Husky Energy (CVE+A) 40-F 27 Feb 20 2019 FY Annual report (Canada) Financial data

DEI Document

DEI Document	12 Months Ended
	Dec. 31, 2019shares
Document Information [Abstract]
Document Type	40-F
Document Period End Date	Dec. 31, 2019
Document Fiscal Year Focus	2019
Document Fiscal Period Focus	FY
Entity Registrant Name	Husky Energy Inc.
Entity Central Index Key	0000049279
Amendment Flag	false
Entity Emerging Growth Company	false
Current Fiscal Year End Date	--12-31
Entity Current Reporting Status	Yes
Entity Common Stock, Shares Outstanding	1,005,120,012

Consolidated Balance Sheets

Consolidated Balance Sheets $ in Millions, $ in Millions	Dec. 31, 2019CAD ($)	Dec. 31, 2018CAD ($)
Current assets
Cash and cash equivalents (note 4)	$ 1,775	$ 2,866
Accounts receivable (notes 5, 25)	1,499	1,355
Income taxes receivable	30	112
Inventories (note 6)	1,486	1,232
Prepaid expenses	148	123
Current assets	4,938	5,688
Non-current assets
Restricted cash (notes 7, 17)	142	128
Exploration and evaluation assets (note 8)	643	997
Property, plant and equipment, net (note 9)	23,623	25,800
Right-of-use assets	1,202	0
Goodwill (note 11)	656	690
Investment in joint ventures (note 12)	1,182	1,319
Long-term income taxes receivable	212	243
Other assets (note 13)	524	360
Total Assets	33,122	35,225
Current liabilities
Accounts payable and accrued liabilities (note 15)	3,465	3,159
Short-term debt (note 16)	550	200
Long-term debt due within one year (note 16)	400	1,433
Lease liabilities (note 10)	109	0
Asset retirement obligations (note 16)	112	202
Current liabilities	4,636	4,994
Non-current liabilities
Long-term debt (note 15)	4,570	4,114
Other long-term liabilities (note 17)	454	1,107
Lease liabilities (note 10)	1,353	0
Asset retirement obligations (note 16)	2,643	2,222
Deferred tax liabilities	2,170	3,174
Total Liabilities	15,826	15,611
Shareholders’ equity
Common shares (note 20)	7,293	7,293
Preferred shares (note 20)	874	874
Contributed surplus	2	2
Retained earnings	8,365	10,273
Accumulated other comprehensive income	748	1,160
Non-controlling interest	14	12
Total Shareholders’ Equity	17,296	19,614
Total Liabilities and Shareholders’ Equity	$ 33,122	$ 35,225

Consolidated Statements of Inco

Consolidated Statements of Income - CAD ($) shares in Millions, $ in Millions	12 Months Ended
	Dec. 31, 2019	Dec. 31, 2018
Profit or loss [abstract]
Gross revenues	$ 20,117	$ 21,919
Royalties	(323)	(335)
Marketing and other	189	668
Revenues, net of royalties	19,983	22,252
Purchases of crude oil and products	12,817	14,555
Production, operating and transportation expenses (note 21)	3,017	2,803
Selling, general and administrative expenses (note 21)	693	654
Depletion, depreciation, amortization and impairment (notes 9, 10)	5,496	2,591
Exploration and evaluation expenses (note 8)	547	149
Gain on sale of assets (note 9)	(8)	(4)
Other – net (note 13)	(584)	(591)
Operating expense	21,978	20,157
Earnings (loss) from operating activities	(1,995)	2,095
Share of equity investment income (note 12)	59	69
Net foreign exchange gain	44	14
Finance income	74	64
Finance expenses	(351)	(314)
Financial Items	(233)	(236)
Earnings (loss) before income taxes	(2,169)	1,928
Provisions for (recovery of) income taxes. current	175	75
Provisions for (recovery of) income taxes, deferred	(974)	396
Provisions for (recovery of) income taxes	(799)	471
Net earnings (loss)	$ (1,370)	$ 1,457
Earnings (loss) per share (note 20)
Earnings (loss) per share – basic ($/share)	$ (1.40)	$ 1.41
Earnings (loss) per share – diluted ($/share)	$ (1.41)	$ 1.40
Weighted average number of common shares outstanding (note 20)
Weighted average number of common shares outstanding, basic	1,005.1	1,005.1
Weighted average number of common shares outstanding, diluted	1,005.1	1,006.1

Consolidated Statements of Comp

Consolidated Statements of Comprehensive Income (Loss) Statement - CAD ($) $ in Millions	12 Months Ended
	Dec. 31, 2019	Dec. 31, 2018
Statement of comprehensive income [abstract]
Net earnings (loss)	$ (1,370)	$ 1,457
Items that will not be reclassified into earnings, net of tax:
Remeasurements of pension plans (note 23)		46
Items that may be reclassified into earnings, net of tax:
Derivatives designated as cash flow hedge	(6)	(13)
Equity investment – share of other comprehensive loss	(2)	(2)
Exchange differences on translation of foreign operations	(550)	857
Hedge of net investment (note 25)	146	(262)
Other comprehensive income (loss)	(412)	626
Comprehensive income (loss)	$ (1,782)	$ 2,083

Consolidated Statements of Chan

Consolidated Statements of Changes in Shareholders Equity Statement - CAD ($) $ in Millions	Total	Common Shares	Preferred Shares	Total Shareholders’ Equity	Total Shareholders’ EquityCommon Shares	Total Shareholders’ EquityPreferred Shares	Non-Controlling Interest	Issued capitalCommon Shares	Issued capitalPreferred Shares	Contributed Surplus	Retained Earnings	Retained EarningsCommon Shares	Retained EarningsPreferred Shares	Foreign Currency Translation	Hedging
Equity, beginning at Dec. 31, 2017				$ 17,967			$ 11	$ 7,293	$ 874	$ 2	$ 9,207			$ 559	$ 21
Net earnings (loss)	$ 1,457			1,457							1,457
Remeasurements of pension plans	46			46							46
Derivatives designated as cash flow hedges	(13)			(13)											(13)
Equity investment - share of other comprehensive income	(2)			(2)											(2)
Exchange differences on translation of foreign operations	857			857										857
Other comprehensive income, net of tax, gains (losses) on hedging instruments that hedge investments in equity instruments				(262)										(262)
Comprehensive income	2,083			2,083							1,503			595	(15)
Dividends declared on common and preferred shares (note 19)		$ 402	$ 35		$ (402)	$ (35)						$ (402)	$ (35)
Equity, ending at Dec. 31, 2018	19,614			19,614			12	7,293	874	2	10,273			1,154	6
Net earnings (loss)	(1,370)			(1,370)							(1,370)
Remeasurements of pension plans				0							0
Derivatives designated as cash flow hedges	(6)			(6)											(6)
Equity investment - share of other comprehensive income	(2)			(2)											(2)
Exchange differences on translation of foreign operations	(550)			(550)										(550)
Other comprehensive income, net of tax, gains (losses) on hedging instruments that hedge investments in equity instruments				146										146
Comprehensive income	(1,782)			(1,782)							(1,370)			(404)	(8)
Dividends declared on common and preferred shares (note 19)		$ 503	$ 35		$ (503)	$ (35)						$ (503)	$ (35)
Non-controlling interests				2			2				0
Equity, ending at Dec. 31, 2019	$ 17,296			$ 17,296			$ 14	$ 7,293	$ 874	$ 2	$ 8,365			$ 750	$ (2)

Consolidated Statements of Ch_2

Consolidated Statements of Changes in Shareholders Equity (Parenthetical) - CAD ($) $ in Millions	12 Months Ended
	Dec. 31, 2019	Dec. 31, 2018
Statement of changes in equity [abstract]
Remeasurement of pension plans	$ (1)	$ (17)
Derivatives designated as cash flow hedges	3	5
Exchange differences on translation of foreign operations	58	(87)
Hedge of net investment	$ (30)	$ 41

Consolidated Statements of Cash

Consolidated Statements of Cash Flows - CAD ($) $ in Millions	12 Months Ended
	Dec. 31, 2019	Dec. 31, 2018
Operating activities
Net earnings (loss)	$ (1,370)	$ 1,457
Accretion (notes 17, 22)	106	97
Depletion, depreciation, amortization and impairment (notes 9, 10)	5,496	2,591
Inventory write-down to net realizable value (note 6)	15	60
Exploration and evaluation expenses (note 8)	355	29
Deferred income taxes (note 19)	(974)	396
Foreign exchange	(26)	(6)
Stock-based compensation (notes 20, 21)	(2)	44
Gain on sale of assets (note 9)	(8)	(4)
Unrealized mark to market loss (gain) (note 25)	44	(150)
Share of equity investment income (note 12)	(59)	(69)
Income from reimbursements under insurance policies	(207)	(253)
Other	12	21
Settlement of asset retirement obligations (note 17)	(276)	(181)
Deferred revenue (note 18)	(42)	(100)
Distribution from joint ventures (note 12)	187	72
Change in non-cash working capital (note 24)	(280)	130
Cash flow – operating activities	2,971	4,134
Financing activities
Long-term debt issuance (note 16)	1,000	0
Long-term debt repayment (note 16)	(1,389)	0
Debt issue costs (note 16)	(9)	0
Payments of finance lease liabilities, classified as financing activities	(233)	0
Other	(1)	(8)
Change in non-cash working capital (note 24)	3	120
Cash flow – financing activities	(817)	(325)
Investing activities
Capital expenditures	(3,432)	(3,578)
Capitalized interest (note 22)	(177)	(108)
Corporate acquisition (note 9)	0	(15)
Proceeds from asset sales (note 9)	277	4
Investment in joint ventures (note 12)	(40)	(40)
Other	2	(19)
Change in non-cash working capital (note 24)	173	235
Cash flow – investing activities	(3,197)	(3,521)
Increase (decrease) in cash and cash equivalents	(1,043)	288
Effect of exchange rates on cash and cash equivalents	(48)	65
Cash and cash equivalents at beginning of year	2,866	2,513
Cash and cash equivalents at end of year	1,775	2,866
Net interest paid	(330)	(285)
Net Income taxes paid	(41)	(37)
Ordinary shares [member]
Financing activities
Dividends paid, classified as financing activities	(503)	(402)
Preference shares [member]
Financing activities
Dividends paid, classified as financing activities	$ (35)	$ (35)

Description of Business and Seg

Description of Business and Segmented Disclosures	12 Months Ended
	Dec. 31, 2019
Corporate Information And Statement Of IFRS Compliance [Abstract]
Description of Business and Segment Disclosures	Description of Business and Segmented Disclosures Husky Energy Inc. (“Husky” or “the Company”) is an international integrated energy company incorporated under the Business Corporations Act (Alberta). The Company’s common shares are listed on the Toronto Stock Exchange (“TSX”) under the symbol “HSE” and the Cumulative Redeemable Preferred Shares, Series 1, Cumulative Redeemable Preferred Shares, Series 2, Cumulative Redeemable Preferred Shares, Series 3, Cumulative Redeemable Preferred Shares, Series 5 and Cumulative Redeemable Preferred Shares, Series 7 are listed under the symbols, ”HSE.PR.A”, “HSE.PR.B”, ”HSE.PR.C”, ”HSE.PR.E” and ”HSE.PR.G”, respectively. The registered office is located at 707, 8th Avenue S.W., PO Box 6525, Station D, Calgary, Alberta, T2P 3G7. Management has identified segments for the Company’s business based on differences in products, services and management responsibility. The Company’s business is conducted predominantly through two major business segments – Upstream and Downstream. Upstream operations in the Integrated Corridor and Offshore include exploration for, and development and production of, crude oil, bitumen, natural gas and natural gas liquids (“NGL”) (“Exploration and Production”) and the marketing of the Company’s and other producers’ crude oil, natural gas, NGL, sulphur and petroleum coke. Additionally, Upstream operations include pipeline transportation, the blending of crude oil and natural gas and storage of crude oil, diluent and natural gas (“Infrastructure and Marketing”). Infrastructure and Marketing markets and distributes products to customers on behalf of Exploration and Production and is grouped in the Upstream business segment based on the nature of its interconnected operations. The Company’s Upstream operations are located primarily in Alberta, Saskatchewan, and British Columbia (“Western Canada”), offshore east coast of Canada (“Atlantic”) and offshore China and offshore Indonesia (“Asia Pacific”). Downstream operations in the Integrated Corridor in Canada include upgrading heavy crude oil feedstock into synthetic crude oil and diesel (“Upgrading”), refining crude oil, producing ethanol and marketing heavy and synthetic crude oil, refined petroleum products including gasoline, diesel, ethanol-blended fuels, asphalt and ancillary products (“Canadian Refined Products”). It also includes crude oil refining in the U.S. to produce and market diesel fuels, gasoline, jet fuel and asphalt (“U.S. Refining and Marketing”). Upgrading, Canadian Refined Products and U.S. Refining and Marketing all process and refine natural resources into marketable products and are grouped together as the Downstream business segment due to the similar nature of their products and services.
Disclosure of entity's operating segments [text block]	Segmented Financial Information Upstream ($ millions) Exploration and Production (1) Infrastructure and Marketing (2) Total Years ended December 31, 2019 2018 2019 2018 2019 2018 Gross revenues 4,958 4,330 2,342 2,211 7,300 6,541 Royalties (323 ) (335 ) — — (323 ) (335 ) Marketing and other — — 189 668 189 668 Revenues, net of royalties 4,635 3,995 2,531 2,879 7,166 6,874 Expenses Purchases of crude oil and products — — 2,336 2,087 2,336 2,087 Production, operating and transportation expenses 1,634 1,527 21 23 1,655 1,550 Selling, general and administrative expenses 297 296 9 5 306 301 Depletion, depreciation, amortization and impairment 4,312 1,811 12 — 4,324 1,811 Exploration and evaluation expenses 547 149 — — 547 149 Loss (gain) on sale of assets (3 ) (2 ) — — (3 ) (2 ) Other – net 86 (120 ) — 2 86 (118 ) 6,873 3,661 2,378 2,117 9,251 5,778 Earnings (loss) from operating activities (2,238 ) 334 153 762 (2,085 ) 1,096 Share of equity investment income 50 51 9 18 59 69 Financial items Net foreign exchange gain — — — — — — Finance income 3 12 — — 3 12 Finance expenses (163 ) (109 ) (3 ) — (166 ) (109 ) (160 ) (97 ) (3 ) — (163 ) (97 ) Earnings (loss) before income taxes (2,348 ) 288 159 780 (2,189 ) 1,068 Provisions for (recovery of) income taxes Current 32 (484 ) — 354 32 (130 ) Deferred (674 ) 549 43 (141 ) (631 ) 408 (642 ) 65 43 213 (599 ) 278 Net earnings (loss) (1,706 ) 223 116 567 (1,590 ) 790 Intersegment revenues 1,660 1,155 — — 1,660 1,155 (1) Includes allocated depletion, depreciation, amortization and impairment related to assets in Infrastructure and Marketing, as these assets provide a service to Exploration and Production. (2) Includes $201 million of revenue (2018 - $172 million ) and $269 million of associated costs (2018 - $142 million ) for construction contracts, inclusive of $193 million of revenue (2018 - $172 million ) and $261 million of costs (2018 - $142 million ) for contracts in progress with revenue recognized as performance obligations are met. (3) Eliminations relate to sales and operating revenues between segments recorded at transfer prices based on current market prices. Segment results include transactions between business segments. Segmented Financial Information Con’t Downstream Corporate and Eliminations (3) Total Upgrading Canadian Refined Products U.S. Refining and Marketing Total 2019 2018 2019 2018 2019 2018 2019 2018 2019 2018 2019 2018 1,777 1,750 3,122 3,412 9,940 11,770 14,839 16,932 (2,022 ) (1,554 ) 20,117 21,919 — — — — — — — — — — (323 ) (335 ) — — — — — — — — — — 189 668 1,777 1,750 3,122 3,412 9,940 11,770 14,839 16,932 (2,022 ) (1,554 ) 19,983 22,252 1,303 928 2,571 2,760 8,629 10,334 12,503 14,022 (2,022 ) (1,554 ) 12,817 14,555 217 195 278 265 869 795 1,364 1,255 (2 ) (2 ) 3,017 2,803 9 7 53 47 33 22 95 76 292 277 693 654 115 123 218 115 735 450 1,068 688 104 92 5,496 2,591 — — — — — — — — — — 547 149 — — (6 ) (2 ) 1 — (5 ) (2 ) — — (8 ) (4 ) — — — (1 ) (654 ) (464 ) (654 ) (465 ) (16 ) (8 ) (584 ) (591 ) 1,644 1,253 3,114 3,184 9,613 11,137 14,371 15,574 (1,644 ) (1,195 ) 21,978 20,157 133 497 8 228 327 633 468 1,358 (378 ) (359 ) (1,995 ) 2,095 — — — — — — — — — — 59 69 — — — — — — — — 44 14 44 14 — — — — — — — — 71 52 74 64 (1 ) (1 ) (15 ) (12 ) (18 ) (14 ) (34 ) (27 ) (151 ) (178 ) (351 ) (314 ) (1 ) (1 ) (15 ) (12 ) (18 ) (14 ) (34 ) (27 ) (36 ) (112 ) (233 ) (236 ) 132 496 (7 ) 216 309 619 434 1,331 (414 ) (471 ) (2,169 ) 1,928 63 168 38 100 17 9 118 277 25 (72 ) 175 75 (28 ) (33 ) (40 ) (42 ) 52 129 (16 ) 54 (327 ) (66 ) (974 ) 396 35 135 (2 ) 58 69 138 102 331 (302 ) (138 ) (799 ) 471 97 361 (5 ) 158 240 481 332 1,000 (112 ) (333 ) (1,370 ) 1,457 263 290 99 109 — — 362 399 — — 2,022 1,554 Segmented Financial Information Upstream ($ millions) Exploration and Production (1) Infrastructure and Marketing Total Years ended December 31, 2019 2018 2019 2018 2019 2018 Expenditures on exploration and evaluation assets (2) 46 242 — — 46 242 Expenditures on property, plant and equipment (2) 2,300 2,414 2 — 2,302 2,414 As at December 31, Exploration and evaluation assets 643 997 — — 643 997 Developing and producing assets at cost 46,587 44,196 — — 46,587 44,196 Accumulated depletion, depreciation, amortization and impairment (31,348 ) (27,379 ) — — (31,348 ) (27,379 ) Other property, plant and equipment at cost — — 101 101 101 101 Accumulated depletion, depreciation and amortization — — (51 ) (50 ) (51 ) (50 ) Total exploration and evaluation assets and property, plant and equipment, net 15,882 17,814 50 51 15,932 17,865 Total right-of-use assets, net 520 — 90 — 610 — Total assets 17,533 19,175 1,661 1,301 19,194 20,476 (1) Includes allocated depletion, depreciation, amortization and impairment related to assets in Infrastructure and Marketing, as these assets provide a service to Exploration and Production. (2) Excludes capitalized costs related to asset retirement obligations and capitalized interest incurred during the year. Includes Exploration and Production assets acquired through acquisition, but excludes assets acquired through corporate acquisition. Geographical Financial Information ($ millions) Canada United States Years ended December 31, 2019 2018 2019 2018 Gross revenues (1) 9,120 9,000 9,940 11,770 Royalties (264 ) (269 ) — — Marketing and other 189 668 — — Revenue, net of royalties 9,045 9,399 9,940 11,770 As at December 31, Restricted cash – non-current — — — — Exploration and evaluation assets 599 935 — — Property, plant and equipment, net 14,630 16,433 6,053 6,336 Right-of-use assets, net 1,044 — 156 — Goodwill — — 656 690 Investment in joint ventures 666 669 — — Long-term income tax receivable 212 243 — — Other assets (2) 47 58 458 276 Total non-current assets 17,198 18,338 7,323 7,302 (1) Sales to external customers are based on the location of the seller. (2) Includes insurance proceeds of $435 million (2018 - $253 million ), related to the Superior Refinery incident. Segmented Financial Information Con’t Downstream Corporate and Eliminations Total Upgrading Canadian Refined Products U.S. Refining and Marketing Total 2019 2018 2019 2018 2019 2018 2019 2018 2019 2018 2019 2018 — — — — — — — — — — 46 242 59 62 119 74 768 665 946 801 138 121 3,386 3,336 — — — — — — — — — — 643 997 — — — — — — — — — — 46,587 44,196 — — — — — — — — — — (31,348 ) (27,379 ) 2,721 2,659 2,360 2,789 9,534 9,746 14,615 15,194 1,377 1,251 16,093 16,546 (1,700 ) (1,585 ) (1,449 ) (1,581 ) (3,481 ) (3,410 ) (6,630 ) (6,576 ) (1,028 ) (937 ) (7,709 ) (7,563 ) 1,021 1,074 911 1,208 6,053 6,336 7,985 8,618 349 314 24,266 26,797 — — 143 — 157 — 300 — 292 — 1,202 — 1,203 1,149 1,287 1,431 8,691 8,566 11,181 11,146 2,747 3,603 33,122 35,225 Geographical Financial Information Con’t China Other International Total 2019 2018 2019 2018 2019 2018 1,057 1,149 — — 20,117 21,919 (59 ) (66 ) — — (323 ) (335 ) — — — — 189 668 998 1,083 — — 19,983 22,252 142 128 — — 142 128 39 57 5 5 643 997 2,938 3,030 2 1 23,623 25,800 2 — — — 1,202 — — — — — 656 690 — — 516 650 1,182 1,319 — — — — 212 243 — — 19 26 524 360 3,121 3,215 542 682 28,184 29,537 Disaggregation of Revenue Upstream ($ millions) Exploration and Production Infrastructure and Marketing Total Years ended December 31, 2019 2018 2019 2018 2019 2018 Primary Geographical Markets Canada 3,901 3,181 2,342 2,211 6,243 5,392 United States — — — — — — China 1,057 1,149 — — 1,057 1,149 Total revenue 4,958 4,330 2,342 2,211 7,300 6,541 Major Product Lines Light & medium crude oil 670 948 — — 670 948 Heavy crude oil 603 527 — — 603 527 Bitumen 2,302 1,367 — — 2,302 1,367 Total crude oil 3,575 2,842 — — 3,575 2,842 NGL 291 381 — — 291 381 Natural gas 1,092 1,107 — — 1,092 1,107 Total exploration and production 4,958 4,330 — — 4,958 4,330 Total infrastructure and marketing — — 2,342 2,211 2,342 2,211 Synthetic crude — — — — — — Gasoline — — — — — — Diesel & distillates — — — — — — Asphalt — — — — — — Other — — — — — — Total refined products — — — — — — Total revenue 4,958 4,330 2,342 2,211 7,300 6,541 Disaggregation of Revenue Con’t Downstream Corporate and Eliminations Total Upgrading Canadian Refined Products U.S. Refining and Marketing Total 2019 2018 2019 2018 2019 2018 2019 2018 2019 2018 2019 2018 1,777 1,750 3,122 3,412 — — 4,899 5,162 (2,022 ) (1,554 ) 9,120 9,000 — — — — 9,940 11,770 9,940 11,770 — — 9,940 11,770 — — — — — — — — — — 1,057 1,149 1,777 1,750 3,122 3,412 9,940 11,770 14,839 16,932 (2,022 ) (1,554 ) 20,117 21,919 — — — — — — — — — — 670 948 — — — — — — — — — — 603 527 — — — — — — — — — — 2,302 1,367 — — — — — — — — — — 3,575 2,842 — — — — — — — — — — 291 381 — — — — — — — — — — 1,092 1,107 — — — — — — — — — — 4,958 4,330 — — — — — — — — — — 2,342 2,211 1,505 1,445 — — — — 1,505 1,445 — — 1,505 1,445 — — 904 1,070 5,414 6,157 6,318 7,227 — — 6,318 7,227 260 278 1,152 1,303 3,644 4,297 5,056 5,878 — — 5,056 5,878 — — 452 454 136 165 588 619 — — 588 619 12 27 614 585 746 1,151 1,372 1,763 — — 1,372 1,763 1,777 1,750 3,122 3,412 9,940 11,770 14,839 16,932 — — 14,839 16,932 1,777 1,750 3,122 3,412 9,940 11,770 14,839 16,932 (2,022 ) (1,554 ) 20,117 21,919

Basis of Presentation

Basis of Presentation	12 Months Ended
	Dec. 31, 2019
Disclosure of changes in accounting policies, accounting estimates and errors [Abstract]
Basis of Presentation	Basis of Presentation a) Basis of Measurement and Statement of Compliance The consolidated financial statements have been prepared by management on a historical cost basis with some exceptions, as detailed in the accounting policies set out below in accordance with International Financial Reporting Standards (“IFRS”), as issued by the International Accounting Standards Board (“IASB”). These accounting policies have been applied consistently for all periods presented in these consolidated financial statements. These consolidated financial statements were approved by the Board of Directors on February 26, 2020. Certain prior years’ amounts have been reclassified to conform with current presentation. b) Principles of Consolidation The consolidated financial statements include the accounts of Husky Energy Inc. and its subsidiaries. Subsidiaries are defined as any entities, including unincorporated entities such as partnerships, for which the Company has the power to govern their financial and operating policies to obtain benefits from their activities. The Company’s accounts reflect the proportionate share of the assets, liabilities, revenues, expenses and cash flows from the Company’s activities that are conducted jointly with third parties. Intercompany balances, net earnings and unrealized gains and losses arising from intercompany transactions are eliminated in preparing the consolidated financial statements. A portion of the Company’s activities relate to joint ventures (see Note 12), which are accounted for using the equity method. c) Use of Estimates, Judgments and Assumptions The timely preparation of the consolidated financial statements requires management to make estimates, judgments and assumptions that affect the reported amounts of assets and liabilities and disclosures of contingencies, if any, as at the date of the financial statements and the reported amounts of revenue and expenses during the period. Actual results may differ from these estimates, judgments and assumptions. Estimates and underlying assumptions are reviewed on an ongoing basis. Revisions to accounting estimates are recognized in the period in which the estimates are revised and on a prospective basis. By their nature, estimates are subject to measurement uncertainty and changes in such estimates in future years could require a material change in the consolidated financial statements. These underlying assumptions are based on historical experience and other factors that management believes to be reasonable under the circumstances, and are subject to change as new events occur, as more industry experience is acquired, as additional information is obtained, and as the Company’s operating environment changes. Specifically, amounts recorded for depletion, depreciation, amortization and impairment, recoveries from insurance claims, asset retirement obligations, assets and liabilities measured at fair value, employee future benefits, income taxes and reserves and contingencies are based on estimates. Management makes judgments regarding the application of IFRS for each accounting policy. Critical judgments that have the most significant effect on the amounts recognized in the consolidated financial statements include determination of technical feasibility and commercial viability, impairment assessments, the determination of cash generating units (“CGUs”), changes in reserves estimates, the determination of a joint arrangement, the designation of the Company’s functional currency and the fair value of related party transactions. Significant estimates, judgments and assumptions made by management in the preparation of these consolidated financial statements are outlined in detail in Note 3. d) Functional and Presentation Currency The consolidated financial statements are presented in Canadian dollars, which is the Company’s functional currency. All financial information is presented in millions of Canadian dollars, except per share amounts and unless otherwise stated. The designation of the Company’s functional currency is a management judgment based on the currency of the primary economic environment in which the Company operates.

