Cenovus Energy (CVE) 40-F 15 Feb 18 2017 FY Annual report (Canada) Financial data

Document and Entity Information

Document and Entity Information	12 Months Ended
	Dec. 31, 2017shares
Document And Entity Information [Abstract]
Document Type	40-F
Amendment Flag	false
Document Period End Date	Dec. 31, 2017
Document Fiscal Year Focus	2,017
Document Fiscal Period Focus	FY
Trading Symbol	CVE
Entity Registrant Name	CENOVUS ENERGY INC.
Entity Central Index Key	1,475,260
Current Fiscal Year End Date	--12-31
Entity Current Reporting Status	Yes
Entity Common Stock, Shares Outstanding	1,228,789,845

Consolidated Statements of Earn

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.

Consolidated Statements of Comp

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.

Consolidated Balance Sheets

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

Consolidated Statements of Shar

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.

Consolidated Statements of Cash

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.

Description of Business and Seg

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 CO 2 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.

Basis of Preparation and Statem

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.

Summary of Significant Accounti

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. 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 Financial Instruments: Recognition and Measurement 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” “Construction Contracts” “Revenue” 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 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 o

Critical Accounting Judgments a

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” Consolidated Financial Statements In determining the classification of its joint arrangements under IFRS 11, the Company considered the following: • The intention of the transaction creating FCCL and WRB was to form an integrated North American heavy oil business. The integrated 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.

Acquisition

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.

Finance Costs

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

Foreign Exchange (Gain) Loss, N

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

Divestitures

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 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.

Other (Income) Loss, Net

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.

Impairment Charges and Reversal

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 One Percent Five Percent (1) Five Percent 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.

Held for Sales Assets and Disco

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 As at December 31, 2017 (Note 17) (Note 18) (Note 24) Conventional - 568 454 Deep Basin 46 434 149 46 1,002 603

Income Taxes

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. 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.

Per Share Amounts

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.

Cash and Cash Equivalents

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

Accounts Receivable and Accrued

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.

Inventories

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).

Exploration and Evaluation Asse

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.

Property, Plant and Equipment,

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 Other Refining 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

Other Assets

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

Goodwill

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.

Accounts Payable and Accrued Li

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.

Contingent Payment

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.

Long-term Debt

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 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

Decommissioning Liabilities

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. 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)

Other Liabilities

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

Pensions and Other Post-Employm

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.

Share Capital

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 (thousands) Amount Number of (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 Stock-Based 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

Accumulated Other Comprehensive

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 Foreign Available 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

Stock-Based Compensation Plans

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 $3.10 before considering forfeitures, which are considered in determining total cost for the period. The fair value of each NSR was estimated on its grant date using the Black-Scholes-Merton valuation model with weighted average assumptions as follows: Risk-Free Interest Rate 1.00% Expected Dividend Yield 1.13% Expected Volatility (1) 29.14% Expected Life (years) 3.70 (1) Expected volatility has been based on historical share volatility of the Company and comparable industry peers. The following tables summarize information related to the NSRs: As at December 31, 2017 Number of (thousands) Weighted ($) 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 ($) Number of (thousands) Weighted (years) Weighted Average Exercise Price ($) 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 – $nil). The following table summarizes information related to the TSARs held by Cenovus employees: As at December 31, 2017 Number of (thousands) Weighted Average Exercise Price ($) 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 (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 (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 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 (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

Employee Salaries and Benefit E

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

Related Party Transactions

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.

Capital Structure

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.

Financial Instruments

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.

Risk Management

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 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.

Supplementary Cash Flow Informa

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 Current Long-Term Share 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

Commitments and Contingencies

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).

Summary of Significant Accoun43

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.
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 Financial Instruments: Recognition and Measurement 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” “Construction Contracts” “Revenue” 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 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”

Description of Business and S44

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.

Acquisition (Tables)

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

Finance Costs (Tables)

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

Foreign Exchange (Gain) Loss,47

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

Impairment Charges and Revers48

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 One Percent Five Percent (1) Five Percent Clearwater 27 (30) (56) 65 Primrose - - - - Christina Lake - - - - Narrows Lake 312 - - 333

Held for Sales Assets and Dis49

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 As at December 31, 2017 (Note 17) (Note 18) (Note 24) Conventional - 568 454 Deep Basin 46 434 149 46 1,002 603

Income Taxes (Tables)

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	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

Per Share Amounts (Tables)

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

Cash and Cash Equivalents (Tabl

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

Accounts Receivable and Accru53

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.

Inventories (Tables)

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

Exploration and Evaluation As55

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.

