(545)	618
Weighted Average Number of Shares(millions)	1,102.5	833.3	818.7
Basic and Diluted Earnings (Loss) Per Share From:($)
Continuing Operations	2.06	(0.55)	1.11
Discontinued Operations	0.99	(0.10)	(0.36)
Net Earnings (Loss) Per Share	3.05	(0.65)	0.75

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Cash and Cash Equivalents (Tables)

12 Months Ended

Dec. 31, 2017

Cash And Cash Equivalents [Abstract]

Schedule Representing Cash and Cash Equivalents

As at December 31,	2017	2016
Cash	547	542
Short-Term Investments	63	3,178
	610	3,720

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Accounts Receivable and Accrued Revenues (Tables)

12 Months Ended

Dec. 31, 2017

Trade And Other Current Receivables [Abstract]

Schedule of Accounts Receivable and Accrued Revenues

As at December 31,	2017	2016
Accruals	1,379	1,606
Prepaids and Deposits	64	127
Partner Advances	94	-
Note Receivable From Partner (1)	-	50
Trade	193	29
Joint Operations Receivables	51	11
Other	49	15
	1,830	1,838

(1) Note receivable from partner was interest bearing at a rate of 1.6783 percent per annum.

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Inventories (Tables)

12 Months Ended

Dec. 31, 2017

Classes Of Inventories [Abstract]

Schedule of Inventories

As at December 31,	2017	2016
Product
Refining and Marketing	894	1,006
Oil Sands	414	156
Deep Basin	2	-
Conventional	2	20
Parts and Supplies	77	55
	1,389	1,237

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Exploration and Evaluation Assets (Tables)

12 Months Ended

Dec. 31, 2017

Disclosure Of Exploration And Evaluation Assets [Abstract]

Summary of Exploration and Valuation Assets

	Total
As at December 31, 2015	1,575
Additions	67
Transfers to PP&E (Note 18)	(49)
Exploration Expense (Note 10)	(2)
Change in Decommissioning Liabilities	(6)
As at December 31, 2016	1,585
Additions	147
Acquisition (Note 5) (1)	3,608
Transfers to Assets Held for Sale (Note 11)	(316)
Transfers to PP&E (Note 18)	(6)
Exploration Expense (Notes 10 and 11)	(890)
Change in Decommissioning Liabilities	5
Exchange Rate Movements and Other	19
Divestitures (1)	(479)
As at December 31, 2017	3,673

(1) In connection with the Acquisition, Cenovus was deemed to have disposed of its pre-existing interest in FCCL and re-acquired it at fair value as required by IFRS 3.

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Property, Plant and Equipment, Net (Tables)

12 Months Ended

Dec. 31, 2017

Disclosure Of Property Plant And Equipment [Abstract]

Summary of Property, Plant and Equipment

	Upstream Assets
	Development & Production	Other Upstream	Refining Equipment	Other (1)	Total
COST
As at December 31, 2015	31,481	331	5,206	1,037	38,055
Additions	717	2	213	38	970
Transfers From E&E Assets (Note 17)	49	-	-	-	49
Change in Decommissioning Liabilities	(267)	-	(8)	-	(275)
Exchange Rate Movements and Other	(16)	-	(152)	(1)	(169)
Divestitures (Note 8)	(23)	-	-	-	(23)
As at December 31, 2016	31,941	333	5,259	1,074	38,607
Additions	1,324	-	168	89	1,581
Acquisition (Note 5) (2)	26,317	-	-	-	26,317
Transfers From E&E Assets (Note 17)	6	-	-	-	6
Transfers to Assets Held for Sale (Note 11)	(19,719)	-	-	-	(19,719)
Change in Decommissioning Liabilities	(67)	-	-	3	(64)
Exchange Rate Movements and Other	(28)	-	(364)	1	(391)
Divestitures (Note 8) (2)	(12,333)	-	(2)	-	(12,335)
As at December 31, 2017	27,441	333	5,061	1,167	34,002
ACCUMULATED DEPRECIATION, DEPLETION AND AMORTIZATION
As at December 31, 2015	18,908	277	896	639	20,720
DD&A	1,173	31	205	66	1,475
Impairment Losses (Note 10)	481	-	-	4	485
Reversal of Impairment Losses (Note 10)	(462)	-	-	-	(462)
Exchange Rate Movements and Other	(4)	-	(25)	-	(29)
Divestitures (Note 8)	(8)	-	-	-	(8)
As at December 31, 2016	20,088	308	1,076	709	22,181
DD&A	1,653	23	209	68	1,953
Impairment Losses (Note 10)	77	-	-	-	77
Transfers to Assets Held for Sale (Note 11)	(16,120)	-	-	-	(16,120)
Exchange Rate Movements and Other	17	-	(91)	1	(73)
Divestitures (Note 8) (2)	(3,611)	-	(1)	-	(3,612)
As at December 31, 2017	2,104	331	1,193	778	4,406
CARRYING VALUE
As at December 31, 2015	12,573	54	4,310	398	17,335
As at December 31, 2016	11,853	25	4,183	365	16,426
As at December 31, 2017	25,337	2	3,868	389	29,596

(1) Includes crude-by-rail terminal, office furniture, fixtures, leasehold improvements, information technology and aircraft.

(2) In connection with the Acquisition, Cenovus was deemed to have disposed of its pre-existing interest in FCCL and re-acquired it at fair value as required by IFRS 3. The carrying value of the pre-existing interest in FCCL was $8,602 million.

Summary of PP&E Under Construction and Not Subject to DD&A

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

As at December 31,	2017	2016
Development and Production	1,809	537
Refining Equipment	131	206
	1,940	743

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Other Assets (Tables)

12 Months Ended

Dec. 31, 2017

Other Noncurrent Assets [Abstract]

Summary of Other Assets

As at December 31,	2017	2016
Equity Investments	37	35
Long-Term Receivables	11	15
Prepaids	9	5
Other	14	1
	71	56

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Goodwill (Tables)

12 Months Ended

Dec. 31, 2017

Goodwill [Abstract]

Summary of Carrying Value of Goodwill

As at December 31,	2017	2016
Carrying Value, Beginning of Year	242	242
Goodwill Recognized on Acquisition (Note 5)	2,030	-
Carrying Value, End of Year	2,272	242

Summary of Carrying Amount of Goodwill Allocated to Company's Exploration and Production CGUs

The carrying amount of goodwill allocated to the Company’s exploration and production CGUs is:

As at December 31,	2017	2016
Primrose (Foster Creek) (1)	1,171	242
Christina Lake (1)	1,101	-
	2,272	242

(1) Goodwill recognized on the Acquisition reflects measurement period adjustments.

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Accounts Payable and Accrued Liabilities (Tables)

12 Months Ended

Dec. 31, 2017

Trade And Other Current Payables [Abstract]

Schedule of Accounts Payable and Accrued Liabilities

As at December 31,	2017	2016
Accruals	2,006	1,927
Trade	337	105
Interest	86	72
Partner Advances	94	-
Note Payable to Partner (1)	-	50
Employee Long-Term Incentives	52	42
Onerous Contract Provisions	8	18
Joint Operations Payables	12	-
Other	40	52
	2,635	2,266

(1) Note payable to partner was interest bearing at a rate of 1.6783 percent per annum.

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Contingent Payment (Tables)

12 Months Ended

Dec. 31, 2017

Disclosure Of Contingent Liabilities In Business Combination [Abstract]

Summary of Contingent Payment

As at January 1, 2017	-
Initial Recognition on May 17, 2017 (Note 5)	361
Re-measurement (1)	(138)
Liabilities Settled or Payable	(17)
As at December 31, 2017	206
Less: Current Portion	38
Long-Term Portion	168

(1) Contingent payment is carried at fair value. Changes in fair value are recorded in net earnings.

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Long-term Debt (Tables)

12 Months Ended

Dec. 31, 2017

Disclosure of detailed information about borrowings [line items]

Schedule of Long Term Debt

As at December 31,	Notes	US$ Principal Amount	2017	2016
Revolving Term Debt (1)	A	-	-	-
Asset Sale Bridge Credit Facility	B	-	-	-
U.S. Dollar Denominated Unsecured Notes	C	7,650	9,597	6,378
Total Debt Principal			9,597	6,378
Debt Discounts and Transaction Costs			(84)	(46)
Long-Term Debt			9,513	6,332

(1) Revolving term debt may include Bankers’ Acceptances, London Interbank Offered Rate based loans, prime rate loans and U.S. base rate loans.

Schedule Of Unsecured Notes Explanatory

Unsecured notes are composed of:

	US$ Principal Amount
As at December 31,		2017	2016
5.70% due October 15, 2019	1,300	1,631	1,746
3.00% due August 15, 2022	500	627	671
3.80% due September 15, 2023	450	565	604
4.25% due April 15, 2027	1,200	1,505	-
5.25% due June 15, 2037	700	878	-
6.75% due November 15, 2039	1,400	1,756	1,880
4.45% due September 15, 2042	750	941	1,007
5.20% due September 15, 2043	350	439	470
5.40% due June 15, 2047	1,000	1,255	-
	7,650	9,597	6,378

Long-term Borrowings [Member]

Disclosure of detailed information about borrowings [line items]

Schedule of Mandatory Debt Payments

	US$ Principal Amount	Total C$ Equivalent
2018	-	-
2019	1,300	1,631
2020	-	-
2021	-	-
2022	500	627
Thereafter	5,850	7,339
	7,650	9,597

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Decommissioning Liabilities (Tables)

12 Months Ended

Dec. 31, 2017

Provision For Decommissioning Restoration And Rehabilitation Costs [Abstract]

Summary of Decommissioning Provision

The aggregate carrying amount of the obligation is:

	2017	2016
Decommissioning Liabilities, Beginning of Year	1,847	2,052
Liabilities Incurred	20	11
Liabilities Acquired (Note 5) (1)	944	-
Liabilities Settled	(70)	(51)
Liabilities Divested (1)	(139)	(1)
Transfers to Liabilities Related to Assets Held for Sale (Note 11)	(1,621)	-
Change in Estimated Future Cash Flows	(155)	(423)
Change in Discount Rate	76	131
Unwinding of Discount on Decommissioning Liabilities	128	130
Foreign Currency Translation	(1)	(2)
Decommissioning Liabilities, End of Year	1,029	1,847

(1) In connection with the Acquisition, Cenovus was deemed to have disposed of its pre-existing interest in FCCL and reacquired it at fair value as required by IFRS.

Summary of Changes to the Credit-Adjusted Risk-Free Rate or the Inflation Rate Impact on the Decommissioning Liabilities

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

	2017		2016
As at December 31,	Credit-Adjusted Risk-Free Rate	Inflation Rate	Credit-Adjusted Risk-Free Rate	Inflation Rate
One Percent Increase	(98)	197	(248)	327
One Percent Decrease	192	(103)	317	(259)

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Other Liabilities (Tables)

12 Months Ended

Dec. 31, 2017

Disclosure Of Other Liabilities [Abstract]

Summary of Other Liabilities

As at December 31,	2017	2016
Employee Long-Term Incentives	43	72
Pension and Other Post-Employment Benefit Plan (Note 26)	62	71
Onerous Contract Provisions	37	35
Other	31	33
	173	211

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Pensions and Other Post-Employment Benefits (Tables)

12 Months Ended

Dec. 31, 2017

Pension Plans [Abstract]

Summary of 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,	2017	2016	2017	2016
Defined Benefit Obligation
Defined Benefit Obligation, Beginning of Year	173	168	23	26
Current Service Costs	14	14	2	(3)
Interest Costs (1)	7	7	1	1
Benefits Paid	(8)	(25)	(1)	(1)
Plan Participant Contributions	2	2	-	-
Past Service Costs – Curtailments	(6)	-	(1)	-
Remeasurements:
(Gains) Losses from Experience Adjustments	1	-	-	-
(Gains) Losses from Changes in Demographic Assumptions	-	-	(1)	-
(Gains) Losses from Changes in Financial Assumptions	(2)	7	(1)	-
Defined Benefit Obligation, End of Year	181	173	22	23
Plan Assets
Fair Value of Plan Assets, Beginning of Year	125	128	-	-
Employer Contributions	9	14	-	-
Plan Participant Contributions	2	2	-	-
Benefits Paid	(8)	(25)	-	-
Interest Income (1)	4	3	-	-
Remeasurements:
Return on Plan Assets (Excluding Interest Income)	9	3	-	-
Fair Value of Plan Assets, End of Year	141	125	-	-
Pension and OPEB (Liability) (2)	(40)	(48)	(22)	(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.

Summary of Pension and OPEB Costs

B) Pension and OPEB Costs

	Pension Benefits			OPEB
For the years ended December 31,	2017	2016	2015	2017	2016	2015
Defined Benefit Plan Cost
Current Service Costs	14	14	19	2	(3)	3
Past Service Costs – Curtailments	(6)	-	(5)	(1)	-	-
Net Settlement Costs	-	-	3	-	-	-
Net Interest Costs	3	4	6	1	1	1
Remeasurements:
Return on Plan Assets (Excluding Interest Income)	(9)	(3)	3	-	-	-
(Gains) Losses from Experience Adjustments	1	-	(3)	-	-	-
(Gains) Losses from Changes in Demographic Assumptions	-	-	-	(1)	-	-
(Gains) Losses from Changes in Financial Assumptions	(2)	7	(28)	(1)	-	-
Defined Benefit Plan Cost (Recovery)	1	22	(5)	-	(2)	4
Defined Contribution Plan Cost	27	25	29	-	-	-
Total Plan Cost	28	47	24	-	(2)	4

Summary of Fair Value of the Plan Assets

The fair value of the plan assets is:

As at December 31,	2017	2016
Equity Funds	89	73
Bond Funds	29	25
Non-Invested Assets	11	13
Real Estate Funds	9	9
Cash and Cash Equivalents	3	5
	141	125

Summary of principal weighted average actuarial assumptions used to determine benefit obligations and expenses

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,	2017	2016	2015	2017	2016	2015
Discount Rate	3.50%	3.75%	4.00%	3.25%	3.75%	3.75%
Future Salary Growth Rate	3.81%	3.80%	3.80%	5.08%	5.15%	5.15%
Average Longevity (years)	88.0	87.9	88.3	88.0	87.9	88.3
Health Care Cost Trend Rate	N/A	N/A	N/A	6.00%	7.00%	7.00%

Sensitivity of defined benefit and OPEB obligation to changes in relevant actuarial assumptions

The sensitivity of the defined benefit and OPEB obligation to changes in relevant actuarial assumptions is:

	2017		2016
As at December 31,	Increase	Decrease	Increase	Decrease
One Percent Change:
Discount Rate	(28)	36	(25)	32
Future Salary Growth Rate	3	(3)	3	(3)
Health Care Cost Trend Rate	1	(1)	2	(1)
One Year Change in Assumed Life Expectancy	4	(4)	4	(4)

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Share Capital (Tables)

12 Months Ended

Dec. 31, 2017

Disclosure Of Classes Of Share Capital [Abstract]

Summary of Share Capital

B) Issued and Outstanding

	2017		2016
As at December 31,	Number of Common Shares (thousands)	Amount	Number of Common Shares (thousands)	Amount
Outstanding, Beginning of Year	833,290	5,534	833,290	5,534
Common Shares Issued, Net of Issuance Costs and Tax	187,500	2,927	-	-
Common Shares Issued to ConocoPhillips (Note 5)	208,000	2,579	-	-
Outstanding, End of Year	1,228,790	11,040	833,290	5,534

Disclosure Of Paid In Surplus Includes Stock Based Compensation Expense Explanatory

Cenovus’s paid in surplus reflects the Company’s retained earnings prior to the split of Encana Corporation (“Encana”) under the plan of arrangement into two independent energy companies, Encana and Cenovus (pre-arrangement earnings). In addition, paid in surplus includes stock-based compensation expense related to the Company’s NSRs discussed in Note 29A.

	Pre-Arrangement Earnings	Stock-Based Compensation	Total
As at December 31, 2015	4,086	244	4,330
Stock-Based Compensation Expense	-	20	20
As at December 31, 2016	4,086	264	4,350
Stock-Based Compensation Expense	-	11	11
As at December 31, 2017	4,086	275	4,361

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Accumulated Other Comprehensive Income (Loss) (Tables)

12 Months Ended

Dec. 31, 2017

Disclosure Of Accumulated Other Comprehensive Income Loss [Abstract]

Summary of Accumulated Other Comprehensive Income (Loss)

	Defined Benefit Pension Plan	Foreign Currency Translation Adjustment	Available for Sale Financial Assets	Total
As at December 31, 2015	(10)	1,014	16	1,020
Other Comprehensive Income (Loss), Before Tax	(4)	(106)	(4)	(114)
Income Tax	1	-	3	4
As at December 31, 2016	(13)	908	15	910
Other Comprehensive Income (Loss), Before Tax	12	(275)	(1)	(264)
Income Tax	(3)	-	-	(3)
As at December 31, 2017	(4)	633	14	643

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Stock-Based Compensation Plans (Tables)

12 Months Ended

Dec. 31, 2017

Disclosure of terms and conditions of share-based payment arrangement [Line Items]

Summary of Stock Option Activity and Related Information

The following tables summarize information related to the NSRs:

As at December 31, 2017	Number of NSRs (thousands)	Weighted Average Exercise Price ($)
Outstanding, Beginning of Year	41,644	30.57
Granted	3,537	14.81
Exercised	-	-
Forfeited	(2,454)	28.27
Outstanding, End of Year	42,727	29.40

Summary of Options Outstanding and Exercisable by Range of Exercise Price

	Outstanding NSRs			Exercisable NSRs
As at December 31, 2017 Range of Exercise Price($)	Number of NSRs (thousands)	Weighted Average Remaining Contractual Life (years)	Weighted Average Exercise Price($)	Number of NSRs (thousands)	Weighted Average Exercise Price($)
10.00 to 14.99	3,319	5.4	14.80	-	-
15.00 to 19.99	3,313	5.2	19.51	995	19.51
20.00 to 24.99	3,723	4.1	22.25	2,254	22.26
25.00 to 29.99	12,115	3.1	28.38	12,106	28.39
30.00 to 34.99	10,419	2.2	32.64	10,419	32.64
35.00 to 39.99	9,838	0.8	38.19	9,838	38.19
	42,727	2.8	29.40	35,612	31.70

Summary of Stock-Based Compensation

For the years ended December 31,	2017	2016	2015
NSRs	9	15	27
TSARs	-	(1)	(5)
PSUs	(7)	13	(13)
RSUs	3	13	6
DSUs	(11)	7	(5)
Stock-Based Compensation Expense (Recovery)	(6)	47	10
Stock-Based Compensation Costs Capitalized	3	12	6
Total Stock-Based Compensation	(3)	59	16

NSRs [Member]

Disclosure of terms and conditions of share-based payment arrangement [Line Items]

Summary of Assumptions Used to Determine Fair Value of Options Granted

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	1.00%
Expected Dividend Yield	1.13%
Expected Volatility (1)	29.14%
Expected Life (years)	3.70

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

TSARs [Member]

Disclosure of terms and conditions of share-based payment arrangement [Line Items]

Summary of Assumptions Used to Determine Fair Value of Options Granted

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	1.85%
Expected Dividend Yield	1.51%
Expected Volatility (1)	28.89%
Cenovus’s Common Share Price ($)	11.48

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

Summary of Stock Option Activity and Related Information

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

As at December 31, 2017	Number of TSARs (thousands)	Weighted Average Exercise Price ($)
Outstanding, Beginning of Year	3,373	26.66
Exercised for Cash Payment	-	-
Exercised as Options for Common Shares	-	-
Forfeited	(16)	29.19
Expired	(3,276)	26.48
Outstanding, End of Year	81	33.52

PSUs [Member]

Disclosure of terms and conditions of share-based payment arrangement [Line Items]

Summary of Units Activity and Related Information

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

As at December 31, 2017	Number of PSUs (thousands)
Outstanding, Beginning of Year	6,157
Granted	2,392
Vested and Paid Out	(451)
Cancelled	(1,192)
Units in Lieu of Dividends	112
Outstanding, End of Year	7,018

RSUs [Member]

Disclosure of terms and conditions of share-based payment arrangement [Line Items]

Summary of Units Activity and Related Information

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

As at December 31, 2017	Number of RSUs (thousands)
Outstanding, Beginning of Year	3,790
Granted	3,278
Vested and Paid Out	(101)
Cancelled	(282)
Units in Lieu of Dividends	100
Outstanding, End of Year	6,785

DSUs [Member]

Disclosure of terms and conditions of share-based payment arrangement [Line Items]

Summary of Units Activity and Related Information

The following table summarizes the information related to the DSUs held by Cenovus directors, officers and employees:

As at December 31, 2017	Number of DSUs (thousands)
Outstanding, Beginning of Year	1,598
Granted to Directors	136
Granted	93
Units in Lieu of Dividends	27
Redeemed	(414)
Outstanding, End of Year	1,440

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Employee Salaries and Benefit Expenses (Tables)

12 Months Ended

Dec. 31, 2017

Disclosure Of Salaries And Employee Benefits [Abstract]

Summary of Employee Salaries and Benefit Expenses

For the years ended December 31,	2017	2016	2015
Salaries, Bonuses and Other Short-Term Employee Benefits	606	500	534
Defined Contribution Pension Plan	19	16	19
Defined Benefit Pension Plan and OPEB	8	11	17
Stock-Based Compensation Expense (Note 29)	(6)	47	10
Termination Benefits	19	19	43
	646	593	623

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Related Party Transactions (Tables)

12 Months Ended

Dec. 31, 2017

Key Management Personnel of Entity or Parent [Member]

Disclosure Of Transactions Between Related Parties [Line Items]

Summary of Key Management Compensation

For the years ended December 31,	2017	2016	2015
Salaries, Director Fees and Short-Term Benefits	26	27	30
Post-Employment Benefits	4	4	5
Stock-Based Compensation	6	4	5
	36	35	40

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Capital Structure (Tables)

12 Months Ended

Dec. 31, 2017

Disclosure Of Objectives Policies And Processes For Managing Capital [Abstract]

Summary of Net Debt to Adjusted EBITDA

A) Net Debt to Adjusted EBITDA

As at December 31,	2017	2016	2015
Long-Term Debt	9,513	6,332	6,525
Less: Cash and Cash Equivalents	(610)	(3,720)	(4,105)
Net Debt	8,903	2,612	2,420
Net Earnings (Loss)	3,366	(545)	618
Add (Deduct):
Finance Costs	725	492	482
Interest Income	(62)	(52)	(28)
Income Tax Expense (Recovery)	352	(382)	(81)
DD&A	2,030	1,498	2,114
E&E Impairment	890	2	138
Unrealized (Gain) Loss on Risk Management	729	554	195
Foreign Exchange (Gain) Loss, Net	(812)	(198)	1,036
Revaluation (Gain)	(2,555)	-	-
Re-measurement of Contingent Payment	(138)	-	-
(Gain) Loss on Discontinuance	(1,285)	-	-
(Gain) Loss on Divestitures of Assets	1	6	(2,392)
Other (Income) Loss, Net	(5)	34	2
Adjusted EBITDA (1)	3,236	1,409	2,084
Net Debt to Adjusted EBITDA	2.8x	1.9x	1.2x

(1) Calculated on a trailing twelve-month basis. Includes discontinued operations.