Significant Accounting Policies

Significant Accounting Policies	12 Months Ended
	Dec. 31, 2019
Disclosure of changes in accounting policies, accounting estimates and errors [Abstract]
Significant Account Policies	Significant Accounting Policies a) Cash and Cash Equivalents Cash and cash equivalents consist of cash on hand less outstanding cheques and deposits with an original maturity of less than three months at the time of purchase. When outstanding cheques are in excess of cash on hand and short-term deposits, and the Company has the ability to net settle, the excess is reported in bank operating loans. Cash and cash equivalents held that are not available for use are classified as restricted cash. When restricted cash is not expected to be used within 12 months, it is classified as a non-current asset. b) Inventories Crude oil, natural gas, refined petroleum products and sulphur inventories are valued at the lower of cost or net realizable value. Cost is determined using average cost or on a first-in, first-out basis, as appropriate. Materials, parts and supplies are valued at the lower of average cost or net realizable value. Cost consists of raw material, labour, direct overhead, operating costs, transportation and depreciation, depletion and amortization. Commodity inventories held for trading purposes are carried at fair value and measured at fair value less costs to sell based on Level 2 observable inputs, refer to policy Note 3 (m). Any changes in commodity trading inventory fair value are included as gains or losses in Marketing and Other in the consolidated statements of income (loss) during the period of change. Previous inventory impairment provisions are reversed when there is a change in the condition that caused the impairment and the inventory remains on hand. Unrealized intersegment net earnings on inventory sales are eliminated. c) Precious Metals The Company uses precious metals in conjunction with a catalyst as part of the downstream upgrading and refining processes. These precious metals remain intact; however, there is a loss during the reclamation process. The estimated loss is amortized to production and operating expenses over the period that the precious metal is in use, which is approximately two to five years. After the reclamation process, the actual loss is compared to the estimated loss and any difference is recognized in net earnings (loss). Precious metals are included in other assets on the balance sheet. d) Exploration and Evaluation Assets and Property, Plant and Equipment i) Cost Oil and gas properties and other property, plant and equipment are recorded at cost, including expenditures that are directly attributable to the purchase or development of an asset. Borrowing costs directly attributable to the acquisition, construction or production of a qualifying asset are included in the asset cost. Capitalization ceases when substantially all activities necessary to prepare the qualifying asset for its intended use are complete. ii) Exploration and Evaluation Costs The accounting treatment of costs incurred for oil and natural gas exploration, evaluation and development is determined by the classification of the underlying activities as either exploratory or developmental. The results from an exploration drilling program can take considerable time to analyze, and the determination that commercial reserves have been discovered requires determination of technical feasibility, commercial viability and industry experience. Exploration activities can fluctuate from year to year, due to such factors as the level of exploratory spending, the level of risk sharing with third parties participating in exploratory drilling and the degree of risk associated with drilling in particular areas. Properties that are assumed to be productive may, over a period of time, actually deliver oil and gas in quantities different than originally estimated because of changes in reservoir performance. Costs incurred after the legal right to explore an area has been obtained and before technical feasibility and commercial viability of the area have been established are capitalized as exploration and evaluation assets. These costs include costs to acquire acreage and exploration rights, legal and other professional fees and land brokerage fees. Pre-license costs and geological and geophysical costs associated with exploration activities are expensed in the period incurred. Costs directly associated with an exploration well are initially capitalized as an exploration and evaluation asset until the drilling of the well is complete and the results have been evaluated. If extractable hydrocarbons are found and are likely to be developed commercially, but are subject to further appraisal activity, which may include the drilling of wells, the costs continue to be carried as an exploration and evaluation asset while sufficient and continued progress is made in assessing the commercial viability of the hydrocarbons. Capitalized exploration and evaluation costs or assets are not depreciated and are carried forward until technical feasibility and commercial viability of the area is determined or the assets are determined to be impaired. Management determines technical feasibility and commercial viability when exploration and evaluation assets are reclassified to property, plant and equipment. This decision considers several factors, including the existence of reserves, establishing commercial and technical feasibility and whether the asset can be developed using a proved development concept and has received internal approval. Upon the determination of technical feasibility and commercial viability, capitalized exploration and evaluation assets are then transferred to property, plant and equipment. All such carried costs are subject to technical, commercial and management review, as well as review for impairment indicators, at least every reporting period to confirm the continued intent to develop or otherwise extract value from the discovery. These costs are also tested for impairment when transferred to property, plant and equipment. Capitalized exploration and evaluation expenditures related to wells that do not find reserves, or where no future activity is planned, are expensed as exploration and evaluation expenses. The application of the Company’s accounting policy for exploration and evaluation costs 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. Judgments may change as new information becomes available. iii) Development Costs Expenditures, including borrowing costs, on the construction, installation and completion of infrastructure facilities, such as platforms, pipelines and the drilling of development wells, are capitalized as oil and gas properties. Costs incurred to operate and maintain wells and equipment to lift oil and gas to the surface are expensed as production and operating expenses. iv) Other Property, Plant and Equipment Repair and maintenance costs, other than major turnaround costs, are expensed as incurred. Major turnaround costs are capitalized as part of property, plant and equipment when incurred and are amortized over the estimated period of time to the anticipated date of the next turnaround. v) Depletion, Depreciation and Amortization Oil and gas properties are depleted on a unit-of-production basis over the proved developed reserves of the particular field, except in the case of assets whose useful life is shorter or longer than the lifetime of the proved developed reserves of that field, in which case the straight-line method or a unit-of-production method based on total proved plus probable reserves is applied. The unit-of-production rate for the depletion of oil and gas properties related to total proved plus probable reserves takes into account expenditures incurred to date together with sanctioned future development expenditures required to develop the field. Oil and gas reserves are evaluated internally and audited by independent qualified reserve engineers. The estimation of reserves is an inherently complex process and involves the exercise of professional judgment. Estimates are based on projected future rates of production, estimated commodity prices, engineering data and the timing of future expenditures, all of which are subject to uncertainty. Changes in reserve estimates can have an impact on reported net earnings (loss) through revisions to depletion, depreciation and amortization expense, in addition to determining possible impairments and reversal of impairments of property, plant and equipment. Net reserves represent the Company’s undivided gross working interest in total reserves after deducting crown, freehold and overriding royalty interests. Assumptions reflect market and regulatory conditions, as applicable, as at the balance sheet date and could differ significantly from other points in time throughout the year or future periods. Changes in market and regulatory conditions and assumptions can materially impact the estimation of net reserves. Depreciation for substantially all other property, plant and equipment is provided using the straight-line method based on the estimated useful lives of assets, which range from five to forty-five years. The useful lives of assets are estimated based upon the period the asset is expected to be available for use by the Company. Depletion, depreciation and amortization rates for all capitalized costs associated with the Company's activities are reviewed at least annually, or when events or conditions occur that impact capitalized costs, reserves and estimated service lives. e) Joint Arrangements Joint arrangements represent activities where the Company has joint control established by a contractual agreement. Joint control requires unanimous consent for financial and operational decisions. A joint arrangement is either a joint operation, whereby the parties have rights to the assets and obligations for the liabilities, or a joint venture, whereby the parties have rights to the net assets. For a joint operation, the consolidated financial statements include the Company’s proportionate share of the assets, liabilities, revenues, expenses and cash flows of the joint arrangement. The Company reports items of a similar nature to those on the financial statements of the joint arrangement, on a line-by-line basis, from the date that joint control commences until the date that joint control ceases. Joint ventures are accounted for using the equity method of accounting and recognized at cost and adjusted thereafter for the post-acquisition change in the Company’s share of the joint venture’s net assets. The Company’s consolidated financial statements include its share of the joint venture’s profit or loss and other comprehensive income (“OCI”) included in investment in joint ventures, until the date that joint control ceases. Classification of a joint arrangement as either joint operation or joint venture requires judgment. Management’s considerations include, but are not limited to, determining if the arrangement is structured through a separate vehicle and whether the legal form and contractual arrangements give the entity direct rights to the assets and obligations for the liabilities within the normal course of business. Other facts and circumstances are also assessed by management, including the entity’s rights to the economic benefits of assets and its involvement and responsibility for settling liabilities associated with the arrangement. f) Investments in Associates An associate is an entity for which the Company has significant influence and thereby has the power to participate in the financial and operational decisions but does not control or jointly control the investee. Investments in associates are accounted for using the equity method of accounting and are recognized at cost and adjusted thereafter for the post-acquisition change in the Company’s share of the investee’s net assets. The Company’s consolidated financial statements include its share of the investee’s profit or loss and OCI until the date that significant influence ceases. g) Business Combinations Business combinations are accounted for using the acquisition method. Determining whether an acquisition meets the definition of a business combination or represents an asset purchase requires judgment on a case-by-case basis. If the acquisition meets the definition of a business combination, the assets and liabilities are recognized based on the contractual terms, economic conditions, the Company’s operating and accounting policies and other factors that exist on the acquisition date, which is the date on which control is transferred to the Company. The identifiable assets and liabilities are measured at their fair values on the acquisition date with limited exceptions. Any additional consideration payable, contingent upon the occurrence of a future event, is recognized at fair value on the acquisition date; subsequent changes in the fair value of the liability are recognized in net earnings (loss). Acquisition costs incurred are expensed and included in selling, general and administrative expenses in the consolidated statements of income (loss). h) Goodwill Goodwill is the excess of the purchase price paid over the recognized amount of net assets acquired through business combinations, which is inherently imprecise as judgment is required in the determination of the fair value of assets and liabilities. Goodwill, which is not amortized, is assigned to appropriate CGUs or groups of CGUs. Goodwill is tested for impairment annually and when circumstances indicate that the carrying value may be impaired. Impairment losses are recognized in net earnings (loss) and are not subject to reversal. On the disposal or termination of a previously acquired business, any remaining balance of associated goodwill is included in the determination of the gain or loss on disposal. i) Impairment and Reversals of Impairment on Non-Financial Assets The carrying amounts of the Company’s non-financial assets, other than inventories and deferred tax assets but including right-of-use assets, are reviewed at the end of each reporting period to determine whether there is an indication of impairment or reversal of previously recorded impairment. If such indication exists, the recoverable amount is estimated. Determining whether there are any indications of impairment or impairment reversals requires significant judgment of external factors, such as an extended change in prices or margins for oil and gas commodities or refined products, a significant change in an asset’s market value, a significant revision of estimated volumes, revision of future development costs, a change in the entity’s market capitalization or significant changes in the technological, market, economic or legal environment that would have an impact on the Company’s CGUs. If any indication of impairment or impairment reversals exist, an estimate of the asset’s recoverable amount is calculated as the higher of the fair value less costs to sell (“FVLCS”) and the asset’s value in use (“VIU”) for an individual asset or CGU. If the asset does not generate cash inflows that are largely independent of those from other assets or groups of assets, the asset is tested as part of a CGU, which is the smallest identifiable group of assets, liabilities and associated goodwill that generates cash inflows that are largely independent of the cash inflows from other assets or groups of assets. Determination of the Company’s CGUs is subject to management’s judgment. FVLCS is the amount that would be obtained from the sale of a CGU in an arm’s length transaction between knowledgeable and willing parties. The FVLCS is generally determined as the net present value of the estimated future cash flows expected to arise from a CGU, including any expansion prospects, and its eventual disposal, using assumptions that an independent market participant may take into account. These cash flows are discounted using a rate that would be applied by a market participant to arrive at a net present value of the CGU, less cost to dispose. VIU is the net present value of the estimated future cash flows expected to arise from the continued use of the asset in its present form and its eventual disposal. VIU is determined by applying assumptions specific to the Company’s continued use and can only take into account sanctioned future development costs. Estimates of future cash flows used in the evaluation of impairment of assets are made using management’s forecasts of commodity prices, royalty rates, operating costs and future capital expenditures, forecasted crack spreads, growth rate, discount rate and, in the case of oil and gas properties, expected production volumes. Expected production volumes take into account assessments of field reservoir performance and include expectations about proved and probable volumes and where applicable economically recoverable resources associated with interests in certain Husky properties which are risk-weighted utilizing geological, production, recovery, market price and economic projections. Either the cash flow estimates or the discount rate is risk-adjusted to reflect local conditions as appropriate. Given that the calculations for recoverable amounts require the use of estimates and assumptions, including forecasts of commodity prices, marketing supply and demand, product margins and in the case of oil and gas properties, expected production volumes, it is possible that the assumptions may change, which may impact the estimated life of the CGU and may require a material adjustment to the carrying value of goodwill and non-financial assets. An impairment loss is recognized if the carrying amount of an asset or its CGU exceeds its estimated recoverable amount. Impairment losses recognized with respect to CGUs are allocated first to reduce the carrying amount of any goodwill allocated to the units and then to reduce the carrying amounts of the other assets in the CGU or group of CGUs on a pro rata basis. Impairment losses are recognized in depletion, depreciation, amortization and impairment in the consolidated statements of income (loss). Impairment losses recognized in prior years are assessed at the end of each reporting period for indications that the impairment has decreased or no longer exists. An impairment loss is reversed only to the extent that the carrying amount of the asset or CGU does not exceed the carrying amount that would have been determined, net of depletion, depreciation and amortization, if no impairment loss had been recognized. j) Asset Retirement Obligations (“ARO”) A liability is recognized for future legal or constructive retirement obligations associated with the Company’s assets. The Company has significant obligations to remove tangible assets and restore land after operations cease and the Company retires or relinquishes the asset. The retirement of Upstream and Downstream assets consists primarily of plugging and abandoning wells, abandoning surface and subsea plant and equipment and facilities and restoring land to a state required by regulation or contract. The amount recognized is the net present value of the estimated future expenditures determined in accordance with local conditions, current technology and current regulatory requirements. The obligation is calculated using the current estimated costs to retire the asset inflated to the estimated retirement date and then discounted using a credit-adjusted risk-free discount rate. The liability is recorded in the period in which an obligation arises with a corresponding increase to the carrying value of the related asset. The liability is progressively accreted over time as the effect of discounting unwinds, creating an expense recognized in finance expenses. The costs capitalized to the related assets are amortized in a manner consistent with the depletion, depreciation and amortization of the underlying assets. Actual retirement expenditures are charged against the accumulated liability as incurred. Liabilities for ARO are adjusted every reporting period for changes in estimates. These adjustments are accounted for as a change in the corresponding capitalized cost, except where a reduction in the provision is greater than the undepreciated capitalized cost of the related assets, in which case the capitalized cost is reduced to nil and the remaining adjustment is recognized in net earnings (loss). Changes to the amount of capitalized costs will result in an adjustment to future depletion, depreciation and amortization, and to finance expenses. Estimating the ARO requires significant judgment as restoration technologies and costs are constantly changing, as are regulatory, political, environmental and safety considerations. Inherent in the calculation of the ARO are numerous assumptions including the ultimate settlement amounts, future third-party pricing, inflation factors, risk-free discount rates, credit risk, timing of settlement and changes in the legal, regulatory, environmental and political environments. Future revisions to these assumptions may result in material changes to the ARO liability. Adjustments to the estimated amounts and timing of future ARO cash flows are a regular occurrence in light of the significant judgments and estimates involved. k) Legal and Other Contingent Matters Provisions and liabilities for legal and other contingent matters are recognized in the period when the circumstance becomes probable that a future cash outflow resulting from past operations or events will occur and the amount of the cash outflow can be reasonably estimated. The timing of recognition and measurement of the provision requires the application of judgment to existing facts and circumstances, which can be subject to change, and the carrying amounts of provisions and liabilities are reviewed regularly and adjusted accordingly. The Company is required to both determine whether a loss is probable based on judgment and interpretation of laws and regulations, and determine that the loss can be reasonably estimated. When a loss is recognized, it is charged to net earnings (loss). The Company continually monitors known and potential contingent matters and makes appropriate disclosure and provisions when warranted by the circumstances present. l) Share Capital Preferred shares are classified as equity since they are cancellable and redeemable only at the Company’s option and dividends are discretionary and payable only if declared by the Board of Directors. Incremental costs directly attributable to the issuance of shares and stock options are recognized as a deduction from equity, net of tax. Common share dividends are paid out in common shares, or in cash, and preferred share dividends are paid in cash. Both common and preferred share dividends are recognized as distributions within equity. m) Financial Instruments Financial instruments are any contracts that give rise to a financial asset of one entity and a financial liability or equity instrument of another entity. Financial assets are classified in one of the following categories: subsequently measured at amortized cost, fair value through other comprehensive income (“FVTOCI”), or fair value through profit or loss (“FVTPL”). Financial liabilities are initially recognized at fair value, and subsequently measured based on classification in one of the following categories: subsequently measured at amortized cost and FVTPL. Financial assets and liabilities are not offset unless there is a currently enforceable legal right to offset the recognized amounts and there is an intention to settle on a net basis, to realize the assets and settle the liabilities simultaneously. Financial assets and liabilities subsequently measured at amortized costs are measured using the effective interest method. The effective interest method is a method of calculating the amortized costs of a financial liability and of allocating interest expense over the relevant period. Transaction costs that are directly attributable to the acquisition or issue of a financial instrument are measured at amortized cost and added to the fair value initially recognized. Financial instruments at FVTPL are stated at fair value, with any gains or losses arising on remeasurement recognized in profit or loss. Unrealized gains and losses on FVTPL financial instruments related to trading activities are recognized in marketing and other in the consolidated statements of income (loss), and unrealized gains and losses on all other FVTPL financial instruments are recognized in other – net. Transaction costs directly attributable to the acquisition of financial assets or liabilities at FVTPL are recognized immediately in profit or loss. Financial instruments at FVTOCI are stated at fair value, with any gains or losses arising on remeasurement recognized in OCI except for impairment gains or losses and foreign exchange gains and losses. Financial instruments subsequently revalued at fair value are further categorized using a three-level hierarchy that reflects the significance of the inputs used in determining fair value. Level 1 fair value is determined by reference to quoted prices in active markets for identical assets and liabilities. Level 2 fair value is based on inputs that are independently observable for similar assets or liabilities. Level 3 fair value is not based on independently observable market data. The disclosure of the fair value hierarchy excludes financial assets and liabilities where book value approximates fair value. A financial asset is derecognized when the contractual rights to the cash flows from the financial asset have expired, or it transfers the contractual rights to receive the cash flows of the financial assets and the Company has transferred substantially all the risks and rewards of ownership of the financial asset. A financial liability is derecognized when the liability is extinguished, discharged, cancelled or expires. n) Derivative Instruments and Hedging Activities Derivatives are financial instruments for which the fair value changes in response to market risks, require little or no initial investment and are settled at a future date. Derivative instruments are utilized by the Company to manage various market risks including volatility in commodity prices, foreign exchange rates and interest rate exposures. The Company’s policy is not to utilize derivative instruments for speculative purposes. The Company may enter into swap and other derivative transactions to hedge or mitigate the Company’s commercial risk, including derivatives that reduce risks that arise in the ordinary course of the Company’s business. The Company may choose to apply hedge accounting to derivative instruments. The fair values of derivatives are determined using valuation models that require assumptions concerning the amount and timing of future cash flows and discount rates. These estimates are also subject to change with fluctuations in commodity prices, interest rates, foreign currency exchange rates and estimates of non-performance. When able, the Company will determine fair value by incorporating forward market prices and rates that are compared to quotes received from financial institutions to ensure reasonability. The actual settlement of a derivative instrument could differ materially from the fair value recorded and could impact future results. i) Derivative Instruments All derivative instruments, other than those designated as effective hedging instruments or certain non-financial derivative contracts that meet the Company’s own use requirements, are classified as FVTPL and are recorded at fair value. Gains and losses on these instruments are recorded in the consolidated statements of income (loss) in the period they occur. The Company may enter into commodity price contracts in order to offset fixed or floating prices with market rates to manage exposures to fluctuations in commodity prices. The estimation of the fair value of commodity derivatives incorporates forward prices and adjustments for quality or location. The related inventory is measured at fair value based on exit prices. Gains and losses from these derivative contracts, which are not designated as effective hedging instruments, are recognized in revenues or purchases of crude oil and products and are initially recorded at settlement date. Derivative instruments that have been designated as effective hedging instruments are further classified as either fair value or cash flow hedges (see “Hedging Activities”). ii) Embedded Derivatives Derivatives embedded within a hybrid contract containing a financial asset host are not accounted for separately, rather the whole instrument is classified as FVTPL. Derivatives embedded in other hybrid contracts are recorded separately when the economic characteristics and risks of the embedded derivative are not clearly and closely related to those of the host contract and the host contract is not measured at FVTPL. The definition of an embedded derivative is the same as freestanding derivatives. Embedded derivatives are measured at fair value with gains and losses recognized in net earnings (loss). iii) Hedging Activities At the inception of a derivative transaction, if the Company elects to use hedge accounting, formal designation and documentation is required. The documentation must include: identification of the hedged item or transaction, the hedging instrument, the nature of the risk being hedged, the Company’s risk management objective and strategy for undertaking the hedge and how the Company will assess the hedging instrument’s effectiveness in offsetting the exposure to changes in the hedged item. A hedge is assessed at inception and at the end of each reporting period to ensure that it is highly effective in offsetting changes in fair values or cash flows of the hedged item. For a fair value hedge, the gain or loss from remeasuring the hedging instrument at fair value is recognized immediately in net earnings (loss) with the offsetting gain or loss on the hedged item. When fair value hedge accounting is discontinued, the carrying amount of the hedging instrument is deferred and amortized to net earnings (loss) over the remaining maturity of the hedged item. For a cash flow hedge, the effective portion of the gain or loss is recorded in OCI. Any hedge or portion of a hedge that is ineffective is immediately recognized in net earnings (loss). Hedge accounting is discontinued on a prospective basis when the hedging relationship no longer qualifies for hedge accounting. Any gain or loss on the hedging instrument resulting from the discontinuation of a cash flow hedge is deferred in OCI until the forecasted transaction date. If the forecasted transaction date is no longer expected to occur, the gain or loss is recognized in net earnings (loss) in the period of discontinuation. A net investment hedge of a foreign operation is accounted for similarly to a cash flow hedge. The Company may designate certain U.S. dollar denominated debt as a hedge of its net investment in foreign operations for which the U.S. dollar is the functional currency. The unrealized foreign exchange gains and losses arising from the translation of the debt are recorded in OCI, net of tax, and are limited to the translation gain or loss on the net investment. o) Comprehensive Income (Loss) Comprehensive income (loss) consists of net earnings (loss) and OCI. OCI is comprised of the change in the fair value of the effective portion of the derivatives used as hedging items in a cash flow hedge or net investment hedge, the exchange gains and losses arising from the translation of foreign operations with a functional currency that is not Canadian dollars and the actuarial gains and losses on defined benefit pension plans. Amounts included in OCI are shown net of tax. Other reserves is an equity category comprised of the cumulative amounts of OCI, relating to foreign currency translation and hedging. p) Impairment of Financial Assets A financial asset is assessed at the end of each reporting period to determine whether it is impaired, based on objective evidence indicating that one or more events have had a negative effect on the estimated future cash flows of that asset. Objective evidence used by the Company to assess impairment of financial assets includes quoted market prices for similar financial assets and historical collection rates. An impairment loss with respect to a financial asset measured at amortized cost is calculated as the difference between its carrying amount and the net present value of the estimated futu

Cash and Cash Equivalents

Cash and Cash Equivalents	12 Months Ended
	Dec. 31, 2019
Subclassifications of assets, liabilities and equities [abstract]
Cash and Cash Equivalents	Cash and Cash Equivalents Cash and cash equivalents at December 31, 2019 included $327 million of cash ( December 31, 2018 – $ 187 million ) and $1,448 million of short-term investments with original maturities less than three months at the time of purchase ( December 31, 2018 – $ 2,679 million ).

Accounts Receivable

Accounts Receivable	12 Months Ended
	Dec. 31, 2019
Subclassifications of assets, liabilities and equities [abstract]
Accounts Receivable	Accounts Receivable Accounts Receivable ($ millions) December 31, 2019 December 31, 2018 Trade receivables 1,327 1,146 Provision for expected credit losses (34 ) (39 ) Derivatives due within one year 38 43 Other (1) 168 205 End of year 1,499 1,355 (1) Includes insurance proceeds of $114 million (2018 – $143 million ), related to the Superior Refinery incident.

Inventories

Inventories	12 Months Ended
	Dec. 31, 2019
Subclassifications of assets, liabilities and equities [abstract]
Inventories	Inventories Inventories ($ millions) December 31, 2019 December 31, 2018 Crude oil, natural gas and NGL 627 445 Refined petroleum products 553 435 Trading inventories measured at fair value less costs to sell 155 200 Materials, supplies and other 151 152 End of year 1,486 1,232 Impairment of inventory to net realizable value for the year ended December 31, 2019 was $15 million ( December 31, 2018 – $60 million ), as a result of declining market benchmark prices. Trading inventories measured at fair value less costs to sell consist of natural gas inventories and crude oil inventories. The fair value measurement incorporates exit commodity prices and adjustments for quality and location.

Restricted Cash

Restricted Cash	12 Months Ended
	Dec. 31, 2019
Subclassifications of assets, liabilities and equities [abstract]
Restricted Cash	Restricted Cash In accordance with the provisions of the regulations of the People’s Republic of China, the Company is required to deposit funds into separate accounts restricted to the funding of future asset retirement obligations in offshore China. As at December 31, 2019 , the Company had deposited funds of $142 million which have been classified as non-current ( 2018 – $128 million ).

Exploration and Evaluation Cost

Exploration and Evaluation Costs	12 Months Ended
	Dec. 31, 2019
Subclassifications of assets, liabilities and equities [abstract]
Exploration and Evaluation Costs	Exploration and Evaluation Costs Exploration and Evaluation Assets ($ millions) 2019 2018 Beginning of year 997 838 Additions 46 287 Disposals — (23 ) Transfers to property, plant and equipment (note 9) (44 ) (79 ) Expensed exploration expenditures previously capitalized (355 ) (29 ) Exchange adjustments (1 ) 3 End of year 643 997 During 2019, $331 million of the $355 million in total expensed exploration expenditures previously capitalized was primarily related to a write-down related to certain crude oil assets in the Atlantic and Western Canada. The write-down was primarily due to changes in management's future development plans resulting from sustained declines in forecasted short and long-term crude oil prices. The following exploration and evaluation expenses for the years ended December 31, 2019 and 2018 relate to activities associated with the exploration for and evaluation of crude oil and natural gas resources and were recorded in the Upstream Exploration and Production business. Exploration and Evaluation Expense Summary ($ millions) 2019 2018 Seismic, geological and geophysical 131 102 Expensed drilling 409 41 Expensed land 7 6 547 149

Property, Plant and Equipment

Property, Plant and Equipment	12 Months Ended
	Dec. 31, 2019
Subclassifications of assets, liabilities and equities [abstract]
Property, Plant and Equipment	Property, Plant and Equipment Property, Plant and Equipment Oil and Gas Properties Processing, Upgrading Refining Retail and Other Total ($ millions) Cost December 31, 2017 41,815 86 2,599 9,191 2,930 56,621 Additions 2,465 12 62 744 151 3,434 Acquisitions 64 — — 3 — 67 Transfers from exploration and evaluation (note 8) 79 — — — — 79 Intersegment transfers — — — (5 ) 5 — Changes in asset retirement obligations (note 17) 43 2 (2 ) (5 ) 7 45 Disposals and derecognition (632 ) — — (10 ) (1 ) (643 ) Exchange adjustments 362 1 — 773 3 1,139 December 31, 2018 44,196 101 2,659 10,691 3,095 60,742 Transfers to right-of-use assets (1) (note 10) (336 ) — — (180 ) — (516 ) Additions (2) 2,340 2 58 899 160 3,459 Acquisitions 10 — — — — 10 Transfers from exploration and evaluation (note 8) 44 — — — — 44 Transfers from right-of-use assets (3) (note 10) 101 — — — — 101 Intersegment transfers 2 — — 27 (29 ) — Changes in asset retirement obligations (note 17) 469 1 5 19 23 517 Disposals and derecognition (16 ) (2 ) (1 ) (943 ) (2 ) (964 ) Exchange adjustments (223 ) (1 ) — (496 ) (2 ) (722 ) December 31, 2019 46,587 101 2,721 10,017 3,245 62,671 Accumulated depletion, depreciation, amortization and impairment December 31, 2017 (26,016 ) (47 ) (1,462 ) (3,176 ) (1,842 ) (32,543 ) Depletion, depreciation, amortization and impairment (1,811 ) (2 ) (123 ) (503 ) (152 ) (2,591 ) Disposals and derecognition 586 — — 10 — 596 Exchange adjustments (138 ) (1 ) — (264 ) (1 ) (404 ) December 31, 2018 (27,379 ) (50 ) (1,585 ) (3,933 ) (1,995 ) (34,942 ) Transfers to right-of-use assets (1) (note 10) 12 — — 40 — 52 Depletion, depreciation, amortization and impairment (4,082 ) (2 ) (115 ) (736 ) (239 ) (5,174 ) Intersegment transfers — — — (17 ) 17 — Disposals and derecognition 8 — — 724 2 734 Exchange adjustments 93 1 — 187 1 282 December 31, 2019 (31,348 ) (51 ) (1,700 ) (3,735 ) (2,214 ) (39,048 ) Net book value December 31, 2018 16,817 51 1,074 6,758 1,100 25,800 December 31, 2019 15,239 50 1,021 6,282 1,031 23,623 (1) Transfer to right-of-use assets due to the adoption of IFRS 16 on January 1, 2019. (2) Includes $5 million of interest expense on lease liabilities allocated to the carrying amount of assets in Oil and Gas Properties. (3) Includes capitalized depreciation from right-of-use assets. Costs of property, plant and equipment, including major development projects, not subject to depletion, depreciation and amortization as at December 31, 2019 were $6.8 billion ( December 31, 2018 – $ 5.2 billion ) including undeveloped land assets of $127 million as at December 31, 2019 ( December 31, 2018 – $117 million ). Included in depletion, depreciation, amortization and impairment for the year ended December 31, 2019 is a pre-tax impairment expense of $2,240 million (December 31, 2018 – $ nil ) on assets on CGUs located at Sunrise, Western Canada and White Rose in the Exploration and Production segment. The impairment charge, reflected in the fourth quarter of 2019 and attributed to the CGUs noted above, was a result of sustained declines in forecasted short and long-term crude oil and natural gas prices and management's decision to reduce capital investment in those CGUs. The recoverable amount of the impaired CGUs was estimated based on fair value less costs to sell methodology using estimated after-tax discounted cash flows on proved plus probable reserves for Sunrise and Western Canada CGUs, and proved plus probable and possible reserves for the White Rose CGU (Level 3). The Company used an after-tax discount rate of 10% (Level 3). The following table summarizes impairment for each Upstream CGU: CGU Impairment recorded ($ millions) Northern 421 Rainbow 241 Western Canada CGUs total 662 White Rose CGU 871 Sunrise CGU 707 Upstream CGUs total 2,240 The recoverable amount of the Upstream CGUs was $5.6 billion as at December 31, 2019. The recoverable amount is sensitive to commodity price, discount rate, production volumes, royalties, operating costs and future capital expenditures. Commodity prices are based on market indicators at the end of the period. Management's long-term assumptions are benchmarked against forward price curve and pricing forecasts prepared by external firms. The table below summarizes the forecasted prices used in determining the recoverable amounts: WTI ($US/bbl) Brent ($US/bbl) Edmonton Light ($CDN/bbl) AECO ($CDN/mcf) Foreign Exchange ($US/$CDN) 2020 61.00 66.00 72.37 2.00 0.76 2021 64.00 68.00 76.62 2.25 0.77 2022 66.00 70.00 78.85 2.50 0.78 2023 68.00 72.00 80.38 2.75 0.79 2024 70.00 74.00 82.91 2.80 0.79 2025 71.40 75.48 84.57 2.86 0.79 2026 (1) 72.83 76.99 86.26 2.91 0.79 (1) Prices are escalated at 2% thereafter. The discount rate for FVLCS represents the rate a market participant would apply to the cash flows in a market transaction. The discount rate is derived from the Company's post-tax weighted average cost of capital with appropriate adjustments made to reflect the risks specific to the CGUs. Production volumes, operating costs, royalties and future capital expenditures are based on management’s best estimates included in the long range plan approved by the Board of Directors. A change in the discount rate or forward price over the life of the reserves will result in the following impact on the Upstream CGUs: Discount Rate Commodity Price ($ millions) 1% Increase in Discount Rate 1% Decrease in Discount Rate 5% Increase in Forward Price 5% Decrease in Forward Price Impairment of PP&E – Increase (Decrease) 528 (605 ) (910 ) 904 Also included in depletion, depreciation, amortization and impairment for the year ended December 31, 2019 is a pre-tax impairment expense of $90 million (December 31, 2018 – $ nil ) at the Lloyd and Minnedosa Ethanol plants within the Canadian Refined Products segment. The impairment charge, reflected in the fourth quarter of 2019 and attributed to the CGUs noted above, was a result of sustained declines in forecasted ethanol margins. The recoverable amount of the impaired CGUs was estimated using after-tax discounted cash flows (Level 3). The Company used comparative market multipliers to corroborate discounted cash flow results. The recoverable amount of these Downstream CGUs was $106 million as at December 31, 2019. The following table summarizes impairment for each CGU in downstream: CGU Impairment recorded ($ millions) Minnedosa Ethanol Plant 78 Lloydminster Ethanol Plant 12 Downstream CGUs total 90 Depletion, depreciation, amortization and impairment for the year ended December 31, 2019 also included a $254 million pre-tax derecognition of the carrying value of components replaced as part of the crude oil flexibility project at the Lima Refinery in the U.S Refining and Marketing segment (December 31, 2018 – a pre-tax impairment expense of $56 million related to the Superior Refinery in the U.S. Refining and Marketing segment). Assets Dispositions On November 1, 2019, the Company completed the sale of its Prince George Refinery to Tidewater Midstream and Infrastructure Ltd. for $215 million in cash plus an inventory closing adjustment of approximately $53.5 million . Upon completion of the sale of the Prince George Refinery, the Company entered into a supply agreement to purchase substantially all of the refinery's production, resulting in a $55 million sale leaseback.The transaction resulted in a pre-tax gain of $2 million and an after-tax gain of $1 million . The assets and related liabilities were recorded in the Canadian Refined Products segment.

Right-of-use Assets and Lease L

Right-of-use Assets and Lease Liabilities	12 Months Ended
	Dec. 31, 2019
Disclosure of leases [Abstract]
Right-of-use Assets and Lease Liabilities	Right-of-use Assets and Lease Liabilities Right-of-use Assets Oil and Gas Properties Processing, Upgrading Refining Retail and Other Total ($ millions) January 1, 2019 Transfers from property, plant and equipment, net (note 9) 324 — — 140 — 464 Initial recognition 721 100 — 70 412 1,303 1,045 100 — 210 412 1,767 Additions 1 — — 80 5 86 Transfers to property, plant and equipment (note 9) (101 ) — — — — (101 ) Disposals and derecognition (11 ) — — (31 ) 2 (40 ) Revaluation (194 ) 1 — (1 ) 8 (186 ) Depreciation and impairment (222 ) (11 ) — (50 ) (39 ) (322 ) Other 2 — — (4 ) — (2 ) December 31, 2019 520 90 — 204 388 1,202 During 2019, $165 million of right-of-use assets were expensed related to impairment recorded within the Exploration and Production segment. Refer to Note 9. Lease Liabilities Balance Sheets ($ millions) December 31, 2019 Current lease liabilities (1) 109 Non-current lease liabilities (1) 1,353 (1) Includes $489 million previously recorded in accrued liabilities and other long-term liabilities as at December 31, 2018. Reconciliation to Operating Lease Commitments ($ millions) Operating agreements included in commitments at December 31, 2018 (1) 2,343 Expenses relating to short-term leases (9 ) Discounting (986 ) Additional lease liability recognized due to adoption of IFRS 16 on January 1, 2019 1,348 (1) Includes commitments from operating agreements, firm transportation agreements, and unconditional purchase obligations. Maturity Analysis Within 1 year After 1 year but no more than 5 years More than 5 years Total ($ millions) 2019 2018 (1) 2019 2018 (1) 2019 2018 (1) 2019 2018 (1) Future lease payments 205 69 653 242 2,174 1,014 3,032 1,325 Interest 96 48 352 175 1,122 613 1,570 836 Present value of lease payments 109 21 301 67 1,052 401 1,462 489 (1) Amounts for 2018 were future payments under finance leases obligations, prior to the adoption of IFRS 16. Results of Operations ($ millions) December 31, 2019 Interest expense on lease liabilities (1) (note 22) 106 Expenses relating to short-term leases 18 (1) Includes $5 million of interest allocated to the carrying amount of assets in Oil and Gas Properties for the year ended December 31, 2019. Cash Flow Summary ($ millions) December 31, 2019 Total cash flow used for leases 339 The Company’s major office building leases contain extension options that are exercisable by the Company up to one year prior to the end of the non-cancellable lease term. As at December 31, 2019, $380 million of lease liabilities related to office buildings have been recognized. Discounted potential lease payments associated with extension options not included in lease liabilities amount to $238 million . During 2019, the Company revalued the Henry Goodrich right-of-use asset due to a shortened contract term, resulting in a reduction of the right-of-use asset and lease liability by $185 million .

Goodwill

Goodwill	12 Months Ended
	Dec. 31, 2019
Subclassifications of assets, liabilities and equities [abstract]
Goodwill	Goodwill Goodwill ($ millions) December 31, 2019 December 31, 2018 Beginning of year 690 633 Exchange adjustments (34 ) 57 End of year 656 690 As at December 31, 2019, the Company’s goodwill balance related entirely to the Lima Refinery. For impairment testing purposes, the recoverable amount of the Lima Refinery CGU was estimated using the FVLCS methodology based on cash flows expected over a 50 -year period and an after-tax discount rate of 9% (2018 – 8% ). Management used the FVLCS calculation for the Lima Refinery CGU, which are sensitive to changes in discount rate, forecasted crack spreads and future capital expenditures. The discount rate is derived from the post-tax weighted average cost of capital, of a group of relevant peers, considered to represent the rate of return that would be required by a typical market participant for similar assets, with appropriate adjustments made to reflect the risks specific to the refinery. Forecasted crack spreads are based on WTI and prices for gasoline and diesel, and are consistent with crack spreads used in the Company’s long range plan. After-tax cash flow projections for the initial 10 -year period are based on long range plan future cash flows and inflated by long-term growth rates of 1% and 2% , for future EBITDA and capital expenditures, respectively, for the remaining 40 -year period. The inflation rate was based upon an average expected inflation rate for the U.S. of 2% (2018 – 2% ). As at December 31, 2019, the recoverable value of the CGU exceeded the carrying amount and no impairment was identified. The Company used comparative market multipliers to corroborate discounted cash flow results.

Joint Arrangements

Joint Arrangements	12 Months Ended
	Dec. 31, 2019
Subclassifications of assets, liabilities and equities [abstract]
Joint Arrangements	Joint Arrangements Joint Operations BP-Husky Refining LLC The Company holds a 50% ownership interest in BP-Husky Refining LLC, which owns and operates the BP-Husky Toledo Refinery in Ohio. Sunrise Oil Sands Partnership The Company holds a 50% interest in the Sunrise Oil Sands Partnership, which is engaged in operating an oil sands project in Northern Alberta. Joint Venture Husky-CNOOC Madura Ltd. The Company holds 40% joint control in Husky-CNOOC Madura Ltd., which is engaged in the exploration for and production of oil and gas resources in Indonesia. Results of the joint venture are included in the consolidated statements of income (loss) in the Exploration and Production in the Upstream segment. Summarized below is the financial information for Husky-CNOOC Madura Ltd. accounted for using the equity method: Results of Operations ($ millions, except share of equity investment) 2019 2018 Revenues 424 441 Expenses (267 ) (273 ) Net earnings 157 168 Share of equity investment 40 % 40 % Proportionate share of equity investment 50 51 Balance Sheets ($ millions, except share of equity investment) December 31, 2019 December 31, 2018 Current assets (1) 208 373 Non-current assets 1,840 2,072 Current liabilities (70 ) (123 ) Non-current liabilities (2) (1,427 ) (1,917 ) Net assets 551 405 Share of net assets 40 % 40 % Carrying amount in balance sheet 516 650 (1) Includes cash and cash equivalents of $ 42 million ( 2018 – $ 203 million ). (2) Includes deferred revenue of nil (2018 – $2 million ) related to take-or-pay commitments, with respect to natural gas production volumes from the BD Project, not taken by the purchaser. As per the terms of the agreement, the purchaser has until the end of the agreement to take these volumes. The Company’s share of equity investment and carrying amount of share of net assets does not equal the 40% joint control of the expenses and net assets of Husky-CNOOC Madura Ltd. due to differences in the accounting policies of the joint venture and the Company and non-current liabilities of the joint venture which are not included in the Company’s carrying amount of net assets due to equity accounting. Husky Midstream Limited Partnership The Company holds a 35% interest in HMLP, which owns midstream assets in Alberta and Saskatchewan. The assets are held by HMLP, of which Husky owns 35% , Power Assets Holdings Ltd. (“PAH”) owns 48.75% and CK Infrastructure Holdings Ltd. (“CKI”) owns 16.25% . Results of the joint venture are included in the consolidated statements of income (loss) in Infrastructure and Marketing in the Upstream segment. Summarized below is the financial information for HMLP accounted for using the equity method: Results of Operations ($ millions, except share of equity investment) 2019 2018 Revenues 316 296 Expenses (228 ) (177 ) Net earnings 88 119 Share of equity investment 35 % 35 % Proportionate share of equity investment 9 18 Balance Sheet ($ millions, except share of net assets) December 31, 2019 December 31, 2018 Current assets (1) 171 115 Non-current assets 3,031 2,849 Current liabilities (163 ) (153 ) Non-current liabilities (1,059 ) (825 ) Net assets 1,980 1,986 Share of net assets 35 % 35 % Carrying amount in balance sheet 666 669 (1) Current assets include cash and cash equivalents of $ 86 million ( 2018 – $16 million ). The Company’s share of equity investment and carrying amount of share of net assets does not equal the 35% joint control of the net income and net assets of HMLP due to the potential fluctuation in the partnership profit structure.

Other Assets

Other Assets	12 Months Ended
	Dec. 31, 2019
Miscellaneous non-current assets [abstract]
Other Assets	Other Assets Other Assets ($ millions) December 31, 2019 December 31, 2018 Long-term receivables (1) 489 319 Precious metals 22 23 Other 13 18 End of year 524 360 (1) Includes insurance proceeds of $435 million (2018 – $253 million ), related to the Superior Refinery incident. For the year ended December 31, 2019, the Company accrued pre-tax recoveries for rebuild costs, incident costs and business interruption associated with the Superior Refinery incident of $630 million (December 31, 2018 – $468 million ), which is included in other-net in the consolidated statements of income (loss).