Property, Plant and Equipment56

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 Other Refining 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

Other Assets (Tables)

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

Goodwill (Tables)

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.

Accounts Payable and Accrued 59

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.

Contingent Payment (Tables)

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.

Long-term Debt (Tables)

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 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

Decommissioning Liabilities (Ta

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)

Other Liabilities (Tables)

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

Pensions and Other Post-Emplo64

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)

Share Capital (Tables)

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 (thousands) Amount Number of (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 Stock-Based 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

Accumulated Other Comprehensi66

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 Foreign Available 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

Stock-Based Compensation Plans

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 (thousands) Weighted ($) Outstanding, Beginning of Year 41,644 30.57 Granted 3,537 14.81 Exercised - - Forfeited (2,454) 28.27 Outstanding, End of Year 42,727 29.40
Summary of Options Outstanding and Exercisable by Range of Exercise Price	Outstanding NSRs Exercisable NSRs As at December 31, 2017 Range of Exercise Price ($) Number of (thousands) Weighted (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 ($) 11.48 (1) Expected volatility has been based on historical share volatility of the Company and comparable industry peers.
Summary of Stock Option Activity and Related Information	The following table summarizes information related to the TSARs held by Cenovus employees: As at December 31, 2017 Number of (thousands) Weighted Average Exercise Price ($) 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 (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 (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 (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

Employee Salaries and Benefit68

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

Related Party Transactions (Tab

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

Capital Structure (Tables)

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%

Financial Instruments (Tables)

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.

Risk Management (Tables)

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 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)

Supplementary Cash Flow Infor73

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 Current Long-Term Share 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

Commitments and Contingencies (

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.

Description of Business and S75

Description of Business and Segmented Disclosures - Additional Information (Detail) CAD in Millions	May 17, 2017	Dec. 31, 2017CADaRefineryCustomer	Dec. 31, 2016CADCustomer		Dec. 31, 2015CADCustomer
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.

Description of Business and S76

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.

Description of Business and S77

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.

Description of Business and S78

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.

Description of Business and S79

Description of Business and Segmented Disclosures - Schedule of Revenues by Product (Parenthetical) (Detail) - Natural Gas [Member] CAD in Millions	12 Months Ended
	Dec. 31, 2017CAD
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

Description of Business and S80

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.

Description of Business and S81

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

Description of Business and S82

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

Description of Business and S83

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

Description of Business and S84

Description of Business and Segmented Disclosures - Schedule of Capital Expenditures (Parenthetical) (Detail) CAD in Millions	May 17, 2017CAD
Disclosure Of Business Combinations [Abstract]
Carrying value of pre-existing interest	CAD 9,081
Estimated fair value	CAD 11,605

Summary of Significant Accoun85

Summary of Significant Accounting Policies - Additional information (Detail) CAD in Millions	12 Months Ended
	Dec. 31, 2017CAD
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

Critical Accounting Judgments86

Critical Accounting Judgments and Key Sources of Estimation Uncertainty - Additional Information (Detail) - JointOperation	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%

Acquisition - Additional Inform

Acquisition - Additional Information (Detail) CAD / shares in Units, CAD in Millions, $ in Billions	May 17, 2017CADsharesCAD / shares	Dec. 31, 2017CAD	Dec. 31, 2017CAD	May 17, 2017USD ($)shares	Aug. 31, 2015CAD
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
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

Acquisition - Summary of Identi

Acquisition - Summary of Identifiable Assets Acquired and Liabilities Assumed (Detail) CAD in Millions	May 17, 2017CAD
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

Acquisition - Summary of Fair V

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

Acquisition - Summary of Goodwi

Acquisition - Summary of Goodwill arising from Acquisition (Detail) - CAD CAD in Millions	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

Acquisition - Summary of Good91

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%

Finance Costs - Schedule of Fin

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.

Foreign Exchange (Gain) Loss,93

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.

Divestitures - Additional Infor

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

Other (Income) Loss, Net - Addi

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

Impairment Charges and Revers96

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.

Impairment Charges and Revers97

Impairment Charges and Reversals - Summary of Forward Prices Used to Determine Future Cash Flows (Detail) - Commodity Price Assumptions [Member]	Dec. 31, 2017$ / bblCAD / bblCAD / Mcf	Dec. 31, 2016$ / bblCAD / bblCAD / 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
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
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
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

Impairment Charges and Revers98

Impairment Charges and Reversals - Summary of Increase (Decrease) to Impairment (Detail) CAD in Millions	12 Months Ended
	Dec. 31, 2017CAD
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

Impairment Charges and Revers99

Impairment Charges and Reversals - Summary of Increase (Decrease) to Impairment (Parenthetical) (Detail) CAD in Millions	12 Months Ended
	Dec. 31, 2017CAD
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

Assets Held for Sale and Discon

Assets Held for Sale and Discontinued Operations - Additional Information (Detail)	Jan. 05, 2018CAD	Dec. 14, 2017CAD	Dec. 07, 2017CAD	Sep. 29, 2017CAD	Sep. 25, 2017CAD$ / bblMMBTU	Dec. 31, 2017CAD
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

Assets Held for Sale and Dis101

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.