Summary of Net Debt to Capitalization

Net Debt to Capitalization

As at December 31,	2017	2016	2015
Net Debt	8,903	2,612	2,420
Shareholders’ Equity	19,981	11,590	12,391
	28,884	14,202	14,811
Net Debt to Capitalization	31%	18%	16%

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Financial Instruments (Tables)

12 Months Ended

Dec. 31, 2017

Disclosure Of Financial Instruments [Abstract]

Reconciliation of Changes in the Fair Value of Available for Sale Financial Assets

The following table provides a reconciliation of changes in the fair value of available for sale financial assets:

As at December 31,	2017	2016
Fair Value, Beginning of Year	35	42
Net Acquisition of Investments	3	-
Change in Fair Value (1)	(1)	(4)
Impairment Losses (2)	-	(3)
Fair Value, End of Year	37	35

(1) Changes in fair value on available for sale financial assets are recorded in OCI.

(2) Impairment losses on available for sale financial assets are reclassified from OCI to profit or loss.

Summary of Unrealized Risk Management Positions

Summary of Unrealized Risk Management Positions

	2017			2016
	Risk Management			Risk Management
As at December 31,	Asset	Liability	Net	Asset	Liability	Net
Crude Oil	63	1,031	(968)	21	307	(286)
Interest Rate	2	20	(18)	3	8	(5)
Total Fair Value	65	1,051	(986)	24	315	(291)

Summary of Fair Value Hierarchy for Risk Management Assets and Liabilities Carried at Fair Value

The following table presents the Company’s fair value hierarchy for risk management assets and liabilities carried at fair value:

As at December 31,	2017	2016
Level 2 – Prices Sourced From Observable Data or Market Corroboration	(986)	(291)

Reconciliation of Changes in the Fair Value of Cenovus's Risk Management Assets and Liabilities

The following table provides a reconciliation of changes in the fair value of Cenovus’s risk management assets and liabilities:

As at December 31,	2017	2016
Fair Value of Contracts, Beginning of Year	(291)		271
Fair Value of Contracts Realized During the Year (1)	200		(211)
Change in Fair Value of Contracts in Place at Beginning of Year and Contracts Entered Into During the Year	(929)		(343)
Unamortized Premium on Put Options	16		-
Unrealized Foreign Exchange Gain (Loss) on U.S. Dollar Contracts	18		(8)
Fair Value of Contracts, End of Year	(986)		(291)

(1) Includes a realized loss of $33 million (2016 – $58 million gain) related to the Conventional segment which is included in discontinued operations.

Summary of Offsetting Risk Management Positions

The following table provides a summary of the Company’s offsetting risk management positions:

	2017			2016
	Risk Management			Risk Management
As at December 31,	Asset	Liability	Net	Asset	Liability	Net
Recognized Risk Management Positions
Gross Amount	135	1,121	(986)	75	366	(291)
Amount Offset	(70)	(70)	-	(51)	(51)	-
Net Amount per Consolidated Financial  Statements	65	1,051	(986)	24	315	(291)

Summary of Changes in Inputs to Option Pricing Model, Resulted in Unrealized Gains (Losses) Impacting Earnings Before Income Tax

Changes in the following inputs to the option pricing model, with fluctuations in all other variables held constant, could have resulted in unrealized gains (losses) impacting earnings before income tax as follows:

	Sensitivity Range	Increase	Decrease
WCS Forward Prices	± $5.00 per bbl	(167)	111
WTI Option Volatility	± five percent	(95)	85
U.S. to Canadian Dollar Foreign Exchange Rate Volatility	± five percent	2	(27)

Summary of Earnings Impact of (Gains) Losses from Risk Management Positions

Earnings Impact of (Gains) Losses From Risk Management Positions

For the years ended December 31,	2017	2016	2015
Realized (Gain) Loss (1)	167	(153)	(447)
Unrealized (Gain) Loss (2)	729	554	195
(Gain) Loss on Risk Management From Continuing Operations	896	401	(252)

(1) Realized gains and losses on risk management are recorded in the reportable segment to which the derivative instrument relates. Excludes realized risk management losses of $33 million in 2017 (2016 – $58 million gain; 2015 – $209 million gain) that were classified as discontinued operations.

(2) Unrealized gains and losses on risk management are recorded in the Corporate and Eliminations segment.

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Risk Management (Tables)

12 Months Ended

Dec. 31, 2017

Description of Objectives, Policies and Processes for Managing Risk [Line Items]

Net Fair Value of Risk Management Positions

Net Fair Value of Risk Management Positions

As at December 31, 2017	Notional Volumes	Terms	Average Price	Fair Value Asset (Liability)
Crude Oil Contracts
Fixed Price Contracts
Brent Fixed Price	60,000 bbls/d	January – June 2018	US$53.34/bbl	(172)
WTI Fixed Price	150,000 bbls/d	January – June 2018	US$48.91/bbl	(384)
WTI Fixed Price	75,000 bbls/d	July – December 2018	US$49.32/bbl	(158)
Brent Put Options	25,000 bbls/d	January – June 2018	US$53.00/bbl	1
Brent Collars	80,000 bbls/d	January – June 2018	US$49.54 – US$59.86/bbl	(124)
Brent Collars	75,000 bbls/d	July – December 2018	US$49.00 – US$59.69/bbl	(110)
WTI Collars	10,000 bbls/d	January – June 2018	US$45.30 – US$62.77/bbl	(2)
WCS Differential	16,300 bbls/d	January – March 2018	US$(13.11)/bbl	14
WCS Differential	14,800 bbls/d	April – June 2018	US$(14.05)/bbl	7
WCS Differential	10,500 bbls/d	January – December 2018	US$(14.52)/bbl	25
Other Financial Positions (1)				(65)
Crude Oil Fair Value Position				(968)
Interest Rate Swaps				(18)
Total Fair Value				(986)

(1) Other financial positions are part of ongoing operations to market the Company’s production.

Summary of Changes in Inputs to Option Pricing Model, Resulted in Unrealized Gains (Losses) Impacting Earnings Before Income Tax

Changes in the following inputs to the option pricing model, with fluctuations in all other variables held constant, could have resulted in unrealized gains (losses) impacting earnings before income tax as follows:

	Sensitivity Range	Increase	Decrease
WCS Forward Prices	± $5.00 per bbl	(167)	111
WTI Option Volatility	± five percent	(95)	85
U.S. to Canadian Dollar Foreign Exchange Rate Volatility	± five percent	2	(27)

Undiscounted Cash Outflows Relating to Financial Liabilities

Undiscounted cash outflows relating to financial liabilities are:

As at December 31, 2017	Less than 1 Year	Years 2 and 3	Years 4 and 5	Thereafter	Total
Accounts Payable and Accrued Liabilities	2,635	-	-	-	2,635
Risk Management Liabilities (1)	1,031	20	-	-	1,051
Long-Term Debt (2)	494	2,527	1,429	13,309	17,759
Other	-	21	11	16	48

As at December 31, 2016	Less than 1 Year	Years 2 and 3	Years 4 and 5	Thereafter	Total
Accounts Payable and Accrued Liabilities	2,266	-	-	-	2,266
Risk Management Liabilities (1)	293	22	-	-	315
Long-Term Debt (2)	339	2,662	1,150	7,550	11,701
Other	-	25	8	16	49

(1) Risk management liabilities subject to master netting agreements.

(2) Principal and interest, including current portion.

Commodity Price Risk [Member]

Description of Objectives, Policies and Processes for Managing Risk [Line Items]

Summary of Changes in Inputs to Option Pricing Model, Resulted in Unrealized Gains (Losses) Impacting Earnings Before Income Tax

The following table summarizes the sensitivity of the fair value of Cenovus’s risk management positions to fluctuations in commodity prices, with all other variables held constant. Management believes the fluctuations identified in the table below are a reasonable measure of volatility. The impact of fluctuating commodity prices and interest rates on the Company’s open risk management positions could have resulted in unrealized gains (losses) impacting earnings before income tax as follows:

As at December 31, 2017	Sensitivity Range	Increase	Decrease
Crude Oil Commodity Price	± US$5.00 per bbl Applied to Brent, WTI and Condensate Hedges	(529)	507
Crude Oil Differential Price	± US$2.50 per bbl Applied to Differential Hedges Tied to Production	11	(11)

As at December 31, 2016	Sensitivity Range	Increase	Decrease
Crude Oil Commodity Price	± US$5.00 per bbl Applied to Brent, WTI and Condensate Hedges	(198)	193
Crude Oil Differential Price	± US$2.50 per bbl Applied to Differential Hedges Tied to Production	1	(1)

Currency risk [Member]

Description of Objectives, Policies and Processes for Managing Risk [Line Items]

Summary of Changes in Inputs to Option Pricing Model, Resulted in Unrealized Gains (Losses) Impacting Earnings Before Income Tax

In respect of these financial instruments, the impact of changes in the U.S. to Canadian dollar exchange rate would have resulted in a change to the foreign exchange (gain) loss as follows:

For the years ended December 31,	2017	2016
$0.01 Increase in the U.S. to Canadian Dollar Foreign Exchange Rate	77	48
$0.01 Decrease in the U.S. to Canadian Dollar Foreign Exchange Rate	(77)	(48)

Interest Rate Risk [Member]

Description of Objectives, Policies and Processes for Managing Risk [Line Items]

Summary of Changes in Inputs to Option Pricing Model, Resulted in Unrealized Gains (Losses) Impacting Earnings Before Income Tax

. In respect of these financial instruments, the impact of changes in the interest rate would have resulted in a change to unrealized gains (losses) impacting earnings before income tax as follows:

For the years ended December 31,	2017	2016
50 Basis Points Increase	44	45
50 Basis Points Decrease	(50)	(52)

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Supplementary Cash Flow Information (Tables)

12 Months Ended

Dec. 31, 2017

Disclosure Of Supplementary Cash Flow Information [Abstract]

Supplementary Cash Flow Information

For the years ended December 31,	2017	2016	2015
Interest Paid	538	350	330
Interest Received	31	32	19
Income Taxes Paid	12	11	933

Summary of Reconciliation of Cash Flows from Financing Activities

The following table provides a reconciliation of cash flows arising from financing activities:

	Dividends Payable	Current Portion of Long-Term Debt	Long-Term Debt	Share Capital
As at December 31, 2015	-	-	6,525	5,534
Changes From Financing Cash Flows:
Dividends Paid	(166)	-	-	-
Non-Cash Changes:
Dividends Declared	166	-	-	-
Unrealized Foreign Exchange (Gain) Loss (Note 7)	-	-	(196)	-
Amortization of Debt Discounts	-	-	3	-
As at December 31, 2016	-	-	6,332	5,534
Changes From Financing Cash Flows:
Issuance of Long-Term Debt	-	-	3,842	-
Net Issuance (Repayment) of Revolving Long-Term Debt	-	-	32	-
Issuance of Debt Under Asset Sale Bridge Facility	-	892	2,677	-
(Repayment) of Debt Under Asset Sale Bridge Facility	-	(900)	(2,700)	-
Common Shares Issued, Net of Issuance Costs	-	-	-	2,899
Dividends Paid	(225)	-	-	-
Non-Cash Changes:
Common Shares Issued to ConocoPhillips	-	-	-	2,579
Deferred Taxes on Share Issuance Costs	-	-	-	28
Dividends Declared	225	-	-	-
Unrealized Foreign Exchange (Gain) Loss	-	-	(697)	-
Finance Costs	-	8	28	-
Other	-	-	(1)	-
As at December 31, 2017	-	-	9,513	11,040

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Commitments and Contingencies (Tables)

12 Months Ended

Dec. 31, 2017

Commitments And Contingencies Abstract

Summary of Future Payments of Commitments

These items exclude amounts recorded in the Consolidated Balance Sheets.

As at December 31, 2017	1 Year	2 Years	3 Years	4 Years	5 Years	Thereafter	Total
Transportation and Storage (1)	899	886	919	1,123	1,223	13,260	18,310
Operating Leases (Building Leases) (2)	155	146	142	141	140	2,305	3,029
Capital Commitments	16	2	-	-	-	-	18
Other Long-Term Commitments	109	39	32	28	25	122	355
Total Payments (3)	1,179	1,073	1,093	1,292	1,388	15,687	21,712
Fixed Price Product Sales	-	-	-	-	-	-	-

As at December 31, 2016	1 Year	2 Years	3 Years	4 Years	5 Years	Thereafter	Total
Transportation and Storage (1)	682	711	722	1,031	1,239	21,875	26,260
Operating Leases (Building Leases) (2)	101	146	146	145	142	2,465	3,145
Product Purchases	70	-	-	-	-	-	70
Capital Commitments	23	3	-	-	-	-	26
Other Long-Term Commitments	80	27	26	15	15	108	271
Total Payments (3)	956	887	894	1,191	1,396	24,448	29,772
Fixed Price Product Sales	3	-	-	-	-	-	3

(1) Includes transportation commitments of $9 billion (2016 – $19 billion) that are subject to regulatory approval or have been approved, but are not yet in service.

(2) Excludes committed payment for which a provision has been provided.

(3) For 2017, contracts undertaken on behalf of WRB are reflected at Cenovus’s 50 percent interest. For 2016, contracts undertaken on behalf of FCCL and WRB are reflected at Cenovus’s 50 percent interest.

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Description of Business and Segmented Disclosures - Additional Information (Detail) CAD in Millions		12 Months Ended
	May 17, 2017	Dec. 31, 2017 CAD a Refinery Customer	Dec. 31, 2016 CAD Customer		Dec. 31, 2015 CAD Customer
Disclosure Of Operating Segments [Line Items]
Number of major customers | Customer		2	3		3
Gross Sales		CAD 17,314	CAD 11,015	[1]	CAD 11,559	[1]
Customer One [Member]
Disclosure Of Operating Segments [Line Items]
Gross Sales		5,655	4,742		4,647
Customer Two [Member]
Disclosure Of Operating Segments [Line Items]
Gross Sales			1,623		1,705
Customer Three [Member]
Disclosure Of Operating Segments [Line Items]
Gross Sales		CAD 1,964	CAD 1,400		CAD 1,545
Bottom of range [Member]
Disclosure Of Operating Segments [Line Items]
Percentage of entity's revenue from gross sales		10.00%	10.00%		10.00%
Canada [Member]
Disclosure Of Operating Segments [Line Items]
Sales of crude oil, natural gas and NGLs		CAD 1,713	CAD 974		CAD 870
Oil Sands [Member]
Disclosure Of Operating Segments [Line Items]
Gross Sales		CAD 7,362	2,929		3,030
Deep Basin [Member]
Disclosure Of Operating Segments [Line Items]
Acres of land | a		3,000,000
Gross Sales		CAD 555
Refining and Marketing [Member]
Disclosure Of Operating Segments [Line Items]
Number of refineries | Refinery		2
Gross Sales		CAD 9,852	CAD 8,439		CAD 8,805
FCCL [Member]
Disclosure Of Operating Segments [Line Items]
Percentage of ownership interest acquired	50.00%
FCCL [Member] | Oil Sands [Member]
Disclosure Of Operating Segments [Line Items]
Percentage of ownership interest acquired	50.00%
Percentage of ownership interest in subsidiary	100.00%

[1] The comparative periods have been restated to reflect discontinued operations as discussed in Notes 1 and 11.

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Description of Business and Segmented Disclosures - Schedule of Segment and Operational Information (Detail) - CAD CAD in Millions	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016		Dec. 31, 2015
Revenues
Gross Sales	CAD 17,314	CAD 11,015	[1]	CAD 11,559	[1]
Less: Royalties	271	9	[1]	30	[1]
Revenue	17,043	11,006	[1]	11,529	[1]
Expenses
Purchased Product	8,033	6,978	[1]	7,374	[1]
Transportation and Blending	3,748	1,715	[1]	1,814	[1]
Operating	1,949	1,239	[1]	1,281	[1]
Production and Mineral Taxes	1			1	[1]
(Gain) Loss on Risk Management	896	401	[1]	(252)	[1]
Depreciation, Depletion and Amortization	1,838	931	[1]	993	[1]
Exploration Expense	888	2	[1]	67	[1]
Segment Income (Loss)	(310)	(260)		251
General and Administrative	308	326	[1]	335	[1]
Finance Costs	645	390	[1]	381	[1]
Interest Income	(62)	(52)	[1]	(28)	[1]
Foreign Exchange (Gain) Loss, Net	(812)	(198)	[1]	1,036	[1]
Revaluation (Gain)	(2,555)
Transaction Costs	56
Re-measurement of Contingent Payment	(138)
Research Costs	36	36	[1]	27	[1]
(Gain) Loss on Divestiture of Assets	1	6	[1]	(2,392)	[1]
Other (Income) Loss, Net	(5)	34	[1]	2	[1]
Total Non-operating (Income) Expense	(2,526)	542		(639)
Earnings (Loss) From Continuing Operations Before Income Tax	2,216	(802)	[1]	890	[1]
Income Tax Expense (Recovery)	(52)	(343)	[1]	(24)	[1]
Net Earnings (Loss) From Continuing Operations	2,268	(459)	[1]	914	[1]
Oil Sands [Member]
Revenues
Gross Sales	7,362	2,929		3,030
Less: Royalties	230	9		29
Revenue	7,132	2,920		3,001
Expenses
Transportation and Blending	3,704	1,721		1,815
Operating	934	501		531
(Gain) Loss on Risk Management	307	(179)		(404)
Operating Margin	2,187	877		1,059
Depreciation, Depletion and Amortization	1,230	655		697
Exploration Expense	888	2		67
Segment Income (Loss)	69	220		295
Deep Basin [Member]
Revenues
Gross Sales	555
Less: Royalties	41
Revenue	514
Expenses
Transportation and Blending	56
Operating	250
Production and Mineral Taxes	1
Operating Margin	207
Depreciation, Depletion and Amortization	331
Segment Income (Loss)	(124)
Refining and Marketing [Member]
Revenues
Gross Sales	9,852	8,439		8,805
Revenue	9,852	8,439		8,805
Expenses
Purchased Product	8,476	7,325		7,709
Operating	772	742		754
(Gain) Loss on Risk Management	6	26		(43)
Operating Margin	598	346		385
Depreciation, Depletion and Amortization	215	211		191
Segment Income (Loss)	383	135		194
Corporate and Eliminations [Member]
Revenues
Gross Sales	(455)	(353)		(276)
Less: Royalties				1
Revenue	(455)	(353)		(277)
Expenses
Purchased Product	(443)	(347)		(335)
Transportation and Blending	(12)	(6)		(1)
Operating	(7)	(4)		(4)
Production and Mineral Taxes				1
(Gain) Loss on Risk Management	583	554		195
Depreciation, Depletion and Amortization	62	65		105
Segment Income (Loss)	(638)	(615)		(238)
General and Administrative	308	326		335
Finance Costs	645	390		381
Interest Income	(62)	(52)		(28)
Foreign Exchange (Gain) Loss, Net	(812)	(198)		1,036
Revaluation (Gain)	(2,555)
Transaction Costs	56
Re-measurement of Contingent Payment	(138)
Research Costs	36	36		27
(Gain) Loss on Divestiture of Assets	1	6		(2,392)
Other (Income) Loss, Net	(5)	34		2
Total Non-operating (Income) Expense	CAD (2,526)	CAD 542		CAD (639)

[1] The comparative periods have been restated to reflect discontinued operations as discussed in Notes 1 and 11.