Bank Operating Loans

Bank Operating Loans	12 Months Ended
	Dec. 31, 2019
Subclassifications of assets, liabilities and equities [abstract]
Bank Operating Loans	Bank Operating Loans At December 31, 2019 , the Company had unsecured short-term borrowing lines of credit with banks totalling $900 million (1) ( December 31, 2018 – $900 million ) and letters of credit under these lines of credit totalling $436 million ( December 31, 2018 – $439 million ). As at December 31, 2019 , bank operating loans were nil ( December 31, 2018 – nil ). Interest payable is based on Bankers’ Acceptance, CAD Prime Rate, U.S. LIBOR, or U.S. Base Rates. Sunrise Oil Sands Partnership has an unsecured demand credit facility of $10 million ( December 31, 2018 – $10 million ) available for general purposes. The Company’s proportionate share of the credit facility is $5 million ( December 31, 2018 – $5 million ). As at December 31, 2019 , there was no balance outstanding under this credit facility ( December 31, 2018 – no balance). (1) Includes $125 million demand facilities available specifically for letters of credit only. The Company had the following available credit facilities as at December 31, 2019 : Credit Facilities ($ millions) Available Unused Operating facilities (1) (note 14) 900 464 Syndicated bank facilities (2) (note 16) 4,000 3,450 End of year 4,900 3,914 (1) Consists of demand credit facilities. (2) Commercial paper outstanding is supported by the Company’s Syndicated credit facilities.

Accounts Payable and Accrued Li

Accounts Payable and Accrued Liabilities	12 Months Ended
	Dec. 31, 2019
Subclassifications of assets, liabilities and equities [abstract]
Accounts Payable and Accrued Liabilities	Accounts Payable and Accrued Liabilities Accounts Payable and Accrued Liabilities ($ millions) December 31, 2019 December 31, 2018 Trade payables 1,178 1,121 Accrued liabilities 1,954 1,712 Dividend payable (note 20) 126 126 Stock-based compensation 19 32 Derivatives due within one year 21 39 Other 167 129 End of year 3,465 3,159

Debt and Credit Facilities

Debt and Credit Facilities	12 Months Ended
	Dec. 31, 2019
Disclosure of borrowing costs [Abstract]
Debt and Credit Facilities	Debt and Credit Facilities Short-term Debt December 31, 2019 December 31, 2018 ($ millions) Commercial paper (1) 550 200 (1) The commercial paper is supported by the Company’s syndicated credit facilities and the Company is authorized to issue commercial paper up to a maximum of $1.0 billion having a term not to exceed 365 days. The weighted average interest rate as at December 31, 2019 was 1.98% per annum ( December 31, 2018 – 2.20% ). Canadian $ Amount U.S. $ Denominated Long-term Debt Maturity December 31, 2019 December 31, 2018 December 31, 2019 December 31, 2018 ($ millions) Long-term debt 5.00% notes (5) 2020 — 400 — — 3.95% notes (1)(4) 2022 648 682 500 500 4.00% notes (1)(4) 2024 973 1,023 750 750 3.55% notes (5) 2025 750 750 — — 3.60% notes (5) 2027 750 750 — — 4.40% notes (1)(4) 2029 973 — 750 — 6.80% notes (1)(4) 2037 501 528 387 387 Debt issue costs (2) (25 ) (19 ) — — Long-term debt 4,570 4,114 2,387 1,637 Long-term debt due within one year 6.15% notes (1)(3) 2019 — 410 — 300 7.25% notes (1)(4) 2019 — 1,023 — 750 5.00% notes (5) 2020 400 — — — Long-term debt due within one year 400 1,433 — 1,050 (1) The U.S. dollar denominated debt is designated as a hedge of the Company’s net investment in selected foreign operations with a U.S. dollar functional currency. Refer to Note 25 for Foreign Currency Risk Management. (2) Calculated using the effective interest rate method. (3) The 6.15% notes represent unsecured securities under a trust indenture dated June 14, 2002. (4) The 7.25% , the 3.95% , the 4.00% , the 4.40% and the 6.80% notes represent unsecured securities under a trust indenture dated September 11, 2007. (5) The 5.00% , the 3.55% and the 3.60% notes represent unsecured securities under a trust indenture dated December 21, 2009. Credit Facilities The Company has two $2.0 billion revolving unsecured syndicated credit facilities that mature on June 19, 2022 and March 9, 2024. As at December 31, 2019 the covenants under the Company’s syndicated credit facilities are debt to capital covenants, calculated as total debt (long-term debt including long-term debt due within one year and short-term debt) and certain adjusting items specified in the agreement divided by total debt, shareholders’ equity and certain adjusting items specified in the agreement. These covenants are used to assess the Company’s financial strength. If the Company does not comply with the covenants under the syndicated credit facilities, there is risk that repayment could be accelerated. The Company was in compliance with the syndicated credit facility covenants at December 31, 2019, and assessed the risk of non-compliance to be low. As at December 31, 2019 , the Company had no direct borrowings under its $2.0 billion facility expiring June 19, 2022 ( December 31, 2018 – no direct borrowings ) and no direct borrowings under its $2.0 billion facility expiring March 9, 2024 ( December 31, 2018 – no direct borrowings ). Interest payable is based on Bankers’ Acceptance, CAD Prime Rate, U.S. LIBOR, or U.S. Base Rates, depending on the borrowing option selected and credit ratings assigned by certain credit rating agencies to the Company. Notes On January 29, 2018, the Company filed a universal short form base shelf prospectus (the ”2018 U.S. Shelf Prospectus”) with the Alberta Securities Commission. On January 30, 2018, the Company’s related U.S. registration statement with the SEC containing the 2018 U.S. Shelf Prospectus became effective which enables the Company to offer up to US$3.0 billion of debt securities, common shares, preferred shares, subscription receipts, warrants and units of the Company in the U.S. up to and including February 29, 2020. On December 4, 2018, the Company entered into cash flow hedges using forward interest rate swaps to fix the underlying U.S. $500 million 10-year note fixed rate to December 15, 2019. During the three months ended March 31, 2019, the Company discontinued these cash flow hedges and these interest rate swaps were settled and derecognized during the year. On March 15, 2019, the Company issued US$750 million in senior unsecured notes. The notes bear an annual interest rate of 4.40% and are due on April 15, 2029. The Company raised the net proceeds of the offering for general corporate purposes, which included the repayment of certain outstanding debt securities that matured in 2019. On May 1, 2019, the Company filed a universal short form base shelf prospectus (the “2019 Canadian Shelf Prospectus”) with applicable securities regulators in each of the provinces of Canada that enables the Company to offer up to $3.0 billion of common shares, preferred shares, debt securities, subscription receipts, warrants and other units in Canada up to and including June 1, 2021. On June 17, 2019, the Company repaid the maturing 6.15% notes. The amount paid to note holders was $402 million. On December 16, 2019, the Company repaid the maturing 7.25% notes. The amount paid to note holders was $987 million. The Company’s notes, credit facilities and short-term lines of credit rank equally in right of payment. Base Shelf Prospectus At December 31, 2019 , the Company had unused capacity of $3.0 billion under its 2019 Canadian Shelf Prospectus and US $2.25 billion under its 2018 U.S. Shelf Prospectus and related U.S. registration statement. Reconciliation of Changes of Liabilities to Cash Flows from Financing Activities Liabilities ($ millions) Short-term debt Long-term debt due within one year Long-term debt Other long-term liabilities Lease liabilities due within one year Lease liabilities December 31, 2018 200 1,433 4,114 1,107 — — Changes from financing cash flows Long-term debt issuance — — 1,000 — — — Long-term debt repayment — (1,389 ) — — — — Short-term debt issuance, net 350 — — — — — Debt issue costs — — (9 ) — — — Finance lease payments — — — — (233 ) — Total change from financing cash flows 350 (1,389 ) 991 — (233 ) — Other changes – liability-related Initial recognition of lease liabilities (note 10) — — — (467 ) 22 1,815 Foreign exchange — — (8 ) (12 ) — (3 ) Fair value changes — — — (4 ) — (240 ) Net additions of lease liabilities — — — — — 89 Reclassification — 400 (400 ) (114 ) 319 (319 ) Deferred revenue — — — (42 ) — — Amortization of debt issuance costs — — 5 — — — Foreign exchange recognized in OCI — (44 ) (132 ) — — — Other — — — (14 ) 1 11 Total other changes – liability related — 356 (535 ) (653 ) 342 1,353 December 31, 2019 550 400 4,570 454 109 1,353

Asset Retirement Obligations

Asset Retirement Obligations	12 Months Ended
	Dec. 31, 2019
Subclassifications of assets, liabilities and equities [abstract]
Asset Retirement Obligations	Asset Retirement Obligations At December 31, 2019 , the estimated total undiscounted inflation-adjusted amount required to settle the Company’s ARO was $10.0 billion ( December 31, 2018 – $9.2 billion ). These obligations will be settled based on the useful lives of the underlying assets, which currently extend an average of 45 years ( December 31, 2018 – 45 years) into the future. This amount has been discounted using credit-adjusted risk-free rates of 3.9% to 4.4% ( December 31, 2018 – 3.8% to 5.0% ) and an inflation rate of 2% ( December 31, 2018 – 2% ). Obligations related to future environmental remediation and cleanup of oil and gas assets are included in the estimated ARO. While the provision is based on management’s best estimates of future costs, discount rates and the economic lives of the assets, there is uncertainty regarding the amount and timing of incurring these costs. A reconciliation of the carrying amount of asset retirement obligations at December 31, 2019 and 2018 is set out below: Asset Retirement Obligations ($ millions) 2019 2018 Beginning of year 2,424 2,526 Additions 76 40 Liabilities settled (276 ) (270 ) Liabilities disposed (6 ) (11 ) Change in discount rate 285 (68 ) Change in estimates 156 93 Exchange adjustment (10 ) 17 Accretion (note 22) 106 97 End of year 2,755 2,424 Expected to be incurred within 1 year 112 202 Expected to be incurred beyond 1 year 2,643 2,222 At December 31, 2019, the Company had deposited funds of $142 million into the restricted accounts for funding of future asset retirement obligations in offshore China (December 31, 2018 – $128 million ). These amounts have been classified as non-current and included in restricted cash.

Other Long-term Liabilities

Other Long-term Liabilities	12 Months Ended
	Dec. 31, 2019
Subclassifications of assets, liabilities and equities [abstract]
Other Long-term Liabilities	Other Long-term Liabilities Other Long-term Liabilities ($ millions) December 31, 2019 December 31, 2018 Employee future benefits (note 23) 214 205 Finance lease obligations (note 10) — 467 Stock-based compensation 19 42 Deferred revenue 152 205 Other 69 188 End of year 454 1,107 Deferred revenue Deferred revenue relates to take-or-pay commitments, with respect to natural gas production volumes from the Liwan 3-1 field in Asia Pacific, not taken by the purchaser. As per the terms of the agreement, the purchaser has until the end of the agreement to take these volumes. ($ millions) December 31, 2019 December 31, 2018 Beginning of year 205 284 Revenue recognized (42 ) (100 ) Exchange adjustment (11 ) 21 End of year 152 205

Income Taxes

Income Taxes	12 Months Ended
	Dec. 31, 2019
Disclosure of income tax [Abstract]
Income Taxes	Income Taxes The major components of income tax expense (recovery) for the years ended December 31, 2019 and 2018 were as follows: Income Tax Expense (Recovery) ($ millions) 2019 2018 Current income tax Current income tax charge 174 86 Adjustments to current income tax estimates 1 (11 ) 175 75 Deferred income tax Relating to origination and reversal of temporary differences (723 ) 378 Adjustments to deferred income tax estimates (251 ) 18 (974 ) 396 Deferred Tax Items in OCI ($ millions) 2019 2018 Deferred tax items expensed (recovered) directly in OCI Derivatives designated as cash flow hedges (3 ) (5 ) Remeasurement of pension plans 1 17 Exchange differences on translation of foreign operations (58 ) 87 Hedge of net investment 30 (41 ) (30 ) 58 The provision for income taxes in the consolidated statements of income (loss) reflects an effective tax rate which differs from the expected statutory tax rate. Differences for the years ended December 31, 2019 and 2018 were accounted for as follows: Reconciliation of Effective Tax Rate ($ millions, except tax rate) 2019 2018 Earnings (loss) before income taxes Canada (3,170 ) 734 United States 337 493 Other foreign jurisdictions 664 701 (2,169 ) 1,928 Statutory Canadian income tax rate 26.8 % 27.2 % Expected income tax (582 ) 525 Effect on income tax resulting from: Foreign jurisdictions 61 (36 ) Non-taxable items (25 ) (13 ) Adjustments with respect to previous year (250 ) 7 Revaluation of foreign tax pools (4 ) (4 ) Other – net 1 (8 ) Income tax expense (recovery) (799 ) 471 The statutory tax rate is 26.8% in 2019 ( 2018 – 27.2% ). The 2019 and 2018 tax rates were changed due to a 0.5% decrease to the Alberta Provincial corporate tax rate that was substantively enacted in the second quarter of 2019 resulting in a deferred tax recovery of $233 million. The following reconciles the movements in the deferred income tax liabilities and assets: Deferred Tax Liabilities and Assets ($ millions) January 1, 2019 Recognized in Earnings Recognized in OCI Other December 31, 2019 Deferred tax liabilities Exploration and evaluation assets and property, plant and equipment (4,089 ) 967 69 — (3,053 ) Foreign exchange gains taxable on realization (174 ) 51 (27 ) — (150 ) Debt issue costs (4 ) (1 ) — — (5 ) Other temporary differences (28 ) (124 ) — — (152 ) Deferred tax assets Pension plans 8 9 (1 ) — 16 Asset retirement obligations 654 16 (4 ) — 666 Loss carry-forwards 468 56 (7 ) — 517 Financial assets at fair value (9 ) — — — (9 ) (3,174 ) 974 30 — (2,170 ) Deferred Tax Liabilities and Assets ($ millions) January 1, 2018 Recognized in Earnings Recognized in OCI Other December 31, 2018 Deferred tax liabilities Exploration and evaluation assets and property, plant and equipment (3,727 ) (260 ) (106 ) 4 (4,089 ) Foreign exchange gains taxable on realization (177 ) (43 ) 46 — (174 ) Debt issue costs (3 ) (1 ) — — (4 ) Other temporary differences (90 ) 62 — — (28 ) Deferred tax assets Pension plans 40 (15 ) (17 ) — 8 Asset retirement obligations 679 (29 ) 4 — 654 Loss carry-forwards 523 (70 ) 15 — 468 Financial assets at fair value 31 (40 ) — — (9 ) (2,724 ) (396 ) (58 ) 4 (3,174 ) The Company has temporary differences associated with its investments in its foreign subsidiaries, branches, and interests in joint ventures. At December 31, 2019 , the Company had nil deferred tax liabilities in respect to these investments ( December 31, 2018 – nil ). At December 31, 2019 , the Company had $2,105 million ( December 31, 2018 – $1,806 million ) of tax losses that will expire between 2030 and 2039. The Company has recorded deferred tax assets in respect of these losses, as there are sufficient taxable temporary differences in the various jurisdictions to utilize these losses.

Share Capital

Share Capital	12 Months Ended
	Dec. 31, 2019
Disclosure of share capital, reserves and other equity interest [Abstract]
Share Capital	Share Capital Common Shares The Company is authorized to issue an unlimited number of no par value common shares. Common Shares Number of Shares Amount ($ millions) December 31, 2017 1,005,120,012 7,293 Options exercised (1) 1,726 — December 31, 2018 1,005,121,738 7,293 December 31, 2019 1,005,121,738 7,293 (1) Stock options exercised was less than $1 million. Quarterly dividends may be declared in an amount expressed in dollars per common share or could be paid by way of issuance of a fraction of a common share per outstanding common share determined by dividing the dollar amount of the dividend by the volume-weighted average trading price of the Common Shares on the principal stock exchange on which the common shares are traded. The volume-weighted average trading price of the common shares is calculated by dividing the total value by the total volume of common shares traded over the five trading day period immediately prior to the payment date of the dividend on the common shares. Common Share Dividends ($ millions) 2019 2018 Declared Paid Declared Paid 503 503 402 276 At December 31, 2019 , Common Share dividends payable were $126 million (December 31, 2018 – $126 million ). Preferred Shares The Company is authorized to issue an unlimited number of no par value preferred shares. Cumulative Redeemable Preferred Shares Number of Shares Amount ($ millions) December 31, 2017 36,000,000 874 December 31, 2018 36,000,000 874 December 31, 2019 36,000,000 874 Cumulative Redeemable Preferred Shares Dividends ($ millions) 2019 2018 Declared Paid Declared Paid Series 1 Preferred Shares 6 6 6 8 Series 2 Preferred Shares 1 1 1 1 Series 3 Preferred Shares 12 12 12 14 Series 5 Preferred Shares 9 9 9 11 Series 7 Preferred Shares 7 7 7 9 35 35 35 43 At December 31, 2019 , Preferred Share dividends payable were nil (December 31, 2018 – nil ). Holders of the Cumulative Redeemable Preferred Shares, Series 1 (the ”Series 1 Preferred Shares”) are entitled to receive a cumulative quarterly fixed dividend yielding 2.404% annually for a five year period ending March 31, 2021, as and when declared by the Company’s Board of Directors. Thereafter, the dividend rate will be reset every five years at a rate equal to the five -year Government of Canada bond yield plus 1.73% . Holders of Series 1 Preferred Shares have the right, at their option, to convert their shares into Cumulative Redeemable Preferred Shares, Series 2 (the “Series 2 Preferred Shares”), subject to certain conditions, on March 31, 2021 and on March 31 every five years thereafter. Holders of the Series 2 Preferred Shares are entitled to receive a cumulative quarterly floating rate dividend that is reset every quarter for a five year period ending March 31, 2021, as and when declared by the Company’s Board of Directors. The dividend rate applicable to the Series 2 Preferred Shares, for the three month period commencing September 30, 2019 but excluding December 31, 2019 , was 3.368% based on the sum of the Government of Canada 90 day Treasury bill rate on August 20, 2019 plus 1.73% . Holders of Series 2 Preferred Shares have the right, at their option, to convert their shares into Series 1 Preferred Shares, subject to certain conditions, on March 31, 2021 and on March 31 every five years thereafter. Holders of the Cumulative Redeemable Preferred Shares, Series 3 (the ”Series 3 Preferred Shares”) are entitled to receive a cumulative quarterly fixed dividend yielding 4.689% annually for the initial period ending December 31, 2024 as and when declared by the Company’s Board of Directors. Thereafter, the dividend rate will be reset every five years at the rate equal to the five -year Government of Canada bond yield plus 3.13% . Holders of Series 3 Preferred Shares will have the right, at their option, to convert their shares into Cumulative Redeemable Preferred Shares, Series 4 (the ”Series 4 Preferred Shares”), subject to certain conditions, on December 31, 2024 and on December 31 every five years thereafter. Holders of the Series 4 Preferred Shares will be entitled to receive cumulative quarterly floating dividends at a rate equal to the 90-day Government of Canada Treasury Bill yield plus 3.13% . Holders of the Cumulative Redeemable Preferred Shares, Series 5 (the ”Series 5 Preferred Shares”) are entitled to receive a cumulative quarterly fixed dividend yielding 4.50% annually for the initial period ending March 31, 2020 as declared by the Board of Directors. Thereafter, the dividend rate will be reset every 5 years at the rate equal to the five -year Government of Canada bond yield plus 3.57% . Holders of Series 5 Preferred Shares will have the right, at their option, to convert their shares into Cumulative Redeemable Preferred Shares, Series 6 (the ”Series 6 Preferred Shares”), subject to certain conditions, on March 31, 2020 and on March 31 every five years thereafter. Holders of the Series 6 Preferred Shares will be entitled to receive cumulative quarterly floating dividends at a rate equal to the 90-day Government of Canada Treasury Bill yield plus 3.57% . Holders of the Cumulative Redeemable Preferred Shares, Series 7 (the ”Series 7 Preferred Shares”) are entitled to receive a cumulative fixed dividend yielding 4.60% annually for the initial period ending June 30, 2020 as declared by the Board of Directors. Thereafter, the dividend rate will be reset every 5 years at the rate equal to the five -year Government of Canada bond yield plus 3.52% . Holders of the Series 7 Preferred Shares will have the right, at their option, to convert their shares into Cumulative Redeemable Preferred Shares, Series 8 (the ”Series 8 Preferred Shares”), subject to certain conditions, on June 30, 2020 and on June 30 every 5 years thereafter. Holders of the Series 8 Preferred Shares will be entitled to receive cumulative quarterly floating dividends at a rate equal to the 90-day Government of Canada Treasury Bill yield plus 3.52% . Stock Option Plan Pursuant to the Incentive Stock Option Plan (the “Option Plan”), the Company may grant from time to time to executive officers and certain employees of the Company options to purchase common shares of the Company. The term of each option is five years, and vests one-third on each of the first three anniversary dates from the grant date. The Option Plan provides the option holder with the right to exercise the option to acquire one common share at the exercise price or surrender the option for a cash payment. The exercise price of the option is equal to the weighted average trading price of the Company’s common shares during the five trading days prior to the grant date. When the stock option is surrendered to the Company, the cash payment is equal to the excess of the aggregate fair market value of the common shares able to be purchased pursuant to the vested and exercisable portion of such stock options on the date of surrender over the aggregate exercise price for those common shares pursuant to those stock options. The fair market value of common shares is calculated as the closing price of the common shares on the date on which board lots of common shares have traded immediately preceding the date a holder of the stock options provides notice to the Company that they wish to surrender their stock options to the Company in lieu of exercise. Included in accounts payable and accrued liabilities and other long-term liabilities in the consolidated balance sheets at December 31, 2019 was $4 million ( December 31, 2018 – $11 million ) representing the estimated fair value of options outstanding. The total recovery recognized in selling, general and administrative expenses in the consolidated statements of income (loss) for the Option Plan for the year ended December 31, 2019 was $6 million (December 31, 2018 – recovery of $3 million ). At December 31, 2019 , the intrinsic value of stock options exercisable for cash was less than one million ( December 31, 2018 – nil ). The following options to purchase common shares have been awarded to officers and certain other employees: Outstanding and Exercisable Options 2019 2018 Number of Options (thousands) Weighted Average ($) Number of Options (thousands) Weighted Average ($) Outstanding, beginning of year 19,967 21.48 22,645 23.96 Granted (1) 4,241 14.31 5,610 17.21 Exercised for common shares — — (2 ) 15.67 Surrendered for cash (4 ) 15.67 (1,772 ) 15.82 Expired or forfeited (5,706 ) 28.27 (6,514 ) 27.69 Outstanding, end of year 18,498 17.75 19,967 21.48 Exercisable, end of year 10,596 19.27 10,461 25.87 (1) Options granted during the year ended December 31, 2019 were attributed a fair value of $2.34 per option (December 31, 2018 – $2.90 ) at grant date. Outstanding and Exercisable Options Outstanding Options Exercisable Options Range of Exercise Price Number of Options (thousands) Weighted Average Exercise Prices ($) Weighted Average (years) Number of Options (thousands) Weighted Average Exercise Prices ($) $9.28 - $16.31 10,341 15.34 2.65 5,350 15.86 $16.32 - $25.41 8,157 20.80 1.86 5,246 22.75 December 31, 2019 18,498 17.75 2.30 10,596 19.27 The fair value of the share options is estimated at each reporting date using the Black-Scholes option pricing model, taking into account the terms and conditions upon which the share options are granted and for the performance options, the current likelihood of achieving the specified target. The following table lists the assumptions used in the Black-Scholes option pricing model for the share options and performance options: Black-Scholes Assumptions December 31, 2019 December 31, 2018 Tandem Options Tandem Options Dividend per option 0.42 0.56 Range of expected volatilities used (percent) 27.5 - 35.5 16.8 - 44.4 Range of risk-free interest rates used (percent) 1.66 - 1.74 1.6 - 1.9 Expected life of share options from vesting date (years) 1.97 1.95 Expected forfeiture rate (percent) 8.8 8.9 Weighted average exercise price 18.19 22.46 Weighted average fair value 0.25 0.65 The expected life of the share options is based on historical data and current expectations and is not necessarily indicative of exercise patterns that may occur. The expected volatility reflects the assumption that the historical volatility over a period similar to the expected life of the options is indicative of future trends, which may also not necessarily be the actual outcome. Performance Share Units The Company has a Performance Share Unit Plan for executive officers and certain employees of the Company. The term of each PSU is three years, and the PSU vests on the second and third anniversary dates of the grant date in percentages determined by the Compensation Committee based on the Company’s total shareholder return relative to a peer group of companies and achieving a ROCIU target set by the Company. ROCIU equals net earnings (loss) plus after tax interest expense divided by the two-year average capital employed, less any capital invested in assets that are not in use. Net earnings (loss) is adjusted for the difference between actual realized and budgeted commodity prices and foreign exchange rates and other actual and budgeted exceptional items. Upon vesting, PSU holders receive a cash payment equal to the number of vested PSUs multiplied by the weighted average trading price of the Company’s common shares for the five preceding trading days. As at December 31, 2019 , the carrying amount of the liability relating to PSUs was $34 million ( December 31, 2018 – $63 million ). The total expense recognized in selling, general and administrative expenses in the consolidated statements of income (loss) for the PSUs for the year ended December 31, 2019 was $4 million ( 2018 – $47 million ). The Company paid out $34 million ( 2018 – $24 million ) for performance share units which vested in the year. The weighted average contractual life of the PSUs at December 31, 2019 was two years ( December 31, 2018 – two years). The number of PSUs outstanding was as follows: Performance Share Units 2019 2018 Beginning of year 11,606,644 8,361,918 Granted 7,673,960 6,108,430 Exercised (2,429,816 ) (1,354,316 ) Forfeited (2,532,146 ) (1,509,388 ) Outstanding, end of year 14,318,642 11,606,644 Vested, end of year 3,264,840 4,487,585 Earnings (loss) per Share Earnings (loss) per Share ($ millions) 2019 2018 Net earnings (loss) (1,370 ) 1,457 Effect of dividends declared on preferred shares in the year (35 ) (35 ) Net earnings (loss) – basic (1,405 ) 1,422 Dilutive effect of accounting for stock options (1) (15 ) (13 ) Net earnings (loss) – diluted (1,420 ) 1,409 (millions) Weighted average common shares outstanding – basic 1,005.1 1,005.1 Effect of stock dividends declared in the year — 1.0 Weighted average common shares outstanding – diluted 1,005.1 1,006.1 Earnings (loss) per share – basic ($/share) (1.40 ) 1.41 Earnings (loss) per share – diluted ($/share) (1.41 ) 1.40 (1) For the year ended December 31, 2019 , equity-settlement of stock options was used to calculate diluted earnings (loss) per share as it was considered more dilutive than cash-settlement (December 31, 2018 – equity-settlement method was used). Stock-based compensation recovery was $6 million based on cash-settlement for the year ended December 31, 2019 ( 2018 – recovery of $3 million). Stock-based compensation expense would have been $9 million based on equity-settlement for the year ended December 31, 2019 ( 2018 – $10 million). For the year ended December 31, 2019 , 18 million tandem options ( 2018 – 13 million ) were excluded from the calculation of diluted earnings (loss) per share as these options were anti-dilutive.

Production, Operating and Trans

Production, Operating and Transportation and Selling, General, and Administrative Expenses	12 Months Ended
	Dec. 31, 2019
Analysis of income and expense [abstract]
Production, Operating and Transportation and Selling, General and Administrative Expenses	Production, Operating and Transportation and Selling, General and Administrative Expenses The following table summarizes production, operating and transportation expenses in the consolidated statements of income (loss) for the years ended December 31, 2019 and 2018 : Production, Operating and Transportation Expenses ($ millions) 2019 2018 Services and support costs 1,255 1,039 Salaries and benefits 773 762 Materials, equipment rentals and leases 250 243 Energy and utility 482 405 Licensing fees 204 191 Transportation 17 24 Other 36 139 Total production, operating and transportation expenses 3,017 2,803 The following table summarizes selling, general and administrative expenses in the consolidated statements of income (loss) for the years ended December 31, 2019 and 2018 : Selling, General and Administrative Expenses ($ millions) 2019 2018 Employee costs (1) 450 332 Stock-based compensation expense (recovery) (2) (2 ) 44 Contract services 133 104 Equipment rentals and leases 11 39 Maintenance and other 101 135 Total selling, general and administrative expenses 693 654 (1) Employee costs are comprised of salary and benefits earned during the year, plus cash bonuses awarded during the year. Annual bonus awards settled in shares are included in stock-based compensation expense. (2) Stock-based compensation expense represents the cost to the Company for participation in share-based payment plans.

Financial Items

Financial Items	12 Months Ended
	Dec. 31, 2019
Disclosure of additional information [Abstract]
Financial Items	Financial Items Financial Items ($ millions) 2019 2018 Foreign exchange gain (loss) Non-cash working capital 17 (3 ) Other foreign exchange 27 17 Net foreign exchange gain 44 14 Finance income 74 64 Finance expenses Long-term debt (310 ) (320 ) Lease liabilities (1) (note 10) (106 ) — Other (6 ) (5 ) (422 ) (325 ) Interest capitalized (2) 177 108 (245 ) (217 ) Accretion of asset retirement obligations (note 17) (106 ) (97 ) Finance expenses (351 ) (314 ) Total Financial Items (233 ) (236 ) (1) Includes $5 million of interest allocated to the carrying amount of assets in Oil and Gas Properties. (2) Interest capitalized on project costs is calculated using the Company’s annualized effective interest rate of 5 % ( 2018 – 5 %).

Pensions and Other Post-employm

Pensions and Other Post-employment Benefits	12 Months Ended
	Dec. 31, 2019
Disclosure of employee benefits [Abstract]
Pensions and Other Post-employment Benefits	Pensions and Other Post-employment Benefits The Company currently provides defined contribution pension plans for all qualified employees and other post-employment benefit plans to its retirees. The other post-employment benefit plans provide certain retired employees with health care and dental benefits. The Company also maintains one defined benefit pension plan, which is closed to new entrants. The defined benefit pension plan provides pension benefits to certain employees based on years of service and final average earnings. The amount and timing of funding of this plan is subject to the funding policy as approved by the Board of Directors. The measurement date of all plan assets and the accrued benefit obligations was December 31, 2019 . The Company is required to file an actuarial valuation of its defined benefit pension with the provincial or state regulator at least every three years. The most recent actuarial valuation was December 31, 2018 for the U.S defined benefit plan. The most recent actuarial valuation was April 30, 2018 for the Canadian Other Post-employment benefit plan. The most recent actuarial valuation of the U.S. Other Post-employment benefit plan was January 18, 2019 . Defined Contribution Pension Plan During the year ended December 31, 2019 , the Company recognized a $59 million expense ( 2018 – $54 million ) for the defined contribution and U.S. 401(k) plans in net earnings (loss). Defined Benefit Pension Plans (“DB Pension Plan”) and Other Post-employment Benefit Plans (“OPEB Plans”) Defined Benefit Obligations DB Pension Plans OPEB Plans ($ millions) 2019 2018 2019 2018 Beginning of year 79 76 199 244 Current service cost — 1 10 11 Interest cost 2 3 7 8 Benefits paid (3 ) (2 ) (4 ) (4 ) Past service cost 3 — (29 ) — Settlements (49 ) — — — Remeasurements Actuarial (gain) loss – experience — 2 (1 ) (13 ) Actuarial (gain) loss – financial assumptions 9 (4 ) 20 (45 ) Effect of changes in foreign exchange rates (2 ) 3 (1 ) (2 ) End of year 39 79 201 199 Fair Value of Plan Assets DB Pension Plans OPEB Plans ($ millions) 2019 2018 2019 2018 Beginning of year 71 67 — — Contributions by employer (1 ) 1 2 2 Benefits paid (3 ) (2 ) (2 ) (2 ) Interest income 2 2 — — Return on plan assets greater than discount rate 16 — — — Settlements (52 ) — — — Effect of changes in foreign exchange rates (2 ) 3 — — End of year 31 71 — — Funded status DB Pension Plans OPEB Plans ($ millions) 2019 2018 2019 2018 Net asset (liability) (8 ) (8 ) (201 ) (199 ) The Company has accrued the total net liability for the DB Pension Plan and the OPEB Plans in the consolidated balance sheets in other long-term liabilities. On July 25, 2019, the Company completed the transaction related to the Canadian DB Pension Plan initiated on July 25, 2017. The transaction settled the remaining service costs for active plan members, thereby settling the defined benefit obligation related to active plan members. This resulted in the Company recognizing a $5 million actuarial gain (net of tax of $1 million ) in other comprehensive income (loss) in 2019. The composition of the DB Pension Plan assets at December 31, 2019 and 2018 was as follows: DB Pension Plan Assets (percent) Target allocation range 2019 2018 Money market type funds — — 5 Equity securities 35 35 — Debt securities 65 65 95 The following table summarizes amounts recognized in net earnings (loss) and OCI for the DB Pension Plans and the OPEB Plans for the years ended December 31, 2019 and 2018 : DB Pension Plans OPEB Plans ($ millions) 2019 2018 2019 2018 Amounts recognized in net earnings (loss) Current service cost — 1 10 11 Past service cost 3 — (29 ) — Net Interest cost — 1 7 8 Benefit cost 3 2 (12 ) 19 Remeasurements Actuarial loss (gain) due to liability experience — 2 (1 ) (13 ) Actuarial loss (gain) due to liability assumption changes 9 (4 ) 20 (45 ) (Gain) loss on plan assets (16 ) — — — Remeasurement effects recognized in OCI (7 ) (2 ) 19 (58 ) The following long-term assumptions were used to estimate the value of the defined benefit obligations, the plan assets and the OPEB Plans: Assumptions DB Pension Plans OPEB Plans (percent) 2019 2018 2019 2018 Discount rate for benefit expense and obligation 2.3 - 4.2 3.4 - 3.6 3.0 - 3.7 3.4 - 3.7 Rate of compensation expense 3.5 N/A N/A N/A The average health care cost trend rate used for the benefit expense for the Canadian OPEB Plan was 6.0% for 2018, 2019 and 2020 , grading 0.5% per year for 2 years to 5.0% in 2022 and thereafter. The average health care cost trend rate used for the obligation related to the Canadian OPEB Plan was 6.0% for 2018, 2019 and 2020 , grading 0.5% per year for 2 years to 5.0% in 2022 and thereafter. The average health care cost trend rate used for the benefit expense for the U.S. OPEB Plan was 6.0% for 2018 , grading 0.25% per year for 5 years to 5.0% per year in 2022 and thereafter. The average health care cost trend rate used for the obligation related to the U.S. OPEB Plan was 6.5% for 2019 and 2020 , grading 0.25% per year for 6 years to 5.0% in 2026 and thereafter. The sensitivity of the defined benefit and OPEB obligations to changes in relevant actuarial assumption is shown below: Sensitivity Analysis DB Pension Plans OPEB Plans ($ millions) 1% increase 1% decrease 1% increase 1% decrease Discount rate (4 ) 5 (23 ) 28 Health care cost trend rate N/A N/A (16 ) 18