Assets Held for Sale and Dis102

Assets Held for Sale and Discontinued Operations - Results of Discontinued Operations (Parenthetical) (Detail) CAD in Millions	12 Months Ended
	Dec. 31, 2017CAD
Disclosure Of Discontinued Operations [Abstract]
Net Deferred Tax Expense	CAD 347

Assets Held for Sale and Dis103

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

Assets Held for Sale and Dis104

Assets Held for Sale and Discontinued Operations - Summary of Assets and Liabilities Held for Sale (Detail) CAD in Millions	Dec. 31, 2017CAD
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

Income Taxes - Provision for In

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.

Income Taxes - Additional Infor

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

Income Taxes - Reconciliation o

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.

Income Taxes - Deferred Income

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)

Income Taxes - Schedule of Move

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)

Income Taxes - Schedule of Amou

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

Per Share Amounts - Schedule Re

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.

Per Share Amounts - Additional

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

Cash and Cash Equivalents - Sch

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

Accounts Receivables and Accrue

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

Accounts Receivables and Acc115

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%

Inventories - Schedule of Inven

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

Inventories - Additional Inform

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

Exploration and Evaluation A118

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.

Property, Plant and Equipmen119

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

Property, Plant and Equipmen120

Property, Plant and Equipment, Net - Summary of Property, Plant and Equipment (Parenthetical) (Detail) CAD in Millions	Dec. 31, 2017CAD
FCCL [Member]
Disclosure Of Property Plant And Equipment [Line Items]
Carrying value of the pre-existing interest in FCCL	CAD 8,602

Property, Plant and Equipmen121

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

Other Assets - Schedule of Othe

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

Goodwill - Summary of Carrying

Goodwill - Summary of Carrying Value of Goodwill (Detail) CAD in Millions	12 Months Ended
	Dec. 31, 2017CAD
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

Goodwill - Summary of Carryi124

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

Accounts Payable and Accrued125

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

Accounts Payable and Accrued126

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%

Contingent Payment - Summary of

Contingent Payment - Summary of Contingent Payment (Detail) CAD in Millions	12 Months Ended
	Dec. 31, 2017CAD
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

Contingent Payment - Additional

Contingent Payment - Additional Information (Detail) CAD in Millions	7 Months Ended	12 Months Ended
	Dec. 31, 2017CADCAD / bbl	Dec. 31, 2017CADCAD / 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
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

Long-term Debt - Schedule of Lo

Long-term Debt - Schedule of Long Term Debt (Detail) CAD in Millions, $ in Millions	Dec. 31, 2017CAD	Dec. 31, 2017USD ($)	Apr. 07, 2017USD ($)	Dec. 31, 2016CAD	Dec. 31, 2016USD ($)	Dec. 31, 2015CAD
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

Long-term Debt - Additional Inf

Long-term Debt - Additional Information (Detail)	Apr. 28, 2017CAD	Dec. 31, 2017CAD	Dec. 31, 2017USD ($)	Oct. 10, 2017USD ($)	May 17, 2017CAD	Apr. 07, 2017USD ($)	Dec. 31, 2016CAD	Dec. 31, 2016USD ($)
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%

Long-term Debt - Summary of Uns

Long-term Debt - Summary of Unsecured Notes (Detail) CAD in Millions, $ in Millions	Dec. 31, 2017CAD	Dec. 31, 2017USD ($)	Apr. 07, 2017USD ($)	Dec. 31, 2016CAD	Dec. 31, 2016USD ($)
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

Long-term Debt - Schedule of Ma

Long-term Debt - Schedule of Mandatory Debt Payments (Detail) CAD in Millions, $ in Millions	Dec. 31, 2017CAD	Dec. 31, 2017USD ($)	Apr. 07, 2017USD ($)	Dec. 31, 2016CAD	Dec. 31, 2016USD ($)
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

Decommissioning Liabilities - S

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

Decommissioning Liabilities - A

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

Decommissioning Liabilities 135

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)

Other Liabilities - Summary of

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

Pensions and Other Post-Empl137

Pensions and Other Post-Employment Benefits - Additional Information (Detail)	12 Months Ended
	Dec. 31, 2018CAD	Dec. 31, 2017Age
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