XML

Description of Business and Segmented Disclosures - Schedule of Segment and Operational Information (Parenthetical) (Detail) - CAD CAD in Millions	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016		Dec. 31, 2015
Disclosure Of Operating Segments [Line Items]
Revenue	CAD 17,043	CAD 11,006	[1]	CAD 11,529	[1]
Depreciation, Depletion and Amortization	1,838	931	[1]	993	[1]
Segment income (loss)	(310)	(260)		251
Corporate and Eliminations [Member]
Disclosure Of Operating Segments [Line Items]
Revenue	(455)	(353)		(277)
Depreciation, Depletion and Amortization	62	65		105
Segment income (loss)	CAD (638)	CAD (615)		(238)
Corporate and Eliminations [Member] | Contribution From Properties Sold in 2015 [Member]
Disclosure Of Operating Segments [Line Items]
Revenue				60
Expense				5
Operating margin				55
Depreciation, Depletion and Amortization				27
Segment income (loss)				CAD 28

[1] The comparative periods have been restated to reflect discontinued operations as discussed in Notes 1 and 11.

XML

Description of Business and Segmented Disclosures - Schedule of Revenues by Product (Detail) - CAD CAD in Millions	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016		Dec. 31, 2015
Disclosure Of Reportable Segments [Line Items]
Refining and Marketing	CAD 9,852	CAD 8,439		CAD 8,805
Corporate and Eliminations	(455)	(353)		(277)
Revenue	17,043	11,006	[1]	11,529	[1]
Upstream
Disclosure Of Reportable Segments [Line Items]
Crude Oil	7,184	2,902		2,971
Natural Gas	235	16		22
NGLs	184
Other	CAD 43	CAD 2		CAD 8

[1] The comparative periods have been restated to reflect discontinued operations as discussed in Notes 1 and 11.

XML

Description of Business and Segmented Disclosures - Schedule of Revenues by Product (Parenthetical) (Detail) - Natural Gas [Member] CAD in Millions	12 Months Ended
	Dec. 31, 2017 CAD
Disclosure Of Products And Services [Line Items]
Percentage of natural gas produced	14.00%
ConocoPhillips Company and Certain of its Subsidiaries [Member]
Disclosure Of Products And Services [Line Items]
Revenue from sale of natural gas	CAD 32

XML

Description of Business and Segmented Disclosures - Schedule of Geographical Information (Detail) - CAD CAD in Millions	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016		Dec. 31, 2015
Disclosure Of Geographical Areas [Line Items]
Revenues	CAD 17,043	CAD 11,006	[1]	CAD 11,529	[1]
Non-Current Assets	35,612	18,309
Canada [Member]
Disclosure Of Geographical Areas [Line Items]
Revenues	9,723	4,978		4,729
Non-Current Assets	31,756	14,130
United States [Member]
Disclosure Of Geographical Areas [Line Items]
Revenues	7,320	6,028		CAD 6,800
Non-Current Assets	CAD 3,856	CAD 4,179

[1] The comparative periods have been restated to reflect discontinued operations as discussed in Notes 1 and 11.

XML

Description of Business and Segmented Disclosures - Schedule of Geographical Information (Parenthetical) (Detail) - CAD CAD in Millions	Dec. 31, 2017	Dec. 31, 2016
Disclosure Of Geographical Areas [Line Items]
Non-Current Assets	CAD 35,612	CAD 18,309
Canada [Member]
Disclosure Of Geographical Areas [Line Items]
Non-Current Assets	CAD 31,756	14,130
Canada [Member] | Conventional [Member]
Disclosure Of Geographical Areas [Line Items]
Non-Current Assets		CAD 3,100

XML

Description of Business and Segmented Disclosures - Schedule of Exploration and Evaluation Assets, Property, Plant and Equipment, Goodwill and Total Assets (Detail) - CAD CAD in Millions	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Disclosure Of Reportable Segments [Line Items]
E&E	CAD 3,673	CAD 1,585
PP&E	29,596	16,426	CAD 17,335
Goodwill	2,272	242	CAD 242
Total Assets	40,933	25,258
Oil Sands [Member]
Disclosure Of Reportable Segments [Line Items]
E&E	617	1,564
PP&E	22,320	8,798
Goodwill	2,272	242
Total Assets	26,799	11,112
Deep Basin [Member]
Disclosure Of Reportable Segments [Line Items]
E&E	3,056
PP&E	3,019
Total Assets	6,694
Conventional [Member]
Disclosure Of Reportable Segments [Line Items]
E&E		21
PP&E		3,080
Total Assets	644	3,196
Refining and Marketing [Member]
Disclosure Of Reportable Segments [Line Items]
PP&E	3,967	4,273
Total Assets	5,432	6,613
Corporate and Eliminations [Member]
Disclosure Of Reportable Segments [Line Items]
PP&E	290	275
Total Assets	CAD 1,364	CAD 4,337

XML

Description of Business and Segmented Disclosures - Schedule of Capital Expenditures (Detail) - CAD CAD in Millions	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Disclosure Of Reportable Segments [Line Items]
Capital Investment	CAD 1,661	CAD 1,026	CAD 1,714
Total Capital Expenditures	20,049	1,037	1,801
Oil Sands [Member]
Disclosure Of Reportable Segments [Line Items]
Capital Investment	973	604	1,185
Total Capital Expenditures	11,614	11	3
Deep Basin [Member]
Disclosure Of Reportable Segments [Line Items]
Capital Investment	225
Total Capital Expenditures	6,774
Conventional [Member]
Disclosure Of Reportable Segments [Line Items]
Capital Investment	206	171	244
Total Capital Expenditures			1
Refining and Marketing [Member]
Disclosure Of Reportable Segments [Line Items]
Capital Investment	180	220	248
Total Capital Expenditures			83
Corporate and Eliminations [Member]
Disclosure Of Reportable Segments [Line Items]
Capital Investment	CAD 77	CAD 31	CAD 37

XML

Description of Business and Segmented Disclosures - Schedule of Capital Expenditures (Parenthetical) (Detail) CAD in Millions	May 17, 2017 CAD
Disclosure Of Business Combinations [Abstract]
Carrying value of pre-existing interest	CAD 9,081
Estimated fair value	CAD 11,605

XML

Summary of Significant Accounting Policies - Additional information (Detail) CAD in Millions	12 Months Ended
	Dec. 31, 2017 CAD
Disclosure Of Property Plant And Equipment [Line Items]
Available for sale private equity investments, fair value	CAD 37
Other Upstream Assets [Member]
Disclosure Of Property Plant And Equipment [Line Items]
Useful lives of assets	3 years
Bottom of range [Member] | Land Improvements and Buildings [Member] | Refining Assets [Member]
Disclosure Of Property Plant And Equipment [Line Items]
Useful lives of assets	25 years
Bottom of range [Member] | Office Equipment and Vehicles [Member] | Refining Assets [Member]
Disclosure Of Property Plant And Equipment [Line Items]
Useful lives of assets	3 years
Bottom of range [Member] | Refining Equipment [Member] | Refining Assets [Member]
Disclosure Of Property Plant And Equipment [Line Items]
Useful lives of assets	5 years
Bottom of range [Member] | Other [Member]
Disclosure Of Property Plant And Equipment [Line Items]
Useful lives of assets	3 years
Top of range [Member] | Land Improvements and Buildings [Member] | Refining Assets [Member]
Disclosure Of Property Plant And Equipment [Line Items]
Useful lives of assets	40 years
Top of range [Member] | Office Equipment and Vehicles [Member] | Refining Assets [Member]
Disclosure Of Property Plant And Equipment [Line Items]
Useful lives of assets	20 years
Top of range [Member] | Refining Equipment [Member] | Refining Assets [Member]
Disclosure Of Property Plant And Equipment [Line Items]
Useful lives of assets	35 years
Top of range [Member] | Other [Member]
Disclosure Of Property Plant And Equipment [Line Items]
Useful lives of assets	40 years

XML

Critical Accounting Judgments and Key Sources of Estimation Uncertainty - Additional Information (Detail) - JointOperation		12 Months Ended
	May 16, 2017	Dec. 31, 2017	Dec. 31, 2016
Disclosure Of Joint Operations [Line Items]
Number of joint operations		2
WRB [Member]
Disclosure Of Joint Operations [Line Items]
Percent of ownership in joint operations		50.00%	50.00%
FCCL [Member]
Disclosure Of Joint Operations [Line Items]
Percent of ownership in joint operations	50.00%		50.00%

XML

Acquisition - Additional Information (Detail) CAD / shares in Units, CAD in Millions, $ in Billions		7 Months Ended	12 Months Ended
	May 17, 2017 CAD shares CAD / shares	Dec. 31, 2017 CAD	Dec. 31, 2017 CAD	May 17, 2017 USD ($) shares	Aug. 31, 2015 CAD
Disclosure Of Business Combinations [Line Items]
Revaluation (Gain)			CAD 2,555
Transaction Costs			56
Debt issuance costs related to acquisition financing	CAD 72
Acquisition related costs, transitional services agreement			40
Refining and Marketing [Member]
Disclosure Of Business Combinations [Line Items]
Cash consideration for acquisition					CAD 75
Change in decommissioning liabilities					4
Working capital assumed					1
Net transportation commitments assumed					CAD 92
Committed Asset Sale Bridge Credit Facility [Member]
Disclosure Of Business Combinations [Line Items]
Borrowings	CAD 3,600	CAD 3,600	CAD 3,600
FCCL [Member]
Disclosure Of Business Combinations [Line Items]
Percentage of ownership interest acquired	50.00%			50.00%
Description of acquiree			On May 17, 2017, Cenovus acquired ConocoPhillips’ 50 percent interest in FCCL and the majority of ConocoPhillips’ Deep Basin Assets in Alberta and British Columbia (the “Acquisition”).
Revaluation (Gain)	CAD 2,600
Fair value of acquired accounts receivables and accrued revenues	980
Acquired accounts receivables and accrued revenues collected			CAD 964
Non-cash revaluation gain, after tax	1,900
Carrying value of assets	9,700
Change in decommissioning liabilities	277
FCCL and Deep Basin Acquisition [Member]
Disclosure Of Business Combinations [Line Items]
Increase in purchase price allocation of property plant and equipment	912
Increase in purchase price allocation of accounts receivable and accrued revenues	16
Increase in purchase price allocation of inventory	56
Decrease in purchase price allocation of exploration and evaluation assets	822
Decrease in goodwill	2,030
Revaluation (Gain)	2,555
Increase to deferred income tax liability	CAD 9
ConocoPhillips Company and Certain of its Subsidiaries [Member]
Disclosure Of Business Combinations [Line Items]
Cash transferred from cash and cash equivalents | $				$ 10.6
Consideration transferred as common shares | shares	208,000,000			208,000,000
Contingent payments period	five years
Common stock price per share | CAD / shares	CAD 12.40
Average crude oil price per barrel	52.00
Quarterly contingent payment	6
Contingent payment percentage	2.9
Estimated contingent payment	CAD 361
Fair Value of Pre-Existing 50 Percent Ownership Interest in FCCL	12,347
Transaction Costs	56
Transition services agreement period			nine months
Revenue		3,300
Net earnings		CAD 172
Proforma revenue			CAD 19,000
Proforma net earnings			CAD 3,500
Cash consideration for acquisition	CAD 15,005
ConocoPhillips Company and Certain of its Subsidiaries [Member] | Bottom of range [Member]
Disclosure Of Business Combinations [Line Items]
Contingent payment percentage	80
ConocoPhillips Company and Certain of its Subsidiaries [Member] | Top of range [Member]
Disclosure Of Business Combinations [Line Items]
Contingent payment percentage	85

XML

Acquisition - Summary of Identifiable Assets Acquired and Liabilities Assumed (Detail) CAD in Millions	May 17, 2017 CAD
Disclosure Of Business Combinations [Line Items]
Total Identifiable Net Assets	CAD 28,262
FCCL [Member]
Disclosure Of Business Combinations [Line Items]
Cash	880
Accounts Receivable and Accrued Revenues	964
Inventories	345
E&E Assets	491
PP&E	22,717
Other Assets	27
Accounts Payable and Accrued Liabilities	(445)
Decommissioning Liabilities	(277)
Other Liabilities	(8)
Deferred Income Taxes	(2,506)
Total Identifiable Net Assets	22,188
Deep Basin [Member]
Disclosure Of Business Combinations [Line Items]
Accounts Receivable and Accrued Revenues	16
Inventories	14
E&E Assets	3,117
PP&E	3,600
Accounts Payable and Accrued Liabilities	(6)
Decommissioning Liabilities	(667)
Total Identifiable Net Assets	CAD 6,074

XML

Acquisition - Summary of Fair Value of the Consideration (Detail) - CAD CAD in Millions	Dec. 31, 2017	May 17, 2017
Disclosure Of Business Combinations [Line Items]
Estimated Contingent Payment (Note 22)	CAD 206
ConocoPhillips Company and Certain of its Subsidiaries [Member]
Disclosure Of Business Combinations [Line Items]
Common Shares		CAD 2,579
Cash		15,005
Fair value of consideration		17,584
Estimated Contingent Payment (Note 22)	CAD 206	361
Total Consideration		CAD 17,945

XML

Acquisition - Summary of Goodwill arising from Acquisition (Detail) - CAD CAD in Millions		12 Months Ended
	May 17, 2017	Dec. 31, 2017
Disclosure Of Business Combinations [Line Items]
Fair Value of Identifiable Net Assets	CAD (28,262)
Goodwill		CAD 2,030
ConocoPhillips Company and Certain of its Subsidiaries [Member]
Disclosure Of Business Combinations [Line Items]
Total Purchase Consideration	17,945
Fair Value of Pre-Existing 50 Percent Ownership Interest in FCCL	12,347
Fair Value of Identifiable Net Assets	(28,262)
Goodwill	CAD 2,030

XML

Acquisition - Summary of Goodwill arising from Acquisition (Parenthetical) (Detail)	May 17, 2017
FCCL [Member]
Disclosure Of Business Combinations [Line Items]
Percentage of ownership interest acquired	50.00%

XML

Finance Costs - Schedule of Finance Costs (Detail) - CAD CAD in Millions	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016		Dec. 31, 2015
Finance Costs [Abstract]
Interest Expense – Short-Term Borrowings and Long-Term Debt	CAD 571	CAD 341		CAD 328
Unwinding of Discount on Decommissioning Liabilities	48	28		25
Other	26	21		28
Total	CAD 645	CAD 390	[1]	CAD 381	[1]

[1] The comparative periods have been restated to reflect discontinued operations as discussed in Notes 1 and 11.

XML

Foreign Exchange (Gain) Loss, Net - Schedule of Foreign Exchange Gain Loss Net (Detail) - CAD CAD in Millions	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016		Dec. 31, 2015
Foreign Exchange Gains Losses:
Unrealized Foreign Exchange (Gain) Loss	CAD (857)	CAD (189)		CAD 1,097
Realized Foreign Exchange (Gain) Loss	45	(9)		(61)
Total	(812)	(198)	[1]	1,036	[1]
Long-term Borrowings [Member]
Foreign Exchange Gains Losses:
Unrealized Foreign Exchange (Gain) Loss	(665)	(196)		1,064
Other [Member]
Foreign Exchange Gains Losses:
Unrealized Foreign Exchange (Gain) Loss	CAD (192)	CAD 7		CAD 33

[1] The comparative periods have been restated to reflect discontinued operations as discussed in Notes 1 and 11.

XML

Divestitures - Additional Information (Detail) - CAD CAD in Millions	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Disclosure Of Disposals [Line Items]
Proceeds From Divestiture of Assets	CAD 3,210	CAD 8	CAD 3,344
Gains losses on disposals of Investment	(1)	(6)	2,392
Heritage Royalty Limited Partnership [Member]
Disclosure Of Disposals [Line Items]
Proceeds From Divestiture of Assets			3,300
Gains losses on disposals of Investment			2,400
Current tax expense	391
Land [Member]
Disclosure Of Disposals [Line Items]
Proceeds From Divestiture of Assets		8
Gains losses on disposals of property plant and equipment		(5)
Other [Member]
Disclosure Of Disposals [Line Items]
Gains losses on disposals of property plant and equipment		CAD (1)
Oil And Gas Assets [Member]
Disclosure Of Disposals [Line Items]
Proceeds From Divestiture of Assets	3,200
Gains losses on disposals of property plant and equipment	CAD 1,300
Oil And Gas Assets [Member] | Heritage Royalty Limited Partnership [Member]
Disclosure Of Disposals [Line Items]
Gains losses on disposals of property plant and equipment			CAD 16

XML

Other (Income) Loss, Net - Additional Information (Detail) - Northern Gateway Pipeline Project [Member] - CAD	12 Months Ended
	Dec. 31, 2016	Dec. 31, 2015
Disclosure Of Other Gains Losses [Line Items]
Written off amount	CAD 7,000,000	CAD 0
Capitalized Costs of Funding Support Unit [Member]
Disclosure Of Other Gains Losses [Line Items]
Written off amount	23,000,000
Expected Costs of Termination [Member]
Disclosure Of Other Gains Losses [Line Items]
Termination costs	CAD 7,000,000

XML

Impairment Charges and Reversals - Additional Information (Detail) - CAD	3 Months Ended	12 Months Ended
	Dec. 31, 2016	Dec. 31, 2017	Dec. 31, 2016		Dec. 31, 2015
Disclosure Of Impairment Loss And Reversal Of Impairment Loss [Line Items]
Decription of key assumptions in determining FVLCOD.		The recoverable amounts of Cenovus’s upstream CGUs were determined based on FVLCOD or an evaluation of comparable asset transactions. The fair values for producing properties were calculated based on discounted after-tax cash flows of proved and probable reserves using forward prices and cost estimates, prepared by Cenovus’s IQREs (Level 3). Key assumptions in the determination of future cash flows from reserves include crude oil and natural gas prices, costs to develop and the discount rate.
Discounted future cash flows, discount rate	10.00%		10.00%
Discounted future cash flows, inflation rate		2.00%
Goodwill impairments		CAD 0	CAD 0		CAD 0
DD&A Impairment value recorded		1,838,000,000	CAD 931,000,000	[1]	993,000,000	[1]
Discounted future cash flows, inflation rate	2.00%		2.00%
Exploration Expense		888,000,000	CAD 2,000,000	[1]	67,000,000	[1]
E&E [Member]
Disclosure Of Impairment Loss And Reversal Of Impairment Loss [Line Items]
Impairment losses					138,000,000
Exploration Expense		CAD 890,000,000	2,000,000
Bottom of range [Member]
Disclosure Of Impairment Loss And Reversal Of Impairment Loss [Line Items]
Discounted future cash flows, discount rate		10.00%
Top of range [Member]
Disclosure Of Impairment Loss And Reversal Of Impairment Loss [Line Items]
Discounted future cash flows, discount rate		15.00%
Clearwater CGU [Member]
Disclosure Of Impairment Loss And Reversal Of Impairment Loss [Line Items]
Impairment losses		CAD 56,000,000
Northern Alberta CGU [Member]
Disclosure Of Impairment Loss And Reversal Of Impairment Loss [Line Items]
Impairment losses			380,000,000		184,000,000
Impairment recoverable value	CAD 1,100,000,000		1,100,000,000		CAD 1,500,000,000
Discounted future cash flows, discount rate					10.00%
Impairment reversal value	400,000,000
DD&A Impairment value recorded	CAD 0
Percentage of reduction in expected future operating costs	5.00%
Discounted future cash flows, inflation rate					2.00%
Suffield CGU [Member] | Property, plant and equipment [member]
Disclosure Of Impairment Loss And Reversal Of Impairment Loss [Line Items]
Impairment losses			65,000,000
Impairment recoverable value	CAD 548,000,000		548,000,000
Impairment reversal value	62,000,000
DD&A Impairment value recorded	CAD 0
Deep Basin [Member]
Disclosure Of Impairment Loss And Reversal Of Impairment Loss [Line Items]
DD&A Impairment value recorded		331,000,000
Deep Basin [Member] | Clearwater CGU [Member]
Disclosure Of Impairment Loss And Reversal Of Impairment Loss [Line Items]
Impairment losses		56,000,000
Impairment recoverable value		295,000,000
Oil Sands [Member]
Disclosure Of Impairment Loss And Reversal Of Impairment Loss [Line Items]
DD&A Impairment value recorded		1,230,000,000	655,000,000		CAD 697,000,000
Exploration Expense		888,000,000	2,000,000		67,000,000
Oil Sands [Member] | Property, plant and equipment [member]
Disclosure Of Impairment Loss And Reversal Of Impairment Loss [Line Items]
Impairment losses		21,000,000	16,000,000		16,000,000
Oil Sands [Member] | E&E [Member]
Disclosure Of Impairment Loss And Reversal Of Impairment Loss [Line Items]
Impairment losses			2,000,000		67,000,000
Oil Sands [Member] | Borealis CGU [Member] | E&E [Member]
Disclosure Of Impairment Loss And Reversal Of Impairment Loss [Line Items]
Exploration Expense		888,000,000
Conventional [Member] | Property, plant and equipment [member]
Disclosure Of Impairment Loss And Reversal Of Impairment Loss [Line Items]
Impairment losses			20,000,000
Conventional [Member] | E&E [Member]
Disclosure Of Impairment Loss And Reversal Of Impairment Loss [Line Items]
Impairment losses					71,000,000
Corporate and Eliminations [Member]
Disclosure Of Impairment Loss And Reversal Of Impairment Loss [Line Items]
DD&A Impairment value recorded		CAD 62,000,000	65,000,000		CAD 105,000,000
Corporate and Eliminations [Member] | Property, plant and equipment [member]
Disclosure Of Impairment Loss And Reversal Of Impairment Loss [Line Items]
Impairment losses			CAD 4,000,000

[1] The comparative periods have been restated to reflect discontinued operations as discussed in Notes 1 and 11.