Cash Flows - Change in Non-cash

Cash Flows - Change in Non-cash Working Capital	12 Months Ended
	Dec. 31, 2019
Disclosure of cash flow statement [Abstract]
Cash Flows - Change in Non-cash Working Capital	Cash Flows – Change in Non-cash Working Capital Non-cash Working Capital ($ millions) 2019 2018 Decrease (increase) in non-cash working capital Accounts receivable (176 ) 127 Inventories (502 ) 393 Prepaid expenses (30 ) 30 Accounts payable and accrued liabilities 604 (65 ) Change in non-cash working capital (104 ) 485 Relating to: Operating activities (280 ) 130 Financing activities 3 120 Investing activities 173 235

Financial Instruments and Risk

Financial Instruments and Risk Management	12 Months Ended
	Dec. 31, 2019
Disclosure of detailed information about financial instruments [abstract]
Financial Instruments and Risk Management	Financial Instruments and Risk Management Financial Instruments The Company’s financial instruments include cash and cash equivalents, accounts receivable, restricted cash, accounts payable and accrued liabilities, short-term debt, long-term debt, derivatives , portions of other assets, lease liabilities and other long-term liabilities. Derivative instruments are measured at fair value through profit or loss (”FVTPL”). The Company’s remaining financial instruments are measured at amortized cost. For financial instruments measured at amortized cost, the carrying values approximate their fair value with the exception of long-term debt. The following table summarizes the Company’s financial instruments that are carried at fair value in the consolidated balance sheets: Financial Instruments at Fair Value ($ millions) December 31, 2019 December 31, 2018 Commodity contracts – fair value through profit or loss (“FVTPL”) Natural gas (1) 31 (9 ) Crude oil (2) 11 89 Crude oil call options (3) (2 ) — Crude oil put options (3) (4 ) — Foreign currency contracts – FVTPL Foreign currency forwards 2 (1 ) Other assets – FVTPL 1 1 End of year 39 80 (1) Natural gas contracts includes a $4 million decrease at December 31, 2019 ( December 31, 2018 – $10 million decrease ) to the fair value of held-for-trading inventory, recognized in the consolidated balance sheets, related to third party physical purchase and sale contracts for natural gas held in storage. Total fair value of the related natural gas storage inventory was $19 million at December 31, 2019 ( December 31, 2018 – $15 million ). (2) Crude oil contracts includes a $12 million increase at December 31, 2019 ( December 31, 2018 – $67 million increase ) to the fair value of held-for-trading inventory, recognized in the consolidated balance sheets, related to third party crude oil physical purchase and sale contracts. Total fair value of the related crude oil inventory was $136 million at December 31, 2019 ( December 31, 2018 – $185 million ). (3) Excludes net unsettled premiums of $6 million . The fair value of long-term debt represents the present value of future cash flows associated with the debt. Market information, such as treasury rates and credit spreads, are used to determine the appropriate discount rates. These fair value determinations are compared to quotes received from financial institutions to ensure reasonability. At December 31, 2019 , the carrying value of the Company’s long-term debt was $5.0 billion and the estimated fair value was $5.3 billion ( December 31, 2018 – carrying value of $5.5 billion , estimated fair value of $5.7 billion ). All financial assets and liabilities are classified as Level 2 fair value measurements, except commodity put and call options under a short-term hedging program, which are classified as Level 1 fair value measurements as they are determined using quoted market prices. During the year ended December 31, 2019, there were no transfers between Level 1 and Level 2 fair value measurements, and no transfers into or out of Level 3 fair value measurements. Risk Management Overview The Company is exposed to risks related to the volatility of commodity prices, foreign exchange rates and interest rates. It is also exposed to financial risks related to liquidity, credit and contract risks. Risk management strategies and policies are employed to ensure that any exposures to risk are in compliance with the Company’s business objectives and risk tolerance levels. Responsibility for the oversight of risk management is held by the Company’s Board of Directors and is implemented and monitored by senior management within the Company. a) Market Risk i) Commodity Price Risk Management The Company uses derivative commodity instruments from time to time to manage exposure to price volatility on a portion of its crude oil and natural gas production, and it also uses firm commitments for the purchase or sale of crude oil and natural gas. These contracts meet the definition of a derivative instrument and have been recorded at their fair value in accounts receivable, inventory, other assets, accounts payable and accrued liabilities and other long-term liabilities. All derivatives are measured at fair value through profit or loss other than non-financial derivative contracts that meet the Company’s own use requirements. At December 30, 2019, the Company was party to crude oil purchase and sale derivative contracts to mitigate its exposure to fluctuations in the benchmark price between the time a sales agreement is entered into and the time inventory is delivered. The Company was also party to third party physical natural gas purchase and sale derivative contracts in order to mitigate commodity price fluctuations. For the year ended December 31, 2019, the net unrealized loss recognized on the derivative contracts was $38 million (2018 – net unrealized gain of $150 million ). During the year ended December 31, 2019, the Company entered into a commodity short-term hedging program using put and call options to manage risks related to volatility of commodity prices. Western Texas Intermediate Crude Oil Call and Put Option Contracts (1) Type Transaction Term Volume (bbls/day) Call Price (US$bbl) Put Price (US$bbl) Call options Sold January - March 2020 35,714 60.50 — Put options Bought January - March 2020 36,263 — 55.61 Put options Sold January - March 2020 20,055 — 50.77 (1) Prices reported are the weighted average prices for the period. For the year ended December 31, 2019, the Company incurred an unrealized loss of $6 million (December 31, 2018 – nil ). For the year ended December 31, 2019, the Company incurred a realized gain of $16 million (December 31, 2018 – nil ).These amounts are recorded in other – net in the consolidated statements of income (loss). II) Foreign Exchange Risk Management The Company’s results are affected by the exchange rates between various currencies and the Company’s functional currency in Canadian dollars. As the majority of the Company’s revenues are denominated in U.S. dollars or based upon a U.S. benchmark price, fluctuations in the value of the Canadian dollar relative to the U.S. dollar may affect revenues significantly. To limit the exposure to foreign exchange risk, the Company hedges against these fluctuations by entering into short-dated foreign exchange contracts to fix the exchange rate for conversion of U.S. revenue dollars. Foreign exchange fluctuations will result in a change in value of the U.S. dollar denominated debt and related finance expense when expressed in Canadian dollars. At December 31, 2019 , the Company had designated US $2.4 billion denominated debt as a hedge of the Company’s selected net investments in its foreign operations with a U.S. dollar functional currency ( December 31, 2018 – US $2.7 billion ). For the year ended December 31, 2019 , the unrealized gain arising from the translation of the debt was $146 million ( December 31, 2018 – unrealized loss of $262 million ), net of tax expense of $30 million ( December 31, 2018 – recovery of $41 million ), which was recorded in hedge of net investment within OCI . I) Interest Rate Risk Management The Company is exposed to fluctuations in short-term interest rates as the Company maintains a portion of its debt capacity in revolving and floating rate bank facilities and commercial paper and invests surplus cash in short-term debt instruments and money market instruments. The Company is also exposed to interest rate risk when fixed rate debt instruments are maturing and require refinancing or when new debt capital needs to be raised. By maintaining a mix of both fixed and floating rate debt, the Company mitigates some of its exposure to interest rate changes. The optimal mix maintained will depend on market conditions. The Company may also enter into fair value or cash flow hedges using interest rate swaps. III) Offsetting Financial Assets and Liabilities The tables below outline the financial assets and financial liabilities that are subject to set-off rights and related arrangements, and the effect of those rights and arrangements on the consolidated balance sheets: As at December 31, 2019 Offsetting Financial Assets and Liabilities ($ millions) Gross Amount Amount Offset Net Amount Financial Assets Financial derivatives 79 (26 ) 53 Normal purchase and sale agreements 817 (274 ) 543 End of year 896 (300 ) 596 Financial Liabilities Financial derivatives (48 ) 25 (23 ) Normal purchase and sale agreements (843 ) 281 (562 ) End of year (891 ) 306 (585 ) As at December 31, 2018 Offsetting Financial Assets and Liabilities ($ millions) Gross Amount Amount Offset Net Amount Financial Assets Financial derivatives 188 (120 ) 68 Normal purchase and sale agreements 625 (335 ) 290 End of year 813 (455 ) 358 Financial Liabilities Financial derivatives (107 ) 62 (45 ) Normal purchase and sale agreements (756 ) 307 (449 ) End of year (863 ) 369 (494 ) IV) Market Risk Sensitivity Analysis A sensitivity analysis for commodities and foreign currency exchange risks has been calculated by increasing or decreasing commodity prices or foreign currency exchange rates, as appropriate. These sensitivities represent the increase or decrease in earnings (loss) before income taxes resulting from changing the relevant rates, with all other variables held constant. These sensitivities have only been applied to financial instruments held at fair value. The Company’s process for determining these sensitivities has not changed during the year. Commodity Price Risk (1) ($ millions) 10% price increase 10% price decrease Crude oil price 13 (13 ) Natural gas price (2 ) 2 Foreign Exchange Rate (2) Canadian dollar Canadian dollar ($ millions) U.S. dollar per Canadian dollar 1 (1 ) (1) Based on average crude oil and natural gas market prices as at December 31, 2019 . (2) Based on the U.S./Canadian dollar exchange rate as at December 31, 2019 . b) Financial Risk i) Liquidity Risk Management Liquidity risk is the risk that the Company will not be able to meet 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. The Company’s processes for managing liquidity risk include ensuring, to the extent possible, that it has access to multiple sources of capital including cash and cash equivalents, cash from operating activities, undrawn credit facilities and capacity to raise capital from various debt and equity capital markets under its shelf prospectuses. The Company prepares annual capital expenditure budgets, which are monitored and updated as required. In addition, the Company requires authorizations for expenditures on projects, which assists with the management of capital. Since the Company operates in the oil and gas industry, it requires significant cash to fund capital programs necessary to maintain or increase production, develop reserves, acquire strategic oil and gas assets and repay maturing debt. The Company’s capital programs are funded principally by cash provided from operating activities and issuances of debt and equity. During times of low oil and gas prices, a portion of capital programs can generally be deferred. However, due to the long cycle times and the importance to future cash flow of maintaining the Company’s production, it may be necessary to utilize alternative sources of capital to continue the Company’s strategic investment plan during periods of low commodity prices. As a result, the Company frequently evaluates the options available with respect to sources of short and long-term capital resources. Occasionally, the Company will economically hedge a portion of its production to protect cash flow in the event of commodity price declines. The Company had the following available credit facilities as at December 31, 2019 : Credit Facilities ($ millions) Available Unused Operating facilities (1) (note 14) 900 464 Syndicated bank facilities (2) (note 16) 4,000 3,450 End of year 4,900 3,914 (1) Consists of demand credit facilities. (2) Commercial paper outstanding is supported by the Company’s Syndicated credit facilities. In addition to the credit facilities listed above, the Company had unused capacity under the Canadian Shelf Prospectus of $3.0 billion and unused capacity under the U.S Shelf Prospectus and related U.S registration statement of US $2.25 billion . The ability of the Company to raise additional capital utilizing these Shelf Prospectuses is dependent on market conditions. The Company believes it has sufficient funding through the use of these facilities and access to the capital markets to meet its future capital requirements. ii) Credit and Contract Risk Management Credit and contract risk represent the financial loss that the Company would suffer if a counterparty in a transaction fails to meet its obligations in accordance with the agreed terms. The Company actively manages its exposure to credit and contract execution risk from both a customer and a supplier perspective. The Company’s accounts receivables are broad based with customers in the energy industry and midstream and end user segments and are subject to normal industry risks. The Company’s policy to mitigate credit risk includes granting credit limits consistent with the financial strength of the counterparties and customers, requiring financial assurances as deemed necessary, reducing the amount and duration of credit exposures and close monitoring of all accounts. The Company had one external customer that constituted more than 10% of gross revenues during the years ended December 31, 2019 and December 31, 2018 . Sales to this customer were approximately $3.9 billion for the year ended December 31, 2019 ( December 31, 2018 – $4.2 billion ). Cash and cash equivalents include cash bank balances and short-term deposits maturing in less than three months. The Company manages the credit exposure related to short-term investments by monitoring exposures daily on a per issuer basis relative to predefined investment limits. The carrying amounts of cash and cash equivalents, accounts receivable and restricted cash represent the Company’s maximum credit exposure. The Company’s accounts receivable was aged as follows at December 31, 2019 : Accounts Receivable Aging ($ millions) December 31, 2019 Current 1,418 Past due (1 - 30 days) 64 Past due (31 - 60 days) 4 Past due (61 - 90 days) — Past due (more than 90 days) 47 Provision for expected credit losses (34 ) 1,499 The Company recognizes a valuation provision when collection of accounts receivable is in doubt. Accounts receivable are impaired directly when collection is no longer expected. For the year ended December 31, 2019 , the Company wrote off $4 million ( December 31, 2018 – $3 million ) of uncollectible receivables.

Related Party Transactions

Related Party Transactions	12 Months Ended
	Dec. 31, 2019
Disclosure of related party [Abstract]
Related Party Transactions	Related Party Transactions The following table lists the Company’s significant subsidiaries and jointly-controlled entities and their respective places of incorporation, continuance or organization, as the case may be, and the Company’s percentage equity interest (to the nearest whole number) as at December 31, 2019. All of the entities listed below, except as otherwise indicated, are 100% beneficially owned, or controlled or directed, directly or indirectly, by the Company. Significant Subsidiaries and Joint Operations % Jurisdiction Husky Oil Operations Limited 100 Alberta Husky Energy International Corporation 100 Alberta Lima Refining Company 100 Delaware Husky Marketing and Supply Company 100 Delaware Husky Oil Limited Partnership 100 Alberta Husky Terra Nova Partnership (1) 100 Alberta Husky Downstream General Partnership (1) 100 Alberta Husky Energy Marketing Partnership 100 Alberta Sunrise Oil Sands Partnership 50 Alberta BP-Husky Refining LLC 50 Delaware (1) Dissolved effective January 1, 2020, assets were transferred to 2188787 Alberta ULC. The Company performs management services as the operator of the assets held by HMLP for which it recovers shared service costs. The Company is also the contractor for HMLP and constructs its assets on a cost recovery basis with certain restrictions. HMLP charges an access fee to the Company for the use of its pipeline systems in performing the Company’s blending business, and the Company also pays for transportation and storage services. These transactions are related party transactions, as the Company has a 35% ownership interest in HMLP and the remaining ownership interests in HMLP belong to PAH and CKI, which are affiliates of one of the Company’s principal shareholders. For the year ended December 31, 2019 , the Company charged HMLP $424 million (December 31, 2018 – $448 million ) related to construction costs and management services. For the year ended December 31, 2019 , the Company had purchases from HMLP of $219 million (December 31, 2018 – $200 million ) related to the use of the pipeline for the Company’s blending activities, transportation and storage activities, received distributions of $94 million (December 31, 2018 – $139 million ) and paid capital contributions of $37 million (December 31, 2018 – $40 million ). At December 31, 2019 , the Company had $143 million due from HMLP, of which nil relates to unbilled revenue from construction contracts (December 31, 2018 – $140 million and nil , respectively). At December 31, 2019, the Company had $16 million due to HMLP (December 31, 2018 – nil ). Key management includes Directors (executive and non-executive), Executive Officers and Senior Vice Presidents of the Company. The amounts disclosed in the table below are the amounts recognized as an expense during the reporting period related to key management personnel: Compensation of Key Management Personnel ($ millions) 2019 2018 Short-term employee benefits (1) 18 17 Stock-based compensation (2) 26 33 44 50 (1) Short-term employee benefits are comprised of salary and benefits earned during the year, plus cash bonuses awarded during the year. Annual bonus awards settled in shares are included in stock-based compensation expense. (2) Stock-based compensation expense represents the cost to the Company for participation in share-based payment plans.

Commitments and Contingencies

Commitments and Contingencies	12 Months Ended
	Dec. 31, 2019
Commitments and Contingencies [Abstract]
Commitments and Contingencies	Commitments and Contingencies At December 31, 2019 , the Company had commitments that require the following minimum future payments, which are not accrued in the consolidated balance sheets: Minimum Future Payments for Commitments ($ millions) Within 1 year After 1 year but not more than 5 years More than 5 years Total Operating agreements (1) 75 310 666 1,051 Firm transportation agreements (1) 576 2,377 4,203 7,156 Unconditional purchase obligations (2) 2,224 5,517 5,143 12,884 Lease rentals and exploration work agreements 79 215 866 1,160 Obligations to fund equity investee (3) 54 290 359 703 3,008 8,709 11,237 22,954 (1) Included in operating agreements and firm transportation agreements are blending and storage agreements and transportation commitments of $1.1 billion and $1.8 billion respectively with HMLP. (2) Includes processing services, distribution services, insurance premiums, drilling services, natural gas purchases and the purchase of refined petroleum products. (3) Equity investee refers to the Company’s investment in Husky-CNOOC Madura Ltd. joint venture, which is accounted for under the equity method for consolidated financial statement purposes. During the three months ended December 31, 2019, the Company entered into an agreement totaling an incremental $2.2 billion for a term of 5 years to purchase refined products to support the retail network. The Company has income tax and royalty filings that are subject to audit and potential reassessment. The findings may impact the liabilities of the Company. The final results are not reasonably determinable at this time, and management believes that it has adequately provided for current and deferred income taxes. The Company is involved in various claims and litigation arising in the normal course of business. While the outcome of these matters is uncertain and there can be no assurance that such matters will be resolved in the Company’s favour, the Company does not currently believe that the outcome of adverse decisions in any pending or threatened proceedings related to these and other matters would have a material adverse impact on its financial position, results of operations or liquidity.

Capital Disclosures

Capital Disclosures	12 Months Ended
	Dec. 31, 2019
Disclosure of additional information [Abstract]
Capital Disclosures	Capital Disclosures The Company’s objectives when managing capital are to maintain a flexible capital structure, which optimizes the cost of capital at acceptable risk, and to maintain investor, creditor and market confidence to sustain the future development of the business. The Company manages its capital structure and makes adjustments as economic conditions and the risk characteristics of its underlying assets change. The Company considers its capital structure to include shareholders’ equity and debt which was $22.8 billion as at December 31, 2019 ( December 31, 2018 – $25.4 billion ). To maintain or adjust the capital structure, the Company may, from time to time, issue shares, raise debt and/or adjust its capital spending to manage its current and projected debt levels. The Company monitors its its financing requirements and capital structure using, among other things, non-GAAP financial metrics consisting of debt to capital employed and debt to funds from operations. Debt to capital employed is defined as long-term debt, long-term debt due within one year, and short-term debt divided by capital employed which is equal to long-term debt, long-term debt due within one year, short-term debt and shareholders’ equity. Debt to funds from operations is defined as long-term debt, long-term debt due within one year and short-term debt divided by funds from operations which is equal to cash flow – operating activities excluding change in non-cash working capital . At December 31, 2019 , debt to capital employed was 24.2% ( December 31, 2018 – 22.7% ) and debt to funds from operations was 1.7 times ( December 31, 2018 – 1.4 times). The Company is subject to a leverage covenant in its credit facilities that limits debt to capital (subject to specific definitions in the credit agreements) to less than 65%. The Company is in compliance with this covenant and considers the risk of non-compliance low. The Company also targets a debt to funds from operations ratio of less than 2.0 times over the longer term. To facilitate the management of these ratios, the Company prepares annual budgets, which are updated depending on varying factors such as general market conditions and successful capital deployment. The annual budget is approved by the Board of Directors. There were no changes in the Company’s approach to capital management from the previous year.

Subsequent Events Subsequent Ev

Subsequent Events Subsequent Events	12 Months Ended
	Dec. 31, 2019
Disclosure of events after reporting period [Abstract]
Subsequent Events	Subsequent Event Reclassification of Segmented Financial Information Commencing in the first quarter of 2020, the Company’s segmented financial information will be reported as the Integrated Corridor and Offshore business segments. Integrated Corridor The Company’s business in the Integrated Corridor includes: crude oil, bitumen, conventional natural gas, NGL and ethanol production from Western Canada; marketing and transportation of the Company’s and other producers' production; the Upgrader and Asphalt Refinery; Husky Midstream Limited Partnership (35% working interest and operatorship); the Lima Refinery, the BP-Husky Toledo Refinery (50% working interest) and the Superior Refinery in the U.S. Midwest; and the marketing of refined petroleum products including gasoline, diesel and ethanol blended fuels through petroleum outlets. Conventional natural gas production from the Western Canada portfolio is closely aligned with the Company's energy requirements for refining and thermal bitumen production and acts as a natural hedge. Offshore The Company’s Offshore business includes operations, development and exploration in Asia Pacific and Atlantic. The revised segmentation is consistent with the Company’s strategic view of its business and is in alignment with how the Company’s results are assessed by management. If the reclassification of the segmented financial information were to have occurred in 2019, the 2018 and 2019 segmented financial information would have reflected this change as follows: Segmented Financial Information - Reclassified Integrated Corridor ($ millions) Lloyd Heavy Oil Value Chain Oil Sands Western Canada Production U.S. Refining Canadian Refined Products Year ended December 31, 2019 2018 2019 2018 2019 2018 2019 2018 2019 2018 Gross revenues 5,117 5,308 931 405 506 661 10,250 11,777 2,425 2,752 Royalties (160 ) (137 ) (13 ) (12 ) (41 ) (58 ) — — — — Marketing and other 60 458 4 166 101 86 24 (42 ) — — Revenues, net of royalties 5,017 5,629 922 559 566 689 10,274 11,735 2,425 2,752 Expenses Purchases of crude oil and products 1,829 2,217 528 306 39 140 8,935 10,342 2,174 2,435 Production, operating and transportation expenses 1,209 1,121 140 132 308 302 869 795 153 151 Selling, general and administrative expenses 154 129 27 28 105 106 51 40 9 10 Depletion, depreciation, amortization and impairment 941 887 938 95 1,034 292 735 450 83 80 Exploration and evaluation expenses 54 32 2 18 111 28 — — — — Loss (gain) on sale of assets — (1 ) — — (2 ) (1 ) 1 — (6 ) (2 ) Other – net 103 (106 ) (28 ) — 2 5 (654 ) (464 ) — (1 ) 4,290 4,279 1,607 579 1,597 872 9,937 11,163 2,413 2,673 Earnings (loss) from operating activities 727 1,350 (685 ) (20 ) (1,031 ) (183 ) 337 572 12 79 Share of equity investment income 9 18 — — — — — — — — Financial items Net foreign exchange gain (loss) — — — — — — — — — — Finance income — — — — — — — — — — Finance expenses (48 ) (43 ) (59 ) (21 ) (24 ) (19 ) (18 ) (14 ) (13 ) (11 ) (48 ) (43 ) (59 ) (21 ) (24 ) (19 ) (18 ) (14 ) (13 ) (11 ) Earnings (loss) before income taxes 688 1,325 (744 ) (41 ) (1,055 ) (202 ) 319 558 (1 ) 68 Provisions for (recovery of) income taxes Current (2 ) (3 ) 10 — — — 17 9 — — Deferred 186 365 (209 ) (11 ) (283 ) (55 ) 54 115 — 19 184 362 (199 ) (11 ) (283 ) (55 ) 71 124 — 19 Net earnings (loss) 504 963 (545 ) (30 ) (772 ) (147 ) 248 434 (1 ) 49 Intersegment revenues 452 693 — — 205 233 3 5 4 6 Expenditures on exploration and evaluation assets (1) 17 18 — — 3 99 — — — — Expenditures on property, plant and equipment (1) 939 1,070 38 51 191 322 768 666 73 40 As at December 31, Total assets 8,312 7,707 2,757 3,237 1,709 2,534 8,645 8,558 838 917 (1) Excludes capitalized costs related to asset retirement obligations and capitalized interest incurred during the year. Includes Exploration and Production assets acquired through acquisition, but excludes assets acquired through corporate acquisition. Segmented Financial Information - Reclassified Con't Integrated Corridor Offshore Corporate Total Eliminations Total 2019 2018 2019 2018 2019 2018 2019 2018 2019 2018 (664 ) (937 ) 18,565 19,966 1,552 1,953 — — 20,117 21,919 — — (214 ) (207 ) (109 ) (128 ) — — (323 ) (335 ) — — 189 668 — — — — 189 668 (664 ) (937 ) 18,540 20,427 1,443 1,825 — — 19,983 22,252 (664 ) (937 ) 12,841 14,503 (24 ) 52 — — 12,817 14,555 — — 2,679 2,501 340 304 (2 ) (2 ) 3,017 2,803 — — 346 313 55 58 292 283 693 654 — — 3,731 1,804 1,661 695 104 92 5,496 2,591 — — 167 78 380 71 — — 547 149 — — (7 ) (4 ) (1 ) — — — (8 ) (4 ) — — (577 ) (566 ) 9 (19 ) (16 ) (6 ) (584 ) (591 ) (664 ) (937 ) 19,180 18,629 2,420 1,161 378 367 21,978 20,157 — — (640 ) 1,798 (977 ) 664 (378 ) (367 ) (1,995 ) 2,095 — — 9 18 50 51 — — 59 69 — — — — — — 44 14 44 14 — — — — 3 12 71 52 74 64 — — (162 ) (108 ) (38 ) (28 ) (151 ) (178 ) (351 ) (314 ) — — (162 ) (108 ) (35 ) (16 ) (36 ) (112 ) (233 ) (236 ) — — (793 ) 1,708 (962 ) 699 (414 ) (479 ) (2,169 ) 1,928 — — 25 6 125 141 25 (72 ) 175 75 — — (252 ) 433 (393 ) 35 (329 ) (72 ) (974 ) 396 — — (227 ) 439 (268 ) 176 (304 ) (144 ) (799 ) 471 — — (566 ) 1,269 (694 ) 523 (110 ) (335 ) (1,370 ) 1,457 — — 664 937 — — — — 664 937 — — 20 117 26 125 — — 46 242 — — 2,009 2,149 1,246 1,066 131 121 3,386 3,336 — — 22,261 22,953 8,077 8,627 2,784 3,645 33,122 35,225