Pensions and Other Post-Empl138

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

Pensions and Other Post-Empl139

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

Pensions and Other Post-Empl140

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

Pensions and Other Post-Empl141

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%

Pensions and Other Post-Empl142

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)

Share Capital - Additional Info

Share Capital - Additional Information (Detail) CAD in Millions	May 17, 2017shares	Apr. 06, 2017CADshares	Dec. 31, 2017CADshares	Dec. 31, 2015CADshares	Dec. 31, 2016shares
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%

Share Capital - Summary of Shar

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

Share Capital - Schedule of Pai

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

Accumulated Other Comprehens146

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

Stock-Based Compensation Pla147

Stock-Based Compensation Plans - Additional Information (Detail)	12 Months Ended
	Dec. 31, 2017CADPlanCAD / shares	Dec. 31, 2016CAD
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%

Stock-Based Compensation Pla148

Stock-Based Compensation Plans - Summary of Assumptions Used to Determine Fair Value of Options Granted (Detail)	12 Months Ended
	Dec. 31, 2017yrCAD / 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

Stock-Based Compensation Pla149

Stock-Based Compensation Plans - Summary of Stock Option Activity and Related Information (Detail) shares in Thousands	12 Months Ended
	Dec. 31, 2017CADshares
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

Stock-Based Compensation Pla150

Stock-Based Compensation Plans - Summary of Options Outstanding and Exercisable by Range of Exercise Price (Detail) - NSRs [Member] shares in Thousands	Dec. 31, 2017CADsharesyr	Dec. 31, 2016CADshares
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

Stock-Based Compensation Pla151

Stock-Based Compensation Plans - Summary of Options Outstanding and Exercisable by Range of Exercise Price (Parenthetical) (Detail) - NSRs [Member]	Dec. 31, 2017CAD
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
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
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
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
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
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
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

Stock-Based Compensation Pla152

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)

Employee Salaries and Benefi153

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

Related Party Transactions - Su

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

Capital Structure - Additional

Capital Structure - Additional Information (Detail) $ in Billions	12 Months Ended
	Dec. 31, 2017CAD	Dec. 31, 2017USD ($)
Capital Structure [Line Items]
Debt to Adjusted EBITDA ratio	2
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%

Capital Structure - Summary of

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.

Capital Structure - Summary 157

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%

Financial Instruments - Additio

Financial Instruments - Additional information (Detail)	12 Months Ended
	Dec. 31, 2017CAD	Dec. 31, 2017$ / bbl	Dec. 31, 2017CAD / bbl	Dec. 31, 2016CAD	Dec. 31, 2015CAD
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

Financial Instruments - Reconci

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

Financial Instruments - Summary

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)

Financial Instruments - Summ161

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)

Financial Instruments - Reco162

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)

Financial Instruments - Reco163

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)

Financial Instruments - Summ164

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)

Financial Instruments - Summ165

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, 2017CADCAD / 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
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)

Financial Instruments - Summ166

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.

Financial Instruments - Summ167

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)

Risk Management - Additional In

Risk Management - Additional Information (Detail) $ in Millions	12 Months Ended
	Dec. 31, 2017CADContract	Dec. 31, 2016CAD	Dec. 31, 2015CAD	Dec. 31, 2017USD ($)	Apr. 07, 2017USD ($)	Dec. 31, 2016USD ($)	Dec. 31, 2014CAD
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

Risk Management - Net Fair Valu

Risk Management - Net Fair Value of Risk Management Positions (Detail) CAD in Millions	12 Months Ended
	Dec. 31, 2017CAD$ / bblbbl / d	Dec. 31, 2016CAD	Dec. 31, 2015CAD
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
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
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

Risk Management - Impact of Flu

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)

Risk Management - Undiscounted

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

Supplementary Cash Flow Info172

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

Supplementary Cash Flow Info173

Supplementary Cash Flow Information - Summary of Reconciliation of Cash Flows from Financing Activities (Detail) - CAD CAD in Millions	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

Commitments and Contingencies -

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

Commitments and Contingencie175

Commitments and Contingencies - Summary of Future Payments of Commitments (Parenthetical) (Detail) - CAD CAD in Billions	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%

Commitments and Contingencie176

Commitments and Contingencies - Additional Information (Detail) CAD in Millions	7 Months Ended	12 Months Ended
	Dec. 31, 2017CADCAD / bbl	Dec. 31, 2017CADCAD / bbl	May 17, 2017CAD	Dec. 31, 2016CAD	Dec. 31, 2015CAD
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
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