XML

Impairment Charges and Reversals - Summary of Forward Prices Used to Determine Future Cash Flows (Detail) - Commodity Price Assumptions [Member]	Dec. 31, 2017 $ / bbl CAD / bbl CAD / Mcf	Dec. 31, 2016 $ / bbl CAD / bbl CAD / Mcf
WTI [Member]
Disclosure Of Information For Individual Asset Or Cash Generating Unit [Line Items]
Average Annual Increase Thereafter	2.10%	2.00%
WTI [Member] | 2018 [Member]
Disclosure Of Information For Individual Asset Or Cash Generating Unit [Line Items]
Average Price | $ / bbl	57.50	58.70
WTI [Member] | 2019 [Member]
Disclosure Of Information For Individual Asset Or Cash Generating Unit [Line Items]
Average Price | $ / bbl	60.90	62.40
WTI [Member] | 2020 [Member]
Disclosure Of Information For Individual Asset Or Cash Generating Unit [Line Items]
Average Price | $ / bbl	64.13	69.00
WTI [Member] | 2021 [Member]
Disclosure Of Information For Individual Asset Or Cash Generating Unit [Line Items]
Average Price | $ / bbl	68.33	75.80
WTI [Member] | 2022 [Member]
Disclosure Of Information For Individual Asset Or Cash Generating Unit [Line Items]
Average Price | $ / bbl	71.19
WTI [Member] | 2017 [Member]
Disclosure Of Information For Individual Asset Or Cash Generating Unit [Line Items]
Average Price | $ / bbl		55.00
WCS [Member]
Disclosure Of Information For Individual Asset Or Cash Generating Unit [Line Items]
Average Annual Increase Thereafter	2.10%	2.00%
WCS [Member] | 2018 [Member]
Disclosure Of Information For Individual Asset Or Cash Generating Unit [Line Items]
Average Price	50.61	58.20
WCS [Member] | 2019 [Member]
Disclosure Of Information For Individual Asset Or Cash Generating Unit [Line Items]
Average Price	56.59	61.90
WCS [Member] | 2020 [Member]
Disclosure Of Information For Individual Asset Or Cash Generating Unit [Line Items]
Average Price	60.86	66.50
WCS [Member] | 2021 [Member]
Disclosure Of Information For Individual Asset Or Cash Generating Unit [Line Items]
Average Price	64.56	71.00
WCS [Member] | 2022 [Member]
Disclosure Of Information For Individual Asset Or Cash Generating Unit [Line Items]
Average Price	66.63
WCS [Member] | 2017 [Member]
Disclosure Of Information For Individual Asset Or Cash Generating Unit [Line Items]
Average Price		53.70
Edmonton C5+ [Member]
Disclosure Of Information For Individual Asset Or Cash Generating Unit [Line Items]
Average Annual Increase Thereafter	2.10%
Edmonton C5+ [Member] | 2018 [Member]
Disclosure Of Information For Individual Asset Or Cash Generating Unit [Line Items]
Average Price	72.41
Edmonton C5+ [Member] | 2019 [Member]
Disclosure Of Information For Individual Asset Or Cash Generating Unit [Line Items]
Average Price	74.90
Edmonton C5+ [Member] | 2020 [Member]
Disclosure Of Information For Individual Asset Or Cash Generating Unit [Line Items]
Average Price	77.07
Edmonton C5+ [Member] | 2021 [Member]
Disclosure Of Information For Individual Asset Or Cash Generating Unit [Line Items]
Average Price	81.07
Edmonton C5+ [Member] | 2022 [Member]
Disclosure Of Information For Individual Asset Or Cash Generating Unit [Line Items]
Average Price	83.32
AECO [Member]
Disclosure Of Information For Individual Asset Or Cash Generating Unit [Line Items]
Average Annual Increase Thereafter	2.00%	2.20%
AECO [Member] | 2018 [Member]
Disclosure Of Information For Individual Asset Or Cash Generating Unit [Line Items]
Average Price | CAD / Mcf	2.43	3.15
AECO [Member] | 2019 [Member]
Disclosure Of Information For Individual Asset Or Cash Generating Unit [Line Items]
Average Price | CAD / Mcf	2.77	3.30
AECO [Member] | 2020 [Member]
Disclosure Of Information For Individual Asset Or Cash Generating Unit [Line Items]
Average Price | CAD / Mcf	3.19	3.60
AECO [Member] | 2021 [Member]
Disclosure Of Information For Individual Asset Or Cash Generating Unit [Line Items]
Average Price | CAD / Mcf	3.48	3.90
AECO [Member] | 2022 [Member]
Disclosure Of Information For Individual Asset Or Cash Generating Unit [Line Items]
Average Price | CAD / Mcf	3.67
AECO [Member] | 2017 [Member]
Disclosure Of Information For Individual Asset Or Cash Generating Unit [Line Items]
Average Price | CAD / Mcf		3.40

XML

Impairment Charges and Reversals - Summary of Increase (Decrease) to Impairment (Detail) CAD in Millions	12 Months Ended
	Dec. 31, 2017 CAD
Clearwater CGU [Member] | One Percent Increase in the Discount Rate [Member]
Disclosure Of Information For Each Material Impairment Loss Recognised Or Reversed For Individual Asset Or Cashgenerating Unit [Line Items]
Increase (Decrease) to Impairment	CAD 27
Clearwater CGU [Member] | One Percent Decrease in the Discount Rate [Member]
Disclosure Of Information For Each Material Impairment Loss Recognised Or Reversed For Individual Asset Or Cashgenerating Unit [Line Items]
Increase (Decrease) to Impairment	(30)
Clearwater CGU [Member] | Five Percent Increase in the Forward Price Estimates [Member]
Disclosure Of Information For Each Material Impairment Loss Recognised Or Reversed For Individual Asset Or Cashgenerating Unit [Line Items]
Increase (Decrease) to Impairment	(56)
Clearwater CGU [Member] | Five Percent Decrease In The Forward Price Estimates
Disclosure Of Information For Each Material Impairment Loss Recognised Or Reversed For Individual Asset Or Cashgenerating Unit [Line Items]
Increase (Decrease) to Impairment	65
Primrose CGU [Member] | One Percent Increase in the Discount Rate [Member]
Disclosure Of Information For Each Material Impairment Loss Recognised Or Reversed For Individual Asset Or Cashgenerating Unit [Line Items]
Increase (Decrease) to Impairment	0
Primrose CGU [Member] | One Percent Decrease in the Discount Rate [Member]
Disclosure Of Information For Each Material Impairment Loss Recognised Or Reversed For Individual Asset Or Cashgenerating Unit [Line Items]
Increase (Decrease) to Impairment	0
Primrose CGU [Member] | Five Percent Increase in the Forward Price Estimates [Member]
Disclosure Of Information For Each Material Impairment Loss Recognised Or Reversed For Individual Asset Or Cashgenerating Unit [Line Items]
Increase (Decrease) to Impairment	0
Primrose CGU [Member] | Five Percent Decrease In The Forward Price Estimates
Disclosure Of Information For Each Material Impairment Loss Recognised Or Reversed For Individual Asset Or Cashgenerating Unit [Line Items]
Increase (Decrease) to Impairment	0
Christina Lake CGU [Member] | One Percent Increase in the Discount Rate [Member]
Disclosure Of Information For Each Material Impairment Loss Recognised Or Reversed For Individual Asset Or Cashgenerating Unit [Line Items]
Increase (Decrease) to Impairment	0
Christina Lake CGU [Member] | One Percent Decrease in the Discount Rate [Member]
Disclosure Of Information For Each Material Impairment Loss Recognised Or Reversed For Individual Asset Or Cashgenerating Unit [Line Items]
Increase (Decrease) to Impairment	0
Christina Lake CGU [Member] | Five Percent Increase in the Forward Price Estimates [Member]
Disclosure Of Information For Each Material Impairment Loss Recognised Or Reversed For Individual Asset Or Cashgenerating Unit [Line Items]
Increase (Decrease) to Impairment	0
Christina Lake CGU [Member] | Five Percent Decrease In The Forward Price Estimates
Disclosure Of Information For Each Material Impairment Loss Recognised Or Reversed For Individual Asset Or Cashgenerating Unit [Line Items]
Increase (Decrease) to Impairment	0
Narrows Lake CGU [Member] | One Percent Increase in the Discount Rate [Member]
Disclosure Of Information For Each Material Impairment Loss Recognised Or Reversed For Individual Asset Or Cashgenerating Unit [Line Items]
Increase (Decrease) to Impairment	312
Narrows Lake CGU [Member] | One Percent Decrease in the Discount Rate [Member]
Disclosure Of Information For Each Material Impairment Loss Recognised Or Reversed For Individual Asset Or Cashgenerating Unit [Line Items]
Increase (Decrease) to Impairment	0
Narrows Lake CGU [Member] | Five Percent Increase in the Forward Price Estimates [Member]
Disclosure Of Information For Each Material Impairment Loss Recognised Or Reversed For Individual Asset Or Cashgenerating Unit [Line Items]
Increase (Decrease) to Impairment	0
Narrows Lake CGU [Member] | Five Percent Decrease In The Forward Price Estimates
Disclosure Of Information For Each Material Impairment Loss Recognised Or Reversed For Individual Asset Or Cashgenerating Unit [Line Items]
Increase (Decrease) to Impairment	CAD 333

XML

Impairment Charges and Reversals - Summary of Increase (Decrease) to Impairment (Parenthetical) (Detail) CAD in Millions	12 Months Ended
	Dec. 31, 2017 CAD
Clearwater CGU [Member]
Disclosure Of Information For Each Material Impairment Loss Recognised Or Reversed For Individual Asset Or Cashgenerating Unit [Line Items]
Impairment losses	CAD 56

XML

Assets Held for Sale and Discontinued Operations - Additional Information (Detail)						12 Months Ended
	Jan. 05, 2018 CAD	Dec. 14, 2017 CAD	Dec. 07, 2017 CAD	Sep. 29, 2017 CAD	Sep. 25, 2017 CAD $ / bbl MMBTU	Dec. 31, 2017 CAD
Conventional [Member]
Disclosure Of Discontinued Operations [Line Items]
Cash proceeds from sale of assets						CAD 3,200,000,000
Pelican Lake Divestiture [Member]
Disclosure Of Discontinued Operations [Line Items]
Cash proceeds from sale of assets				CAD 975,000,000
Gain (Loss) before tax on sale of assets				CAD (623,000,000)
Palliser Divestiture [Member]
Disclosure Of Discontinued Operations [Line Items]
Cash proceeds from sale of assets			CAD 1,300,000,000
Gain (Loss) before tax on sale of assets			CAD 1,600,000,000
Weyburn Divestiture [Member]
Disclosure Of Discontinued Operations [Line Items]
Cash proceeds from sale of assets		CAD 940,000,000
Gain (Loss) before tax on sale of assets		CAD 276,000,000
Suffiled Divestiture [Member]
Disclosure Of Discontinued Operations [Line Items]
Cash proceeds from sale of assets					CAD 512,000,000
Gain (Loss) before tax on sale of assets	CAD 350,000,000
Fair value of deferred purchase price adjustment					7,000,000
Suffiled Divestiture [Member] | Top of range [Member]
Disclosure Of Discontinued Operations [Line Items]
Purchase price adjustments					36,000,000
Suffiled Divestiture [Member] | Top of range [Member] | Crude oil contracts [Member]
Disclosure Of Discontinued Operations [Line Items]
Purchase price adjustments					375,000
Suffiled Divestiture [Member] | Top of range [Member] | Natural gas contracts [Member]
Disclosure Of Discontinued Operations [Line Items]
Purchase price adjustments					CAD 1,125,000
Suffiled Divestiture [Member] | Bottom of range [Member] | WTI [Member]
Disclosure Of Discontinued Operations [Line Items]
Average daily crude oil price | $ / bbl					55
Suffiled Divestiture [Member] | Bottom of range [Member] | Henry Hub
Disclosure Of Discontinued Operations [Line Items]
Average natural gas price | MMBTU					3.50

XML

Assets Held for Sale and Discontinued Operations - Results of Discontinued Operations (Detail) - CAD CAD in Millions	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016		Dec. 31, 2015
Revenues
Gross Sales	CAD 1,309	CAD 1,267		CAD 1,648
Less: Royalties	174	139		113
Revenue	1,135	1,128		1,535
Expenses
Transportation and Blending	167	186		229
Operating	426	444		558
Production and Mineral Taxes	18	12		17
(Gain) Loss on Risk Management	33	(58)		(209)
Operating Margin	491	544		940
Depreciation, Depletion and Amortization	192	567		1,121
Exploration Expense	2			71
Finance Costs	80	102		101
Earnings (Loss) From Discontinued Operations Before Income Tax	217	(125)		(353)
Current Tax Expense (Recovery)	24	86		145
Deferred Tax Expense (Recovery)	33	(125)		(202)
After-tax Earnings (Loss) From Discontinued Operations	160	(86)		(296)
After-tax Gain (Loss) on Discontinuance	938
Net Earnings (Loss) From Discontinued Operations	CAD 1,098	CAD (86)	[1]	CAD (296)	[1]

[1] The comparative periods have been restated to reflect discontinued operations as discussed in Notes 1 and 11.

XML

Assets Held for Sale and Discontinued Operations - Results of Discontinued Operations (Parenthetical) (Detail) CAD in Millions	12 Months Ended
	Dec. 31, 2017 CAD
Disclosure Of Discontinued Operations [Abstract]
Net Deferred Tax Expense	CAD 347

XML

Assets Held for Sale and Discontinued Operations - Summary of Cash Flows from Discontinued Operations (Detail) - CAD CAD in Millions	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Cash Flows From Discontinued Operations [Abstract]
Cash From Operating Activities	CAD 448	CAD 435	CAD 778
Cash From (Used in) Investing Activities	2,993	(168)	(243)
Net Cash Flow	CAD 3,441	CAD 267	CAD 535

XML

Assets Held for Sale and Discontinued Operations - Summary of Assets and Liabilities Held for Sale (Detail) CAD in Millions	Dec. 31, 2017 CAD
Disclosure Of Assets And Liabilities Classified As Held For Sale [Line Items]
Noncurrent assets held for sale	CAD 1,048
Decommissioning Liabilities	603
Conventional [Member]
Disclosure Of Assets And Liabilities Classified As Held For Sale [Line Items]
Decommissioning Liabilities	454
Deep Basin [Member]
Disclosure Of Assets And Liabilities Classified As Held For Sale [Line Items]
Decommissioning Liabilities	149
E&E [Member]
Disclosure Of Assets And Liabilities Classified As Held For Sale [Line Items]
Noncurrent assets held for sale	46
E&E [Member] | Deep Basin [Member]
Disclosure Of Assets And Liabilities Classified As Held For Sale [Line Items]
Noncurrent assets held for sale	46
Property, plant and equipment [member]
Disclosure Of Assets And Liabilities Classified As Held For Sale [Line Items]
Noncurrent assets held for sale	1,002
Property, plant and equipment [member] | Conventional [Member]
Disclosure Of Assets And Liabilities Classified As Held For Sale [Line Items]
Noncurrent assets held for sale	568
Property, plant and equipment [member] | Deep Basin [Member]
Disclosure Of Assets And Liabilities Classified As Held For Sale [Line Items]
Noncurrent assets held for sale	CAD 434

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Income Taxes - Provision for Income Taxes (Detail) - CAD CAD in Millions	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016		Dec. 31, 2015
Major Components Of Tax Expense Income [Line Items]
Current Tax Expense (Recovery)	CAD (255)	CAD (259)		CAD 429
Deferred Tax Expense (Recovery)	203	(84)		(453)
Tax Expense (Recovery) From Continuing Operations	(52)	(343)	[1]	(24)	[1]
Canada [Member]
Major Components Of Tax Expense Income [Line Items]
Current Tax Expense (Recovery)	(217)	(260)		441
United States [member]
Major Components Of Tax Expense Income [Line Items]
Current Tax Expense (Recovery)	CAD (38)	CAD 1		CAD (12)

[1] The comparative periods have been restated to reflect discontinued operations as discussed in Notes 1 and 11.

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Income Taxes - Additional Information (Detail) - CAD	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Disclosure of income taxes [line items]
Deferred tax expense (recovery)	CAD (275,000,000)		CAD 114,000,000
Income tax rate	35.00%
Deferred tax recovery due to adjustment to the tax basis of the refining assets			CAD (415,000,000)
Increase in applicable tax rate			2.00%
Deferred tax liability has been recognized	CAD 0
Amounts of tax pools available, including tax losses	10,031,000,000	CAD 6,309,000,000
Unrecognized as a deferred income tax asset		40,000,000
Canadian Non Capital Losses [Member]
Disclosure of income taxes [line items]
Amounts of tax pools available, including tax losses	73,000,000	46,000,000
US Federal Net Operating Losses [Member]
Disclosure of income taxes [line items]
Amounts of tax pools available, including tax losses	593,000,000	623,000,000
Canadian Net Capital Losses [Member]
Disclosure of income taxes [line items]
Amounts of tax pools available, including tax losses	8,000,000	43,000,000
Net capital losses associated with unrealized foreign exchange losses	CAD 293,000,000	730,000,000
Reduction of U.S. Federal Corporate Income Tax Rate
Disclosure of income taxes [line items]
Income tax rate, current	21.00%
Temporary Differences [Member]
Disclosure of income taxes [line items]
Income tax expense		CAD 7,457,000,000

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Income Taxes - Reconciliation of Income Taxes Calculated at Statutory Rate (Detail) - CAD CAD in Millions	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016		Dec. 31, 2015
Reconciliation Of Average Effective Tax Rate And Applicable Tax Rate [Abstract]
Earnings (Loss) From Continuing Operations Before Income Tax	CAD 2,216	CAD (802)		CAD 890
Canadian Statutory Rate	27.00%	27.00%		26.10%
Expected Income Tax Expense (Recovery) From Continuing Operations	CAD 598	CAD (217)		CAD 232
Effect of Taxes Resulting From:
Foreign Tax Rate Differential	(17)	(46)		(41)
Non-Taxable Capital (Gains) Losses	(148)	(26)		137
Non-Recognition of Capital (Gains) Losses	(118)	(26)		135
Adjustments Arising From Prior Year Tax Filings	(41)	(46)		(55)
(Recognition) of Previously Unrecognized Capital Losses	(68)			(149)
(Recognition) of U.S. Tax Basis				(415)
Change in Statutory Rate	(275)			114
Non-Deductible Expenses	(5)	5		7
Other	22	13		11
Tax Expense (Recovery) From Continuing Operations	CAD (52)	CAD (343)	[1]	CAD (24)	[1]
Effective Tax Rate	(2.30%)	42.80%		(2.70%)

[1] The comparative periods have been restated to reflect discontinued operations as discussed in Notes 1 and 11.