Significant Accounting Polici_2

Significant Accounting Policies (Policies)	12 Months Ended
	Dec. 31, 2019
Disclosure of changes in accounting policies, accounting estimates and errors [Abstract]
Measurement Bases	Basis of Measurement and Statement of Compliance The consolidated financial statements have been prepared by management on a historical cost basis with some exceptions, as detailed in the accounting policies set out below in accordance with International Financial Reporting Standards (“IFRS”), as issued by the International Accounting Standards Board (“IASB”). These accounting policies have been applied consistently for all periods presented in these consolidated financial statements. These consolidated financial statements were approved by the Board of Directors on February 26, 2020. Certain prior years’ amounts have been reclassified to conform with current presentation.
Principles of Consolidation	Principles of Consolidation The consolidated financial statements include the accounts of Husky Energy Inc. and its subsidiaries. Subsidiaries are defined as any entities, including unincorporated entities such as partnerships, for which the Company has the power to govern their financial and operating policies to obtain benefits from their activities. The Company’s accounts reflect the proportionate share of the assets, liabilities, revenues, expenses and cash flows from the Company’s activities that are conducted jointly with third parties. Intercompany balances, net earnings and unrealized gains and losses arising from intercompany transactions are eliminated in preparing the consolidated financial statements. A portion of the Company’s activities relate to joint ventures (see Note 12), which are accounted for using the equity method.
Use of Estimates, Judgments and Assumptions	Use of Estimates, Judgments and Assumptions The timely preparation of the consolidated financial statements requires management to make estimates, judgments and assumptions that affect the reported amounts of assets and liabilities and disclosures of contingencies, if any, as at the date of the financial statements and the reported amounts of revenue and expenses during the period. Actual results may differ from these estimates, judgments and assumptions. Estimates and underlying assumptions are reviewed on an ongoing basis. Revisions to accounting estimates are recognized in the period in which the estimates are revised and on a prospective basis. By their nature, estimates are subject to measurement uncertainty and changes in such estimates in future years could require a material change in the consolidated financial statements. These underlying assumptions are based on historical experience and other factors that management believes to be reasonable under the circumstances, and are subject to change as new events occur, as more industry experience is acquired, as additional information is obtained, and as the Company’s operating environment changes. Specifically, amounts recorded for depletion, depreciation, amortization and impairment, recoveries from insurance claims, asset retirement obligations, assets and liabilities measured at fair value, employee future benefits, income taxes and reserves and contingencies are based on estimates. Management makes judgments regarding the application of IFRS for each accounting policy. Critical judgments that have the most significant effect on the amounts recognized in the consolidated financial statements include determination of technical feasibility and commercial viability, impairment assessments, the determination of cash generating units (“CGUs”), changes in reserves estimates, the determination of a joint arrangement, the designation of the Company’s functional currency and the fair value of related party transactions. Significant estimates, judgments and assumptions made by management in the preparation of these consolidated financial statements are outlined in detail in Note 3.
Functional and Presentation Currency	Functional and Presentation Currency The consolidated financial statements are presented in Canadian dollars, which is the Company’s functional currency. All financial information is presented in millions of Canadian dollars, except per share amounts and unless otherwise stated. The designation of the Company’s functional currency is a management judgment based on the currency of the primary economic environment in which the Company operates.
Cash and Cash Equivalents	Cash and Cash Equivalents Cash and cash equivalents consist of cash on hand less outstanding cheques and deposits with an original maturity of less than three months at the time of purchase. When outstanding cheques are in excess of cash on hand and short-term deposits, and the Company has the ability to net settle, the excess is reported in bank operating loans. Cash and cash equivalents held that are not available for use are classified as restricted cash. When restricted cash is not expected to be used within 12 months, it is classified as a non-current asset.
Inventories	Inventories Crude oil, natural gas, refined petroleum products and sulphur inventories are valued at the lower of cost or net realizable value. Cost is determined using average cost or on a first-in, first-out basis, as appropriate. Materials, parts and supplies are valued at the lower of average cost or net realizable value. Cost consists of raw material, labour, direct overhead, operating costs, transportation and depreciation, depletion and amortization. Commodity inventories held for trading purposes are carried at fair value and measured at fair value less costs to sell based on Level 2 observable inputs, refer to policy Note 3 (m). Any changes in commodity trading inventory fair value are included as gains or losses in Marketing and Other in the consolidated statements of income (loss) during the period of change. Previous inventory impairment provisions are reversed when there is a change in the condition that caused the impairment and the inventory remains on hand. Unrealized intersegment net earnings on inventory sales are eliminated.
Precious Metals	Precious Metals The Company uses precious metals in conjunction with a catalyst as part of the downstream upgrading and refining processes. These precious metals remain intact; however, there is a loss during the reclamation process. The estimated loss is amortized to production and operating expenses over the period that the precious metal is in use, which is approximately two to five years. After the reclamation process, the actual loss is compared to the estimated loss and any difference is recognized in net earnings (loss). Precious metals are included in other assets on the balance sheet.
Exploration and Evaluation Assets and Property, Plant and Equipment	Exploration and Evaluation Assets and Property, Plant and Equipment i) Cost Oil and gas properties and other property, plant and equipment are recorded at cost, including expenditures that are directly attributable to the purchase or development of an asset. Borrowing costs directly attributable to the acquisition, construction or production of a qualifying asset are included in the asset cost. Capitalization ceases when substantially all activities necessary to prepare the qualifying asset for its intended use are complete. ii) Exploration and Evaluation Costs The accounting treatment of costs incurred for oil and natural gas exploration, evaluation and development is determined by the classification of the underlying activities as either exploratory or developmental. The results from an exploration drilling program can take considerable time to analyze, and the determination that commercial reserves have been discovered requires determination of technical feasibility, commercial viability and industry experience. Exploration activities can fluctuate from year to year, due to such factors as the level of exploratory spending, the level of risk sharing with third parties participating in exploratory drilling and the degree of risk associated with drilling in particular areas. Properties that are assumed to be productive may, over a period of time, actually deliver oil and gas in quantities different than originally estimated because of changes in reservoir performance. Costs incurred after the legal right to explore an area has been obtained and before technical feasibility and commercial viability of the area have been established are capitalized as exploration and evaluation assets. These costs include costs to acquire acreage and exploration rights, legal and other professional fees and land brokerage fees. Pre-license costs and geological and geophysical costs associated with exploration activities are expensed in the period incurred. Costs directly associated with an exploration well are initially capitalized as an exploration and evaluation asset until the drilling of the well is complete and the results have been evaluated. If extractable hydrocarbons are found and are likely to be developed commercially, but are subject to further appraisal activity, which may include the drilling of wells, the costs continue to be carried as an exploration and evaluation asset while sufficient and continued progress is made in assessing the commercial viability of the hydrocarbons. Capitalized exploration and evaluation costs or assets are not depreciated and are carried forward until technical feasibility and commercial viability of the area is determined or the assets are determined to be impaired. Management determines technical feasibility and commercial viability when exploration and evaluation assets are reclassified to property, plant and equipment. This decision considers several factors, including the existence of reserves, establishing commercial and technical feasibility and whether the asset can be developed using a proved development concept and has received internal approval. Upon the determination of technical feasibility and commercial viability, capitalized exploration and evaluation assets are then transferred to property, plant and equipment. All such carried costs are subject to technical, commercial and management review, as well as review for impairment indicators, at least every reporting period to confirm the continued intent to develop or otherwise extract value from the discovery. These costs are also tested for impairment when transferred to property, plant and equipment. Capitalized exploration and evaluation expenditures related to wells that do not find reserves, or where no future activity is planned, are expensed as exploration and evaluation expenses. The application of the Company’s accounting policy for exploration and evaluation costs 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. Judgments may change as new information becomes available. iii) Development Costs Expenditures, including borrowing costs, on the construction, installation and completion of infrastructure facilities, such as platforms, pipelines and the drilling of development wells, are capitalized as oil and gas properties. Costs incurred to operate and maintain wells and equipment to lift oil and gas to the surface are expensed as production and operating expenses. iv) Other Property, Plant and Equipment Repair and maintenance costs, other than major turnaround costs, are expensed as incurred. Major turnaround costs are capitalized as part of property, plant and equipment when incurred and are amortized over the estimated period of time to the anticipated date of the next turnaround. v) Depletion, Depreciation and Amortization Oil and gas properties are depleted on a unit-of-production basis over the proved developed reserves of the particular field, except in the case of assets whose useful life is shorter or longer than the lifetime of the proved developed reserves of that field, in which case the straight-line method or a unit-of-production method based on total proved plus probable reserves is applied. The unit-of-production rate for the depletion of oil and gas properties related to total proved plus probable reserves takes into account expenditures incurred to date together with sanctioned future development expenditures required to develop the field. Oil and gas reserves are evaluated internally and audited by independent qualified reserve engineers. The estimation of reserves is an inherently complex process and involves the exercise of professional judgment. Estimates are based on projected future rates of production, estimated commodity prices, engineering data and the timing of future expenditures, all of which are subject to uncertainty. Changes in reserve estimates can have an impact on reported net earnings (loss) through revisions to depletion, depreciation and amortization expense, in addition to determining possible impairments and reversal of impairments of property, plant and equipment. Net reserves represent the Company’s undivided gross working interest in total reserves after deducting crown, freehold and overriding royalty interests. Assumptions reflect market and regulatory conditions, as applicable, as at the balance sheet date and could differ significantly from other points in time throughout the year or future periods. Changes in market and regulatory conditions and assumptions can materially impact the estimation of net reserves. Depreciation for substantially all other property, plant and equipment is provided using the straight-line method based on the estimated useful lives of assets, which range from five to forty-five years. The useful lives of assets are estimated based upon the period the asset is expected to be available for use by the Company. Depletion, depreciation and amortization rates for all capitalized costs associated with the Company's activities are reviewed at least annually, or when events or conditions occur that impact capitalized costs, reserves and estimated service lives.
Joint Arrangements	Joint Arrangements Joint arrangements represent activities where the Company has joint control established by a contractual agreement. Joint control requires unanimous consent for financial and operational decisions. A joint arrangement is either a joint operation, whereby the parties have rights to the assets and obligations for the liabilities, or a joint venture, whereby the parties have rights to the net assets. For a joint operation, the consolidated financial statements include the Company’s proportionate share of the assets, liabilities, revenues, expenses and cash flows of the joint arrangement. The Company reports items of a similar nature to those on the financial statements of the joint arrangement, on a line-by-line basis, from the date that joint control commences until the date that joint control ceases. Joint ventures are accounted for using the equity method of accounting and recognized at cost and adjusted thereafter for the post-acquisition change in the Company’s share of the joint venture’s net assets. The Company’s consolidated financial statements include its share of the joint venture’s profit or loss and other comprehensive income (“OCI”) included in investment in joint ventures, until the date that joint control ceases. Classification of a joint arrangement as either joint operation or joint venture requires judgment. Management’s considerations include, but are not limited to, determining if the arrangement is structured through a separate vehicle and whether the legal form and contractual arrangements give the entity direct rights to the assets and obligations for the liabilities within the normal course of business. Other facts and circumstances are also assessed by management, including the entity’s rights to the economic benefits of assets and its involvement and responsibility for settling liabilities associated with the arrangement.
Investments in Associates	Investments in Associates An associate is an entity for which the Company has significant influence and thereby has the power to participate in the financial and operational decisions but does not control or jointly control the investee. Investments in associates are accounted for using the equity method of accounting and are recognized at cost and adjusted thereafter for the post-acquisition change in the Company’s share of the investee’s net assets. The Company’s consolidated financial statements include its share of the investee’s profit or loss and OCI until the date that significant influence ceases.
Business Combinations	Business Combinations Business combinations are accounted for using the acquisition method. Determining whether an acquisition meets the definition of a business combination or represents an asset purchase requires judgment on a case-by-case basis. If the acquisition meets the definition of a business combination, the assets and liabilities are recognized based on the contractual terms, economic conditions, the Company’s operating and accounting policies and other factors that exist on the acquisition date, which is the date on which control is transferred to the Company. The identifiable assets and liabilities are measured at their fair values on the acquisition date with limited exceptions. Any additional consideration payable, contingent upon the occurrence of a future event, is recognized at fair value on the acquisition date; subsequent changes in the fair value of the liability are recognized in net earnings (loss). Acquisition costs incurred are expensed and included in selling, general and administrative expenses in the consolidated statements of income (loss).
Goodwill	Goodwill Goodwill is the excess of the purchase price paid over the recognized amount of net assets acquired through business combinations, which is inherently imprecise as judgment is required in the determination of the fair value of assets and liabilities. Goodwill, which is not amortized, is assigned to appropriate CGUs or groups of CGUs. Goodwill is tested for impairment annually and when circumstances indicate that the carrying value may be impaired. Impairment losses are recognized in net earnings (loss) and are not subject to reversal. On the disposal or termination of a previously acquired business, any remaining balance of associated goodwill is included in the determination of the gain or loss on disposal.
Impairment and Reversals of Impairment on Non-Financial Assets	Impairment and Reversals of Impairment on Non-Financial Assets The carrying amounts of the Company’s non-financial assets, other than inventories and deferred tax assets but including right-of-use assets, are reviewed at the end of each reporting period to determine whether there is an indication of impairment or reversal of previously recorded impairment. If such indication exists, the recoverable amount is estimated. Determining whether there are any indications of impairment or impairment reversals requires significant judgment of external factors, such as an extended change in prices or margins for oil and gas commodities or refined products, a significant change in an asset’s market value, a significant revision of estimated volumes, revision of future development costs, a change in the entity’s market capitalization or significant changes in the technological, market, economic or legal environment that would have an impact on the Company’s CGUs. If any indication of impairment or impairment reversals exist, an estimate of the asset’s recoverable amount is calculated as the higher of the fair value less costs to sell (“FVLCS”) and the asset’s value in use (“VIU”) for an individual asset or CGU. If the asset does not generate cash inflows that are largely independent of those from other assets or groups of assets, the asset is tested as part of a CGU, which is the smallest identifiable group of assets, liabilities and associated goodwill that generates cash inflows that are largely independent of the cash inflows from other assets or groups of assets. Determination of the Company’s CGUs is subject to management’s judgment. FVLCS is the amount that would be obtained from the sale of a CGU in an arm’s length transaction between knowledgeable and willing parties. The FVLCS is generally determined as the net present value of the estimated future cash flows expected to arise from a CGU, including any expansion prospects, and its eventual disposal, using assumptions that an independent market participant may take into account. These cash flows are discounted using a rate that would be applied by a market participant to arrive at a net present value of the CGU, less cost to dispose. VIU is the net present value of the estimated future cash flows expected to arise from the continued use of the asset in its present form and its eventual disposal. VIU is determined by applying assumptions specific to the Company’s continued use and can only take into account sanctioned future development costs. Estimates of future cash flows used in the evaluation of impairment of assets are made using management’s forecasts of commodity prices, royalty rates, operating costs and future capital expenditures, forecasted crack spreads, growth rate, discount rate and, in the case of oil and gas properties, expected production volumes. Expected production volumes take into account assessments of field reservoir performance and include expectations about proved and probable volumes and where applicable economically recoverable resources associated with interests in certain Husky properties which are risk-weighted utilizing geological, production, recovery, market price and economic projections. Either the cash flow estimates or the discount rate is risk-adjusted to reflect local conditions as appropriate. Given that the calculations for recoverable amounts require the use of estimates and assumptions, including forecasts of commodity prices, marketing supply and demand, product margins and in the case of oil and gas properties, expected production volumes, it is possible that the assumptions may change, which may impact the estimated life of the CGU and may require a material adjustment to the carrying value of goodwill and non-financial assets. An impairment loss is recognized if the carrying amount of an asset or its CGU exceeds its estimated recoverable amount. Impairment losses recognized with respect to CGUs are allocated first to reduce the carrying amount of any goodwill allocated to the units and then to reduce the carrying amounts of the other assets in the CGU or group of CGUs on a pro rata basis. Impairment losses are recognized in depletion, depreciation, amortization and impairment in the consolidated statements of income (loss). Impairment losses recognized in prior years are assessed at the end of each reporting period for indications that the impairment has decreased or no longer exists. An impairment loss is reversed only to the extent that the carrying amount of the asset or CGU does not exceed the carrying amount that would have been determined, net of depletion, depreciation and amortization, if no impairment loss had been recognized.
Asset Retirement Obligations (ARO)	Asset Retirement Obligations (“ARO”) A liability is recognized for future legal or constructive retirement obligations associated with the Company’s assets. The Company has significant obligations to remove tangible assets and restore land after operations cease and the Company retires or relinquishes the asset. The retirement of Upstream and Downstream assets consists primarily of plugging and abandoning wells, abandoning surface and subsea plant and equipment and facilities and restoring land to a state required by regulation or contract. The amount recognized is the net present value of the estimated future expenditures determined in accordance with local conditions, current technology and current regulatory requirements. The obligation is calculated using the current estimated costs to retire the asset inflated to the estimated retirement date and then discounted using a credit-adjusted risk-free discount rate. The liability is recorded in the period in which an obligation arises with a corresponding increase to the carrying value of the related asset. The liability is progressively accreted over time as the effect of discounting unwinds, creating an expense recognized in finance expenses. The costs capitalized to the related assets are amortized in a manner consistent with the depletion, depreciation and amortization of the underlying assets. Actual retirement expenditures are charged against the accumulated liability as incurred. Liabilities for ARO are adjusted every reporting period for changes in estimates. These adjustments are accounted for as a change in the corresponding capitalized cost, except where a reduction in the provision is greater than the undepreciated capitalized cost of the related assets, in which case the capitalized cost is reduced to nil and the remaining adjustment is recognized in net earnings (loss). Changes to the amount of capitalized costs will result in an adjustment to future depletion, depreciation and amortization, and to finance expenses. Estimating the ARO requires significant judgment as restoration technologies and costs are constantly changing, as are regulatory, political, environmental and safety considerations. Inherent in the calculation of the ARO are numerous assumptions including the ultimate settlement amounts, future third-party pricing, inflation factors, risk-free discount rates, credit risk, timing of settlement and changes in the legal, regulatory, environmental and political environments. Future revisions to these assumptions may result in material changes to the ARO liability. Adjustments to the estimated amounts and timing of future ARO cash flows are a regular occurrence in light of the significant judgments and estimates involved.
Legal and Other Contingent Matters	Legal and Other Contingent Matters Provisions and liabilities for legal and other contingent matters are recognized in the period when the circumstance becomes probable that a future cash outflow resulting from past operations or events will occur and the amount of the cash outflow can be reasonably estimated. The timing of recognition and measurement of the provision requires the application of judgment to existing facts and circumstances, which can be subject to change, and the carrying amounts of provisions and liabilities are reviewed regularly and adjusted accordingly. The Company is required to both determine whether a loss is probable based on judgment and interpretation of laws and regulations, and determine that the loss can be reasonably estimated. When a loss is recognized, it is charged to net earnings (loss). The Company continually monitors known and potential contingent matters and makes appropriate disclosure and provisions when warranted by the circumstances present.
Financial Instruments	Financial Instruments Financial instruments are any contracts that give rise to a financial asset of one entity and a financial liability or equity instrument of another entity. Financial assets are classified in one of the following categories: subsequently measured at amortized cost, fair value through other comprehensive income (“FVTOCI”), or fair value through profit or loss (“FVTPL”). Financial liabilities are initially recognized at fair value, and subsequently measured based on classification in one of the following categories: subsequently measured at amortized cost and FVTPL. Financial assets and liabilities are not offset unless there is a currently enforceable legal right to offset the recognized amounts and there is an intention to settle on a net basis, to realize the assets and settle the liabilities simultaneously. Financial assets and liabilities subsequently measured at amortized costs are measured using the effective interest method. The effective interest method is a method of calculating the amortized costs of a financial liability and of allocating interest expense over the relevant period. Transaction costs that are directly attributable to the acquisition or issue of a financial instrument are measured at amortized cost and added to the fair value initially recognized. Financial instruments at FVTPL are stated at fair value, with any gains or losses arising on remeasurement recognized in profit or loss. Unrealized gains and losses on FVTPL financial instruments related to trading activities are recognized in marketing and other in the consolidated statements of income (loss), and unrealized gains and losses on all other FVTPL financial instruments are recognized in other – net. Transaction costs directly attributable to the acquisition of financial assets or liabilities at FVTPL are recognized immediately in profit or loss. Financial instruments at FVTOCI are stated at fair value, with any gains or losses arising on remeasurement recognized in OCI except for impairment gains or losses and foreign exchange gains and losses. Financial instruments subsequently revalued at fair value are further categorized using a three-level hierarchy that reflects the significance of the inputs used in determining fair value. Level 1 fair value is determined by reference to quoted prices in active markets for identical assets and liabilities. Level 2 fair value is based on inputs that are independently observable for similar assets or liabilities. Level 3 fair value is not based on independently observable market data. The disclosure of the fair value hierarchy excludes financial assets and liabilities where book value approximates fair value. A financial asset is derecognized when the contractual rights to the cash flows from the financial asset have expired, or it transfers the contractual rights to receive the cash flows of the financial assets and the Company has transferred substantially all the risks and rewards of ownership of the financial asset. A financial liability is derecognized when the liability is extinguished, discharged, cancelled or expires.
Derivative Instruments and Hedging Activities	Derivative Instruments and Hedging Activities Derivatives are financial instruments for which the fair value changes in response to market risks, require little or no initial investment and are settled at a future date. Derivative instruments are utilized by the Company to manage various market risks including volatility in commodity prices, foreign exchange rates and interest rate exposures. The Company’s policy is not to utilize derivative instruments for speculative purposes. The Company may enter into swap and other derivative transactions to hedge or mitigate the Company’s commercial risk, including derivatives that reduce risks that arise in the ordinary course of the Company’s business. The Company may choose to apply hedge accounting to derivative instruments. The fair values of derivatives are determined using valuation models that require assumptions concerning the amount and timing of future cash flows and discount rates. These estimates are also subject to change with fluctuations in commodity prices, interest rates, foreign currency exchange rates and estimates of non-performance. When able, the Company will determine fair value by incorporating forward market prices and rates that are compared to quotes received from financial institutions to ensure reasonability. The actual settlement of a derivative instrument could differ materially from the fair value recorded and could impact future results. i) Derivative Instruments All derivative instruments, other than those designated as effective hedging instruments or certain non-financial derivative contracts that meet the Company’s own use requirements, are classified as FVTPL and are recorded at fair value. Gains and losses on these instruments are recorded in the consolidated statements of income (loss) in the period they occur. The Company may enter into commodity price contracts in order to offset fixed or floating prices with market rates to manage exposures to fluctuations in commodity prices. The estimation of the fair value of commodity derivatives incorporates forward prices and adjustments for quality or location. The related inventory is measured at fair value based on exit prices. Gains and losses from these derivative contracts, which are not designated as effective hedging instruments, are recognized in revenues or purchases of crude oil and products and are initially recorded at settlement date. Derivative instruments that have been designated as effective hedging instruments are further classified as either fair value or cash flow hedges (see “Hedging Activities”). ii) Embedded Derivatives Derivatives embedded within a hybrid contract containing a financial asset host are not accounted for separately, rather the whole instrument is classified as FVTPL. Derivatives embedded in other hybrid contracts are recorded separately when the economic characteristics and risks of the embedded derivative are not clearly and closely related to those of the host contract and the host contract is not measured at FVTPL. The definition of an embedded derivative is the same as freestanding derivatives. Embedded derivatives are measured at fair value with gains and losses recognized in net earnings (loss). iii) Hedging Activities At the inception of a derivative transaction, if the Company elects to use hedge accounting, formal designation and documentation is required. The documentation must include: identification of the hedged item or transaction, the hedging instrument, the nature of the risk being hedged, the Company’s risk management objective and strategy for undertaking the hedge and how the Company will assess the hedging instrument’s effectiveness in offsetting the exposure to changes in the hedged item. A hedge is assessed at inception and at the end of each reporting period to ensure that it is highly effective in offsetting changes in fair values or cash flows of the hedged item. For a fair value hedge, the gain or loss from remeasuring the hedging instrument at fair value is recognized immediately in net earnings (loss) with the offsetting gain or loss on the hedged item. When fair value hedge accounting is discontinued, the carrying amount of the hedging instrument is deferred and amortized to net earnings (loss) over the remaining maturity of the hedged item. For a cash flow hedge, the effective portion of the gain or loss is recorded in OCI. Any hedge or portion of a hedge that is ineffective is immediately recognized in net earnings (loss). Hedge accounting is discontinued on a prospective basis when the hedging relationship no longer qualifies for hedge accounting. Any gain or loss on the hedging instrument resulting from the discontinuation of a cash flow hedge is deferred in OCI until the forecasted transaction date. If the forecasted transaction date is no longer expected to occur, the gain or loss is recognized in net earnings (loss) in the period of discontinuation. A net investment hedge of a foreign operation is accounted for similarly to a cash flow hedge. The Company may designate certain U.S. dollar denominated debt as a hedge of its net investment in foreign operations for which the U.S. dollar is the functional currency. The unrealized foreign exchange gains and losses arising from the translation of the debt are recorded in OCI, net of tax, and are limited to the translation gain or loss on the net investment.
Impairment of Financial Assets	Impairment of Financial Assets A financial asset is assessed at the end of each reporting period to determine whether it is impaired, based on objective evidence indicating that one or more events have had a negative effect on the estimated future cash flows of that asset. Objective evidence used by the Company to assess impairment of financial assets includes quoted market prices for similar financial assets and historical collection rates. An impairment loss with respect to a financial asset measured at amortized cost is calculated as the difference between its carrying amount and the net present value of the estimated future cash flows discounted at the original effective interest rate, according to the expected credit loss model. Significant financial assets are tested for impairment on an individual basis. The remaining financial assets are assessed for lifetime expected credit losses collectively in groups that share similar credit risk characteristics. All impairment losses are recognized in net earnings (loss). An impairment loss is reversed if the reversal can be related objectively to an event occurring after the impairment loss was recognized. Given that the calculations for the net present value of estimated future cash flows related to derivative financial assets require the use of estimates and assumptions, including forecasts of commodity prices, marketing supply and demand, product margins and expected production volumes, it is possible that the assumptions may change, which may require a material adjustment to the carrying value of financial assets.
Description of accounting policy for employee benefits [text block]	Pensions and Other Post-employment Benefits The Company maintains various defined contribution and defined benefit pension plans for its employees. The cost of the pension benefits earned by employees in the defined contribution pension plans is expensed as incurred. The cost of the benefits earned by employees in the defined benefit pension plans is determined using the projected unit credit funding method. Actuarial gains and losses are recognized in retained earnings as incurred. The defined benefit asset or liability is comprised of the fair value of plan assets from which the obligations are to be settled and the present value of the defined benefit obligation. Plan assets are measured at fair value based on the closing bid price when there is a quoted price in an active market. Plan assets are assets that are held by a long-term employee benefit fund or qualifying insurance policies. Plan assets are not available to the Company’s creditors. The value of any defined benefit asset is restricted to the sum of any past service costs and the present value of refunds from and reductions in future contributions to the plan. Defined benefit obligations are estimated by discounting expected future payments using the year-end market rate of interest for high-quality corporate debt instruments with cash flows that match the timing and amount of expected benefit payments. Post-retirement medical benefits are also provided to qualifying retirees. In some cases the benefits are provided through medical care plans to which the Company, the employees, the retirees and covered family members contribute. In some plans there is no funding of the benefits before retirement. These plans are recognized on the same basis as described above for the defined benefit pension plan. The determination of the cost of the defined benefit pension plan and the other post-retirement benefit plans reflects a number of assumptions that affect the expected future benefit payments. The valuation of these plans is prepared by an independent actuary engaged by the Company. These assumptions include, but are not limited to, the estimate of expected plan investment performance, salary escalation, retirement age, attrition, future health care costs and mortality. The fair value of the plan assets is used for the purposes of calculating the expected return on plan assets. The assumptions for each pension plan are reviewed each year and are adjusted where necessary to reflect changes in fund experience and actuarial recommendations. Mortality rates are based on the latest available standard mortality tables for the individual countries concerned. The rate of return on pension plan assets is based on a projection of real long-term bond yields and an equity risk premium, which are combined with local inflation assumptions and applied to the actual asset mix of each plan. The amount of the expected return on plan assets is calculated using the expected rate of return for the year and the fair value of assets at the beginning of the year. Future salary increases are based on expected future inflation rates for the individual countries.
Income Taxes	Income Taxes Current income tax is recognized in net earnings (loss) in the period unless it relates to items recognized directly to equity, including OCI, in which case the deferred income tax is also recorded in equity. Management periodically evaluates positions taken in the Company’s tax returns with respect to situations in which applicable tax regulations are subject to interpretation and reassessment and establishes provisions where appropriate. Deferred tax is measured using the liability method on temporary differences at the reporting date between the tax bases of assets and liabilities and their carrying amounts for financial reporting purposes. Deferred tax assets and liabilities are recognized at expected tax rates in effect in the year when the asset is expected to be realized or the liability settled, based on tax rates and tax laws that have been enacted or substantively enacted at the reporting date. 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 (loss) in the period that the change occurs unless it relates to items recognized directly to equity, including OCI, in which case the deferred income tax is also recorded in equity. Deferred tax assets and deferred tax liabilities are offset if a legally enforceable right exists to set off current tax assets against current income tax liabilities and the deferred taxes relate to the same taxable entity and the same taxation authority. The determination of the Company’s income and other tax liabilities requires interpretation of complex laws and regulations often involving multiple jurisdictions. Estimates that require significant judgments are also made with respect to the timing of temporary difference reversals, the realizability of tax assets and in circumstances where the transaction and calculations for which the ultimate tax determination are uncertain. All tax filings are subject to audit and potential reassessment after the lapse of considerable time. Accordingly, the actual income tax liability may differ significantly from that estimated and recorded by management.
Description of accounting policy for non-monetary transactions [Policy Text Block]	Asset Exchange Transactions Asset exchange transactions are measured at cost if the transaction lacks commercial substance or the fair value of neither the asset received nor the asset given up is reliably measurable. Otherwise, asset exchange transactions are measured at the fair value of the asset given up, unless the fair value of the asset received is more clearly evident. If the acquired item is not measured at fair value, its cost is measured at the carrying amount of the asset given up. Gains and losses are recorded in other – net in the consolidated statements of income in the period they occur.
Revenue Recognition	Revenue Recognition Revenue is recognized when the performance obligations are satisfied and revenue can be reliably measured. Revenue is measured at the consideration specified in the contract and represents amounts receivable for goods or services provided in the normal course of business, net of discounts, customs duties and sales taxes. The Company has no obligations for returns, refunds, warranties or similar obligations. i) Nature of Goods or Services The following is a description of the principal activities, by operating segment, from which the Company generates revenue. a) Upstream The Upstream segment includes Exploration and Production, and Infrastructure and Marketing. i) Exploration and Production Exploration and Production principally generates revenue from the sale of crude oil, bitumen, natural gas, and NGLs, as well as crude oil and natural gas processing services. Performance obligations associated with sales of these products are satisfied at the point in time when the products are delivered to and title passes to the customer. Performance obligations associated with the sale of processing services are satisfied at the point in time when the services are provided. Royalties are recognized as a reduction to gross revenues. Sales, services and royalties are billed and paid on a monthly basis. Under take-or-pay contracts, the Company makes a long-term supply commitment in return for a commitment from the buyer to pay for minimum quantities, whether or not the customer takes delivery. If a buyer has a right to get a “make-up” delivery at a later date the performance obligation is not satisfied and revenue is deferred and recognized only when the product is delivered or the make-up product can no longer be taken. Determining when the make-up product can no longer be taken, or how much can no longer be taken, requires estimates of future deliveries. Changes in these estimates may result in a material difference in deferred revenue recognized. If no such option exists within the contractual terms, performance obligation is satisfied, and revenue is recognized when the take-or-pay penalty is triggered. Physical exchanges of inventory are recognized as non-monetary exchanges and are reported on a net basis for swaps of similar items, as are sales and purchases made with a common counterparty as part of an arrangement similar to a physical exchange. ii) Infrastructure and Marketing Infrastructure and Marketing principally generates revenue from marketing the Company’s and other producers’ crude oil, natural gas, NGL, sulphur and petroleum coke, pipeline transportation, the blending of crude oil and natural gas, and storage of crude oil, diluent and natural gas. Performance obligations associated with sales of these products are satisfied at the point in time when the products are delivered to and title passes to the customer. Performance obligations associated with transportation, blending and storage are satisfied at the point in time when the services are provided. Sales, services and royalties are billed and paid on a monthly basis. Infrastructure and Marketing also includes revenue from construction services provided to Husky Midstream Limited Partnership (“HMLP”), of which the Company owns 35%. The Company acts as the general contractor for HMLP projects for fixed price and cost plus contracts. Revenue from fixed price contracts is recognized as performance obligations are met. Revenue from cost plus contracts are recognized as services are performed. Construction services are billed and paid on a monthly basis, or on completion of the project. b) Downstream The Downstream segment includes Upgrading, Canadian Refined Products, and U.S. Refining and Marketing. i) Upgrading Upgrading principally generates revenue from the sale of synthetic crude oil and diesel in Canada, upgraded from heavy oil feedstock. Performance obligations associated with sales of these products are satisfied at the point in time when the products are delivered to and title passes to the customer. Sales are billed and paid on a monthly basis. ii) Canadian Refined Products Canadian Refined Products principally generates revenue from refining of crude oil and marketing of refined petroleum products, including gasoline, diesel, ethanol blended fuels, asphalt and ancillary products, and production of ethanol. Canadian Refined Products also includes, the Company’s retail gasoline and diesel distribution and sales network. Performance obligations associated with sales of these products are satisfied at the point in time when the products are delivered to and title passes to the customer. Performance obligations associated with marketing services are satisfied when the services are performed. Sales for retail gasoline, diesel and ancillary products are billed and paid upon delivery. All other sales and services are billed and paid on a weekly or monthly basis. iii) U.S. Refining and Marketing U.S. Refining and Marketing primarily generates revenue from refining crude oil to produce and market gasoline, jet fuel and diesel fuels. Performance obligations associated with sale of these products are satisfied at the point in time when the products are delivered to and title passes to the customer. All sales are billed and paid on a weekly or monthly basis. Performance obligations associated with the sale of crude oil, natural gas, natural gas liquids, synthetic crude oil, purchased commodities and refined petroleum products are satisfied at the point in time when the products are delivered to and title passes to the customer. Performance obligations associated with the sale of transportation, processing and natural gas storage services are satisfied at the point in time when the services are provided. All amounts are due upon delivery of goods or when services are provided. c) Corporate and Eliminations Corporate and Eliminations primarily generates revenue from finance income. Finance income is recognized as the interest accrues using the effective interest rate, which is the rate that discounts estimated future cash receipts through the expected life of the financial instrument to the net carrying amount of the financial asset. Corporate and Eliminations also includes the elimination of sales of crude oil, bitumen, natural gas and NGLs between segments.
Foreign Currency	Foreign Currency Functional currency is the currency of the primary economic environment in which the Company and its subsidiaries operate and is normally the currency in which the entity primarily generates and expends cash. The financial statements of Husky’s subsidiaries are translated into Canadian dollars, which is the presentation and functional currency of the Company. The assets and liabilities of subsidiaries whose functional currencies are other than Canadian dollars are translated into Canadian dollars at the foreign exchange rate at the balance sheet date, while revenues and expenses of such subsidiaries are translated using average monthly foreign exchange rates, which approximate the foreign exchange rates on the dates of the transactions. Foreign exchange differences arising on translation are included in OCI. The Company’s transactions in foreign currencies are translated to the appropriate functional currency at the foreign exchange rate on the dates of the transactions. Monetary assets and liabilities denominated in foreign currencies are translated to the functional currency at the foreign exchange rate at the balance sheet date and differences arising on translation are recognized in net earnings (loss). Non-monetary assets that are measured in terms of historical cost in a foreign currency are translated using the exchange rate at the dates of the transactions.
Share-based Payments	Share-based Payments In accordance with the Company’s stock option plan, stock options to acquire common shares may be granted to officers and certain other employees. The Company records compensation expense over the vesting period based on the fair value of options granted. Compensation expense is recorded in net earnings (loss) as part of selling, general and administrative expenses. The Company’s stock option plan is a tandem plan that provides the stock option holder with the right to exercise the stock option or surrender the option for a cash payment. A liability for the stock options is accrued over their vesting period and measured at fair value using the Black-Scholes option pricing model. The liability is revalued each reporting period until it is settled to reflect changes in the fair value of the options. The net change is recognized in net earnings (loss). When stock options are surrendered for cash, the cash settlement paid reduces the outstanding liability. When stock options are exercised for common shares, consideration paid by the stock option holders and the previously recognized liability associated with the stock options are recorded as share capital. The Company’s Performance Share Unit Plan provides a time-vested award to certain officers and employees of the Company. Performance Share Units (“PSU”) entitle participants to receive cash based on the Company’s share price at the time of vesting. The amount of cash payment is contingent on the Company’s total shareholder return relative to a peer group of companies and achieving a return on capital in use (“ROCIU”) target. ROCIU equals net earnings (loss) plus after tax interest expense divided by the two-year average capital employed, less any capital invested in assets that are not in use. Net earnings (loss) is adjusted for the difference between actual realized and budgeted commodity prices and foreign exchange rates and other actual and budgeted exceptional items. A liability for expected cash payments is accrued over the vesting period of the PSUs and is revalued at each reporting date based on the market price of the Company’s common shares and the expected vesting percentage. Upon vesting, a cash payment is made to the participants and the outstanding liability is reduced by the payment amount.
Earnings per Share	The number of basic common shares outstanding is the weighted average number of common shares outstanding for each period. Shares issued during the period are included in the weighted average number of shares from the date consideration is received. The calculation of basic earnings (loss) per common share is based on net earnings (loss) attributable to common shareholders divided by the weighted average number of common shares outstanding. The number of diluted common shares outstanding is calculated using the treasury stock method, which assumes that any proceeds received from in-the-money stock options would be used to buy back common shares at the average market price for the period. The calculation of diluted earnings (loss) per share is based on net earnings (loss) attributable to common shareholders divided by the weighted average number of common shares outstanding adjusted for the effects of all potential dilutive common share issuances, which are comprised of common shares issuable upon exercise of stock options granted to employees. Stock options granted to employees provide the holder with the ability to settle in cash or equity. For the purposes of the diluted earnings (loss) per share calculation, the Company must adjust the numerator for the more dilutive effect of cash-settlement versus equity-settlement despite how the stock options are accounted for in net earnings (loss). As a result, net earnings (loss) reported based on accounting of cash-settled stock options may be adjusted for the results of equity-settlements for the purposes of determining the numerator for the diluted earnings (loss) per share calculation.
Government Grants	Government Grants Government grants are recognized when there is reasonable assurance that the grant will be received and all attached conditions will be complied with. If a grant is received but reasonable assurance and compliance with conditions is not achieved, the grant is recognized as a deferred liability until such conditions are fulfilled. When the grant relates to an expense item, it is recognized as income in the period in which the costs are incurred. Where the grant relates to an asset, it is recognized as a reduction to the net book value of the related asset and recognized in net earnings (loss) in equal amounts over the expected useful life of the related asset through lower depletion, depreciation and amortization.
Description of accounting policy for transactions with related parties [text block]	Related Party Judgments and Estimates The Company entered into transactions and agreements in the normal course of business with certain related parties, joint arrangements and associates. Proceeds for disposition of assets to related parties are recognized at fair value, based on discounted cash flow forecast from those assets. Independent opinions of the fair value may be obtained. Changes in the assumptions used to determine these fair values may result in a material difference in the proceeds and any gain or loss on disposition.
Recent Accounting Standards	Recent Accounting Standards The Company has not early adopted any standard, interpretation or amendment that has been issued but is not yet effective.
Changes in Accounting Policy	<div style="line-height:120%;padding-bottom:16px;text-align:left;font-size:12pt;"><font style="font-family:Myriad Pro,sans-serif;font-size:12pt;color:#00497f;">Change in Accounting Policy</font></div><div style="line-height:110%;padding-bottom:4px;text-align:justify;font-size:10pt;"><font style="font-family:Myriad Pro,sans-serif;font-size:10pt;color:#00497f;">i)    Leases</font></div><div style="line-height:120%;padding-bottom:12px;text-align:justify;font-size:9pt;"><font style="font-family:Myriad Pro Light,sans-serif;font-size:9pt;">In January 2016, the IASB issued IFRS 16 Leases (“IFRS 16”), which replaces the existing IFRS guidance on leases: IAS 17 Leases (“IAS 17”). Under IAS 17, lessees were required to determine if the lease is a finance or operating lease, based on specified criteria of whether the lease transferred significantly all the risks and rewards associated with ownership of the underlying asset. Finance leases were recognized on the balance sheet while operating leases were recognized in the Consolidated Statements of Income (Loss) when the expense was incurred. Under IFRS 16, lessees must recognize a lease liability and a right-of-use asset for most lease contracts. The recognition of the present value of the lease payments for certain contracts previously classified as operating leases resulted in increases to assets, liabilities, depletion, depreciation and amortization and finance expense, and a decrease to production, operating and transportation expense, purchases of crude oil and products and selling, general and administrative expenses. </font><font style="font-family:Myriad Pro Light,sans-serif;font-size:9pt;"> </font></div><div style="line-height:120%;padding-bottom:16px;text-align:justify;font-size:9pt;"><font style="font-family:Myriad Pro Light,sans-serif;font-size:9pt;">The Company adopted IFRS 16 on January 1, 2019 using the modified retrospective approach. The modified retrospective approach does not require restatement of prior period financial information as it recognizes the cumulative effect as an adjustment to opening retained earnings and applies the standard prospectively. Accordingly, comparative information in the Company’s financial statements are not restated. </font><font style="font-family:Myriad Pro Light,sans-serif;font-size:9pt;"> </font></div><div style="line-height:120%;padding-bottom:16px;text-align:justify;font-size:9pt;"><font style="font-family:Myriad Pro Light,sans-serif;font-size:9pt;">On adoption, lease liabilities were measured at the present value of the remaining lease payments discounted using the Company’s incremental borrowing rate on January 1, 2019. Right-of-use assets were measured at an amount equal to the lease liability. For leases previously classified as operating leases, the Company applied the exemption not to recognize right-of-use assets and liabilities for leases with a lease term of less than 12 months, excluded initial direct costs from measuring the right-of-use asset at the date of initial application and applied a single discount rate to a portfolio of leases with similar characteristics. For leases that were previously classified as finance leases under IAS 17, the carrying amount of the lease asset and lease liability remain unchanged upon transition and were determined at the carrying amount immediately before adoption date. Additionally, instead of an impairment review, the Company adjusted the right-of-use assets by the amount of IAS 37 onerous contract provision immediately before the date of initial application. </font><font style="font-family:Myriad Pro Light,sans-serif;font-size:9pt;"> </font></div><div style="line-height:120%;padding-bottom:16px;text-align:justify;font-size:9pt;"><font style="font-family:Myriad Pro Light,sans-serif;font-size:9pt;">No adjustments were required upon transition to IFRS 16 for leases where the Company is a lessor. Under IFRS 16, the Company is required to assess the classification of a sub-lease with reference to the right-of-use asset, not the underlying asset. On transition, the Company reassessed the classification of any sub-lease contracts previously assessed under IAS 17. No changes to sublease classification or associated accounting treatment was required. </font><font style="font-family:Myriad Pro Light,sans-serif;font-size:9pt;"> </font></div><div style="line-height:110%;padding-bottom:4px;text-align:justify;font-size:10pt;"><font style="font-family:Myriad Pro,sans-serif;font-size:10pt;color:#00497f;">Financial Statement Impact</font></div><div style="line-height:120%;padding-bottom:16px;text-align:justify;font-size:9pt;"><font style="font-family:Myriad Pro Light,sans-serif;font-size:9pt;">The recognition of the present value of lease payments resulted in an additional $1.3 billion of right-of-use assets and associated lease liabilities. The Company has recognized lease liabilities in relation to lease arrangements previously disclosed as operating lease commitments under IAS 17 that meet the criteria of a lease under IFRS 16. Upon recognition in the consolidated statement of financial position, the Company’s weighted average incremental borrowing rate used in measuring lease liabilities was 3.58%. </font><font style="font-family:Myriad Pro Light,sans-serif;font-size:9pt;"> </font></div></div>" id="sjs-B32">&lt;div style="font-family:Times New Roman;font-size:10pt;">&lt;div style="line-height:120%;padding-bottom:16px;text-align:left;font-size:12pt;">&lt;font style="font-family:Myriad Pro,sans-serif;font-size:12pt;color:#00497f;">Change in Accounting Policy&lt;/font>&lt;/div>&lt;div style="line-height:110%;padding-bottom:4px;text-align:justify;font-size:10pt;">&lt;font style="font-family:Myriad Pro,sans-serif;font-size:10pt;color:#00497f;">i)&#160;&#160;&#160;&#160;Leases&lt;/font>&lt;/div>&lt;div style="line-height:120%;padding-bottom:12px;text-align:justify;font-size:9pt;">&lt;font style="font-family:Myriad Pro Light,sans-serif;font-size:9pt;">In January 2016, the IASB issued IFRS 16 Leases (&#8220;IFRS 16&#8221;), which replaces the existing IFRS guidance on leases: IAS 17 Leases (&#8220;IAS 17&#8221;). Under IAS 17, lessees were required to determine if the lease is a finance or operating lease, based on specified criteria of whether the lease transferred significantly all the risks and rewards associated with ownership of the underlying asset. Finance leases were recognized on the balance sheet while operating leases were recognized in the Consolidated Statements of Income (Loss) when the expense was incurred. Under IFRS 16, lessees must recognize a lease liability and a right-of-use asset for most lease contracts. The recognition of the present value of the lease payments for certain contracts previously classified as operating leases resulted in increases to assets, liabilities, depletion, depreciation and amortization and finance expense, and a decrease to production, operating and transportation expense, purchases of crude oil and products and selling, general and administrative expenses. &lt;/font>&lt;font style="font-family:Myriad Pro Light,sans-serif;font-size:9pt;"> &lt;/font>&lt;/div>&lt;div style="line-height:120%;padding-bottom:16px;text-align:justify;font-size:9pt;">&lt;font style="font-family:Myriad Pro Light,sans-serif;font-size:9pt;">The Company adopted IFRS 16 on January 1, 2019 using the modified retrospective approach. The modified retrospective approach does not require restatement of prior period financial information as it recognizes the cumulative effect as an adjustment to opening retained earnings and applies the standard prospectively. Accordingly, comparative information in the Company&#8217;s financial statements are not restated. &lt;/font>&lt;font style="font-family:Myriad Pro Light,sans-serif;font-size:9pt;"> &lt;/font>&lt;/div>&lt;div style="line-height:120%;padding-bottom:16px;text-align:justify;font-size:9pt;">&lt;font style="font-family:Myriad Pro Light,sans-serif;font-size:9pt;">On adoption, lease liabilities were measured at the present value of the remaining lease payments discounted using the Company&#8217;s incremental borrowing rate on January 1, 2019. Right-of-use assets were measured at an amount equal to the lease liability. For leases previously classified as operating leases, the Company applied the exemption not to recognize right-of-use assets and liabilities for leases with a lease term of less than 12 months, excluded initial direct costs from measuring the right-of-use asset at the date of initial application and applied a single discount rate to a portfolio of leases with similar characteristics. For leases that were previously classified as finance leases under IAS 17, the carrying amount of the lease asset and lease liability remain unchanged upon transition and were determined at the carrying amount immediately before adoption date. Additionally, instead of an impairment review, the Company adjusted the right-of-use assets by the amount of IAS 37 onerous contract provision immediately before the date of initial application. &lt;/font>&lt;font style="font-family:Myriad Pro Light,sans-serif;font-size:9pt;"> &lt;/font>&lt;/div>&lt;div style="line-height:120%;padding-bottom:16px;text-align:justify;font-size:9pt;">&lt;font style="font-family:Myriad Pro Light,sans-serif;font-size:9pt;">No adjustments were required upon transition to IFRS 16 for leases where the Company is a lessor. Under IFRS 16, the Company is required to assess the classification of a sub-lease with reference to the right-of-use asset, not the underlying asset. On transition, the Company reassessed the classification of any sub-lease contracts previously assessed under IAS 17. No changes to sublease classification or associated accounting treatment was required. &lt;/font>&lt;font style="font-family:Myriad Pro Light,sans-serif;font-size:9pt;"> &lt;/font>&lt;/div>&lt;div style="line-height:110%;padding-bottom:4px;text-align:justify;font-size:10pt;">&lt;font style="font-family:Myriad Pro,sans-serif;font-size:10pt;color:#00497f;">Financial Statement Impact&lt;/font>&lt;/div>&lt;div style="line-height:120%;padding-bottom:16px;text-align:justify;font-size:9pt;">&lt;font style="font-family:Myriad Pro Light,sans-serif;font-size:9pt;">The recognition of the present value of lease payments resulted in an additional $1.3 billion of right-of-use assets and associated lease liabilities. The Company has recognized lease liabilities in relation to lease arrangements previously disclosed as operating lease commitments under IAS 17 that meet the criteria of a lease under IFRS 16. Upon recognition in the consolidated statement of financial position, the Company&#8217;s weighted average incremental borrowing rate used in measuring lease liabilities was 3.58%. &lt;/font>&lt;font style="font-family:Myriad Pro Light,sans-serif;font-size:9pt;"> &lt;/font>&lt;/div>&lt;/div>

Description of Business and S_2

Description of Business and Segmented Disclosures (Tables)	12 Months Ended
	Dec. 31, 2019
Disclosure of notes and other explanatory information [Abstract]
Disclosure of entity's operating segments [text block]	Segmented Financial Information Upstream ($ millions) Exploration and Production (1) Infrastructure and Marketing (2) Total Years ended December 31, 2019 2018 2019 2018 2019 2018 Gross revenues 4,958 4,330 2,342 2,211 7,300 6,541 Royalties (323 ) (335 ) — — (323 ) (335 ) Marketing and other — — 189 668 189 668 Revenues, net of royalties 4,635 3,995 2,531 2,879 7,166 6,874 Expenses Purchases of crude oil and products — — 2,336 2,087 2,336 2,087 Production, operating and transportation expenses 1,634 1,527 21 23 1,655 1,550 Selling, general and administrative expenses 297 296 9 5 306 301 Depletion, depreciation, amortization and impairment 4,312 1,811 12 — 4,324 1,811 Exploration and evaluation expenses 547 149 — — 547 149 Loss (gain) on sale of assets (3 ) (2 ) — — (3 ) (2 ) Other – net 86 (120 ) — 2 86 (118 ) 6,873 3,661 2,378 2,117 9,251 5,778 Earnings (loss) from operating activities (2,238 ) 334 153 762 (2,085 ) 1,096 Share of equity investment income 50 51 9 18 59 69 Financial items Net foreign exchange gain — — — — — — Finance income 3 12 — — 3 12 Finance expenses (163 ) (109 ) (3 ) — (166 ) (109 ) (160 ) (97 ) (3 ) — (163 ) (97 ) Earnings (loss) before income taxes (2,348 ) 288 159 780 (2,189 ) 1,068 Provisions for (recovery of) income taxes Current 32 (484 ) — 354 32 (130 ) Deferred (674 ) 549 43 (141 ) (631 ) 408 (642 ) 65 43 213 (599 ) 278 Net earnings (loss) (1,706 ) 223 116 567 (1,590 ) 790 Intersegment revenues 1,660 1,155 — — 1,660 1,155 (1) Includes allocated depletion, depreciation, amortization and impairment related to assets in Infrastructure and Marketing, as these assets provide a service to Exploration and Production. (2) Includes $201 million of revenue (2018 - $172 million ) and $269 million of associated costs (2018 - $142 million ) for construction contracts, inclusive of $193 million of revenue (2018 - $172 million ) and $261 million of costs (2018 - $142 million ) for contracts in progress with revenue recognized as performance obligations are met. (3) Eliminations relate to sales and operating revenues between segments recorded at transfer prices based on current market prices. Segment results include transactions between business segments. Segmented Financial Information Con’t Downstream Corporate and Eliminations (3) Total Upgrading Canadian Refined Products U.S. Refining and Marketing Total 2019 2018 2019 2018 2019 2018 2019 2018 2019 2018 2019 2018 1,777 1,750 3,122 3,412 9,940 11,770 14,839 16,932 (2,022 ) (1,554 ) 20,117 21,919 — — — — — — — — — — (323 ) (335 ) — — — — — — — — — — 189 668 1,777 1,750 3,122 3,412 9,940 11,770 14,839 16,932 (2,022 ) (1,554 ) 19,983 22,252 1,303 928 2,571 2,760 8,629 10,334 12,503 14,022 (2,022 ) (1,554 ) 12,817 14,555 217 195 278 265 869 795 1,364 1,255 (2 ) (2 ) 3,017 2,803 9 7 53 47 33 22 95 76 292 277 693 654 115 123 218 115 735 450 1,068 688 104 92 5,496 2,591 — — — — — — — — — — 547 149 — — (6 ) (2 ) 1 — (5 ) (2 ) — — (8 ) (4 ) — — — (1 ) (654 ) (464 ) (654 ) (465 ) (16 ) (8 ) (584 ) (591 ) 1,644 1,253 3,114 3,184 9,613 11,137 14,371 15,574 (1,644 ) (1,195 ) 21,978 20,157 133 497 8 228 327 633 468 1,358 (378 ) (359 ) (1,995 ) 2,095 — — — — — — — — — — 59 69 — — — — — — — — 44 14 44 14 — — — — — — — — 71 52 74 64 (1 ) (1 ) (15 ) (12 ) (18 ) (14 ) (34 ) (27 ) (151 ) (178 ) (351 ) (314 ) (1 ) (1 ) (15 ) (12 ) (18 ) (14 ) (34 ) (27 ) (36 ) (112 ) (233 ) (236 ) 132 496 (7 ) 216 309 619 434 1,331 (414 ) (471 ) (2,169 ) 1,928 63 168 38 100 17 9 118 277 25 (72 ) 175 75 (28 ) (33 ) (40 ) (42 ) 52 129 (16 ) 54 (327 ) (66 ) (974 ) 396 35 135 (2 ) 58 69 138 102 331 (302 ) (138 ) (799 ) 471 97 361 (5 ) 158 240 481 332 1,000 (112 ) (333 ) (1,370 ) 1,457 263 290 99 109 — — 362 399 — — 2,022 1,554 Segmented Financial Information Upstream ($ millions) Exploration and Production (1) Infrastructure and Marketing Total Years ended December 31, 2019 2018 2019 2018 2019 2018 Expenditures on exploration and evaluation assets (2) 46 242 — — 46 242 Expenditures on property, plant and equipment (2) 2,300 2,414 2 — 2,302 2,414 As at December 31, Exploration and evaluation assets 643 997 — — 643 997 Developing and producing assets at cost 46,587 44,196 — — 46,587 44,196 Accumulated depletion, depreciation, amortization and impairment (31,348 ) (27,379 ) — — (31,348 ) (27,379 ) Other property, plant and equipment at cost — — 101 101 101 101 Accumulated depletion, depreciation and amortization — — (51 ) (50 ) (51 ) (50 ) Total exploration and evaluation assets and property, plant and equipment, net 15,882 17,814 50 51 15,932 17,865 Total right-of-use assets, net 520 — 90 — 610 — Total assets 17,533 19,175 1,661 1,301 19,194 20,476 (1) Includes allocated depletion, depreciation, amortization and impairment related to assets in Infrastructure and Marketing, as these assets provide a service to Exploration and Production. (2) Excludes capitalized costs related to asset retirement obligations and capitalized interest incurred during the year. Includes Exploration and Production assets acquired through acquisition, but excludes assets acquired through corporate acquisition. Geographical Financial Information ($ millions) Canada United States Years ended December 31, 2019 2018 2019 2018 Gross revenues (1) 9,120 9,000 9,940 11,770 Royalties (264 ) (269 ) — — Marketing and other 189 668 — — Revenue, net of royalties 9,045 9,399 9,940 11,770 As at December 31, Restricted cash – non-current — — — — Exploration and evaluation assets 599 935 — — Property, plant and equipment, net 14,630 16,433 6,053 6,336 Right-of-use assets, net 1,044 — 156 — Goodwill — — 656 690 Investment in joint ventures 666 669 — — Long-term income tax receivable 212 243 — — Other assets (2) 47 58 458 276 Total non-current assets 17,198 18,338 7,323 7,302 (1) Sales to external customers are based on the location of the seller. (2) Includes insurance proceeds of $435 million (2018 - $253 million ), related to the Superior Refinery incident. Segmented Financial Information Con’t Downstream Corporate and Eliminations Total Upgrading Canadian Refined Products U.S. Refining and Marketing Total 2019 2018 2019 2018 2019 2018 2019 2018 2019 2018 2019 2018 — — — — — — — — — — 46 242 59 62 119 74 768 665 946 801 138 121 3,386 3,336 — — — — — — — — — — 643 997 — — — — — — — — — — 46,587 44,196 — — — — — — — — — — (31,348 ) (27,379 ) 2,721 2,659 2,360 2,789 9,534 9,746 14,615 15,194 1,377 1,251 16,093 16,546 (1,700 ) (1,585 ) (1,449 ) (1,581 ) (3,481 ) (3,410 ) (6,630 ) (6,576 ) (1,028 ) (937 ) (7,709 ) (7,563 ) 1,021 1,074 911 1,208 6,053 6,336 7,985 8,618 349 314 24,266 26,797 — — 143 — 157 — 300 — 292 — 1,202 — 1,203 1,149 1,287 1,431 8,691 8,566 11,181 11,146 2,747 3,603 33,122 35,225 Geographical Financial Information Con’t China Other International Total 2019 2018 2019 2018 2019 2018 1,057 1,149 — — 20,117 21,919 (59 ) (66 ) — — (323 ) (335 ) — — — — 189 668 998 1,083 — — 19,983 22,252 142 128 — — 142 128 39 57 5 5 643 997 2,938 3,030 2 1 23,623 25,800 2 — — — 1,202 — — — — — 656 690 — — 516 650 1,182 1,319 — — — — 212 243 — — 19 26 524 360 3,121 3,215 542 682 28,184 29,537 Disaggregation of Revenue Upstream ($ millions) Exploration and Production Infrastructure and Marketing Total Years ended December 31, 2019 2018 2019 2018 2019 2018 Primary Geographical Markets Canada 3,901 3,181 2,342 2,211 6,243 5,392 United States — — — — — — China 1,057 1,149 — — 1,057 1,149 Total revenue 4,958 4,330 2,342 2,211 7,300 6,541 Major Product Lines Light & medium crude oil 670 948 — — 670 948 Heavy crude oil 603 527 — — 603 527 Bitumen 2,302 1,367 — — 2,302 1,367 Total crude oil 3,575 2,842 — — 3,575 2,842 NGL 291 381 — — 291 381 Natural gas 1,092 1,107 — — 1,092 1,107 Total exploration and production 4,958 4,330 — — 4,958 4,330 Total infrastructure and marketing — — 2,342 2,211 2,342 2,211 Synthetic crude — — — — — — Gasoline — — — — — — Diesel & distillates — — — — — — Asphalt — — — — — — Other — — — — — — Total refined products — — — — — — Total revenue 4,958 4,330 2,342 2,211 7,300 6,541 Disaggregation of Revenue Con’t Downstream Corporate and Eliminations Total Upgrading Canadian Refined Products U.S. Refining and Marketing Total 2019 2018 2019 2018 2019 2018 2019 2018 2019 2018 2019 2018 1,777 1,750 3,122 3,412 — — 4,899 5,162 (2,022 ) (1,554 ) 9,120 9,000 — — — — 9,940 11,770 9,940 11,770 — — 9,940 11,770 — — — — — — — — — — 1,057 1,149 1,777 1,750 3,122 3,412 9,940 11,770 14,839 16,932 (2,022 ) (1,554 ) 20,117 21,919 — — — — — — — — — — 670 948 — — — — — — — — — — 603 527 — — — — — — — — — — 2,302 1,367 — — — — — — — — — — 3,575 2,842 — — — — — — — — — — 291 381 — — — — — — — — — — 1,092 1,107 — — — — — — — — — — 4,958 4,330 — — — — — — — — — — 2,342 2,211 1,505 1,445 — — — — 1,505 1,445 — — 1,505 1,445 — — 904 1,070 5,414 6,157 6,318 7,227 — — 6,318 7,227 260 278 1,152 1,303 3,644 4,297 5,056 5,878 — — 5,056 5,878 — — 452 454 136 165 588 619 — — 588 619 12 27 614 585 746 1,151 1,372 1,763 — — 1,372 1,763 1,777 1,750 3,122 3,412 9,940 11,770 14,839 16,932 — — 14,839 16,932 1,777 1,750 3,122 3,412 9,940 11,770 14,839 16,932 (2,022 ) (1,554 ) 20,117 21,919

Accounts Receivable (Tables)

Accounts Receivable (Tables)	12 Months Ended
	Dec. 31, 2019
Subclassifications of assets, liabilities and equities [abstract]
Accounts Receivable	Accounts Receivable ($ millions) December 31, 2019 December 31, 2018 Trade receivables 1,327 1,146 Provision for expected credit losses (34 ) (39 ) Derivatives due within one year 38 43 Other (1) 168 205 End of year 1,499 1,355 (1) Includes insurance proceeds of $114 million (2018 – $143 million ), related to the Superior Refinery incident.

Inventories (Tables)

Inventories (Tables)	12 Months Ended
	Dec. 31, 2019
Subclassifications of assets, liabilities and equities [abstract]
Schedule of Inventories	Inventories ($ millions) December 31, 2019 December 31, 2018 Crude oil, natural gas and NGL 627 445 Refined petroleum products 553 435 Trading inventories measured at fair value less costs to sell 155 200 Materials, supplies and other 151 152 End of year 1,486 1,232

Exploration and Evaluation Co_2

Exploration and Evaluation Costs (Tables)	12 Months Ended
	Dec. 31, 2019
Subclassifications of assets, liabilities and equities [abstract]
Disclosure of detailed information about exploration and evaluation assets	Exploration and Evaluation Assets ($ millions) 2019 2018 Beginning of year 997 838 Additions 46 287 Disposals — (23 ) Transfers to property, plant and equipment (note 9) (44 ) (79 ) Expensed exploration expenditures previously capitalized (355 ) (29 ) Exchange adjustments (1 ) 3 End of year 643 997 Property, Plant and Equipment Oil and Gas Properties Processing, Upgrading Refining Retail and Other Total ($ millions) Cost December 31, 2017 41,815 86 2,599 9,191 2,930 56,621 Additions 2,465 12 62 744 151 3,434 Acquisitions 64 — — 3 — 67 Transfers from exploration and evaluation (note 8) 79 — — — — 79 Intersegment transfers — — — (5 ) 5 — Changes in asset retirement obligations (note 17) 43 2 (2 ) (5 ) 7 45 Disposals and derecognition (632 ) — — (10 ) (1 ) (643 ) Exchange adjustments 362 1 — 773 3 1,139 December 31, 2018 44,196 101 2,659 10,691 3,095 60,742 Transfers to right-of-use assets (1) (note 10) (336 ) — — (180 ) — (516 ) Additions (2) 2,340 2 58 899 160 3,459 Acquisitions 10 — — — — 10 Transfers from exploration and evaluation (note 8) 44 — — — — 44 Transfers from right-of-use assets (3) (note 10) 101 — — — — 101 Intersegment transfers 2 — — 27 (29 ) — Changes in asset retirement obligations (note 17) 469 1 5 19 23 517 Disposals and derecognition (16 ) (2 ) (1 ) (943 ) (2 ) (964 ) Exchange adjustments (223 ) (1 ) — (496 ) (2 ) (722 ) December 31, 2019 46,587 101 2,721 10,017 3,245 62,671 Accumulated depletion, depreciation, amortization and impairment December 31, 2017 (26,016 ) (47 ) (1,462 ) (3,176 ) (1,842 ) (32,543 ) Depletion, depreciation, amortization and impairment (1,811 ) (2 ) (123 ) (503 ) (152 ) (2,591 ) Disposals and derecognition 586 — — 10 — 596 Exchange adjustments (138 ) (1 ) — (264 ) (1 ) (404 ) December 31, 2018 (27,379 ) (50 ) (1,585 ) (3,933 ) (1,995 ) (34,942 ) Transfers to right-of-use assets (1) (note 10) 12 — — 40 — 52 Depletion, depreciation, amortization and impairment (4,082 ) (2 ) (115 ) (736 ) (239 ) (5,174 ) Intersegment transfers — — — (17 ) 17 — Disposals and derecognition 8 — — 724 2 734 Exchange adjustments 93 1 — 187 1 282 December 31, 2019 (31,348 ) (51 ) (1,700 ) (3,735 ) (2,214 ) (39,048 ) Net book value December 31, 2018 16,817 51 1,074 6,758 1,100 25,800 December 31, 2019 15,239 50 1,021 6,282 1,031 23,623
Disclosure of exploration and evaluation expenses	The following exploration and evaluation expenses for the years ended December 31, 2019 and 2018 relate to activities associated with the exploration for and evaluation of crude oil and natural gas resources and were recorded in the Upstream Exploration and Production business. Exploration and Evaluation Expense Summary ($ millions) 2019 2018 Seismic, geological and geophysical 131 102 Expensed drilling 409 41 Expensed land 7 6 547 149

Property, Plant and Equipment (

Property, Plant and Equipment (Tables)	12 Months Ended
	Dec. 31, 2019
Subclassifications of assets, liabilities and equities [abstract]
Disclosure of detailed information about property, plant and equipment	Exploration and Evaluation Assets ($ millions) 2019 2018 Beginning of year 997 838 Additions 46 287 Disposals — (23 ) Transfers to property, plant and equipment (note 9) (44 ) (79 ) Expensed exploration expenditures previously capitalized (355 ) (29 ) Exchange adjustments (1 ) 3 End of year 643 997 Property, Plant and Equipment Oil and Gas Properties Processing, Upgrading Refining Retail and Other Total ($ millions) Cost December 31, 2017 41,815 86 2,599 9,191 2,930 56,621 Additions 2,465 12 62 744 151 3,434 Acquisitions 64 — — 3 — 67 Transfers from exploration and evaluation (note 8) 79 — — — — 79 Intersegment transfers — — — (5 ) 5 — Changes in asset retirement obligations (note 17) 43 2 (2 ) (5 ) 7 45 Disposals and derecognition (632 ) — — (10 ) (1 ) (643 ) Exchange adjustments 362 1 — 773 3 1,139 December 31, 2018 44,196 101 2,659 10,691 3,095 60,742 Transfers to right-of-use assets (1) (note 10) (336 ) — — (180 ) — (516 ) Additions (2) 2,340 2 58 899 160 3,459 Acquisitions 10 — — — — 10 Transfers from exploration and evaluation (note 8) 44 — — — — 44 Transfers from right-of-use assets (3) (note 10) 101 — — — — 101 Intersegment transfers 2 — — 27 (29 ) — Changes in asset retirement obligations (note 17) 469 1 5 19 23 517 Disposals and derecognition (16 ) (2 ) (1 ) (943 ) (2 ) (964 ) Exchange adjustments (223 ) (1 ) — (496 ) (2 ) (722 ) December 31, 2019 46,587 101 2,721 10,017 3,245 62,671 Accumulated depletion, depreciation, amortization and impairment December 31, 2017 (26,016 ) (47 ) (1,462 ) (3,176 ) (1,842 ) (32,543 ) Depletion, depreciation, amortization and impairment (1,811 ) (2 ) (123 ) (503 ) (152 ) (2,591 ) Disposals and derecognition 586 — — 10 — 596 Exchange adjustments (138 ) (1 ) — (264 ) (1 ) (404 ) December 31, 2018 (27,379 ) (50 ) (1,585 ) (3,933 ) (1,995 ) (34,942 ) Transfers to right-of-use assets (1) (note 10) 12 — — 40 — 52 Depletion, depreciation, amortization and impairment (4,082 ) (2 ) (115 ) (736 ) (239 ) (5,174 ) Intersegment transfers — — — (17 ) 17 — Disposals and derecognition 8 — — 724 2 734 Exchange adjustments 93 1 — 187 1 282 December 31, 2019 (31,348 ) (51 ) (1,700 ) (3,735 ) (2,214 ) (39,048 ) Net book value December 31, 2018 16,817 51 1,074 6,758 1,100 25,800 December 31, 2019 15,239 50 1,021 6,282 1,031 23,623
Disclosure of impairment loss recognised or reversed for cash-generating unit [text block]	The following table summarizes impairment for each CGU in downstream: CGU Impairment recorded ($ millions) Minnedosa Ethanol Plant 78 Lloydminster Ethanol Plant 12 Downstream CGUs total 90 The following table summarizes impairment for each Upstream CGU: CGU Impairment recorded ($ millions) Northern 421 Rainbow 241 Western Canada CGUs total 662 White Rose CGU 871 Sunrise CGU 707 Upstream CGUs total 2,240
Disclosure of information for cash-generating units [text block]	The table below summarizes the forecasted prices used in determining the recoverable amounts: WTI ($US/bbl) Brent ($US/bbl) Edmonton Light ($CDN/bbl) AECO ($CDN/mcf) Foreign Exchange ($US/$CDN) 2020 61.00 66.00 72.37 2.00 0.76 2021 64.00 68.00 76.62 2.25 0.77 2022 66.00 70.00 78.85 2.50 0.78 2023 68.00 72.00 80.38 2.75 0.79 2024 70.00 74.00 82.91 2.80 0.79 2025 71.40 75.48 84.57 2.86 0.79 2026 (1) 72.83 76.99 86.26 2.91 0.79 (1) Prices are escalated at 2% thereafter.
Sensitivity analysis for types of market risk [text block]	A change in the discount rate or forward price over the life of the reserves will result in the following impact on the Upstream CGUs: Discount Rate Commodity Price ($ millions) 1% Increase in Discount Rate 1% Decrease in Discount Rate 5% Increase in Forward Price 5% Decrease in Forward Price Impairment of PP&E – Increase (Decrease) 528 (605 ) (910 ) 904

Right-of-use Assets and Lease_2

Right-of-use Assets and Lease Liabilities (Tables)	12 Months Ended
	Dec. 31, 2019
Disclosure of leases [Abstract]
Disclosure of quantitative information about right-of-use assets [text block]	Results of Operations ($ millions) December 31, 2019 Interest expense on lease liabilities (1) (note 22) 106 Expenses relating to short-term leases 18 (1) Includes $5 million of interest allocated to the carrying amount of assets in Oil and Gas Properties for the year ended December 31, 2019. Cash Flow Summary ($ millions) December 31, 2019 Total cash flow used for leases 339 Right-of-use Assets Oil and Gas Properties Processing, Upgrading Refining Retail and Other Total ($ millions) January 1, 2019 Transfers from property, plant and equipment, net (note 9) 324 — — 140 — 464 Initial recognition 721 100 — 70 412 1,303 1,045 100 — 210 412 1,767 Additions 1 — — 80 5 86 Transfers to property, plant and equipment (note 9) (101 ) — — — — (101 ) Disposals and derecognition (11 ) — — (31 ) 2 (40 ) Revaluation (194 ) 1 — (1 ) 8 (186 ) Depreciation and impairment (222 ) (11 ) — (50 ) (39 ) (322 ) Other 2 — — (4 ) — (2 ) December 31, 2019 520 90 — 204 388 1,202
Disclosure of additional information about leasing activities for lessee [text block]	Lease Liabilities Balance Sheets ($ millions) December 31, 2019 Current lease liabilities (1) 109 Non-current lease liabilities (1) 1,353 (1) Includes $489 million previously recorded in accrued liabilities and other long-term liabilities as at December 31, 2018.
Explanation of difference between operating lease commitments disclosed applying IAS 17 and lease liabilities recognised at date of initial application of IFRS 16 [text block]	Reconciliation to Operating Lease Commitments ($ millions) Operating agreements included in commitments at December 31, 2018 (1) 2,343 Expenses relating to short-term leases (9 ) Discounting (986 ) Additional lease liability recognized due to adoption of IFRS 16 on January 1, 2019 1,348 (1) Includes commitments from operating agreements, firm transportation agreements, and unconditional purchase obligations.
Disclosure of maturity analysis for non-derivative financial liabilities [text block]	Maturity Analysis Within 1 year After 1 year but no more than 5 years More than 5 years Total ($ millions) 2019 2018 (1) 2019 2018 (1) 2019 2018 (1) 2019 2018 (1) Future lease payments 205 69 653 242 2,174 1,014 3,032 1,325 Interest 96 48 352 175 1,122 613 1,570 836 Present value of lease payments 109 21 301 67 1,052 401 1,462 489 (1) Amounts for 2018 were future payments under finance leases obligations, prior to the adoption of IFRS 16.

Goodwill (Tables)

Goodwill (Tables)	12 Months Ended
	Dec. 31, 2019
Subclassifications of assets, liabilities and equities [abstract]
Disclosure of reconciliation of changes in goodwill	Goodwill ($ millions) December 31, 2019 December 31, 2018 Beginning of year 690 633 Exchange adjustments (34 ) 57 End of year 656 690

Joint Arrangements (Tables)

Joint Arrangements (Tables)	12 Months Ended
	Dec. 31, 2019
Disclosure of joint ventures [line items]
Disclosure of joint operations	The following table lists the Company’s significant subsidiaries and jointly-controlled entities and their respective places of incorporation, continuance or organization, as the case may be, and the Company’s percentage equity interest (to the nearest whole number) as at December 31, 2019. All of the entities listed below, except as otherwise indicated, are 100% beneficially owned, or controlled or directed, directly or indirectly, by the Company. Significant Subsidiaries and Joint Operations % Jurisdiction Husky Oil Operations Limited 100 Alberta Husky Energy International Corporation 100 Alberta Lima Refining Company 100 Delaware Husky Marketing and Supply Company 100 Delaware Husky Oil Limited Partnership 100 Alberta Husky Terra Nova Partnership (1) 100 Alberta Husky Downstream General Partnership (1) 100 Alberta Husky Energy Marketing Partnership 100 Alberta Sunrise Oil Sands Partnership 50 Alberta BP-Husky Refining LLC 50 Delaware (1) Dissolved effective January 1, 2020, assets were transferred to 2188787 Alberta ULC.
Husky-CNOOC Madura Ltd.
Disclosure of joint ventures [line items]
Disclosure of joint ventures	Summarized below is the financial information for Husky-CNOOC Madura Ltd. accounted for using the equity method: Results of Operations ($ millions, except share of equity investment) 2019 2018 Revenues 424 441 Expenses (267 ) (273 ) Net earnings 157 168 Share of equity investment 40 % 40 % Proportionate share of equity investment 50 51 Balance Sheets ($ millions, except share of equity investment) December 31, 2019 December 31, 2018 Current assets (1) 208 373 Non-current assets 1,840 2,072 Current liabilities (70 ) (123 ) Non-current liabilities (2) (1,427 ) (1,917 ) Net assets 551 405 Share of net assets 40 % 40 % Carrying amount in balance sheet 516 650 (1) Includes cash and cash equivalents of $ 42 million ( 2018 – $ 203 million ). (2) Includes deferred revenue of nil (2018 – $2 million ) related to take-or-pay commitments, with respect to natural gas production volumes from the BD Project, not taken by the purchaser. As per the terms of the agreement, the purchaser has until the end of the agreement to take these volumes.
BP-Husky Refining LLC
Disclosure of joint ventures [line items]
Disclosure of joint ventures	Summarized below is the financial information for HMLP accounted for using the equity method: Results of Operations ($ millions, except share of equity investment) 2019 2018 Revenues 316 296 Expenses (228 ) (177 ) Net earnings 88 119 Share of equity investment 35 % 35 % Proportionate share of equity investment 9 18 Balance Sheet ($ millions, except share of net assets) December 31, 2019 December 31, 2018 Current assets (1) 171 115 Non-current assets 3,031 2,849 Current liabilities (163 ) (153 ) Non-current liabilities (1,059 ) (825 ) Net assets 1,980 1,986 Share of net assets 35 % 35 % Carrying amount in balance sheet 666 669 (1) Current assets include cash and cash equivalents of $ 86 million ( 2018 – $16 million ).

Other Assets (Tables)

Other Assets (Tables)	12 Months Ended
	Dec. 31, 2019
Miscellaneous non-current assets [abstract]
Schedule of other assets	Other Assets ($ millions) December 31, 2019 December 31, 2018 Long-term receivables (1) 489 319 Precious metals 22 23 Other 13 18 End of year 524 360 (1) Includes insurance proceeds of $435 million (2018 – $253 million ), related to the Superior Refinery incident. For the year ended December 31, 2019, the Company accrued pre-tax recoveries for rebuild costs, incident costs and business interruption associated with the Superior Refinery incident of $630 million (December 31, 2018 – $468 million ), which is included in other-net in the consolidated statements of income (loss).