XML

Income Taxes - Deferred Income Tax Liabilities and Deferred Income Tax Assets (Detail) - CAD CAD in Millions	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Disclosure of income taxes [line items]
Deferred Income Tax Liabilities	CAD 6,415	CAD 3,153	CAD 3,151
Deferred Income Tax Assets	(802)	(568)	(335)
Net Deferred Income Tax Liability	5,613	2,585	CAD 2,816
Less Than 1 Year [Member]
Disclosure of income taxes [line items]
Deferred Income Tax Liabilities	186	6
Deferred Income Tax Assets	(374)	(117)
1 Year [member]
Disclosure of income taxes [line items]
Deferred Income Tax Liabilities	6,229	3,147
Deferred Income Tax Assets	CAD (428)	CAD (451)

XML

Income Taxes - Schedule of Movement in Deferred Income Tax Liabilities and Assets (Detail) - CAD CAD in Millions	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016
Reconciliation Of Changes In Deferred Tax Liability Asset [Line Items]
Deferred Income Tax Liabilities, Beginning Balance	CAD 3,153	CAD 3,151
Deferred Income Tax Liabilities, Ending Balance	6,415	3,153
Deferred Income Tax Assets, Beginning Balance	(568)	(335)
Deferred Income Tax Assets, Ending Balance	(802)	(568)
Net Deferred Income Tax Liabilities, Beginning Balance	2,585	2,816
Net Deferred Income Tax Liabilities, Ending Balance	5,613	2,585
Unused Tax Losses [Member]
Reconciliation Of Changes In Deferred Tax Liability Asset [Line Items]
Deferred Income Tax Assets, Beginning Balance	(270)	(172)
Deferred Income Tax Assets, Ending Balance	(191)	(270)
Deferred Income Tax Liabilities [Member]
Reconciliation Of Changes In Deferred Tax Liability Asset [Line Items]
Charged (Credited) to Earnings	801	26
Charged (Credited) to OCI	(45)	(24)
Charged (Credited) to Purchase Price Allocation	2,506
Deferred Income Tax Assets [Member]
Reconciliation Of Changes In Deferred Tax Liability Asset [Line Items]
Charged (Credited) to Earnings	(218)	(235)
Charged (Credited) to OCI	12	2
Charged (Credited) to Share Capital	(28)
Deferred Income Tax Assets [Member] | Unused Tax Losses [Member]
Reconciliation Of Changes In Deferred Tax Liability Asset [Line Items]
Charged (Credited) to Earnings	67	(102)
Charged (Credited) to OCI	12	4
Net Deferred Income Tax Liabilities [Member]
Reconciliation Of Changes In Deferred Tax Liability Asset [Line Items]
Charged (Credited) to Earnings	583	(209)
Charged (Credited) to OCI	(33)	(22)
Charged (Credited) to Purchase Price Allocation	2,506
Charged (Credited) to Share Capital	(28)
PP&E [Member]
Reconciliation Of Changes In Deferred Tax Liability Asset [Line Items]
Deferred Income Tax Liabilities, Beginning Balance	3,146	3,052
Deferred Income Tax Liabilities, Ending Balance	6,232	3,146
PP&E [Member] | Deferred Income Tax Liabilities [Member]
Reconciliation Of Changes In Deferred Tax Liability Asset [Line Items]
Charged (Credited) to Earnings	625	118
Charged (Credited) to OCI	(45)	(24)
Charged (Credited) to Purchase Price Allocation	2,506
Timing of Partnership Items [Member]
Reconciliation Of Changes In Deferred Tax Liability Asset [Line Items]
Deferred Income Tax Liabilities, Ending Balance	164
Deferred Income Tax Assets, Beginning Balance		(36)
Timing of Partnership Items [Member] | Deferred Income Tax Liabilities [Member]
Reconciliation Of Changes In Deferred Tax Liability Asset [Line Items]
Charged (Credited) to Earnings	164
Timing of Partnership Items [Member] | Deferred Income Tax Assets [Member]
Reconciliation Of Changes In Deferred Tax Liability Asset [Line Items]
Charged (Credited) to Earnings		36
Risk Management [Member]
Reconciliation Of Changes In Deferred Tax Liability Asset [Line Items]
Deferred Income Tax Liabilities, Beginning Balance	6	82
Deferred Income Tax Liabilities, Ending Balance	17	6
Deferred Income Tax Assets, Beginning Balance	(85)	(8)
Deferred Income Tax Assets, Ending Balance	(283)	(85)
Risk Management [Member] | Deferred Income Tax Liabilities [Member]
Reconciliation Of Changes In Deferred Tax Liability Asset [Line Items]
Charged (Credited) to Earnings	11	(76)
Risk Management [Member] | Deferred Income Tax Assets [Member]
Reconciliation Of Changes In Deferred Tax Liability Asset [Line Items]
Charged (Credited) to Earnings	(198)	(77)
Other [Member]
Reconciliation Of Changes In Deferred Tax Liability Asset [Line Items]
Deferred Income Tax Liabilities, Beginning Balance	1	17
Deferred Income Tax Liabilities, Ending Balance	2	1
Deferred Income Tax Assets, Beginning Balance	(213)	(119)
Deferred Income Tax Assets, Ending Balance	(328)	(213)
Other [Member] | Deferred Income Tax Liabilities [Member]
Reconciliation Of Changes In Deferred Tax Liability Asset [Line Items]
Charged (Credited) to Earnings	1	(16)
Other [Member] | Deferred Income Tax Assets [Member]
Reconciliation Of Changes In Deferred Tax Liability Asset [Line Items]
Charged (Credited) to Earnings	(87)	(92)
Charged (Credited) to OCI		CAD (2)
Charged (Credited) to Share Capital	CAD (28)

XML

Income Taxes - Schedule of Amounts of Tax Pools Available, Including Tax Losses (Detail) - CAD CAD in Millions	Dec. 31, 2017	Dec. 31, 2016
Disclosure of temporary difference, unused tax losses and unused tax credits [Line Items]
Amounts of tax pools available, including tax losses	CAD 10,031	CAD 6,309
Canada [Member]
Disclosure of temporary difference, unused tax losses and unused tax credits [Line Items]
Amounts of tax pools available, including tax losses	8,317	4,273
United States [member]
Disclosure of temporary difference, unused tax losses and unused tax credits [Line Items]
Amounts of tax pools available, including tax losses	CAD 1,714	CAD 2,036

XML

Per Share Amounts - Schedule Representing Per Share Amounts (Detail) - CAD CAD / shares in Units, shares in Millions, CAD in Millions	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016		Dec. 31, 2015
Earnings (Loss) From:
Continuing Operations	CAD 2,268	CAD (459)	[1]	CAD 914	[1]
Discontinued Operations	1,098	(86)	[1]	(296)	[1]
Net Earnings (Loss)	CAD 3,366	CAD (545)	[1]	CAD 618	[1]
Weighted Average Number of Shares (millions)	1,102.5	833.3		818.7
Basic and Diluted Earnings (Loss) Per Share ($)
Continuing Operations	CAD 2.06	CAD (0.55)	[1]	CAD 1.11	[1]
Discontinued Operations	0.99	(0.10)	[1]	(0.36)	[1]
Net Earnings (Loss) Per Share	CAD 3.05	CAD (0.65)	[1]	CAD 0.75	[1]

[1] The comparative periods have been restated to reflect discontinued operations as discussed in Notes 1 and 11.

XML

Per Share Amounts - Additional Information (Detail) - CAD CAD / shares in Units, shares in Millions, CAD in Millions	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Earnings Per Share [Line Items]
Dividends paid on common shares	CAD 225	CAD 166	CAD 710
Dividends paid in cash	CAD 225	CAD 166	CAD 528
Dividend paid per share	CAD 0.20	CAD 0.20	CAD 0.8524
Dividend declared but not paid	CAD 0.05
NSRs [Member]
Earnings Per Share [Line Items]
Options excluded from diluted weighted average number of shares	43	42
TSARs [Member]
Earnings Per Share [Line Items]
Options excluded from diluted weighted average number of shares	81	3

XML

Cash and Cash Equivalents - Schedule Representing Cash and Cash Equivalents (Detail) - CAD CAD in Millions	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
Cash And Cash Equivalents [Abstract]
Cash	CAD 547	CAD 542
Short-Term Investments	63	3,178
Total	CAD 610	CAD 3,720	CAD 4,105	CAD 883

XML

Accounts Receivables and Accrued Revenues - Schedule of accounts receivables and accrued revenues (Detail) - CAD CAD in Millions	Dec. 31, 2017	Dec. 31, 2016
Trade And Other Current Receivables [Abstract]
Accruals	CAD 1,379	CAD 1,606
Prepaids and Deposits	64	127
Partner Advances	94
Note Receivable From Partner		50
Trade	193	29
Joint Operations Receivables	51	11
Other	49	15
Accounts Receivable and Accrued Revenues	CAD 1,830	CAD 1,838

XML

Accounts Receivables and Accrued Revenues - Schedule of accounts receivables and accrued revenues (Parenthetical) (Detail)	12 Months Ended
	Dec. 31, 2017
Trade And Other Current Receivables [Abstract]
Interest rate on note receivable from partner	1.6783%

XML

Inventories - Schedule of Inventories (Detail) - CAD CAD in Millions	Dec. 31, 2017	Dec. 31, 2016
Disclosure of inventories [line items]
Parts and Supplies	CAD 77	CAD 55
Inventories	1,389	1,237
Refining and Marketing [Member]
Disclosure of inventories [line items]
Refining and Marketing	894	1,006
Oil Sands [Member]
Disclosure of inventories [line items]
Crude Oil	414	156
Deep Basin [Member]
Disclosure of inventories [line items]
Crude Oil	2
Conventional [Member]
Disclosure of inventories [line items]
Crude Oil	CAD 2	CAD 20

XML

Inventories - Additional Information (Detail) - CAD CAD in Millions	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Disclosure Of Inventories [Abstract]
Cost of inventories recognized as expense during period	CAD 12,856	CAD 9,964	CAD 10,618

XML

Exploration and Evaluation Assets - Summary of Exploration and Valuation Assets (Detail) - CAD CAD in Millions	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016		Dec. 31, 2015
Disclosure Of Exploration And Evaluation Assets [Line Items]
Beginning Balance	CAD 1,585
Exploration Expense	(888)	CAD (2)	[1]	CAD (67)	[1]
Ending Balance	3,673	1,585
E&E [Member]
Disclosure Of Exploration And Evaluation Assets [Line Items]
Beginning Balance	1,585	1,575
Additions	147	67
Acquisition	3,608
Transfers to Assets Held for Sale	(316)
Transfers to PP&E	(6)	(49)
Exploration Expense	(890)	(2)
Change in Decommissioning Liabilities	5	(6)
Exchange Rate Movements and Other	19
Divestitures	(479)
Ending Balance	CAD 3,673	CAD 1,585		CAD 1,575

[1] The comparative periods have been restated to reflect discontinued operations as discussed in Notes 1 and 11.

XML

Property, Plant and Equipment, Net - Summary of Property, Plant and Equipment (Detail) - CAD CAD in Millions	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016
Disclosure Of Property Plant And Equipment [Line Items]
Beginning Balance	CAD 16,426	CAD 17,335
Ending Balance	29,596	16,426
Cost [Member]
Disclosure Of Property Plant And Equipment [Line Items]
Beginning Balance	38,607	38,055
Additions	1,581	970
Acquisition	26,317
Transfers From E&E Assets	6	49
Transfers to Assets Held for Sale	(19,719)
Change in Decommissioning Liabilities	(64)	(275)
Exchange Rate Movements and Other	(391)	(169)
Divestitures	(12,335)	(23)
Ending Balance	34,002	38,607
Accumulated Depreciation, Depletion and Amortization [Member]
Disclosure Of Property Plant And Equipment [Line Items]
Beginning Balance	22,181	20,720
Transfers to Assets Held for Sale	(16,120)
DD&A	1,953	1,475
Impairment Losses	77	485
Reversal of Impairment Losses		(462)
Exchange Rate Movements and Other	(73)	(29)
Divestitures	(3,612)	(8)
Ending Balance	4,406	22,181
Development & Production Upstream Assets [Member]
Disclosure Of Property Plant And Equipment [Line Items]
Beginning Balance	11,853	12,573
Ending Balance	25,337	11,853
Development & Production Upstream Assets [Member] | Cost [Member]
Disclosure Of Property Plant And Equipment [Line Items]
Beginning Balance	31,941	31,481
Additions	1,324	717
Acquisition	26,317
Transfers From E&E Assets	6	49
Transfers to Assets Held for Sale	(19,719)
Change in Decommissioning Liabilities	(67)	(267)
Exchange Rate Movements and Other	(28)	(16)
Divestitures	(12,333)	(23)
Ending Balance	27,441	31,941
Development & Production Upstream Assets [Member] | Accumulated Depreciation, Depletion and Amortization [Member]
Disclosure Of Property Plant And Equipment [Line Items]
Beginning Balance	20,088	18,908
Transfers to Assets Held for Sale	(16,120)
DD&A	1,653	1,173
Impairment Losses	77	481
Reversal of Impairment Losses		(462)
Exchange Rate Movements and Other	17	(4)
Divestitures	(3,611)	(8)
Ending Balance	2,104	20,088
Other Upstream Assets [Member]
Disclosure Of Property Plant And Equipment [Line Items]
Beginning Balance	25	54
Ending Balance	2	25
Other Upstream Assets [Member] | Cost [Member]
Disclosure Of Property Plant And Equipment [Line Items]
Beginning Balance	333	331
Additions		2
Ending Balance	333	333
Other Upstream Assets [Member] | Accumulated Depreciation, Depletion and Amortization [Member]
Disclosure Of Property Plant And Equipment [Line Items]
Beginning Balance	308	277
DD&A	23	31
Ending Balance	331	308
Refining Equipment [Member]
Disclosure Of Property Plant And Equipment [Line Items]
Beginning Balance	4,183	4,310
Ending Balance	3,868	4,183
Refining Equipment [Member] | Cost [Member]
Disclosure Of Property Plant And Equipment [Line Items]
Beginning Balance	5,259	5,206
Additions	168	213
Change in Decommissioning Liabilities		(8)
Exchange Rate Movements and Other	(364)	(152)
Divestitures	(2)
Ending Balance	5,061	5,259
Refining Equipment [Member] | Accumulated Depreciation, Depletion and Amortization [Member]
Disclosure Of Property Plant And Equipment [Line Items]
Beginning Balance	1,076	896
DD&A	209	205
Exchange Rate Movements and Other	(91)	(25)
Divestitures	(1)
Ending Balance	1,193	1,076
Other [Member]
Disclosure Of Property Plant And Equipment [Line Items]
Beginning Balance	365	398
Ending Balance	389	365
Other [Member] | Cost [Member]
Disclosure Of Property Plant And Equipment [Line Items]
Beginning Balance	1,074	1,037
Additions	89	38
Change in Decommissioning Liabilities	3
Exchange Rate Movements and Other	1	(1)
Ending Balance	1,167	1,074
Other [Member] | Accumulated Depreciation, Depletion and Amortization [Member]
Disclosure Of Property Plant And Equipment [Line Items]
Beginning Balance	709	639
DD&A	68	66
Impairment Losses		4
Exchange Rate Movements and Other	1
Ending Balance	CAD 778	CAD 709

XML

Property, Plant and Equipment, Net - Summary of Property, Plant and Equipment (Parenthetical) (Detail) CAD in Millions	Dec. 31, 2017 CAD
FCCL [Member]
Disclosure Of Property Plant And Equipment [Line Items]
Carrying value of the pre-existing interest in FCCL	CAD 8,602

XML

Property, Plant and Equipment, Net - Summary of PP&E Under Construction and Not Subject to DD&A (Detail) - CAD CAD in Millions	Dec. 31, 2017	Dec. 31, 2016
Disclosure Of Property Plant And Equipment [Line Items]
Property Plant and Equipment Temporarily Idle	CAD 1,940	CAD 743
Development & Production Upstream Assets [Member]
Disclosure Of Property Plant And Equipment [Line Items]
Property Plant and Equipment Temporarily Idle	1,809	537
Refining Equipment [Member]
Disclosure Of Property Plant And Equipment [Line Items]
Property Plant and Equipment Temporarily Idle	CAD 131	CAD 206

XML

Other Assets - Schedule of Other Assets (Detail) - CAD CAD in Millions	Dec. 31, 2017	Dec. 31, 2016
Other Noncurrent Assets [Abstract]
Equity Investments	CAD 37	CAD 35
Long-Term Receivables	11	15
Prepaids	9	5
Other	14	1
Other assets	CAD 71	CAD 56

XML

Goodwill - Summary of Carrying Value of Goodwill (Detail) CAD in Millions	12 Months Ended
	Dec. 31, 2017 CAD
Disclosure Of Reconciliation Of Changes In Goodwill [Abstract]
Carrying Value, Beginning of Year	CAD 242
Goodwill Recognized on Acquisition (Note 5)	2,030
Carrying Value, End of Year	CAD 2,272

XML

Goodwill - Summary of Carrying Amount of Goodwill Allocated to Company's Exploration and Production CGUs (Detail) - CAD CAD in Millions	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Disclosure Of Information For Individual Asset Or Cashgenerating Unit With Significant Amount Of Goodwill Or Intangible Assets With Indefinite Useful Lives [Line Items]
Goodwill	CAD 2,272	CAD 242	CAD 242
Primrose (Foster Creek) [Member]
Disclosure Of Information For Individual Asset Or Cashgenerating Unit With Significant Amount Of Goodwill Or Intangible Assets With Indefinite Useful Lives [Line Items]
Goodwill	1,171	CAD 242
Christina Lake [Member]
Disclosure Of Information For Individual Asset Or Cashgenerating Unit With Significant Amount Of Goodwill Or Intangible Assets With Indefinite Useful Lives [Line Items]
Goodwill	CAD 1,101

XML

Accounts Payable and Accrued Liabilities - Schedule of Accounts Payable and Accrued Liabilities (Detail) - CAD CAD in Millions	Dec. 31, 2017	Dec. 31, 2016
Trade And Other Current Payables [Abstract]
Accruals	CAD 2,006	CAD 1,927
Trade	337	105
Interest	86	72
Partner Advances	94
Note Payable to Partner		50
Employee Long-Term Incentives	52	42
Onerous Contract Provisions	8	18
Joint Operations Payables	12
Other	40	52
Accounts payable and accrued liabilities	CAD 2,635	CAD 2,266

XML

Accounts Payable and Accrued Liabilities - Schedule of Accounts Payable and Accrued Liabilities (Parenthetical) (Detail)	12 Months Ended
	Dec. 31, 2017
Trade And Other Current Payables [Abstract]
Interest rate on note payable to partner	1.6783%

XML

Contingent Payment - Summary of Contingent Payment (Detail) CAD in Millions	12 Months Ended
	Dec. 31, 2017 CAD
Disclosure Of Contingent Liabilities In Business Combination [Abstract]
Initial Recognition on May 17, 2017	CAD 361
Re-measurement	(138)
Liabilities Settled or Payable	(17)
Contingent Liabilities	206
Less: Current Portion	38
Long-Term Portion	CAD 168

XML

Contingent Payment - Additional Information (Detail) CAD in Millions	7 Months Ended	12 Months Ended
	Dec. 31, 2017 CAD CAD / bbl	Dec. 31, 2017 CAD CAD / bbl
Disclosure Of Contingent Liabilities In Business Combination [Line Items]
Contingent payable		CAD 17
ConocoPhillips Company and Certain of its Subsidiaries [Member]
Disclosure Of Contingent Liabilities In Business Combination [Line Items]
Contingent payment description		In connection with the Acquisition (see Note 5), Cenovus agreed to make quarterly payments to ConocoPhillips during the five years subsequent to May 17, 2017 for quarters in which the average WCS crude oil price exceeds $52.00 per barrel during the quarter. The quarterly payment will be $6 million for each dollar that the WCS price exceeds $52.00 per barrel. The calculation includes an adjustment mechanism related to certain significant production outages at Foster Creek and Christina Lake which may reduce the amount of a contingent payment. As at December 31, 2017, $17 million is payable under this agreement.
Contingent payments period		5 years
Average crude oil price per barrel for contingent payment | CAD / bbl		52.00
Quarterly contingent payment	CAD 6	CAD 6
Contingent payable		CAD 17
ConocoPhillips Company and Certain of its Subsidiaries [Member] | Top of range [Member]
Disclosure Of Contingent Liabilities In Business Combination [Line Items]
Average crude oil price per barrel for contingent payment | CAD / bbl	52.00

XML

Long-term Debt - Schedule of Long Term Debt (Detail) CAD in Millions, $ in Millions	Dec. 31, 2017 CAD	Dec. 31, 2017 USD ($)	Apr. 07, 2017 USD ($)	Dec. 31, 2016 CAD	Dec. 31, 2016 USD ($)	Dec. 31, 2015 CAD
Disclosure of detailed information about borrowings [line items]
Total Debt Principal | $			$ 2,900
Debt Discounts and Transaction Costs	CAD (84)			CAD (46)
Non-current portion of non-current borrowings	9,513			6,332		CAD 6,525
Long-term Borrowings [Member]
Disclosure of detailed information about borrowings [line items]
Total Debt Principal | $		$ 7,650			$ 4,750
Total Debt Principal, (CAD equivalent)	9,597			6,378
U.S. Dollar Denominated Unsecured Notes [Member] | Long-term Borrowings [Member]
Disclosure of detailed information about borrowings [line items]
Total Debt Principal | $		$ 7,650
Total Debt Principal, (CAD equivalent)	CAD 9,597			CAD 6,378