Accounts Payable and Accrued _2

Accounts Payable and Accrued Liabilities (Tables)	12 Months Ended
	Dec. 31, 2019
Subclassifications of assets, liabilities and equities [abstract]
Schedule of accounts payable and accrued liabilities	Accounts Payable and Accrued Liabilities ($ millions) December 31, 2019 December 31, 2018 Trade payables 1,178 1,121 Accrued liabilities 1,954 1,712 Dividend payable (note 20) 126 126 Stock-based compensation 19 32 Derivatives due within one year 21 39 Other 167 129 End of year 3,465 3,159

Debt and Credit Facilities (Tab

Debt and Credit Facilities (Tables)	12 Months Ended
	Dec. 31, 2019
Disclosure of borrowing costs [Abstract]
Schedule of short-term debt	Short-term Debt December 31, 2019 December 31, 2018 ($ millions) Commercial paper (1) 550 200 (1) The commercial paper is supported by the Company’s syndicated credit facilities and the Company is authorized to issue commercial paper up to a maximum of $1.0 billion having a term not to exceed 365 days. The weighted average interest rate as at December 31, 2019 was 1.98% per annum ( December 31, 2018 – 2.20% ).
Schedule of long-term debt	Canadian $ Amount U.S. $ Denominated Long-term Debt Maturity December 31, 2019 December 31, 2018 December 31, 2019 December 31, 2018 ($ millions) Long-term debt 5.00% notes (5) 2020 — 400 — — 3.95% notes (1)(4) 2022 648 682 500 500 4.00% notes (1)(4) 2024 973 1,023 750 750 3.55% notes (5) 2025 750 750 — — 3.60% notes (5) 2027 750 750 — — 4.40% notes (1)(4) 2029 973 — 750 — 6.80% notes (1)(4) 2037 501 528 387 387 Debt issue costs (2) (25 ) (19 ) — — Long-term debt 4,570 4,114 2,387 1,637 Long-term debt due within one year 6.15% notes (1)(3) 2019 — 410 — 300 7.25% notes (1)(4) 2019 — 1,023 — 750 5.00% notes (5) 2020 400 — — — Long-term debt due within one year 400 1,433 — 1,050 (1) The U.S. dollar denominated debt is designated as a hedge of the Company’s net investment in selected foreign operations with a U.S. dollar functional currency. Refer to Note 25 for Foreign Currency Risk Management. (2) Calculated using the effective interest rate method. (3) The 6.15% notes represent unsecured securities under a trust indenture dated June 14, 2002. (4) The 7.25% , the 3.95% , the 4.00% , the 4.40% and the 6.80% notes represent unsecured securities under a trust indenture dated September 11, 2007. (5) The 5.00% , the 3.55% and the 3.60% notes represent unsecured securities under a trust indenture dated December 21, 2009.
Reconciliation of changes of liabilities to cash flows from financing activities	Reconciliation of Changes of Liabilities to Cash Flows from Financing Activities Liabilities ($ millions) Short-term debt Long-term debt due within one year Long-term debt Other long-term liabilities Lease liabilities due within one year Lease liabilities December 31, 2018 200 1,433 4,114 1,107 — — Changes from financing cash flows Long-term debt issuance — — 1,000 — — — Long-term debt repayment — (1,389 ) — — — — Short-term debt issuance, net 350 — — — — — Debt issue costs — — (9 ) — — — Finance lease payments — — — — (233 ) — Total change from financing cash flows 350 (1,389 ) 991 — (233 ) — Other changes – liability-related Initial recognition of lease liabilities (note 10) — — — (467 ) 22 1,815 Foreign exchange — — (8 ) (12 ) — (3 ) Fair value changes — — — (4 ) — (240 ) Net additions of lease liabilities — — — — — 89 Reclassification — 400 (400 ) (114 ) 319 (319 ) Deferred revenue — — — (42 ) — — Amortization of debt issuance costs — — 5 — — — Foreign exchange recognized in OCI — (44 ) (132 ) — — — Other — — — (14 ) 1 11 Total other changes – liability related — 356 (535 ) (653 ) 342 1,353 December 31, 2019 550 400 4,570 454 109 1,353

Asset Retirement Obligations (T

Asset Retirement Obligations (Tables)	12 Months Ended
	Dec. 31, 2019
Subclassifications of assets, liabilities and equities [abstract]
Reconciliation of the carrying amount of asset retirement obligations	A reconciliation of the carrying amount of asset retirement obligations at December 31, 2019 and 2018 is set out below: Asset Retirement Obligations ($ millions) 2019 2018 Beginning of year 2,424 2,526 Additions 76 40 Liabilities settled (276 ) (270 ) Liabilities disposed (6 ) (11 ) Change in discount rate 285 (68 ) Change in estimates 156 93 Exchange adjustment (10 ) 17 Accretion (note 22) 106 97 End of year 2,755 2,424 Expected to be incurred within 1 year 112 202 Expected to be incurred beyond 1 year 2,643 2,222

Other Long-term Liabilities (Ta

Other Long-term Liabilities (Tables)	12 Months Ended
	Dec. 31, 2019
Subclassifications of assets, liabilities and equities [abstract]
Schedule of other long-term liabilities	Other Long-term Liabilities ($ millions) December 31, 2019 December 31, 2018 Employee future benefits (note 23) 214 205 Finance lease obligations (note 10) — 467 Stock-based compensation 19 42 Deferred revenue 152 205 Other 69 188 End of year 454 1,107
Schedule of Deferred Revenue [Table Text Block]	Deferred revenue Deferred revenue relates to take-or-pay commitments, with respect to natural gas production volumes from the Liwan 3-1 field in Asia Pacific, not taken by the purchaser. As per the terms of the agreement, the purchaser has until the end of the agreement to take these volumes. ($ millions) December 31, 2019 December 31, 2018 Beginning of year 205 284 Revenue recognized (42 ) (100 ) Exchange adjustment (11 ) 21 End of year 152 205

Income Taxes (Tables)

Income Taxes (Tables)	12 Months Ended
	Dec. 31, 2019
Disclosure of income tax [Abstract]
Disclosure of income tax expense (recovery)	The major components of income tax expense (recovery) for the years ended December 31, 2019 and 2018 were as follows: Income Tax Expense (Recovery) ($ millions) 2019 2018 Current income tax Current income tax charge 174 86 Adjustments to current income tax estimates 1 (11 ) 175 75 Deferred income tax Relating to origination and reversal of temporary differences (723 ) 378 Adjustments to deferred income tax estimates (251 ) 18 (974 ) 396
Disclosure of deferred tax items in OCI	Deferred Tax Items in OCI ($ millions) 2019 2018 Deferred tax items expensed (recovered) directly in OCI Derivatives designated as cash flow hedges (3 ) (5 ) Remeasurement of pension plans 1 17 Exchange differences on translation of foreign operations (58 ) 87 Hedge of net investment 30 (41 ) (30 ) 58
Disclosure of reconciliation of effective tax rate	The provision for income taxes in the consolidated statements of income (loss) reflects an effective tax rate which differs from the expected statutory tax rate. Differences for the years ended December 31, 2019 and 2018 were accounted for as follows: Reconciliation of Effective Tax Rate ($ millions, except tax rate) 2019 2018 Earnings (loss) before income taxes Canada (3,170 ) 734 United States 337 493 Other foreign jurisdictions 664 701 (2,169 ) 1,928 Statutory Canadian income tax rate 26.8 % 27.2 % Expected income tax (582 ) 525 Effect on income tax resulting from: Foreign jurisdictions 61 (36 ) Non-taxable items (25 ) (13 ) Adjustments with respect to previous year (250 ) 7 Revaluation of foreign tax pools (4 ) (4 ) Other – net 1 (8 ) Income tax expense (recovery) (799 ) 471
Disclosure of deferred tax liabilities and assets	The following reconciles the movements in the deferred income tax liabilities and assets: Deferred Tax Liabilities and Assets ($ millions) January 1, 2019 Recognized in Earnings Recognized in OCI Other December 31, 2019 Deferred tax liabilities Exploration and evaluation assets and property, plant and equipment (4,089 ) 967 69 — (3,053 ) Foreign exchange gains taxable on realization (174 ) 51 (27 ) — (150 ) Debt issue costs (4 ) (1 ) — — (5 ) Other temporary differences (28 ) (124 ) — — (152 ) Deferred tax assets Pension plans 8 9 (1 ) — 16 Asset retirement obligations 654 16 (4 ) — 666 Loss carry-forwards 468 56 (7 ) — 517 Financial assets at fair value (9 ) — — — (9 ) (3,174 ) 974 30 — (2,170 ) Deferred Tax Liabilities and Assets ($ millions) January 1, 2018 Recognized in Earnings Recognized in OCI Other December 31, 2018 Deferred tax liabilities Exploration and evaluation assets and property, plant and equipment (3,727 ) (260 ) (106 ) 4 (4,089 ) Foreign exchange gains taxable on realization (177 ) (43 ) 46 — (174 ) Debt issue costs (3 ) (1 ) — — (4 ) Other temporary differences (90 ) 62 — — (28 ) Deferred tax assets Pension plans 40 (15 ) (17 ) — 8 Asset retirement obligations 679 (29 ) 4 — 654 Loss carry-forwards 523 (70 ) 15 — 468 Financial assets at fair value 31 (40 ) — — (9 ) (2,724 ) (396 ) (58 ) 4 (3,174 )

Share Capital (Tables)

Share Capital (Tables)	12 Months Ended
	Dec. 31, 2019
Disclosure of share capital, reserves and other equity interest [Abstract]
Disclosure of classes of share capital	The Company is authorized to issue an unlimited number of no par value preferred shares. Cumulative Redeemable Preferred Shares Number of Shares Amount ($ millions) December 31, 2017 36,000,000 874 December 31, 2018 36,000,000 874 December 31, 2019 36,000,000 874 Cumulative Redeemable Preferred Shares Dividends ($ millions) 2019 2018 Declared Paid Declared Paid Series 1 Preferred Shares 6 6 6 8 Series 2 Preferred Shares 1 1 1 1 Series 3 Preferred Shares 12 12 12 14 Series 5 Preferred Shares 9 9 9 11 Series 7 Preferred Shares 7 7 7 9 35 35 35 43 The following table lists the assumptions used in the Black-Scholes option pricing model for the share options and performance options: Black-Scholes Assumptions December 31, 2019 December 31, 2018 Tandem Options Tandem Options Dividend per option 0.42 0.56 Range of expected volatilities used (percent) 27.5 - 35.5 16.8 - 44.4 Range of risk-free interest rates used (percent) 1.66 - 1.74 1.6 - 1.9 Expected life of share options from vesting date (years) 1.97 1.95 Expected forfeiture rate (percent) 8.8 8.9 Weighted average exercise price 18.19 22.46 Weighted average fair value 0.25 0.65 Earnings (loss) per Share ($ millions) 2019 2018 Net earnings (loss) (1,370 ) 1,457 Effect of dividends declared on preferred shares in the year (35 ) (35 ) Net earnings (loss) – basic (1,405 ) 1,422 Dilutive effect of accounting for stock options (1) (15 ) (13 ) Net earnings (loss) – diluted (1,420 ) 1,409 (millions) Weighted average common shares outstanding – basic 1,005.1 1,005.1 Effect of stock dividends declared in the year — 1.0 Weighted average common shares outstanding – diluted 1,005.1 1,006.1 Earnings (loss) per share – basic ($/share) (1.40 ) 1.41 Earnings (loss) per share – diluted ($/share) (1.41 ) 1.40 (1) For the year ended December 31, 2019 , equity-settlement of stock options was used to calculate diluted earnings (loss) per share as it was considered more dilutive than cash-settlement (December 31, 2018 – equity-settlement method was used). Stock-based compensation recovery was $6 million based on cash-settlement for the year ended December 31, 2019 ( 2018 – recovery of $3 million). Stock-based compensation expense would have been $9 million based on equity-settlement for the year ended December 31, 2019 ( 2018 – $10 million). The Company is authorized to issue an unlimited number of no par value common shares. Common Shares Number of Shares Amount ($ millions) December 31, 2017 1,005,120,012 7,293 Options exercised (1) 1,726 — December 31, 2018 1,005,121,738 7,293 December 31, 2019 1,005,121,738 7,293 (1) Stock options exercised was less than $1 million. Quarterly dividends may be declared in an amount expressed in dollars per common share or could be paid by way of issuance of a fraction of a common share per outstanding common share determined by dividing the dollar amount of the dividend by the volume-weighted average trading price of the Common Shares on the principal stock exchange on which the common shares are traded. The volume-weighted average trading price of the common shares is calculated by dividing the total value by the total volume of common shares traded over the five trading day period immediately prior to the payment date of the dividend on the common shares. Common Share Dividends ($ millions) 2019 2018 Declared Paid Declared Paid 503 503 402 276 The following options to purchase common shares have been awarded to officers and certain other employees: Outstanding and Exercisable Options 2019 2018 Number of Options (thousands) Weighted Average ($) Number of Options (thousands) Weighted Average ($) Outstanding, beginning of year 19,967 21.48 22,645 23.96 Granted (1) 4,241 14.31 5,610 17.21 Exercised for common shares — — (2 ) 15.67 Surrendered for cash (4 ) 15.67 (1,772 ) 15.82 Expired or forfeited (5,706 ) 28.27 (6,514 ) 27.69 Outstanding, end of year 18,498 17.75 19,967 21.48 Exercisable, end of year 10,596 19.27 10,461 25.87 (1) Options granted during the year ended December 31, 2019 were attributed a fair value of $2.34 per option (December 31, 2018 – $2.90 ) at grant date. Outstanding and Exercisable Options Outstanding Options Exercisable Options Range of Exercise Price Number of Options (thousands) Weighted Average Exercise Prices ($) Weighted Average (years) Number of Options (thousands) Weighted Average Exercise Prices ($) $9.28 - $16.31 10,341 15.34 2.65 5,350 15.86 $16.32 - $25.41 8,157 20.80 1.86 5,246 22.75 December 31, 2019 18,498 17.75 2.30 10,596 19.27 The number of PSUs outstanding was as follows: Performance Share Units 2019 2018 Beginning of year 11,606,644 8,361,918 Granted 7,673,960 6,108,430 Exercised (2,429,816 ) (1,354,316 ) Forfeited (2,532,146 ) (1,509,388 ) Outstanding, end of year 14,318,642 11,606,644 Vested, end of year 3,264,840 4,487,585

Production, Operating and Tra_2

Production, Operating and Transportation and Selling, General, and Administrative Expenses (Tables)	12 Months Ended
	Dec. 31, 2019
Analysis of income and expense [abstract]
Disclosure of production, operating and transportation expenses	The following table summarizes production, operating and transportation expenses in the consolidated statements of income (loss) for the years ended December 31, 2019 and 2018 : Production, Operating and Transportation Expenses ($ millions) 2019 2018 Services and support costs 1,255 1,039 Salaries and benefits 773 762 Materials, equipment rentals and leases 250 243 Energy and utility 482 405 Licensing fees 204 191 Transportation 17 24 Other 36 139 Total production, operating and transportation expenses 3,017 2,803
Disclosure of general and administrative expense	The following table summarizes selling, general and administrative expenses in the consolidated statements of income (loss) for the years ended December 31, 2019 and 2018 : Selling, General and Administrative Expenses ($ millions) 2019 2018 Employee costs (1) 450 332 Stock-based compensation expense (recovery) (2) (2 ) 44 Contract services 133 104 Equipment rentals and leases 11 39 Maintenance and other 101 135 Total selling, general and administrative expenses 693 654 (1) Employee costs are comprised of salary and benefits earned during the year, plus cash bonuses awarded during the year. Annual bonus awards settled in shares are included in stock-based compensation expense. (2) Stock-based compensation expense represents the cost to the Company for participation in share-based payment plans.

Financial Items (Tables)

Financial Items (Tables)	12 Months Ended
	Dec. 31, 2019
Disclosure of additional information [Abstract]
Schedule of financial items	Financial Items ($ millions) 2019 2018 Foreign exchange gain (loss) Non-cash working capital 17 (3 ) Other foreign exchange 27 17 Net foreign exchange gain 44 14 Finance income 74 64 Finance expenses Long-term debt (310 ) (320 ) Lease liabilities (1) (note 10) (106 ) — Other (6 ) (5 ) (422 ) (325 ) Interest capitalized (2) 177 108 (245 ) (217 ) Accretion of asset retirement obligations (note 17) (106 ) (97 ) Finance expenses (351 ) (314 ) Total Financial Items (233 ) (236 ) (1) Includes $5 million of interest allocated to the carrying amount of assets in Oil and Gas Properties. (2) Interest capitalized on project costs is calculated using the Company’s annualized effective interest rate of 5 % ( 2018 – 5 %).

Pensions and Other Post-emplo_2

Pensions and Other Post-employment Benefits (Tables)	12 Months Ended
	Dec. 31, 2019
Disclosure of employee benefits [Abstract]
Disclosure of net benefit obligation	Defined Benefit Obligations DB Pension Plans OPEB Plans ($ millions) 2019 2018 2019 2018 Beginning of year 79 76 199 244 Current service cost — 1 10 11 Interest cost 2 3 7 8 Benefits paid (3 ) (2 ) (4 ) (4 ) Past service cost 3 — (29 ) — Settlements (49 ) — — — Remeasurements Actuarial (gain) loss – experience — 2 (1 ) (13 ) Actuarial (gain) loss – financial assumptions 9 (4 ) 20 (45 ) Effect of changes in foreign exchange rates (2 ) 3 (1 ) (2 ) End of year 39 79 201 199 Fair Value of Plan Assets DB Pension Plans OPEB Plans ($ millions) 2019 2018 2019 2018 Beginning of year 71 67 — — Contributions by employer (1 ) 1 2 2 Benefits paid (3 ) (2 ) (2 ) (2 ) Interest income 2 2 — — Return on plan assets greater than discount rate 16 — — — Settlements (52 ) — — — Effect of changes in foreign exchange rates (2 ) 3 — — End of year 31 71 — — Funded status DB Pension Plans OPEB Plans ($ millions) 2019 2018 2019 2018 Net asset (liability) (8 ) (8 ) (201 ) (199 )
Disclosure of pension plan assets	The composition of the DB Pension Plan assets at December 31, 2019 and 2018 was as follows: DB Pension Plan Assets (percent) Target allocation range 2019 2018 Money market type funds — — 5 Equity securities 35 35 — Debt securities 65 65 95
Disclosure of a defined benefit amount recognized in net earnings and OCI	The following table summarizes amounts recognized in net earnings (loss) and OCI for the DB Pension Plans and the OPEB Plans for the years ended December 31, 2019 and 2018 : DB Pension Plans OPEB Plans ($ millions) 2019 2018 2019 2018 Amounts recognized in net earnings (loss) Current service cost — 1 10 11 Past service cost 3 — (29 ) — Net Interest cost — 1 7 8 Benefit cost 3 2 (12 ) 19 Remeasurements Actuarial loss (gain) due to liability experience — 2 (1 ) (13 ) Actuarial loss (gain) due to liability assumption changes 9 (4 ) 20 (45 ) (Gain) loss on plan assets (16 ) — — — Remeasurement effects recognized in OCI (7 ) (2 ) 19 (58 )
Disclosure of actuarial assumptions and sensitivity analysis	The sensitivity of the defined benefit and OPEB obligations to changes in relevant actuarial assumption is shown below: Sensitivity Analysis DB Pension Plans OPEB Plans ($ millions) 1% increase 1% decrease 1% increase 1% decrease Discount rate (4 ) 5 (23 ) 28 Health care cost trend rate N/A N/A (16 ) 18 The following long-term assumptions were used to estimate the value of the defined benefit obligations, the plan assets and the OPEB Plans: Assumptions DB Pension Plans OPEB Plans (percent) 2019 2018 2019 2018 Discount rate for benefit expense and obligation 2.3 - 4.2 3.4 - 3.6 3.0 - 3.7 3.4 - 3.7 Rate of compensation expense 3.5 N/A N/A N/A

Cash Flows - Change in Non-ca_2

Cash Flows - Change in Non-cash Working Capital (Tables)	12 Months Ended
	Dec. 31, 2019
Disclosure of cash flow statement [Abstract]
Disclosure Of Changes In Non-Cash Working Capital	Non-cash Working Capital ($ millions) 2019 2018 Decrease (increase) in non-cash working capital Accounts receivable (176 ) 127 Inventories (502 ) 393 Prepaid expenses (30 ) 30 Accounts payable and accrued liabilities 604 (65 ) Change in non-cash working capital (104 ) 485 Relating to: Operating activities (280 ) 130 Financing activities 3 120 Investing activities 173 235

Financial Instruments and Ris_2

Financial Instruments and Risk Management (Tables)	12 Months Ended
	Dec. 31, 2019
Disclosure of detailed information about financial instruments [abstract]
Disclosure of detailed information about hedged items [text block]	During the year ended December 31, 2019, the Company entered into a commodity short-term hedging program using put and call options to manage risks related to volatility of commodity prices. Western Texas Intermediate Crude Oil Call and Put Option Contracts (1) Type Transaction Term Volume (bbls/day) Call Price (US$bbl) Put Price (US$bbl) Call options Sold January - March 2020 35,714 60.50 — Put options Bought January - March 2020 36,263 — 55.61 Put options Sold January - March 2020 20,055 — 50.77 (1) Prices reported are the weighted average prices for the period.
Disclosure of financial instruments that are carried at fair value	The following table summarizes the Company’s financial instruments that are carried at fair value in the consolidated balance sheets: Financial Instruments at Fair Value ($ millions) December 31, 2019 December 31, 2018 Commodity contracts – fair value through profit or loss (“FVTPL”) Natural gas (1) 31 (9 ) Crude oil (2) 11 89 Crude oil call options (3) (2 ) — Crude oil put options (3) (4 ) — Foreign currency contracts – FVTPL Foreign currency forwards 2 (1 ) Other assets – FVTPL 1 1 End of year 39 80 (1) Natural gas contracts includes a $4 million decrease at December 31, 2019 ( December 31, 2018 – $10 million decrease ) to the fair value of held-for-trading inventory, recognized in the consolidated balance sheets, related to third party physical purchase and sale contracts for natural gas held in storage. Total fair value of the related natural gas storage inventory was $19 million at December 31, 2019 ( December 31, 2018 – $15 million ). (2) Crude oil contracts includes a $12 million increase at December 31, 2019 ( December 31, 2018 – $67 million increase ) to the fair value of held-for-trading inventory, recognized in the consolidated balance sheets, related to third party crude oil physical purchase and sale contracts. Total fair value of the related crude oil inventory was $136 million at December 31, 2019 ( December 31, 2018 – $185 million ). (3) Excludes net unsettled premiums of $6 million .
Disclosure of offsetting of financial assets and financial liabilities [text block]	The tables below outline the financial assets and financial liabilities that are subject to set-off rights and related arrangements, and the effect of those rights and arrangements on the consolidated balance sheets: As at December 31, 2019 Offsetting Financial Assets and Liabilities ($ millions) Gross Amount Amount Offset Net Amount Financial Assets Financial derivatives 79 (26 ) 53 Normal purchase and sale agreements 817 (274 ) 543 End of year 896 (300 ) 596 Financial Liabilities Financial derivatives (48 ) 25 (23 ) Normal purchase and sale agreements (843 ) 281 (562 ) End of year (891 ) 306 (585 ) As at December 31, 2018 Offsetting Financial Assets and Liabilities ($ millions) Gross Amount Amount Offset Net Amount Financial Assets Financial derivatives 188 (120 ) 68 Normal purchase and sale agreements 625 (335 ) 290 End of year 813 (455 ) 358 Financial Liabilities Financial derivatives (107 ) 62 (45 ) Normal purchase and sale agreements (756 ) 307 (449 ) End of year (863 ) 369 (494 )
Disclosure of nature and extent of risks arising from financial instruments [text block]	Commodity Price Risk (1) ($ millions) 10% price increase 10% price decrease Crude oil price 13 (13 ) Natural gas price (2 ) 2 Foreign Exchange Rate (2) Canadian dollar Canadian dollar ($ millions) U.S. dollar per Canadian dollar 1 (1 ) (1) Based on average crude oil and natural gas market prices as at December 31, 2019 . (2) Based on the U.S./Canadian dollar exchange rate as at December 31, 2019 .
Analysis of age of financial assets that are past due but not impaired [text block]	The Company’s accounts receivable was aged as follows at December 31, 2019 : Accounts Receivable Aging ($ millions) December 31, 2019 Current 1,418 Past due (1 - 30 days) 64 Past due (31 - 60 days) 4 Past due (61 - 90 days) — Past due (more than 90 days) 47 Provision for expected credit losses (34 ) 1,499
Disclosure of available credit facilities	Bank Operating Loans At December 31, 2019 , the Company had unsecured short-term borrowing lines of credit with banks totalling $900 million (1) ( December 31, 2018 – $900 million ) and letters of credit under these lines of credit totalling $436 million ( December 31, 2018 – $439 million ). As at December 31, 2019 , bank operating loans were nil ( December 31, 2018 – nil ). Interest payable is based on Bankers’ Acceptance, CAD Prime Rate, U.S. LIBOR, or U.S. Base Rates. Sunrise Oil Sands Partnership has an unsecured demand credit facility of $10 million ( December 31, 2018 – $10 million ) available for general purposes. The Company’s proportionate share of the credit facility is $5 million ( December 31, 2018 – $5 million ). As at December 31, 2019 , there was no balance outstanding under this credit facility ( December 31, 2018 – no balance). (1) Includes $125 million demand facilities available specifically for letters of credit only. The Company had the following available credit facilities as at December 31, 2019 : Credit Facilities ($ millions) Available Unused Operating facilities (1) (note 14) 900 464 Syndicated bank facilities (2) (note 16) 4,000 3,450 End of year 4,900 3,914 (1) Consists of demand credit facilities. (2) Commercial paper outstanding is supported by the Company’s Syndicated credit facilities.

Related Party Transactions (Tab

Related Party Transactions (Tables)	12 Months Ended
	Dec. 31, 2019
Disclosure of related party [Abstract]
Related party transaction	The following table lists the Company’s significant subsidiaries and jointly-controlled entities and their respective places of incorporation, continuance or organization, as the case may be, and the Company’s percentage equity interest (to the nearest whole number) as at December 31, 2019. All of the entities listed below, except as otherwise indicated, are 100% beneficially owned, or controlled or directed, directly or indirectly, by the Company. Significant Subsidiaries and Joint Operations % Jurisdiction Husky Oil Operations Limited 100 Alberta Husky Energy International Corporation 100 Alberta Lima Refining Company 100 Delaware Husky Marketing and Supply Company 100 Delaware Husky Oil Limited Partnership 100 Alberta Husky Terra Nova Partnership (1) 100 Alberta Husky Downstream General Partnership (1) 100 Alberta Husky Energy Marketing Partnership 100 Alberta Sunrise Oil Sands Partnership 50 Alberta BP-Husky Refining LLC 50 Delaware (1) Dissolved effective January 1, 2020, assets were transferred to 2188787 Alberta ULC.
Disclosure of transactions between related parties	Key management includes Directors (executive and non-executive), Executive Officers and Senior Vice Presidents of the Company. The amounts disclosed in the table below are the amounts recognized as an expense during the reporting period related to key management personnel: Compensation of Key Management Personnel ($ millions) 2019 2018 Short-term employee benefits (1) 18 17 Stock-based compensation (2) 26 33 44 50 (1) Short-term employee benefits are comprised of salary and benefits earned during the year, plus cash bonuses awarded during the year. Annual bonus awards settled in shares are included in stock-based compensation expense. (2) Stock-based compensation expense represents the cost to the Company for participation in share-based payment plans.

Commitments and Contingencies (

Commitments and Contingencies (Tables)	12 Months Ended
	Dec. 31, 2019
Commitments and Contingencies [Abstract]
Minimum Future Payments For Commitments	At December 31, 2019 , the Company had commitments that require the following minimum future payments, which are not accrued in the consolidated balance sheets: Minimum Future Payments for Commitments ($ millions) Within 1 year After 1 year but not more than 5 years More than 5 years Total Operating agreements (1) 75 310 666 1,051 Firm transportation agreements (1) 576 2,377 4,203 7,156 Unconditional purchase obligations (2) 2,224 5,517 5,143 12,884 Lease rentals and exploration work agreements 79 215 866 1,160 Obligations to fund equity investee (3) 54 290 359 703 3,008 8,709 11,237 22,954 (1) Included in operating agreements and firm transportation agreements are blending and storage agreements and transportation commitments of $1.1 billion and $1.8 billion respectively with HMLP. (2) Includes processing services, distribution services, insurance premiums, drilling services, natural gas purchases and the purchase of refined petroleum products. (3) Equity investee refers to the Company’s investment in Husky-CNOOC Madura Ltd. joint venture, which is accounted for under the equity method for consolidated financial statement purposes.

Subsequent Events (Tables)

Subsequent Events (Tables)	12 Months Ended
	Dec. 31, 2019
Disclosure of events after reporting period [Abstract]
Disclosure of operating segments [text block]	Segmented Financial Information - Reclassified Integrated Corridor ($ millions) Lloyd Heavy Oil Value Chain Oil Sands Western Canada Production U.S. Refining Canadian Refined Products Year ended December 31, 2019 2018 2019 2018 2019 2018 2019 2018 2019 2018 Gross revenues 5,117 5,308 931 405 506 661 10,250 11,777 2,425 2,752 Royalties (160 ) (137 ) (13 ) (12 ) (41 ) (58 ) — — — — Marketing and other 60 458 4 166 101 86 24 (42 ) — — Revenues, net of royalties 5,017 5,629 922 559 566 689 10,274 11,735 2,425 2,752 Expenses Purchases of crude oil and products 1,829 2,217 528 306 39 140 8,935 10,342 2,174 2,435 Production, operating and transportation expenses 1,209 1,121 140 132 308 302 869 795 153 151 Selling, general and administrative expenses 154 129 27 28 105 106 51 40 9 10 Depletion, depreciation, amortization and impairment 941 887 938 95 1,034 292 735 450 83 80 Exploration and evaluation expenses 54 32 2 18 111 28 — — — — Loss (gain) on sale of assets — (1 ) — — (2 ) (1 ) 1 — (6 ) (2 ) Other – net 103 (106 ) (28 ) — 2 5 (654 ) (464 ) — (1 ) 4,290 4,279 1,607 579 1,597 872 9,937 11,163 2,413 2,673 Earnings (loss) from operating activities 727 1,350 (685 ) (20 ) (1,031 ) (183 ) 337 572 12 79 Share of equity investment income 9 18 — — — — — — — — Financial items Net foreign exchange gain (loss) — — — — — — — — — — Finance income — — — — — — — — — — Finance expenses (48 ) (43 ) (59 ) (21 ) (24 ) (19 ) (18 ) (14 ) (13 ) (11 ) (48 ) (43 ) (59 ) (21 ) (24 ) (19 ) (18 ) (14 ) (13 ) (11 ) Earnings (loss) before income taxes 688 1,325 (744 ) (41 ) (1,055 ) (202 ) 319 558 (1 ) 68 Provisions for (recovery of) income taxes Current (2 ) (3 ) 10 — — — 17 9 — — Deferred 186 365 (209 ) (11 ) (283 ) (55 ) 54 115 — 19 184 362 (199 ) (11 ) (283 ) (55 ) 71 124 — 19 Net earnings (loss) 504 963 (545 ) (30 ) (772 ) (147 ) 248 434 (1 ) 49 Intersegment revenues 452 693 — — 205 233 3 5 4 6 Expenditures on exploration and evaluation assets (1) 17 18 — — 3 99 — — — — Expenditures on property, plant and equipment (1) 939 1,070 38 51 191 322 768 666 73 40 As at December 31, Total assets 8,312 7,707 2,757 3,237 1,709 2,534 8,645 8,558 838 917 (1) Excludes capitalized costs related to asset retirement obligations and capitalized interest incurred during the year. Includes Exploration and Production assets acquired through acquisition, but excludes assets acquired through corporate acquisition. Segmented Financial Information - Reclassified Con't Integrated Corridor Offshore Corporate Total Eliminations Total 2019 2018 2019 2018 2019 2018 2019 2018 2019 2018 (664 ) (937 ) 18,565 19,966 1,552 1,953 — — 20,117 21,919 — — (214 ) (207 ) (109 ) (128 ) — — (323 ) (335 ) — — 189 668 — — — — 189 668 (664 ) (937 ) 18,540 20,427 1,443 1,825 — — 19,983 22,252 (664 ) (937 ) 12,841 14,503 (24 ) 52 — — 12,817 14,555 — — 2,679 2,501 340 304 (2 ) (2 ) 3,017 2,803 — — 346 313 55 58 292 283 693 654 — — 3,731 1,804 1,661 695 104 92 5,496 2,591 — — 167 78 380 71 — — 547 149 — — (7 ) (4 ) (1 ) — — — (8 ) (4 ) — — (577 ) (566 ) 9 (19 ) (16 ) (6 ) (584 ) (591 ) (664 ) (937 ) 19,180 18,629 2,420 1,161 378 367 21,978 20,157 — — (640 ) 1,798 (977 ) 664 (378 ) (367 ) (1,995 ) 2,095 — — 9 18 50 51 — — 59 69 — — — — — — 44 14 44 14 — — — — 3 12 71 52 74 64 — — (162 ) (108 ) (38 ) (28 ) (151 ) (178 ) (351 ) (314 ) — — (162 ) (108 ) (35 ) (16 ) (36 ) (112 ) (233 ) (236 ) — — (793 ) 1,708 (962 ) 699 (414 ) (479 ) (2,169 ) 1,928 — — 25 6 125 141 25 (72 ) 175 75 — — (252 ) 433 (393 ) 35 (329 ) (72 ) (974 ) 396 — — (227 ) 439 (268 ) 176 (304 ) (144 ) (799 ) 471 — — (566 ) 1,269 (694 ) 523 (110 ) (335 ) (1,370 ) 1,457 — — 664 937 — — — — 664 937 — — 20 117 26 125 — — 46 242 — — 2,009 2,149 1,246 1,066 131 121 3,386 3,336 — — 22,261 22,953 8,077 8,627 2,784 3,645 33,122 35,225