XML

Long-term Debt - Additional Information (Detail)		12 Months Ended
	Apr. 28, 2017 CAD	Dec. 31, 2017 CAD	Dec. 31, 2017 USD ($)	Oct. 10, 2017 USD ($)	May 17, 2017 CAD	Apr. 07, 2017 USD ($)	Dec. 31, 2016 CAD	Dec. 31, 2016 USD ($)
Disclosure of detailed information about borrowings [line items]
Weighted average interest rate		4.90%	4.90%				5.30%	5.30%
Senior unsecured notes issued | $						$ 2,900,000,000
Credit Facility [member]
Disclosure of detailed information about borrowings [line items]
Total Debt Principal, (CAD equivalent)		CAD 0					CAD 0
Long-term Borrowings [Member]
Disclosure of detailed information about borrowings [line items]
Total Debt Principal, (CAD equivalent)		CAD 9,597,000,000					CAD 6,378,000,000
Senior unsecured notes issued | $			$ 7,650,000,000					$ 4,750,000,000
Base Shelf Prospectus [Member] | Top of range [Member]
Disclosure of detailed information about borrowings [line items]
Authorized capacity under base shelf prospectus | $			4,600,000,000	$ 7,500,000,000
Revolving Term Debt [Member]
Disclosure of detailed information about borrowings [line items]
Maturity date		The committed credit facility consists of a $1.2 billion tranche maturing on November 30, 2020 and a $3.3 billion tranche maturing on November 30, 2021.
Revolving Term Debt [Member] | Committed Credit Facility [member] | Bottom of range [Member]
Disclosure of detailed information about borrowings [line items]
Increase to committed credit facility capacity	CAD 500,000,000
Revolving Term Debt [Member] | Committed Credit Facility [member] | Top of range [Member]
Disclosure of detailed information about borrowings [line items]
Committed credit facility capacity	4,500,000,000
Revolving Term Debt [Member] | Tranche One [Member]
Disclosure of detailed information about borrowings [line items]
Committed credit facility capacity	1,200,000,000
Maturity date		November 30, 2020
Revolving Term Debt [Member] | Tranche Two [Member]
Disclosure of detailed information about borrowings [line items]
Committed credit facility capacity	CAD 3,300,000,000
Maturity date		November 30, 2021
Committed Asset Sale Bridge Credit Facility [Member]
Disclosure of detailed information about borrowings [line items]
Borrowings		CAD 3,600,000,000			CAD 3,600,000,000
4.25% Due April 15, 2027 [Member] | Long-term Borrowings [Member]
Disclosure of detailed information about borrowings [line items]
Total Debt Principal, (CAD equivalent)		1,505,000,000
Senior unsecured notes issued | $			1,200,000,000			$ 1,200,000,000
Borrowings interest rate						4.25%
5.25% Due June 15, 2037 [Member] | Long-term Borrowings [Member]
Disclosure of detailed information about borrowings [line items]
Total Debt Principal, (CAD equivalent)		878,000,000
Senior unsecured notes issued | $			700,000,000			$ 700,000,000
Borrowings interest rate						5.25%
5.40% Due June 15, 2047 [Member] | Long-term Borrowings [Member]
Disclosure of detailed information about borrowings [line items]
Total Debt Principal, (CAD equivalent)		CAD 1,255,000,000
Senior unsecured notes issued | $			$ 1,000,000,000			$ 1,000,000,000
Borrowings interest rate						5.40%

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Long-term Debt - Summary of Unsecured Notes (Detail) CAD in Millions, $ in Millions	Dec. 31, 2017 CAD	Dec. 31, 2017 USD ($)	Apr. 07, 2017 USD ($)	Dec. 31, 2016 CAD	Dec. 31, 2016 USD ($)
Disclosure of detailed information about borrowings [line items]
Total Debt Principal			$ 2,900
Long-term Borrowings [Member]
Disclosure of detailed information about borrowings [line items]
Total Debt Principal		$ 7,650			$ 4,750
Total Debt Principal, (CAD equivalent) | CAD	CAD 9,597			CAD 6,378
5.70 % Due October 15, 2019 [Member] | Long-term Borrowings [Member]
Disclosure of detailed information about borrowings [line items]
Total Debt Principal		1,300
Total Debt Principal, (CAD equivalent) | CAD	1,631			1,746
3.00% Due August 15, 2022 [Member] | Long-term Borrowings [Member]
Disclosure of detailed information about borrowings [line items]
Total Debt Principal		500
Total Debt Principal, (CAD equivalent) | CAD	627			671
3.80% Due September 15, 2023 [Member] | Long-term Borrowings [Member]
Disclosure of detailed information about borrowings [line items]
Total Debt Principal		450
Total Debt Principal, (CAD equivalent) | CAD	565			604
4.25% Due April 15, 2027 [Member] | Long-term Borrowings [Member]
Disclosure of detailed information about borrowings [line items]
Total Debt Principal		1,200	1,200
Total Debt Principal, (CAD equivalent) | CAD	1,505
5.25% Due June 15, 2037 [Member] | Long-term Borrowings [Member]
Disclosure of detailed information about borrowings [line items]
Total Debt Principal		700	700
Total Debt Principal, (CAD equivalent) | CAD	878
6.75% Due November 15, 2039 [Member] | Long-term Borrowings [Member]
Disclosure of detailed information about borrowings [line items]
Total Debt Principal		1,400
Total Debt Principal, (CAD equivalent) | CAD	1,756			1,880
4.45% Due September 15, 2042 [Member] | Long-term Borrowings [Member]
Disclosure of detailed information about borrowings [line items]
Total Debt Principal		750
Total Debt Principal, (CAD equivalent) | CAD	941			1,007
5.20% Due September 15, 2043 [Member] | Long-term Borrowings [Member]
Disclosure of detailed information about borrowings [line items]
Total Debt Principal		350
Total Debt Principal, (CAD equivalent) | CAD	439			CAD 470
5.40% Due June 15, 2047 [Member] | Long-term Borrowings [Member]
Disclosure of detailed information about borrowings [line items]
Total Debt Principal		$ 1,000	$ 1,000
Total Debt Principal, (CAD equivalent) | CAD	CAD 1,255

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Long-term Debt - Schedule of Mandatory Debt Payments (Detail) CAD in Millions, $ in Millions	Dec. 31, 2017 CAD	Dec. 31, 2017 USD ($)	Apr. 07, 2017 USD ($)	Dec. 31, 2016 CAD	Dec. 31, 2016 USD ($)
Disclosure of detailed information about borrowings [line items]
Total Debt Principal			$ 2,900
Long-term Borrowings [Member]
Disclosure of detailed information about borrowings [line items]
Total Debt Principal		$ 7,650			$ 4,750
Total Debt Principal, (CAD equivalent) | CAD	CAD 9,597			CAD 6,378
Long-term Borrowings [Member] | Later than one year and not later than two years [Member]
Disclosure of detailed information about borrowings [line items]
Total Debt Principal, (CAD equivalent) | CAD	1,631
Long-term Borrowings [Member] | Later than four years and not later than five years [Member]
Disclosure of detailed information about borrowings [line items]
Total Debt Principal, (CAD equivalent) | CAD	627
Long-term Borrowings [Member] | 5 Years [Member]
Disclosure of detailed information about borrowings [line items]
Total Debt Principal, (CAD equivalent) | CAD	CAD 7,339
Long-term Borrowings [Member] | Us Dollar [Member]
Disclosure of detailed information about borrowings [line items]
Total Debt Principal		7,650
Long-term Borrowings [Member] | Us Dollar [Member] | Later than one year and not later than two years [Member]
Disclosure of detailed information about borrowings [line items]
Total Debt Principal		1,300
Long-term Borrowings [Member] | Us Dollar [Member] | Later than four years and not later than five years [Member]
Disclosure of detailed information about borrowings [line items]
Total Debt Principal		500
Long-term Borrowings [Member] | Us Dollar [Member] | 5 Years [Member]
Disclosure of detailed information about borrowings [line items]
Total Debt Principal		$ 5,850

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Decommissioning Liabilities - Summary of Decommissioning Provision (Detail) - CAD CAD in Millions	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016
Provision For Decommissioning Restoration And Rehabilitation Costs [Abstract]
Decommissioning Liabilities, Beginning of Year	CAD 1,847	CAD 2,052
Liabilities Incurred	20	11
Liabilities Acquired	944
Liabilities Settled	(70)	(51)
Liabilities Divested	(139)	(1)
Transfers to Liabilities Related to Assets Held for Sale	(1,621)
Change in Estimated Future Cash Flows	(155)	(423)
Change in Discount Rate	76	131
Unwinding of Discount on Decommissioning Liabilities	128	130
Foreign Currency Translation	(1)	(2)
Decommissioning Liabilities, End of Year	CAD 1,029	CAD 1,847

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Decommissioning Liabilities - Additional Information (Detail) - CAD	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016
Disclosure Of Other Provisions [Line Items]
Estimated future cash flows required to settle the obligation	CAD 3,360,000,000	CAD 6,270,000,000
Credit-adjusted risk-free rate	5.30%	5.90%
Inflation Rate	2.00%	2.00%
Bottom of range [Member]
Disclosure Of Other Provisions [Line Items]
Settlement Of Decommissioning Liabilities	CAD 40,000,000
Top of range [Member]
Disclosure Of Other Provisions [Line Items]
Settlement Of Decommissioning Liabilities		CAD 50,000,000

XML

Decommissioning Liabilities - Summary of Changes to the Credit-Adjusted Risk-Free Rate or the Inflation Rate Impact on the Decommissioning Liabilities (Detail) - CAD CAD in Millions	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016
One percent increase [member]
Disclosure Of Other Provisions [Line Items]
Credit-AdjustedRisk-FreeRate	CAD (98)	CAD (248)
Inflation Rate	197	327
One percent decrease [member]
Disclosure Of Other Provisions [Line Items]
Credit-AdjustedRisk-FreeRate	192	317
Inflation Rate	CAD (103)	CAD (259)

XML

Other Liabilities - Summary of Other Liabilities (Detail) - CAD CAD in Millions	Dec. 31, 2017	Dec. 31, 2016
Miscellaneous Noncurrent Liabilities [Abstract]
Employee Long-Term Incentives	CAD 43	CAD 72
Pension and Other Post-Employment Benefit Plan (Note 26)	62	71
Onerous Contract Provisions	37	35
Other	31	33
Other Liabilities	CAD 173	CAD 211

XML

Pensions and Other Post-Employment Benefits - Additional Information (Detail)	12 Months Ended
	Dec. 31, 2018 CAD	Dec. 31, 2017 Age
Disclosure Of Defined Benefit Plans [Line Items]
Maximum age for retired employees eligible for health care dental and life insurance benefits | Age		65
Bottom of range [Member]
Disclosure Of Defined Benefit Plans [Line Items]
Defined benefit plan, equity securities allocation percentage		50.00%
Defined benefit plan, fixed income assets allocation percentage		25.00%
Defined benefit plan, real estate assets allocation percentage		0.00%
Defined benefit plan, cash and cash equivalents allocation percentage		0.00%
Top of range [Member]
Disclosure Of Defined Benefit Plans [Line Items]
Defined benefit plan, equity securities allocation percentage		75.00%
Defined benefit plan, fixed income assets allocation percentage		35.00%
Defined benefit plan, real estate assets allocation percentage		15.00%
Defined benefit plan, cash and cash equivalents allocation percentage		10.00%
Pension Benefits [Member]
Disclosure Of Defined Benefit Plans [Line Items]
Weighted average duration of the defined benefit plan		16 years
Percentage of employees contribution under pension plan		4.00%
Expected employer contribution	CAD 9,000,000
OPEB [Member]
Disclosure Of Defined Benefit Plans [Line Items]
Weighted average duration of the defined benefit plan		10 years
Expected employer contribution	CAD 0

XML

Pensions and Other Post-Employment Benefits - Summary of Defined Benefit and OPEB Plan Obligation and Funded Status (Detail) - CAD CAD in Millions	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Pension Benefits [Member]
Disclosure Of Net Defined Benefit Liability Asset [Line Items]
Defined Benefit Obligation, Beginning of Year	CAD (48)
Current Service Costs	(14)	CAD (14)	CAD (19)
Interest Income (Costs)	(3)	(4)	(6)
Past Service Costs – Curtailments	6		5
Remeasurements:
(Gains) Losses from Experience Adjustments	1		(3)
(Gains) Losses from Changes in Financial Assumptions	2	(7)	28
Return on Plan Assets (Excluding Interest Income)	(9)	(3)	3
Defined Benefit Obligation, End of Year	(40)	(48)
Pension Benefits [Member] | Present value of defined benefit obligation [Member]
Disclosure Of Net Defined Benefit Liability Asset [Line Items]
Defined Benefit Obligation, Beginning of Year	173	168
Current Service Costs	14	14
Interest Income (Costs)	7	7
Benefits Paid	(8)	(25)
Plan Participant Contributions	2	2
Past Service Costs – Curtailments	(6)
Remeasurements:
(Gains) Losses from Experience Adjustments	1
(Gains) Losses from Changes in Financial Assumptions	(2)	7
Defined Benefit Obligation, End of Year	181	173	168
Pension Benefits [Member] | Plan assets [Member]
Disclosure Of Net Defined Benefit Liability Asset [Line Items]
Interest Income (Costs)	4	3
Benefits Paid	(8)	(25)
Employer Contributions	9	14
Plan Participant Contributions	2	2
Remeasurements:
Return on Plan Assets (Excluding Interest Income)	9	3
Fair Value of Plan Assets, Beginning of Year	125	128
Fair Value of Plan Assets, End of Year	141	125	128
OPEB [Member]
Disclosure Of Net Defined Benefit Liability Asset [Line Items]
Defined Benefit Obligation, Beginning of Year	(23)
Current Service Costs	(2)	3	(3)
Interest Income (Costs)	(1)	(1)	(1)
Past Service Costs – Curtailments	1
Remeasurements:
(Gains) Losses from Changes in Demographic Assumptions	(1)
(Gains) Losses from Changes in Financial Assumptions	1
Defined Benefit Obligation, End of Year	(22)	(23)
OPEB [Member] | Present value of defined benefit obligation [Member]
Disclosure Of Net Defined Benefit Liability Asset [Line Items]
Defined Benefit Obligation, Beginning of Year	23	26
Current Service Costs	2	(3)
Interest Income (Costs)	1	1
Benefits Paid	(1)	(1)
Past Service Costs – Curtailments	(1)
Remeasurements:
(Gains) Losses from Changes in Demographic Assumptions	(1)
(Gains) Losses from Changes in Financial Assumptions	(1)
Defined Benefit Obligation, End of Year	CAD 22	CAD 23	CAD 26

XML

Pensions and Other Post-Employment Benefits - Summary of Pension and OPEB Costs (Detail) - CAD CAD in Millions	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Remeasurements:
Defined Benefit Plan Cost (Recovery)	CAD 8	CAD 11	CAD 17
Defined Contribution Plan Cost	19	16	19
Pension Benefits [Member]
Disclosure Of Defined Benefit Plans [Line Items]
Current Service Costs	14	14	19
Past Service Costs – Curtailments	(6)		(5)
Net Settlement Costs			3
Net Interest Costs	3	4	6
Remeasurements:
Return on Plan Assets (Excluding Interest Income)	(9)	(3)	3
(Gains) Losses from Experience Adjustments	1		(3)
(Gains) Losses from Changes in Financial Assumptions	(2)	7	(28)
Defined Benefit Plan Cost (Recovery)	1	22	(5)
Defined Contribution Plan Cost	27	25	29
Total Plan Cost	28	47	24
OPEB [Member]
Disclosure Of Defined Benefit Plans [Line Items]
Current Service Costs	2	(3)	3
Past Service Costs – Curtailments	(1)
Net Interest Costs	1	1	1
Remeasurements:
(Gains) Losses from Changes in Demographic Assumptions	(1)
(Gains) Losses from Changes in Financial Assumptions	CAD (1)
Defined Benefit Plan Cost (Recovery)		CAD (2)	CAD 4

XML

Pensions and Other Post-Employment Benefits - Summary of Fair Value of the Plan Assets (Detail) - CAD CAD in Millions	Dec. 31, 2017	Dec. 31, 2016
Disclosure Of Fair Value Of Plan Assets [Abstract]
Equity Funds	CAD 89	CAD 73
Bond Funds	29	25
Non-Invested Assets	11	13
Real Estate Funds	9	9
Cash and Cash Equivalents	3	5
Total fair value	CAD 141	CAD 125

XML

Pensions and Other Post-Employment Benefits - Summary of Principal Weighted Average Actuarial Assumptions Used to Determine Benefit Obligations and Expenses (Detail)	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Pension Benefits [Member]
Disclosure Of Actuarial Assumptions [Line Items]
Discount Rate	3.50%	3.75%	4.00%
Future Salary Growth Rate	3.81%	3.80%	3.80%
Average Longevity (years)	88 years	87 years 10 months 25 days	88 years 3 months 19 days
OPEB [Member]
Disclosure Of Actuarial Assumptions [Line Items]
Discount Rate	3.25%	3.75%	3.75%
Future Salary Growth Rate	5.08%	5.15%	5.15%
Average Longevity (years)	88 years	87 years 10 months 25 days	88 years 3 months 19 days
Health Care Cost Trend Rate	6.00%	7.00%	7.00%

XML

Pensions and Other Post-Employment Benefits - Sensitivity of Defined Benefit and OPEB Obligation to Changes in Relevant Actuarial Assumptions (Detail) - CAD CAD in Millions	Dec. 31, 2017	Dec. 31, 2016
Discount Rate [Member]
Disclosure Of Sensitivity Analysis For Actuarial Assumptions [Line Items]
Increase	CAD (28)	CAD (25)
Decrease	36	32
Future Salary Growth Rate [Member]
Disclosure Of Sensitivity Analysis For Actuarial Assumptions [Line Items]
Increase	3	3
Decrease	(3)	(3)
Health Care Cost Trend Rate [Member]
Disclosure Of Sensitivity Analysis For Actuarial Assumptions [Line Items]
Increase	1	2
Decrease	(1)	(1)
One Year Change in Assumed Life Expectancy [Member]
Disclosure Of Sensitivity Analysis For Actuarial Assumptions [Line Items]
Increase	4	4
Decrease	CAD (4)	CAD (4)

XML

Share Capital - Additional Information (Detail) CAD in Millions			12 Months Ended
	May 17, 2017 shares	Apr. 06, 2017 CAD shares	Dec. 31, 2017 CAD shares	Dec. 31, 2015 CAD shares	Dec. 31, 2016 shares
Disclosure of classes of share capital [Line Items]
Maximum percentage of preferred stock upon issuance or outstanding of common stock			20.00%
Number of common shares authorized			unlimited
Number of common share financing through bought-deal		187,500,000	187,500,000
Gross proceeds from bought-deal offering | CAD		CAD 3,000
Net proceeds from bought-deal offering | CAD		2,900	CAD 2,899	CAD 1,449
Share issuance costs | CAD		CAD 101
Shares outstanding			1,228,790,000	833,290,000	833,290,000
Preferred Shares [Member]
Disclosure of classes of share capital [Line Items]
Shares outstanding			0		0
Stock Option Plan [member]
Disclosure of classes of share capital [Line Items]
Shares available for future issuance			15,000,000		12,000,000
ConocoPhillips Company and Certain of its Subsidiaries [Member]
Disclosure of classes of share capital [Line Items]
Consideration transferred as common shares	208,000,000
Percentage of owned outstanding shares	3.50%

XML

Share Capital - Summary of Share Capital (Detail) - CAD shares in Thousands, CAD in Millions	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016	Apr. 06, 2017
Disclosure of classes of share capital [Line Items]
Outstanding, Beginning of Year	CAD 5,534	CAD 5,534
Common Shares Issued, Net of Issuance Costs and Tax	2,927	0
Outstanding, End of Year	CAD 11,040	CAD 5,534
Outstanding, Beginning of Year	833,290	833,290
Common Shares Issued, Net of Issuance Costs and Tax	187,500		187,500
Outstanding, End of Year	1,228,790	833,290
ConocoPhillips Company and Certain of its Subsidiaries [Member]
Disclosure of classes of share capital [Line Items]
Common Shares Issued to ConocoPhillips (Note 5)	CAD 2,579	CAD 0
Common Shares Issued to ConocoPhillips (Note 5)	208,000

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Share Capital - Schedule of Paid in Surplus Includes Stock Based Compensation Expense (Detail) - CAD CAD in Millions	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016
Disclosure of reserves within equity [line items]
Beginning Balance	CAD 4,350	CAD 4,330
Stock-Based Compensation Expense	11	20
Ending Balance	4,361	4,350
Pre-Arrangement Earnings [member]
Disclosure of reserves within equity [line items]
Beginning Balance	4,086	4,086
Ending Balance	4,086	4,086
Stock-Based Compensation [member]
Disclosure of reserves within equity [line items]
Beginning Balance	264	244
Stock-Based Compensation Expense	11	20
Ending Balance	CAD 275	CAD 264

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Accumulated Other Comprehensive Income (Loss) - Schedule of Accumulated Other Comprehensive Income (Loss) (Detail) - CAD CAD in Millions	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016
Disclosure of accumulated other comprehensive income loss [line items]
Beginning Balance	CAD 910	CAD 1,020
Other Comprehensive Income (Loss), Before Tax	(264)	(114)
Income Tax	(3)	4
Ending Balance	643	910
Defined Benefit Pension Plan [member]
Disclosure of accumulated other comprehensive income loss [line items]
Beginning Balance	(13)	(10)
Other Comprehensive Income (Loss), Before Tax	12	(4)
Income Tax	(3)	1
Ending Balance	(4)	(13)
Foreign Currency Translation Adjustment [member]
Disclosure of accumulated other comprehensive income loss [line items]
Beginning Balance	908	1,014
Other Comprehensive Income (Loss), Before Tax	(275)	(106)
Ending Balance	633	908
Available for Sale Financial Assets [member]
Disclosure of accumulated other comprehensive income loss [line items]
Beginning Balance	15	16
Other Comprehensive Income (Loss), Before Tax	(1)	(4)
Income Tax		3
Ending Balance	CAD 14	CAD 15

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Stock-Based Compensation Plans - Additional Information (Detail)	12 Months Ended
	Dec. 31, 2017 CAD Plan CAD / shares	Dec. 31, 2016 CAD
Disclosure of terms and conditions of share-based payment arrangement [Line Items]
Liabilities from share based payment	CAD 52,000,000	CAD 42,000,000
NSRs [Member]
Disclosure of terms and conditions of share-based payment arrangement [Line Items]
Options expiration term	7 years
Weighted average unit fair value of granted	CAD 3.10
TSARs [Member]
Disclosure of terms and conditions of share-based payment arrangement [Line Items]
Options expiration term	7 years
Liabilities from share based payment	CAD 0	0
Intrinsic value of vested	CAD 0	0
Cenovus's Common Share Price | CAD / shares	CAD 11.48
PSUs [Member]
Disclosure of terms and conditions of share-based payment arrangement [Line Items]
Liabilities from share based payment	CAD 37,000,000	51,000,000
Intrinsic value of vested	CAD 0	0
Vesting period	3 years
RSUs [Member]
Disclosure of terms and conditions of share-based payment arrangement [Line Items]
Liabilities from share based payment	CAD 41,000,000	30,000,000
Intrinsic value of vested	CAD 0	0
Vesting period	3 years
DSUs [Member]
Disclosure of terms and conditions of share-based payment arrangement [Line Items]
Liabilities from share based payment	CAD 17,000,000	CAD 32,000,000
Number of Deferred Share Unit Plans | Plan	2
DSUs Option One [Member]
Disclosure of terms and conditions of share-based payment arrangement [Line Items]
Percentage of annual bonus award to convert into DSUs	0.00%
DSUs Option Two [Member]
Disclosure of terms and conditions of share-based payment arrangement [Line Items]
Percentage of annual bonus award to convert into DSUs	25.00%
DSUs Option Three [Member]
Disclosure of terms and conditions of share-based payment arrangement [Line Items]
Percentage of annual bonus award to convert into DSUs	50.00%
Later than one year [Member]
Disclosure of terms and conditions of share-based payment arrangement [Line Items]
Percentage of options exercisable	30.00%
Later than one year [Member] | PSUs [Member]
Disclosure of terms and conditions of share-based payment arrangement [Line Items]
Percentage of units vesting	30.00%
Later than two years [Member]
Disclosure of terms and conditions of share-based payment arrangement [Line Items]
Percentage of options exercisable	30.00%
Later than two years [Member] | PSUs [Member]
Disclosure of terms and conditions of share-based payment arrangement [Line Items]
Percentage of units vesting	30.00%
Later than three years [member] | PSUs [Member]
Disclosure of terms and conditions of share-based payment arrangement [Line Items]
Percentage of units vesting	40.00%

XML

Stock-Based Compensation Plans - Summary of Assumptions Used to Determine Fair Value of Options Granted (Detail)	12 Months Ended
	Dec. 31, 2017 yr CAD / shares
NSRs [Member]
Disclosure of terms and conditions of share-based payment arrangement [Line Items]
Risk-Free Interest Rate	1.00%
Expected Dividend Yield	1.13%
Expected Volatility	29.14%
Expected Life | yr	3.70
TSARs [Member]
Disclosure of terms and conditions of share-based payment arrangement [Line Items]
Risk-Free Interest Rate	1.85%
Expected Dividend Yield	1.51%
Expected Volatility	28.89%
Cenovus's Common Share Price | CAD / shares	CAD 11.48

XML

Stock-Based Compensation Plans - Summary of Stock Option Activity and Related Information (Detail) shares in Thousands	12 Months Ended
	Dec. 31, 2017 CAD shares
NSRs [Member]
Disclosure of terms and conditions of share-based payment arrangement [Line Items]
Number of Share Options Outstanding, Beginning of Year	41,644
Number of Share Options, Granted	3,537
Number of Share Options, Forfeited	(2,454)
Number of Share Options Outstanding, End of Year	42,727
Weighted Average Exercise Price, Outstanding, Beginning of Year | CAD	CAD 30.57
Weighted Average Exercise Price, Granted | CAD	14.81
Weighted Average Exercise Price, Forfeited | CAD	28.27
Weighted Average Exercise Price, Outstanding, End of Year | CAD	CAD 29.40
TSARs [Member]
Disclosure of terms and conditions of share-based payment arrangement [Line Items]
Number of Share Options Outstanding, Beginning of Year	3,373
Number of Share Options, Forfeited	(16)
Number of Share Options Outstanding, End of Year	81
Weighted Average Exercise Price, Outstanding, Beginning of Year | CAD	CAD 26.66
Weighted Average Exercise Price, Forfeited | CAD	29.19
Weighted Average Exercise Price, Outstanding, End of Year | CAD	CAD 33.52
Number of Share Options, Expired	(3,276)
Weighted Average Exercise Price, Expired | CAD	CAD 26.48
PSUs [Member]
Disclosure of terms and conditions of share-based payment arrangement [Line Items]
Number of Share Units, Outstanding, Beginning of Year	6,157
Number of Share Units, Granted	2,392
Number of Share Units, Vested and Paid Out	(451)
Number of Share Units, Cancelled	(1,192)
Number of Share Units, Units in Lieu of Dividends	112
Number of Share Units, Outstanding, End of Year	7,018
RSUs [Member]
Disclosure of terms and conditions of share-based payment arrangement [Line Items]
Number of Share Units, Outstanding, Beginning of Year	3,790
Number of Share Units, Granted	3,278
Number of Share Units, Vested and Paid Out	(101)
Number of Share Units, Cancelled	(282)
Number of Share Units, Units in Lieu of Dividends	100
Number of Share Units, Outstanding, End of Year	6,785
DSUs [Member]
Disclosure of terms and conditions of share-based payment arrangement [Line Items]
Number of Share Units, Outstanding, Beginning of Year	1,598
Number of Share Units, Granted	93
Number of Share Units, Units in Lieu of Dividends	27
Number of Share Units, Outstanding, End of Year	1,440
Number of Share Units, Redeemed	(414)
DSUs [Member] | Director [Member]
Disclosure of terms and conditions of share-based payment arrangement [Line Items]
Number of Share Units, Granted	136

XML

Stock-Based Compensation Plans - Summary of Options Outstanding and Exercisable by Range of Exercise Price (Detail) - NSRs [Member] shares in Thousands	Dec. 31, 2017 CAD shares yr	Dec. 31, 2016 CAD shares
Disclosure of range of exercise prices of outstanding share options [Line Items]
Outstanding Number | shares	42,727	41,644
Outstanding Weighted Average Remaining Contractual Life | yr	2.8
Outstanding Weighted Average Exercise Price | CAD	CAD 29.40	CAD 30.57
Exercisable Number | shares	35,612
Exercisable Weighted Average Exercise Price | CAD	CAD 31.70
10.00 to 14.99 [Member]
Disclosure of range of exercise prices of outstanding share options [Line Items]
Outstanding Number | shares	3,319
Outstanding Weighted Average Remaining Contractual Life | yr	5.4
Outstanding Weighted Average Exercise Price | CAD	CAD 14.80
15.00 to 19.99 [Member]
Disclosure of range of exercise prices of outstanding share options [Line Items]
Outstanding Number | shares	3,313
Outstanding Weighted Average Remaining Contractual Life | yr	5.2
Outstanding Weighted Average Exercise Price | CAD	CAD 19.51
Exercisable Number | shares	995
Exercisable Weighted Average Exercise Price | CAD	CAD 19.51
20.00 to 24.99 [Member]
Disclosure of range of exercise prices of outstanding share options [Line Items]
Outstanding Number | shares	3,723
Outstanding Weighted Average Remaining Contractual Life | yr	4.1
Outstanding Weighted Average Exercise Price | CAD	CAD 22.25
Exercisable Number | shares	2,254
Exercisable Weighted Average Exercise Price | CAD	CAD 22.26
25.00 to 29.99 [Member]
Disclosure of range of exercise prices of outstanding share options [Line Items]
Outstanding Number | shares	12,115
Outstanding Weighted Average Remaining Contractual Life | yr	3.1
Outstanding Weighted Average Exercise Price | CAD	CAD 28.38
Exercisable Number | shares	12,106
Exercisable Weighted Average Exercise Price | CAD	CAD 28.39
30.00 to 34.99 [Member]
Disclosure of range of exercise prices of outstanding share options [Line Items]
Outstanding Number | shares	10,419
Outstanding Weighted Average Remaining Contractual Life | yr	2.2
Outstanding Weighted Average Exercise Price | CAD	CAD 32.64
Exercisable Number | shares	10,419
Exercisable Weighted Average Exercise Price | CAD	CAD 32.64
35.00 to 39.99 [Member]
Disclosure of range of exercise prices of outstanding share options [Line Items]
Outstanding Number | shares	9,838
Outstanding Weighted Average Remaining Contractual Life | yr	0.8
Outstanding Weighted Average Exercise Price | CAD	CAD 38.19
Exercisable Number | shares	9,838
Exercisable Weighted Average Exercise Price | CAD	CAD 38.19

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Stock-Based Compensation Plans - Summary of Options Outstanding and Exercisable by Range of Exercise Price (Parenthetical) (Detail) - NSRs [Member]	Dec. 31, 2017 CAD
Bottom of range [Member] | 10.00 to 14.99 [Member]
Disclosure of range of exercise prices of outstanding share options [Line Items]
Options outstanding, exercise price	CAD 10.00
Bottom of range [Member] | 15.00 to 19.99 [Member]
Disclosure of range of exercise prices of outstanding share options [Line Items]
Options outstanding, exercise price	15.00
Bottom of range [Member] | 20.00 to 24.99 [Member]
Disclosure of range of exercise prices of outstanding share options [Line Items]
Options outstanding, exercise price	20.00
Bottom of range [Member] | 25.00 to 29.99 [Member]
Disclosure of range of exercise prices of outstanding share options [Line Items]
Options outstanding, exercise price	25.00
Bottom of range [Member] | 30.00 to 34.99 [Member]
Disclosure of range of exercise prices of outstanding share options [Line Items]
Options outstanding, exercise price	30.00
Bottom of range [Member] | 35.00 to 39.99 [Member]
Disclosure of range of exercise prices of outstanding share options [Line Items]
Options outstanding, exercise price	35.00
Top of range [Member] | 10.00 to 14.99 [Member]
Disclosure of range of exercise prices of outstanding share options [Line Items]
Options outstanding, exercise price	14.99
Top of range [Member] | 15.00 to 19.99 [Member]
Disclosure of range of exercise prices of outstanding share options [Line Items]
Options outstanding, exercise price	19.99
Top of range [Member] | 20.00 to 24.99 [Member]
Disclosure of range of exercise prices of outstanding share options [Line Items]
Options outstanding, exercise price	24.99
Top of range [Member] | 25.00 to 29.99 [Member]
Disclosure of range of exercise prices of outstanding share options [Line Items]
Options outstanding, exercise price	29.99
Top of range [Member] | 30.00 to 34.99 [Member]
Disclosure of range of exercise prices of outstanding share options [Line Items]
Options outstanding, exercise price	34.99
Top of range [Member] | 35.00 to 39.99 [Member]
Disclosure of range of exercise prices of outstanding share options [Line Items]
Options outstanding, exercise price	CAD 39.99

XML

Stock-Based Compensation Plans - Summary of Stock-Based Compensation (Detail) - CAD CAD in Millions	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Disclosure of terms and conditions of share-based payment arrangement [Line Items]
Stock-Based Compensation Expense (Recovery)	CAD (6)	CAD 47	CAD 10
Stock-Based Compensation Costs Capitalized	3	12	6
Total Stock-Based Compensation	(3)	59	16
NSRs [Member]
Disclosure of terms and conditions of share-based payment arrangement [Line Items]
Stock-Based Compensation Expense	9	15	27
TSARs [Member]
Disclosure of terms and conditions of share-based payment arrangement [Line Items]
Stock-Based Compensation Expense		(1)	(5)
PSUs [Member]
Disclosure of terms and conditions of share-based payment arrangement [Line Items]
Stock-Based Compensation Expense	(7)	13	(13)
RSUs [Member]
Disclosure of terms and conditions of share-based payment arrangement [Line Items]
Stock-Based Compensation Expense	3	13	6
DSUs [Member]
Disclosure of terms and conditions of share-based payment arrangement [Line Items]
Stock-Based Compensation Expense	CAD (11)	CAD 7	CAD (5)

XML

Employee Salaries and Benefit Expenses - Summary of Employee Salaries and Benefit Expenses (Detail) - CAD CAD in Millions	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Disclosure Of Salaries And Employee Benefits [Abstract]
Salaries, Bonuses and Other Short-Term Employee Benefits	CAD 606	CAD 500	CAD 534
Defined Contribution Pension Plan	19	16	19
Defined Benefit Pension Plan and OPEB	8	11	17
Stock-Based Compensation Expense (Note 29)	(6)	47	10
Termination Benefits	19	19	43
Employee Salaries and Benefit Expenses	CAD 646	CAD 593	CAD 623

XML

Related Party Transactions - Summary of Key Management Compensation (Detail) - CAD CAD in Millions	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Disclosure Of Transactions Between Related Parties [Abstract]
Salaries, Director Fees and Short-Term Benefits	CAD 26	CAD 27	CAD 30
Post-Employment Benefits	4	4	5
Stock-Based Compensation	6	4	5
Total compensation paid or payable	CAD 36	CAD 35	CAD 40

XML

Capital Structure - Additional Information (Detail) $ in Billions	12 Months Ended
	Dec. 31, 2017 CAD	Dec. 31, 2017 USD ($)
Capital Structure [Line Items]
Debt to Adjusted EBITDA ratio	2.0
Net debt to adjusted EBITDA ratio	2.8
Committed Credit Facility [member]
Capital Structure [Line Items]
Amount drawn under committed credit facility	CAD 0
Committed Credit Facility [member] | Tranche One [Member]
Capital Structure [Line Items]
Long-Term Debt	CAD 1,200,000
Borrowings, maturity date	November 30, 2020
Committed Credit Facility [member] | Tranche Two [Member]
Capital Structure [Line Items]
Long-Term Debt	CAD 3,300,000
Borrowings, maturity date	November 30, 2021
Shelf Prospectus [Member]
Capital Structure [Line Items]
Shelf prospectus amount | $		$ 4.6
Top of range [Member] | Committed Credit Facility [member]
Capital Structure [Line Items]
Credit facility requirement maximum debt to capitalization ratio	65.00%	65.00%

XML

Capital Structure - Summary of Net Debt to Adjusted EBITDA (Detail) - CAD CAD in Millions	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016		Dec. 31, 2015		Dec. 31, 2014
Disclosure Of Objectives Policies And Processes For Managing Capital [Abstract]
Long-Term Debt	CAD 9,513	CAD 6,332		CAD 6,525
Less: Cash and Cash Equivalents	(610)	(3,720)		(4,105)		CAD (883)
Net Debt	8,903	2,612		2,420
Net Earnings (Loss)	3,366	(545)	[1]	618	[1]
Add (Deduct):
Finance Costs	725	492		482
Interest Income	(62)	(52)	[1]	(28)	[1]
Income Tax Expense (Recovery)	352	(382)		(81)
DD&A	2,030	1,498		2,114
E&E Impairment	890	2		138
Unrealized (Gain) Loss on Risk Management	729	554		195
Foreign Exchange (Gain) Loss, Net	(812)	(198)	[1]	1,036	[1]
Revaluation (Gain)	(2,555)
Re-measurement of Contingent Payment	(138)
(Gain) Loss on Discontinuance	(1,285)
(Gain) Loss on Divestitures of Assets	1	6		(2,392)
Other (Income) Loss, Net	(5)	34	[1]	2	[1]
Adjusted EBITDA	CAD 3,236	CAD 1,409		CAD 2,084
Net Debt to Adjusted EBITDA	280.00%	190.00%		120.00%

[1] The comparative periods have been restated to reflect discontinued operations as discussed in Notes 1 and 11.

XML

Capital Structure - Summary of Net Debt to Capitalization (Detail) - CAD CAD in Millions	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
Disclosure Of Objectives Policies And Processes For Managing Capital [Abstract]
Net Debt	CAD 8,903	CAD 2,612	CAD 2,420
Shareholders’ Equity	19,981	11,590	12,391	CAD 10,186
Debt and Shareholders' Equity, Net	CAD 28,884	CAD 14,202	CAD 14,811
Net Debt to Capitalization	31.00%	18.00%	16.00%

XML

Financial Instruments - Additional information (Detail)	12 Months Ended
	Dec. 31, 2017 CAD	Dec. 31, 2017 $ / bbl	Dec. 31, 2017 CAD / bbl	Dec. 31, 2016 CAD	Dec. 31, 2015 CAD
Disclosure of detailed information about financial instruments [Line Items]
Debt, carrying value	CAD 9,513,000,000			CAD 6,332,000,000	CAD 6,525,000,000
Cash collateral for risk management contracts price change	26,000,000			84,000,000
Amount of cash collateral to be withdrawn	CAD 0			18,000,000
Discounted Credit adjusted risk free rate	3.30%
Estimated fair value of contingent payment	CAD 206,000,000
WCS Forward Prices [Member]
Disclosure of detailed information about financial instruments [Line Items]
Average forward price for Western Canadian Select Crude Oil for the remaining term		35.51	44.55
WTI Option Volatility [Member]
Disclosure of detailed information about financial instruments [Line Items]
Average volatility contingent payment percentage	20.00%
U.S. to Canadian Dollar Foreign Exchange Average Rate Volatility Contingent Payment [Member]
Disclosure of detailed information about financial instruments [Line Items]
Average volatility contingent payment percentage	7.00%
Level 2 of Fair Value Hierarchy [Member]
Disclosure of detailed information about financial instruments [Line Items]
Debt, fair value	CAD 10,061,000,000			CAD 6,539,000,000

XML

Financial Instruments - Reconciliation of Changes in the Fair Value of Available for Sale Financial Assets (Detail) - CAD CAD in Millions	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016
Disclosure of fair value measurement of assets [Line Items]
Fair Value, End of Year	CAD 37
Level 3 of Fair Value Hierarchy [Member]
Disclosure of fair value measurement of assets [Line Items]
Fair Value, Beginning of Year	35	CAD 42
Net Acquisition of Investments	3
Change in Fair Value	(1)	(4)
Impairment Losses		(3)
Fair Value, End of Year	CAD 37	CAD 35

XML

Financial Instruments - Summary of Urealized Risk Management Positions (Detail) - CAD CAD in Millions	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Disclosure Of Recurring Fair Value Measurement Of Assets And Liabilities [Line Items]
Risk Management Asset	CAD 37
Risk Management Net	(986)	CAD (291)	CAD 271
Level 2 of Fair Value Hierarchy [Member]
Disclosure Of Recurring Fair Value Measurement Of Assets And Liabilities [Line Items]
Risk Management Asset	65	24
Risk Management Liability	1,051	315
Risk Management Net	(986)	(291)
Level 2 of Fair Value Hierarchy [Member] | Interest rate swap contract [Member]
Disclosure Of Recurring Fair Value Measurement Of Assets And Liabilities [Line Items]
Risk Management Asset	2	3
Risk Management Liability	20	8
Risk Management Net	(18)	(5)
Level 2 of Fair Value Hierarchy [Member] | Commodity Price Risk [Member] | Crude Oil Contracts [Member]
Disclosure Of Recurring Fair Value Measurement Of Assets And Liabilities [Line Items]
Risk Management Asset	63	21
Risk Management Liability	1,031	307
Risk Management Net	CAD (968)	CAD (286)

XML

Financial Instruments - Summary of Fair Value Hierarchy for Risk Management Assets and Liabilities Carried at Fair Value (Detail) - CAD CAD in Millions	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Disclosure Of Levels Of Fair Value Hierarchy [Line Items]
Fair Value of Risk Management Assets and Liabilities	CAD (986)	CAD (291)	CAD 271
Level 2 of Fair Value Hierarchy [Member]
Disclosure Of Levels Of Fair Value Hierarchy [Line Items]
Fair Value of Risk Management Assets and Liabilities	CAD (986)	CAD (291)

XML

Financial Instruments - Reconciliation of Changes in the Fair Value of Cenovus's Risk Management Assets and Liabilities (Detail) - CAD CAD in Millions	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016
Reconciliation Of Changes In Fair Value Measurement Assets Liabilities [Abstract]
Fair Value of Contracts, Beginning of Year	CAD (291)	CAD 271
Fair Value of Contracts Realized During the Year	200	(211)
Change in Fair Value of Contracts in Place at Beginning of Year and Contracts Entered Into During the Year	(929)	(343)
Unamortized Premium on Put Options	16
Unrealized Foreign Exchange Gain (Loss) on U.S. Dollar Contracts	18	(8)
Fair Value of Contracts, End of Year	CAD (986)	CAD (291)

XML

Financial Instruments - Reconciliation of Changes in the Fair Value of Cenovus's Risk Management Assets and Liabilities (Parenthetical) (Detail) - CAD CAD in Millions	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Disclosure Of Reconciliation Of Changes In Fair Value Measurement Assets Liabilities [Line Items]
Realized (Gain) Loss	CAD 167	CAD (153)	CAD (447)
Discontinued Operations [Member]
Disclosure Of Reconciliation Of Changes In Fair Value Measurement Assets Liabilities [Line Items]
Realized (Gain) Loss	33	(58)	CAD (209)
Conventional [Member] | Discontinued Operations [Member]
Disclosure Of Reconciliation Of Changes In Fair Value Measurement Assets Liabilities [Line Items]
Realized (Gain) Loss	CAD 33	CAD (58)

XML

Financial Instruments - Summary of Offsetting Risk Management Positions (Detail) - CAD CAD in Millions	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016
Disclosure Of Offsetting Of Financial Assets Liabilities [Abstract]
Gross Amount, Risk Management Asset	CAD 135	CAD 75
Amount Offset, Risk Management Asset	(70)	(51)
Net Amount per Consolidated Financial Statements, Risk Management Asset	65	24
Gross Amount, Risk Management Liabilities	1,121	366
Amount Offset, Risk Management Liabilities	(70)	(51)
Net Amount per Consolidated Financial Statements, Risk Management Liabilities	1,051	315
Gross Amount, Risk Management Net	(986)	(291)
Net Amount per Consolidated Financial Statements, Risk Management Net	CAD (986)	CAD (291)

XML

Financial Instruments - Summary of Changes in Inputs to Option Pricing Model, Resulted in Unrealized Gains (Losses) Impacting Earnings Before Income Tax (Detail) CAD in Millions	12 Months Ended
	Dec. 31, 2017 CAD CAD / bbl
WCS Forward Prices [Member]
Disclosure Of Sensitivity Of Fair Value Measurement To Changes In Unobservable Inputs Liabilities [Line Items]
Sensitivity Price Range | CAD / bbl	5.00
Increase in volatility	CAD (167)
Decrease in volatility	CAD 111
WTI Option Volatility [Member]
Disclosure Of Sensitivity Of Fair Value Measurement To Changes In Unobservable Inputs Liabilities [Line Items]
Sensitivity Range	5.00%
Increase in volatility	CAD (95)
Decrease in volatility	CAD 85
Foreign Exchange Volatility Rate [Member]
Disclosure Of Sensitivity Of Fair Value Measurement To Changes In Unobservable Inputs Liabilities [Line Items]
Sensitivity Range	5.00%
Increase in volatility	CAD 2
Decrease in volatility	CAD (27)

XML

Financial Instruments - Summary of Earnings Impact of (Gains) Losses from Risk Management Positions (Detail) - CAD CAD in Millions	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016		Dec. 31, 2015
Disclosure Of Financial Instruments [Abstract]
Realized (Gain) Loss	CAD 167	CAD (153)		CAD (447)
Unrealized (Gain) Loss	729	554		195
(Gain) Loss on Risk Management From Continuing Operations	CAD 896	CAD 401	[1]	CAD (252)	[1]

[1] The comparative periods have been restated to reflect discontinued operations as discussed in Notes 1 and 11.

XML

Financial Instruments - Summary of Earnings Impact of (Gains) Losses from Risk Management Positions (Parenthetical) (Detail) - CAD CAD in Millions	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Disclosure of detailed information about financial instruments [Line Items]
Realized (Gain) Loss	CAD 167	CAD (153)	CAD (447)
Discontinued Operations [Member]
Disclosure of detailed information about financial instruments [Line Items]
Realized (Gain) Loss	CAD 33	CAD (58)	CAD (209)

XML

Risk Management - Additional Information (Detail) $ in Millions	12 Months Ended
	Dec. 31, 2017 CAD Contract	Dec. 31, 2016 CAD	Dec. 31, 2015 CAD	Dec. 31, 2017 USD ($)	Apr. 07, 2017 USD ($)	Dec. 31, 2016 USD ($)	Dec. 31, 2014 CAD
Disclosure of Nature and Extent of Risks Arising from Financial Instruments [Line Items]
Total Debt Principal | $					$ 2,900
Number of foreign exchange contracts outstanding | Contract	0
Cash and cash equivalents | CAD	CAD 610,000,000	CAD 3,720,000,000	CAD 4,105,000,000				CAD 883,000,000
Top of range [Member]
Disclosure of Nature and Extent of Risks Arising from Financial Instruments [Line Items]
Target debt to adjusted EBITDA ratio	200.00%
Liquidity risk [member] | Top of range [Member] | Base Shelf Prospectus [Member]
Disclosure of Nature and Extent of Risks Arising from Financial Instruments [Line Items]
Shelf prospectus amount | $				$ 4,600
Long-term Borrowings [Member]
Disclosure of Nature and Extent of Risks Arising from Financial Instruments [Line Items]
Total Debt Principal | $				7,650		$ 4,750
Floating rate debt [Member] | Interest Rate Risk [Member]
Disclosure of Nature and Extent of Risks Arising from Financial Instruments [Line Items]
Calculated change in net earnings due to one percent change in interest rates | CAD	CAD 0	CAD 0	CAD 0
Committed Credit Facility [member]
Disclosure of Nature and Extent of Risks Arising from Financial Instruments [Line Items]
Cash and cash equivalents | CAD	610,000,000
Available on committed credit facility | CAD	CAD 4,500,000,000
Interest rate swap contract [Member]
Disclosure of Nature and Extent of Risks Arising from Financial Instruments [Line Items]
Total Debt Principal | $				$ 400		$ 400
Trade receivables [member] | Credit risk [member] | Investment grade counterparties [member]
Disclosure of Nature and Extent of Risks Arising from Financial Instruments [Line Items]
Percent of accounts receivable held with investment grade counterparties	89.00%	90.00%		89.00%		90.00%
Number of investment grade counterparties accounted for more than 10% in accounts receivable	3	3		3		3

XML

Risk Management - Net Fair Value of Risk Management Positions (Detail) CAD in Millions	12 Months Ended
	Dec. 31, 2017 CAD $ / bbl bbl / d	Dec. 31, 2016 CAD	Dec. 31, 2015 CAD
Disclosure of Derivative Financial Instruments [Line Items]
Fair Value Asset (Liability)	CAD (986)	CAD (291)	CAD 271
Fair value derivative financial instruments [Member]
Disclosure of Derivative Financial Instruments [Line Items]
Fair Value Asset (Liability)	(986)
Fair value derivative financial instruments [Member] | Other financial positions [Member]
Disclosure of Derivative Financial Instruments [Line Items]
Fair Value Asset (Liability)	(65)
Fair value derivative financial instruments [Member] | Interest rate swap contract [Member]
Disclosure of Derivative Financial Instruments [Line Items]
Fair Value Asset (Liability)	(18)
Fair value derivative financial instruments [Member] | Crude oil contracts [Member]
Disclosure of Derivative Financial Instruments [Line Items]
Fair Value Asset (Liability)	CAD (968)
Fair value derivative financial instruments [Member] | Crude oil contracts [Member] | Brent fixed price contract term one [Member]
Disclosure of Derivative Financial Instruments [Line Items]
Notional Volumes | bbl / d	60,000
Terms	January – June 2018
Average Price | $ / bbl	53.34
Fair Value Asset (Liability)	CAD (172)
Fair value derivative financial instruments [Member] | Crude oil contracts [Member] | West Texas intermediate fixed price term one [Member]
Disclosure of Derivative Financial Instruments [Line Items]
Notional Volumes | bbl / d	150,000
Terms	January – June 2018
Average Price | $ / bbl	48.91
Fair Value Asset (Liability)	CAD (384)
Fair value derivative financial instruments [Member] | Crude oil contracts [Member] | West Texas intermediate fixed price term two [Member]
Disclosure of Derivative Financial Instruments [Line Items]
Notional Volumes | bbl / d	75,000
Terms	July – December 2018
Average Price | $ / bbl	49.32
Fair Value Asset (Liability)	CAD (158)
Fair value derivative financial instruments [Member] | Crude oil contracts [Member] | West Texas intermediate fixed price term two [Member] | Bottom of range [Member]
Disclosure of Derivative Financial Instruments [Line Items]
Notional Volumes | bbl / d	75,000
Terms	July – December 2018
Average Price | $ / bbl	49.00
Fair Value Asset (Liability)	CAD (110)
Fair value derivative financial instruments [Member] | Crude oil contracts [Member] | Brent Collars Contract Term [Member] | Bottom of range [Member]
Disclosure of Derivative Financial Instruments [Line Items]
Notional Volumes | bbl / d	80,000
Terms	January – June 2018
Average Price | $ / bbl	49.54
Fair Value Asset (Liability)	CAD (124)
Fair value derivative financial instruments [Member] | Crude oil contracts [Member] | Brent Collars Contract Term [Member] | Top of range [Member]
Disclosure of Derivative Financial Instruments [Line Items]
Average Price | $ / bbl	59.86
Fair value derivative financial instruments [Member] | Crude oil contracts [Member] | West Texas intermediate collars for term one [Member] | Bottom of range [Member]
Disclosure of Derivative Financial Instruments [Line Items]
Notional Volumes | bbl / d	10,000
Terms	January – June 2018
Average Price | $ / bbl	45.30
Fair Value Asset (Liability)	CAD (2)
Fair value derivative financial instruments [Member] | Crude oil contracts [Member] | West Texas intermediate collars for term one [Member] | Top of range [Member]
Disclosure of Derivative Financial Instruments [Line Items]
Average Price | $ / bbl	62.77
Fair value derivative financial instruments [Member] | Crude oil contracts [Member] | Brent put options contract term one [Member]
Disclosure of Derivative Financial Instruments [Line Items]
Notional Volumes | bbl / d	25,000
Terms	January – June 2018
Average Price | $ / bbl	53.00
Fair Value Asset (Liability)	CAD 1
Fair value derivative financial instruments [Member] | Crude oil contracts [Member] | Brent Collars Contract Term One [Member] | Top of range [Member]
Disclosure of Derivative Financial Instruments [Line Items]
Average Price | $ / bbl	59.69
Fair value derivative financial instruments [Member] | Crude oil contracts [Member] | Western canadian select differential for term three [Member]
Disclosure of Derivative Financial Instruments [Line Items]
Notional Volumes | bbl / d	10,500
Terms	January – December 2018
Average Price | $ / bbl	(14.52)
Fair Value Asset (Liability)	CAD 25
Fair value derivative financial instruments [Member] | Crude oil contracts [Member] | Western canadian select differential for term one [Member]
Disclosure of Derivative Financial Instruments [Line Items]
Notional Volumes | bbl / d	16,300
Terms	January – March 2018
Average Price | $ / bbl	(13.11)
Fair Value Asset (Liability)	CAD 14
Fair value derivative financial instruments [Member] | Crude oil contracts [Member] | Western canadian select differential for term two [Member]
Disclosure of Derivative Financial Instruments [Line Items]
Notional Volumes | bbl / d	14,800
Terms	April – June 2018
Average Price | $ / bbl	(14.05)
Fair Value Asset (Liability)	CAD 7

XML

Risk Management - Impact of Fluctuating Commodity Prices and Interest Rates on Company'S Open Risk Management Positions (Detail) - CAD CAD in Millions	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016
Commodity Price Risk [Member] | Crude oil contracts [Member]
Disclosure of Nature and Extent of Risks Arising from Financial Instruments [Line Items]
Description of exposure to risk	Crude Oil Commodity Price	Crude Oil Commodity Price
Sensitivity Range	US$5.00 per bbl Applied to Brent, WTI and Condensate Hedges	US$5.00 per bbl Applied to Brent, WTI and Condensate Hedges
Increase	CAD (529)	CAD (198)
Decrease	CAD 507	CAD 193
Commodity Price Risk [Member] | Crude oil differential contracts one [Member]
Disclosure of Nature and Extent of Risks Arising from Financial Instruments [Line Items]
Description of exposure to risk	Crude Oil Differential Price	Crude Oil Differential Price
Sensitivity Range	US$2.50 per bbl Applied to Differential Hedges Tied to Production	US$2.50 per bbl Applied to Differential Hedges Tied to Production
Increase	CAD 11	CAD 1
Decrease	(11)	(1)
Currency risk [Member] | Us Dollar [Member]
Disclosure of Nature and Extent of Risks Arising from Financial Instruments [Line Items]
$0.01 Increase in the U.S. to Canadian Dollar Foreign Exchange Rate	77	48
$0.01 Decrease in the U.S. to Canadian Dollar Foreign Exchange Rate	(77)	(48)
Interest Rate Risk [Member]
Disclosure of Nature and Extent of Risks Arising from Financial Instruments [Line Items]
50 Basis Points Increase	44	45
50 Basis Points Decrease	CAD (50)	CAD (52)

XML

Risk Management - Undiscounted Cash Outflows Relating to Financial Liabilities (Detail) - CAD CAD in Millions	Dec. 31, 2017	Dec. 31, 2016
Accounts payable and accrued liabilities [member]
Disclosure of Maturity Analysis for Financial Liabilities [Line Items]
Derivative Financial Instruments	CAD 2,635	CAD 2,266
Accounts payable and accrued liabilities [member] | Less Than 1 Year [Member]
Disclosure of Maturity Analysis for Financial Liabilities [Line Items]
Derivative Financial Instruments	2,635	2,266
Risk management liabilities [member]
Disclosure of Maturity Analysis for Financial Liabilities [Line Items]
Derivative Financial Instruments	1,051	315
Risk management liabilities [member] | Less Than 1 Year [Member]
Disclosure of Maturity Analysis for Financial Liabilities [Line Items]
Derivative Financial Instruments	1,031	293
Risk management liabilities [member] | Years 2 and 3 [Member]
Disclosure of Maturity Analysis for Financial Liabilities [Line Items]
Derivative Financial Instruments	20	22
Long-term Borrowings [Member]
Disclosure of Maturity Analysis for Financial Liabilities [Line Items]
Derivative Financial Instruments	17,759	11,701
Long-term Borrowings [Member] | Less Than 1 Year [Member]
Disclosure of Maturity Analysis for Financial Liabilities [Line Items]
Derivative Financial Instruments	494	339
Long-term Borrowings [Member] | Years 2 and 3 [Member]
Disclosure of Maturity Analysis for Financial Liabilities [Line Items]
Derivative Financial Instruments	2,527	2,662
Long-term Borrowings [Member] | Years 4 and 5 [Member]
Disclosure of Maturity Analysis for Financial Liabilities [Line Items]
Derivative Financial Instruments	1,429	1,150
Long-term Borrowings [Member] | 5 Years [Member]
Disclosure of Maturity Analysis for Financial Liabilities [Line Items]
Derivative Financial Instruments	13,309	7,550
Other Nonderivative Financial Liabilities [Member]
Disclosure of Maturity Analysis for Financial Liabilities [Line Items]
Derivative Financial Instruments	48	49
Other Nonderivative Financial Liabilities [Member] | Years 2 and 3 [Member]
Disclosure of Maturity Analysis for Financial Liabilities [Line Items]
Derivative Financial Instruments	21	25
Other Nonderivative Financial Liabilities [Member] | Years 4 and 5 [Member]
Disclosure of Maturity Analysis for Financial Liabilities [Line Items]
Derivative Financial Instruments	11	8
Other Nonderivative Financial Liabilities [Member] | 5 Years [Member]
Disclosure of Maturity Analysis for Financial Liabilities [Line Items]
Derivative Financial Instruments	CAD 16	CAD 16

XML

Supplementary Cash Flow Information - Summary of Supplementary Cash Flow Information (Detail) - CAD CAD in Millions	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Disclosure Of Supplementary Cash Flow Information [Abstract]
Interest Paid	CAD 538	CAD 350	CAD 330
Interest Received	31	32	19
Income Taxes Paid	CAD 12	CAD 11	CAD 933

XML

Supplementary Cash Flow Information - Summary of Reconciliation of Cash Flows from Financing Activities (Detail) - CAD CAD in Millions		12 Months Ended
	Apr. 06, 2017	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Changes From Financing Cash Flows:
Issuance of Long-Term Debt		CAD 3,842
Net Issuance (Repayment) of Revolving Long-Term Debt		32
Issuance of Debt Under Asset Sale Bridge Facility		3,569
(Repayment) of Debt Under Asset Sale Bridge Facility		(3,600)
Common Shares Issued, Net of Issuance Costs	CAD 2,900	2,899		CAD 1,449
Dividends Payable [Member]
Changes From Financing Cash Flows:
Dividends Paid		(225)	CAD (166)
Non-Cash Changes:
Dividends Declared		225	166
Current Portion of Long Term Debt [Member]
Non-Cash Changes:
Finance Costs		8
Current Portion of Long Term Debt [Member] | Bridge Credit Facility [Member]
Changes From Financing Cash Flows:
Issuance of Debt Under Asset Sale Bridge Facility		892
(Repayment) of Debt Under Asset Sale Bridge Facility		(900)
Long Term Debt [Member]
Disclosure Of Reconciliation Of Liabilities Arising From Financing Activities [Line Items]
Beginning balance		6,332	6,525
Changes From Financing Cash Flows:
Issuance of Long-Term Debt		3,842
Net Issuance (Repayment) of Revolving Long-Term Debt		32
Non-Cash Changes:
Unrealized Foreign Exchange (Gain) Loss		(697)	(196)
Amortization of Debt Discounts			3
Finance Costs		28
Other		(1)
Ending balance		9,513	6,332	6,525
Long Term Debt [Member] | Bridge Credit Facility [Member]
Changes From Financing Cash Flows:
Issuance of Debt Under Asset Sale Bridge Facility		2,677
(Repayment) of Debt Under Asset Sale Bridge Facility		(2,700)
Share Capital [Member]
Disclosure Of Reconciliation Of Liabilities Arising From Financing Activities [Line Items]
Beginning balance		5,534	5,534
Changes From Financing Cash Flows:
Common Shares Issued, Net of Issuance Costs		2,899
Non-Cash Changes:
Common Shares		2,579
Deferred Taxes on Share Issuance Costs		28
Ending balance		CAD 11,040	CAD 5,534	CAD 5,534

XML

Commitments and Contingencies - Summary of Future Payments of Commitments (Detail) - CAD CAD in Millions	Dec. 31, 2017	Dec. 31, 2016
Disclosure of commitments [Line Items]
Transportation and Storage	CAD 18,310	CAD 26,260
Operating Leases (Building Leases)	3,029	3,145
Product Purchases		70
Capital Commitments	18	26
Other Long-Term Commitments	355	271
Total Payments	21,712	29,772
Fixed Price Product Sales		3
1 Year [member]
Disclosure of commitments [Line Items]
Transportation and Storage	899	682
Operating Leases (Building Leases)	155	101
Product Purchases		70
Capital Commitments	16	23
Other Long-Term Commitments	109	80
Total Payments	1,179	956
Fixed Price Product Sales		3
2 Years [member]
Disclosure of commitments [Line Items]
Transportation and Storage	886	711
Operating Leases (Building Leases)	146	146
Capital Commitments	2	3
Other Long-Term Commitments	39	27
Total Payments	1,073	887
Later than two years [Member]
Disclosure of commitments [Line Items]
Transportation and Storage	919	722
Operating Leases (Building Leases)	142	146
Other Long-Term Commitments	32	26
Total Payments	1,093	894
4 Years [member]
Disclosure of commitments [Line Items]
Transportation and Storage	1,123	1,031
Operating Leases (Building Leases)	141	145
Other Long-Term Commitments	28	15
Total Payments	1,292	1,191
5 Years [Member]
Disclosure of commitments [Line Items]
Transportation and Storage	1,223	1,239
Operating Leases (Building Leases)	140	142
Other Long-Term Commitments	25	15
Total Payments	1,388	1,396
Thereafter [member]
Disclosure of commitments [Line Items]
Transportation and Storage	13,260	21,875
Operating Leases (Building Leases)	2,305	2,465
Other Long-Term Commitments	122	108
Total Payments	CAD 15,687	CAD 24,448

XML

Commitments and Contingencies - Summary of Future Payments of Commitments (Parenthetical) (Detail) - CAD CAD in Billions		12 Months Ended
	May 16, 2017	Dec. 31, 2017	Dec. 31, 2016
Disclosure of commitments [Line Items]
Transportation Commitment		CAD 9	CAD 19
WRB [Member]
Disclosure of commitments [Line Items]
Percent of ownership in joint operations		50.00%	50.00%
FCCL [Member]
Disclosure of commitments [Line Items]
Percent of ownership in joint operations	50.00%		50.00%

XML

Commitments and Contingencies - Additional Information (Detail) CAD in Millions	7 Months Ended	12 Months Ended
	Dec. 31, 2017 CAD CAD / bbl	Dec. 31, 2017 CAD CAD / bbl	May 17, 2017 CAD	Dec. 31, 2016 CAD	Dec. 31, 2015 CAD
Disclosure of Commitments and Contingent Liabilities [Line Items]
Decrease of transportation commitments		CAD 8,000
Outstanding letter of credit	CAD 376	376		CAD 258
Decommissioning liabilities	1,029	1,029		CAD 1,847	CAD 2,052
Estimated fair value of contingent payment	206	CAD 206
ConocoPhillips Company and Certain of its Subsidiaries [Member]
Disclosure of Commitments and Contingent Liabilities [Line Items]
Contingent payments period		5 years
Average crude oil price per barrel for contingent payment | CAD / bbl		52.00
Estimated fair value of contingent payment	CAD 206	CAD 206	CAD 361
Top of range [Member]
Disclosure of Commitments and Contingent Liabilities [Line Items]
Term of agreement		20 years
Top of range [Member] | ConocoPhillips Company and Certain of its Subsidiaries [Member]
Disclosure of Commitments and Contingent Liabilities [Line Items]
Average crude oil price per barrel for contingent payment | CAD / bbl	52.00