Description of Business and S_3

Description of Business and Segmented Disclosures - Income Statement (Details) - CAD ($) $ in Millions	12 Months Ended
	Dec. 31, 2019	Dec. 31, 2018
Disclosure of operating segments [line items]
Gross revenues	$ 20,117	$ 21,919
Royalties	(323)	(335)
Marketing and other	189	668
Revenues, net of royalties	19,983	22,252
Purchases of crude oil and products	12,817	14,555
Production, operating and transportation expenses (note 21)	3,017	2,803
Selling, general and administrative expenses (note 21)	693	654
Depletion, depreciation, amortization and impairment (notes 9, 10)	5,496	2,591
Expense arising from exploration for and evaluation of mineral resources	547	149
Loss (gain) on sale of assets	8	4
Other – net (note 13)	(584)	(591)
Expenses	21,978	20,157
Earnings from operating activities	(1,995)	2,095
Share of equity investment income (note 12)	59	69
Net foreign exchange gain	44	14
Finance income	74	64
Finance expenses	(351)	(314)
Financial Items	(233)	(236)
Earnings before income taxes	(2,169)	1,928
Current tax expense (income) and adjustments for current tax of prior periods	175	75
Deferred tax expense (income)	(974)	396
Tax expense (income)	(799)	471
Net earnings (loss)	(1,370)	1,457
Intersegment revenues	2,022	1,554
Exploration and Production(1)
Disclosure of operating segments [line items]
Gross revenues	4,958	4,330
Infrastructure and Marketing(2)
Disclosure of operating segments [line items]
Gross revenues	2,342	2,211
Upgrading
Disclosure of operating segments [line items]
Gross revenues	1,777	1,750
Canadian Refined Products
Disclosure of operating segments [line items]
Gross revenues	3,122	3,412
U.S. Refining and Marketing
Disclosure of operating segments [line items]
Gross revenues	9,940	11,770
Upstream
Disclosure of operating segments [line items]
Gross revenues	7,300	6,541
Royalties	(323)	(335)
Marketing and other	189	668
Revenues, net of royalties	7,166	6,874
Purchases of crude oil and products	2,336	2,087
Production, operating and transportation expenses (note 21)	1,655	1,550
Selling, general and administrative expenses (note 21)	306	301
Depletion, depreciation, amortization and impairment (notes 9, 10)	4,324	1,811
Expense arising from exploration for and evaluation of mineral resources	547	149
Loss (gain) on sale of assets	3	2
Other – net (note 13)	86	(118)
Expenses	9,251	5,778
Earnings from operating activities	(2,085)	1,096
Share of equity investment income (note 12)	59	69
Net foreign exchange gain	0	0
Finance income	3	12
Finance expenses	(166)	(109)
Financial Items	(163)	(97)
Earnings before income taxes	(2,189)	1,068
Current tax expense (income) and adjustments for current tax of prior periods	32	(130)
Deferred tax expense (income)	(631)	408
Tax expense (income)	(599)	278
Net earnings (loss)	(1,590)	790
Intersegment revenues	1,660	1,155
Upstream | Exploration and Production(1)
Disclosure of operating segments [line items]
Gross revenues	4,958	4,330
Royalties	(323)	(335)
Marketing and other	0	0
Revenues, net of royalties	4,635	3,995
Purchases of crude oil and products	0	0
Production, operating and transportation expenses (note 21)	1,634	1,527
Selling, general and administrative expenses (note 21)	297	296
Depletion, depreciation, amortization and impairment (notes 9, 10)	4,312	1,811
Expense arising from exploration for and evaluation of mineral resources	547	149
Loss (gain) on sale of assets	3	2
Other – net (note 13)	86	(120)
Expenses	6,873	3,661
Earnings from operating activities	(2,238)	334
Share of equity investment income (note 12)	50	51
Net foreign exchange gain	0	0
Finance income	3	12
Finance expenses	(163)	(109)
Financial Items	(160)	(97)
Earnings before income taxes	(2,348)	288
Current tax expense (income) and adjustments for current tax of prior periods	32	(484)
Deferred tax expense (income)	(674)	549
Tax expense (income)	(642)	65
Net earnings (loss)	(1,706)	223
Intersegment revenues	1,660	1,155
Upstream | Infrastructure and Marketing(2)
Disclosure of operating segments [line items]
Gross revenues	2,342	2,211
Royalties	0	0
Marketing and other	189	668
Revenues, net of royalties	2,531	2,879
Purchases of crude oil and products	2,336	2,087
Production, operating and transportation expenses (note 21)	21	23
Selling, general and administrative expenses (note 21)	9	5
Depletion, depreciation, amortization and impairment (notes 9, 10)	12	0
Expense arising from exploration for and evaluation of mineral resources	0	0
Loss (gain) on sale of assets	0	0
Other – net (note 13)	0	2
Expenses	2,378	2,117
Earnings from operating activities	153	762
Share of equity investment income (note 12)	9	18
Net foreign exchange gain	0	0
Finance income	0	0
Finance expenses	(3)	0
Financial Items	(3)	0
Earnings before income taxes	159	780
Current tax expense (income) and adjustments for current tax of prior periods	0	354
Deferred tax expense (income)	43	(141)
Tax expense (income)	43	213
Net earnings (loss)	116	567
Intersegment revenues	0	0
Revenue from construction contracts	201	172
Costs of construction contracts	269	142
Revenue from construction contracts, percentage of completion method	193	172
Costs of construction contracts, percentage of completion method	261	142
Downstream | Reportable segments
Disclosure of operating segments [line items]
Gross revenues	14,839	16,932
Royalties	0	0
Marketing and other	0	0
Revenues, net of royalties	14,839	16,932
Purchases of crude oil and products	12,503	14,022
Production, operating and transportation expenses (note 21)	1,364	1,255
Selling, general and administrative expenses (note 21)	95	76
Depletion, depreciation, amortization and impairment (notes 9, 10)	1,068	688
Expense arising from exploration for and evaluation of mineral resources	0	0
Loss (gain) on sale of assets	5	2
Other – net (note 13)	(654)	(465)
Expenses	14,371	15,574
Earnings from operating activities	468	1,358
Share of equity investment income (note 12)	0	0
Net foreign exchange gain	0	0
Finance income	0	0
Finance expenses	(34)	(27)
Financial Items	(34)	(27)
Earnings before income taxes	434	1,331
Current tax expense (income) and adjustments for current tax of prior periods	118	277
Deferred tax expense (income)	(16)	54
Tax expense (income)	102	331
Net earnings (loss)	332	1,000
Intersegment revenues	362	399
Downstream | Upgrading
Disclosure of operating segments [line items]
Gross revenues	1,777	1,750
Royalties	0	0
Marketing and other	0	0
Revenues, net of royalties	1,777	1,750
Purchases of crude oil and products	1,303	928
Production, operating and transportation expenses (note 21)	217	195
Selling, general and administrative expenses (note 21)	9	7
Depletion, depreciation, amortization and impairment (notes 9, 10)	115	123
Expense arising from exploration for and evaluation of mineral resources	0	0
Loss (gain) on sale of assets	0	0
Other – net (note 13)	0	0
Expenses	1,644	1,253
Earnings from operating activities	133	497
Share of equity investment income (note 12)	0	0
Net foreign exchange gain	0	0
Finance income	0	0
Finance expenses	(1)	(1)
Financial Items	(1)	(1)
Earnings before income taxes	132	496
Current tax expense (income) and adjustments for current tax of prior periods	63	168
Deferred tax expense (income)	(28)	(33)
Tax expense (income)	35	135
Net earnings (loss)	97	361
Intersegment revenues	263	290
Downstream | Canadian Refined Products
Disclosure of operating segments [line items]
Gross revenues	3,122	3,412
Royalties	0	0
Marketing and other	0	0
Revenues, net of royalties	3,122	3,412
Purchases of crude oil and products	2,571	2,760
Production, operating and transportation expenses (note 21)	278	265
Selling, general and administrative expenses (note 21)	53	47
Depletion, depreciation, amortization and impairment (notes 9, 10)	218	115
Expense arising from exploration for and evaluation of mineral resources	0	0
Loss (gain) on sale of assets	6	2
Other – net (note 13)	0	(1)
Expenses	3,114	3,184
Earnings from operating activities	8	228
Share of equity investment income (note 12)	0	0
Net foreign exchange gain	0	0
Finance income	0	0
Finance expenses	(15)	(12)
Financial Items	(15)	(12)
Earnings before income taxes	(7)	216
Current tax expense (income) and adjustments for current tax of prior periods	38	100
Deferred tax expense (income)	(40)	(42)
Tax expense (income)	(2)	58
Net earnings (loss)	(5)	158
Intersegment revenues	99	109
Downstream | U.S. Refining and Marketing
Disclosure of operating segments [line items]
Gross revenues	9,940	11,770
Royalties	0	0
Marketing and other	0	0
Revenues, net of royalties	9,940	11,770
Purchases of crude oil and products	8,629	10,334
Production, operating and transportation expenses (note 21)	869	795
Selling, general and administrative expenses (note 21)	33	22
Depletion, depreciation, amortization and impairment (notes 9, 10)	735	450
Expense arising from exploration for and evaluation of mineral resources	0	0
Loss (gain) on sale of assets	(1)	0
Other – net (note 13)	(654)	(464)
Expenses	9,613	11,137
Earnings from operating activities	327	633
Share of equity investment income (note 12)	0	0
Net foreign exchange gain	0	0
Finance income	0	0
Finance expenses	(18)	(14)
Financial Items	(18)	(14)
Earnings before income taxes	309	619
Current tax expense (income) and adjustments for current tax of prior periods	17	9
Deferred tax expense (income)	52	129
Tax expense (income)	69	138
Net earnings (loss)	240	481
Intersegment revenues	0	0
Corporate and Eliminations(3)
Disclosure of operating segments [line items]
Gross revenues	(2,022)	(1,554)
Royalties	0	0
Marketing and other	0	0
Revenues, net of royalties	(2,022)	(1,554)
Purchases of crude oil and products	(2,022)	(1,554)
Production, operating and transportation expenses (note 21)	(2)	(2)
Selling, general and administrative expenses (note 21)	292	277
Depletion, depreciation, amortization and impairment (notes 9, 10)	104	92
Expense arising from exploration for and evaluation of mineral resources	0	0
Loss (gain) on sale of assets	0	0
Other – net (note 13)	(16)	(8)
Expenses	(1,644)	(1,195)
Earnings from operating activities	(378)	(359)
Share of equity investment income (note 12)	0	0
Net foreign exchange gain	44	14
Finance income	71	52
Finance expenses	(151)	(178)
Financial Items	(36)	(112)
Earnings before income taxes	(414)	(471)
Current tax expense (income) and adjustments for current tax of prior periods	25	(72)
Deferred tax expense (income)	(327)	(66)
Tax expense (income)	(302)	(138)
Net earnings (loss)	(112)	(333)
Intersegment revenues	$ 0	$ 0
Goodwill [member]
Disclosure of operating segments [line items]
Discount rate (as a percent)	9.00%	8.00%

Description of Business and S_4

Description of Business and Segmented Disclosures - Segmented Financial Information (Details) - CAD ($) $ in Millions	12 Months Ended
	Dec. 31, 2019	Dec. 31, 2018	Jan. 01, 2019
Disclosure of disaggregation of revenue from contracts with customers [line items]
Expense arising from exploration for and evaluation of mineral resources	$ 46	$ 242
Expenditures on property, plant and equipment(2)	3,386	3,336
Exploration and evaluation assets (note 8)	643	997
Total exploration and evaluation assets and property, plant and equipment, net	24,266	26,797
Right-of-use assets	1,202	0	$ 1,767
Total Assets	33,122	35,225
Upstream
Disclosure of disaggregation of revenue from contracts with customers [line items]
Expense arising from exploration for and evaluation of mineral resources	46	242
Expenditures on property, plant and equipment(2)	2,302	2,414
Exploration and evaluation assets (note 8)	643	997
Total exploration and evaluation assets and property, plant and equipment, net	15,932	17,865
Right-of-use assets	610	0
Total Assets	19,194	20,476
Downstream
Disclosure of disaggregation of revenue from contracts with customers [line items]
Expense arising from exploration for and evaluation of mineral resources	0	0
Expenditures on property, plant and equipment(2)	946	801
Exploration and evaluation assets (note 8)	0	0
Total exploration and evaluation assets and property, plant and equipment, net	7,985	8,618
Right-of-use assets	300	0
Total Assets	11,181	11,146
Corporate and Eliminations(3)
Disclosure of disaggregation of revenue from contracts with customers [line items]
Expense arising from exploration for and evaluation of mineral resources	0	0
Expenditures on property, plant and equipment(2)	138	121
Exploration and evaluation assets (note 8)	0	0
Total exploration and evaluation assets and property, plant and equipment, net	349	314
Right-of-use assets	292	0
Total Assets	2,747	3,603
Exploration and Production(1) | Upstream
Disclosure of disaggregation of revenue from contracts with customers [line items]
Expense arising from exploration for and evaluation of mineral resources	46	242
Expenditures on property, plant and equipment(2)	2,300	2,414
Exploration and evaluation assets (note 8)	643	997
Total exploration and evaluation assets and property, plant and equipment, net	15,882	17,814
Right-of-use assets	520	0
Total Assets	17,533	19,175
Infrastructure and Marketing(2) | Upstream
Disclosure of disaggregation of revenue from contracts with customers [line items]
Revenue from construction contracts	201	172
Expense arising from exploration for and evaluation of mineral resources	0	0
Expenditures on property, plant and equipment(2)	2	0
Exploration and evaluation assets (note 8)	0	0
Total exploration and evaluation assets and property, plant and equipment, net	50	51
Right-of-use assets	90	0
Total Assets	1,661	1,301
Costs of construction contracts	269	142
Revenue from construction contracts, percentage of completion method	193	172
Costs of construction contracts, percentage of completion method	261	142
Upgrading | Downstream
Disclosure of disaggregation of revenue from contracts with customers [line items]
Expense arising from exploration for and evaluation of mineral resources	0	0
Expenditures on property, plant and equipment(2)	59	62
Exploration and evaluation assets (note 8)	0	0
Total exploration and evaluation assets and property, plant and equipment, net	1,021	1,074
Right-of-use assets	0	0
Total Assets	1,203	1,149
Canadian Refined Products | Downstream
Disclosure of disaggregation of revenue from contracts with customers [line items]
Expense arising from exploration for and evaluation of mineral resources	0	0
Expenditures on property, plant and equipment(2)	119	74
Exploration and evaluation assets (note 8)	0	0
Total exploration and evaluation assets and property, plant and equipment, net	911	1,208
Right-of-use assets	143	0
Total Assets	1,287	1,431
U.S. Refining and Marketing | Downstream
Disclosure of disaggregation of revenue from contracts with customers [line items]
Expense arising from exploration for and evaluation of mineral resources	0	0
Expenditures on property, plant and equipment(2)	768	665
Exploration and evaluation assets (note 8)	0	0
Total exploration and evaluation assets and property, plant and equipment, net	6,053	6,336
Right-of-use assets	157	0
Total Assets	8,691	8,566
Cost
Disclosure of disaggregation of revenue from contracts with customers [line items]
Developing and producing assets	46,587	44,196
Other property, plant and equipment	16,093	16,546
Cost | Upstream
Disclosure of disaggregation of revenue from contracts with customers [line items]
Developing and producing assets	46,587	44,196
Other property, plant and equipment	101	101
Cost | Downstream
Disclosure of disaggregation of revenue from contracts with customers [line items]
Developing and producing assets	0	0
Other property, plant and equipment	14,615	15,194
Cost | Corporate and Eliminations(3)
Disclosure of disaggregation of revenue from contracts with customers [line items]
Developing and producing assets	0	0
Other property, plant and equipment	1,377	1,251
Cost | Exploration and Production(1) | Upstream
Disclosure of disaggregation of revenue from contracts with customers [line items]
Developing and producing assets	46,587	44,196
Other property, plant and equipment	0	0
Cost | Infrastructure and Marketing(2) | Upstream
Disclosure of disaggregation of revenue from contracts with customers [line items]
Developing and producing assets	0	0
Other property, plant and equipment	101	101
Cost | Upgrading | Downstream
Disclosure of disaggregation of revenue from contracts with customers [line items]
Developing and producing assets	0	0
Other property, plant and equipment	2,721	2,659
Cost | Canadian Refined Products | Downstream
Disclosure of disaggregation of revenue from contracts with customers [line items]
Developing and producing assets	0	0
Other property, plant and equipment	2,360	2,789
Cost | U.S. Refining and Marketing | Downstream
Disclosure of disaggregation of revenue from contracts with customers [line items]
Developing and producing assets	0	0
Other property, plant and equipment	9,534	9,746
Accumulated depletion, depreciation, amortization and impairment
Disclosure of disaggregation of revenue from contracts with customers [line items]
Developing and producing assets	(31,348)	(27,379)
Other property, plant and equipment	(7,709)	(7,563)
Accumulated depletion, depreciation, amortization and impairment | Upstream
Disclosure of disaggregation of revenue from contracts with customers [line items]
Developing and producing assets	(31,348)	(27,379)
Other property, plant and equipment	(51)	(50)
Accumulated depletion, depreciation, amortization and impairment | Downstream
Disclosure of disaggregation of revenue from contracts with customers [line items]
Developing and producing assets	0	0
Other property, plant and equipment	(6,630)	(6,576)
Accumulated depletion, depreciation, amortization and impairment | Corporate and Eliminations(3)
Disclosure of disaggregation of revenue from contracts with customers [line items]
Developing and producing assets	0	0
Other property, plant and equipment	(1,028)	(937)
Accumulated depletion, depreciation, amortization and impairment | Exploration and Production(1) | Upstream
Disclosure of disaggregation of revenue from contracts with customers [line items]
Developing and producing assets	(31,348)	(27,379)
Other property, plant and equipment	0	0
Accumulated depletion, depreciation, amortization and impairment | Infrastructure and Marketing(2) | Upstream
Disclosure of disaggregation of revenue from contracts with customers [line items]
Developing and producing assets	0	0
Other property, plant and equipment	(51)	(50)
Accumulated depletion, depreciation, amortization and impairment | Upgrading | Downstream
Disclosure of disaggregation of revenue from contracts with customers [line items]
Developing and producing assets	0	0
Other property, plant and equipment	(1,700)	(1,585)
Accumulated depletion, depreciation, amortization and impairment | Canadian Refined Products | Downstream
Disclosure of disaggregation of revenue from contracts with customers [line items]
Developing and producing assets	0	0
Other property, plant and equipment	(1,449)	(1,581)
Accumulated depletion, depreciation, amortization and impairment | U.S. Refining and Marketing | Downstream
Disclosure of disaggregation of revenue from contracts with customers [line items]
Developing and producing assets	0	0
Other property, plant and equipment	(3,481)	(3,410)
Later than one year
Disclosure of disaggregation of revenue from contracts with customers [line items]
Receivables and payables related to insurance contracts	$ 435	$ 253

Description of Business and S_5

Description of Business and Segmented Disclosures - Geographical (Details) - CAD ($) $ in Millions	12 Months Ended
	Dec. 31, 2019	Dec. 31, 2018	Jan. 01, 2019	Dec. 31, 2017
Disclosure of disaggregation of revenue from contracts with customers [line items]
Gross revenues	$ 20,117	$ 21,919
Royalties	(323)	(335)
Marketing and other	189	668
Revenues, net of royalties	19,983	22,252
Restricted cash – non-current	142	128
Exploration and evaluation assets (note 8)	643	997
Property, plant and equipment, net	23,623	25,800
Right-of-use assets	1,202	0	$ 1,767
Goodwill (note 11)	656	690		$ 633
Investment in joint ventures (note 12)	1,182	1,319
Long-term income taxes receivable	212	243
Other assets (note 13)	524	360
Non-current assets	28,184	29,537
Canada
Disclosure of disaggregation of revenue from contracts with customers [line items]
Gross revenues	9,120	9,000
Royalties	(264)	(269)
Marketing and other	189	668
Revenues, net of royalties	9,045	9,399
Restricted cash – non-current	0	0
Exploration and evaluation assets (note 8)	599	935
Property, plant and equipment, net	14,630	16,433
Right-of-use assets	1,044	0
Goodwill (note 11)	0	0
Investment in joint ventures (note 12)	666	669
Long-term income taxes receivable	212	243
Other assets (note 13)	47	58
Non-current assets	17,198	18,338
United States
Disclosure of disaggregation of revenue from contracts with customers [line items]
Gross revenues	9,940	11,770
Royalties	0	0
Marketing and other	0	0
Revenues, net of royalties	9,940	11,770
Restricted cash – non-current	0	0
Exploration and evaluation assets (note 8)	0	0
Property, plant and equipment, net	6,053	6,336
Right-of-use assets	156	0
Goodwill (note 11)	656	690
Investment in joint ventures (note 12)	0	0
Long-term income taxes receivable	0	0
Other assets (note 13)	458	276
Non-current assets	7,323	7,302
China
Disclosure of disaggregation of revenue from contracts with customers [line items]
Gross revenues	1,057	1,149
Royalties	(59)	(66)
Marketing and other	0	0
Revenues, net of royalties	998	1,083
Restricted cash – non-current	142	128
Exploration and evaluation assets (note 8)	39	57
Property, plant and equipment, net	2,938	3,030
Right-of-use assets	2	0
Goodwill (note 11)	0	0
Investment in joint ventures (note 12)	0	0
Long-term income taxes receivable	0	0
Other assets (note 13)	0	0
Non-current assets	3,121	3,215
Other International
Disclosure of disaggregation of revenue from contracts with customers [line items]
Gross revenues	0	0
Royalties	0	0
Marketing and other	0	0
Revenues, net of royalties	0	0
Restricted cash – non-current	0	0
Exploration and evaluation assets (note 8)	5	5
Property, plant and equipment, net	2	1
Right-of-use assets	0	0
Goodwill (note 11)	0	0
Investment in joint ventures (note 12)	516	650
Long-term income taxes receivable	0	0
Other assets (note 13)	19	26
Non-current assets	$ 542	$ 682

Description of Business and S_6

Description of Business and Segmented Disclosures - Disaggregation of Revenue (Details) - CAD ($) $ in Millions	12 Months Ended
	Dec. 31, 2019	Dec. 31, 2018
Disclosure of disaggregation of revenue from contracts with customers [line items]
Gross revenues	$ 20,117	$ 21,919
Upgrading
Disclosure of disaggregation of revenue from contracts with customers [line items]
Gross revenues	1,777	1,750
Canadian Refined Products
Disclosure of disaggregation of revenue from contracts with customers [line items]
Gross revenues	3,122	3,412
U.S. Refining and Marketing
Disclosure of disaggregation of revenue from contracts with customers [line items]
Gross revenues	9,940	11,770
Downstream
Disclosure of disaggregation of revenue from contracts with customers [line items]
Gross revenues	14,839	16,932
Corporate and Eliminations(3)
Disclosure of disaggregation of revenue from contracts with customers [line items]
Gross revenues	(2,022)	(1,554)
Upstream
Disclosure of disaggregation of revenue from contracts with customers [line items]
Gross revenues	7,300	6,541
Exploration and Production(1)
Disclosure of disaggregation of revenue from contracts with customers [line items]
Gross revenues	4,958	4,330
Infrastructure and Marketing(2)
Disclosure of disaggregation of revenue from contracts with customers [line items]
Gross revenues	2,342	2,211
Canada
Disclosure of disaggregation of revenue from contracts with customers [line items]
Gross revenues	9,120	9,000
Canada | Upgrading
Disclosure of disaggregation of revenue from contracts with customers [line items]
Gross revenues	1,777	1,750
Canada | Canadian Refined Products
Disclosure of disaggregation of revenue from contracts with customers [line items]
Gross revenues	3,122	3,412
Canada | Downstream
Disclosure of disaggregation of revenue from contracts with customers [line items]
Gross revenues	4,899	5,162
Canada | Corporate and Eliminations(3)
Disclosure of disaggregation of revenue from contracts with customers [line items]
Gross revenues	(2,022)	(1,554)
Canada | Upstream
Disclosure of disaggregation of revenue from contracts with customers [line items]
Gross revenues	6,243	5,392
Canada | Exploration and Production(1)
Disclosure of disaggregation of revenue from contracts with customers [line items]
Gross revenues	3,901	3,181
Canada | Infrastructure and Marketing(2)
Disclosure of disaggregation of revenue from contracts with customers [line items]
Gross revenues	2,342	2,211
United States
Disclosure of disaggregation of revenue from contracts with customers [line items]
Gross revenues	9,940	11,770
United States | U.S. Refining and Marketing
Disclosure of disaggregation of revenue from contracts with customers [line items]
Gross revenues	9,940	11,770
United States | Downstream
Disclosure of disaggregation of revenue from contracts with customers [line items]
Gross revenues	9,940	11,770
China
Disclosure of disaggregation of revenue from contracts with customers [line items]
Gross revenues	1,057	1,149
China | Upstream
Disclosure of disaggregation of revenue from contracts with customers [line items]
Gross revenues	1,057	1,149
China | Exploration and Production(1)
Disclosure of disaggregation of revenue from contracts with customers [line items]
Gross revenues	1,057	1,149
Light and Medium Crude Oil [Member]
Disclosure of disaggregation of revenue from contracts with customers [line items]
Gross revenues	670	948
Light and Medium Crude Oil [Member] | Upstream
Disclosure of disaggregation of revenue from contracts with customers [line items]
Gross revenues	670	948
Light and Medium Crude Oil [Member] | Exploration and Production(1)
Disclosure of disaggregation of revenue from contracts with customers [line items]
Gross revenues	670	948
Heavy Crude Oil [Member]
Disclosure of disaggregation of revenue from contracts with customers [line items]
Gross revenues	603	527
Heavy Crude Oil [Member] | Upstream
Disclosure of disaggregation of revenue from contracts with customers [line items]
Gross revenues	603	527
Heavy Crude Oil [Member] | Exploration and Production(1)
Disclosure of disaggregation of revenue from contracts with customers [line items]
Gross revenues	603	527
Bitumen [Member]
Disclosure of disaggregation of revenue from contracts with customers [line items]
Gross revenues	2,302	1,367
Bitumen [Member] | Upstream
Disclosure of disaggregation of revenue from contracts with customers [line items]
Gross revenues	2,302	1,367
Bitumen [Member] | Exploration and Production(1)
Disclosure of disaggregation of revenue from contracts with customers [line items]
Gross revenues	2,302	1,367
Crude Oil [Member]
Disclosure of disaggregation of revenue from contracts with customers [line items]
Gross revenues	3,575	2,842
Crude Oil [Member] | Upstream
Disclosure of disaggregation of revenue from contracts with customers [line items]
Gross revenues	3,575	2,842
Crude Oil [Member] | Exploration and Production(1)
Disclosure of disaggregation of revenue from contracts with customers [line items]
Gross revenues	3,575	2,842
Natural Gas Liquids [Member]
Disclosure of disaggregation of revenue from contracts with customers [line items]
Gross revenues	291	381
Natural Gas Liquids [Member] | Upstream
Disclosure of disaggregation of revenue from contracts with customers [line items]
Gross revenues	291	381
Natural Gas Liquids [Member] | Exploration and Production(1)
Disclosure of disaggregation of revenue from contracts with customers [line items]
Gross revenues	291	381
Natural Gas [Member]
Disclosure of disaggregation of revenue from contracts with customers [line items]
Gross revenues	1,092	1,107
Natural Gas [Member] | Upstream
Disclosure of disaggregation of revenue from contracts with customers [line items]
Gross revenues	1,092	1,107
Natural Gas [Member] | Exploration and Production(1)
Disclosure of disaggregation of revenue from contracts with customers [line items]
Gross revenues	1,092	1,107
Synthetic Oil [Member]
Disclosure of disaggregation of revenue from contracts with customers [line items]
Gross revenues	1,505	1,445
Synthetic Oil [Member] | Upgrading
Disclosure of disaggregation of revenue from contracts with customers [line items]
Gross revenues	1,505	1,445
Synthetic Oil [Member] | Downstream
Disclosure of disaggregation of revenue from contracts with customers [line items]
Gross revenues	1,505	1,445
Gasoline [Member]
Disclosure of disaggregation of revenue from contracts with customers [line items]
Gross revenues	6,318	7,227
Gasoline [Member] | Canadian Refined Products
Disclosure of disaggregation of revenue from contracts with customers [line items]
Gross revenues	904	1,070
Gasoline [Member] | U.S. Refining and Marketing
Disclosure of disaggregation of revenue from contracts with customers [line items]
Gross revenues	5,414	6,157
Gasoline [Member] | Downstream
Disclosure of disaggregation of revenue from contracts with customers [line items]
Gross revenues	6,318	7,227
Diesel and distillates [Member]
Disclosure of disaggregation of revenue from contracts with customers [line items]
Gross revenues	5,056	5,878
Diesel and distillates [Member] | Upgrading
Disclosure of disaggregation of revenue from contracts with customers [line items]
Gross revenues	260	278
Diesel and distillates [Member] | Canadian Refined Products
Disclosure of disaggregation of revenue from contracts with customers [line items]
Gross revenues	1,152	1,303
Diesel and distillates [Member] | U.S. Refining and Marketing
Disclosure of disaggregation of revenue from contracts with customers [line items]
Gross revenues	3,644	4,297
Diesel and distillates [Member] | Downstream
Disclosure of disaggregation of revenue from contracts with customers [line items]
Gross revenues	5,056	5,878
Asphalt [Member]
Disclosure of disaggregation of revenue from contracts with customers [line items]
Gross revenues	588	619
Asphalt [Member] | Canadian Refined Products
Disclosure of disaggregation of revenue from contracts with customers [line items]
Gross revenues	452	454
Asphalt [Member] | U.S. Refining and Marketing
Disclosure of disaggregation of revenue from contracts with customers [line items]
Gross revenues	136	165
Asphalt [Member] | Downstream
Disclosure of disaggregation of revenue from contracts with customers [line items]
Gross revenues	588	619
Other Refined Products [Member]
Disclosure of disaggregation of revenue from contracts with customers [line items]
Gross revenues	1,372	1,763
Other Refined Products [Member] | Upgrading
Disclosure of disaggregation of revenue from contracts with customers [line items]
Gross revenues	12	27
Other Refined Products [Member] | Canadian Refined Products
Disclosure of disaggregation of revenue from contracts with customers [line items]
Gross revenues	614	585
Other Refined Products [Member] | U.S. Refining and Marketing
Disclosure of disaggregation of revenue from contracts with customers [line items]
Gross revenues	746	1,151
Other Refined Products [Member] | Downstream
Disclosure of disaggregation of revenue from contracts with customers [line items]
Gross revenues	1,372	1,763
Refined Products [Member]
Disclosure of disaggregation of revenue from contracts with customers [line items]
Gross revenues	14,839	16,932
Refined Products [Member] | Upgrading
Disclosure of disaggregation of revenue from contracts with customers [line items]
Gross revenues	1,777	1,750
Refined Products [Member] | Canadian Refined Products
Disclosure of disaggregation of revenue from contracts with customers [line items]
Gross revenues	3,122	3,412
Refined Products [Member] | U.S. Refining and Marketing
Disclosure of disaggregation of revenue from contracts with customers [line items]
Gross revenues	9,940	11,770
Refined Products [Member] | Downstream
Disclosure of disaggregation of revenue from contracts with customers [line items]
Gross revenues	$ 14,839	$ 16,932

Cash and Cash Equivalents (Deta

Cash and Cash Equivalents (Details) - CAD ($) $ in Millions	Dec. 31, 2019	Dec. 31, 2018
Subclassifications of assets, liabilities and equities [abstract]
Cash	$ 327	$ 187
Short-term investments, classified as cash equivalents	$ 1,448	$ 2,679

Accounts Receivable (Details)

Accounts Receivable (Details) - CAD ($) $ in Millions	Dec. 31, 2019	Dec. 31, 2018
Disclosure of types of insurance contracts [line items]
Trade receivables	$ 1,327	$ 1,146
Provision for expected credit losses	(34)	(39)
Derivatives due within one year	38	43
Other(1)	168	205
Accounts receivable	1,499	1,355
Within 1 year
Disclosure of types of insurance contracts [line items]
Receivables and payables related to insurance contracts	$ 114	$ 143

Inventories (Details)

Inventories (Details) - CAD ($) $ in Millions	12 Months Ended
	Dec. 31, 2019	Dec. 31, 2018
Subclassifications of assets, liabilities and equities [abstract]
Crude oil, natural gas and NGL	$ 627	$ 445
Refined petroleum products	553	435
Trading inventories measured at fair value less costs to sell	155	200
Materials, supplies and other	151	152
Inventories	1,486	1,232
Inventory write-down to net realizable value (note 6)	$ 15	$ 60

Restricted Cash Restricted Cash

Restricted Cash Restricted Cash (Details) - CAD ($) $ in Millions	Dec. 31, 2019	Dec. 31, 2018
Peoples Republic of China
Disclosure of geographical areas [line items]
Restricted cash and cash equivalents	$ 142	$ 128

Exploration and Evaluation Co_3

Exploration and Evaluation Costs - Exploration and Evaluation Assets (Details) - CAD ($) $ in Millions	12 Months Ended
	Dec. 31, 2019	Dec. 31, 2018
Disclosure of detailed information about property, plant and equipment [line items]
Property, plant and equipment, beginning balance	$ 25,800
Expensed exploration expenditures previously capitalized	355	$ 29
Property, plant and equipment, ending balance	23,623	25,800
Tangible exploration and evaluation assets
Disclosure of detailed information about property, plant and equipment [line items]
Property, plant and equipment, beginning balance	997	838
Additions	46	287
Disposals	0	(23)
Transfers to property, plant and equipment (note 9)	(44)	(79)
Expensed exploration expenditures previously capitalized	(355)	(29)
Exchange adjustments	(1)	3
Property, plant and equipment, ending balance	$ 643	$ 997

Exploration and Evaluation Co_4

Exploration and Evaluation Costs - Narrative (Details) - CAD ($) $ in Millions	12 Months Ended
	Dec. 31, 2019	Dec. 31, 2018
Disclosure of detailed information about property, plant and equipment [line items]
Expensed exploration expenditures previously capitalized	$ (355)	$ (29)
Tangible exploration and evaluation assets
Disclosure of detailed information about property, plant and equipment [line items]
Expensed exploration expenditures previously capitalized	$ 355	$ 29

Exploration and Evaluation Co_5

Exploration and Evaluation Costs - Exploration and Evaluation Expense Summary (Details) - CAD ($) $ in Millions	12 Months Ended
	Dec. 31, 2019	Dec. 31, 2018
Subclassifications of assets, liabilities and equities [abstract]
Seismic, geological and geophysical	$ 131	$ 102
Expensed drilling	409	41
Expensed land	7	6
Exploration and evaluation expenses	$ 547	$ 149

Property, Plant and Equipment -

Property, Plant and Equipment - Reconciliation of PP&E (Details) - CAD ($) $ in Millions	12 Months Ended
	Dec. 31, 2019	Dec. 31, 2019	Dec. 31, 2018	Jan. 01, 2019
Disclosure of detailed information about property, plant and equipment [line items]
Property, plant and equipment, beginning balance		$ 25,800
Transfers from right-of-use assets	$ 101
Transfers from property, plant and equipment, net (note 9)				$ 464
Property, plant and equipment, ending balance	23,623	23,623	$ 25,800
Interest expense on lease liabilities		106
Cost
Disclosure of detailed information about property, plant and equipment [line items]
Property, plant and equipment, beginning balance		60,742	56,621
Transfers from exploration and evaluation (note 8)		44	79
Transfers from right-of-use assets		101
Transfers from property, plant and equipment, net (note 9)				(516)
Additions		3,459	3,434
Acquisitions		10	67
Intersegment transfers		0	0
Changes in asset retirement obligations (note 17)		517	45
Disposals and derecognition		(964)	(643)
Exchange adjustments		(722)	1,139
Property, plant and equipment, ending balance	62,671	62,671	60,742
Accumulated depletion, depreciation, amortization and impairment
Disclosure of detailed information about property, plant and equipment [line items]
Property, plant and equipment, beginning balance		(34,942)	(32,543)
Depletion, depreciation, amortization and impairment		(5,174)	(2,591)
Transfers from property, plant and equipment, net (note 9)				52
Intersegment transfers		0
Disposals and derecognition		734	596
Exchange adjustments		282	(404)
Property, plant and equipment, ending balance	(39,048)	(39,048)	(34,942)
Oil and Gas Properties
Disclosure of detailed information about property, plant and equipment [line items]
Property, plant and equipment, beginning balance		16,817
Transfers from right-of-use assets	101
Transfers from property, plant and equipment, net (note 9)				324
Property, plant and equipment, ending balance	15,239	15,239	16,817
Interest expense on lease liabilities		5
Oil and Gas Properties | Cost
Disclosure of detailed information about property, plant and equipment [line items]
Property, plant and equipment, beginning balance		44,196	41,815
Transfers from exploration and evaluation (note 8)		44	79
Transfers from right-of-use assets		101
Transfers from property, plant and equipment, net (note 9)				(336)
Additions		2,340	2,465
Acquisitions		10	64
Intersegment transfers		2	0
Changes in asset retirement obligations (note 17)		469	43
Disposals and derecognition		(16)	(632)
Exchange adjustments		(223)	362
Property, plant and equipment, ending balance	46,587	46,587	44,196
Oil and Gas Properties | Accumulated depletion, depreciation, amortization and impairment
Disclosure of detailed information about property, plant and equipment [line items]
Property, plant and equipment, beginning balance		(27,379)	(26,016)
Depletion, depreciation, amortization and impairment		(4,082)	(1,811)
Transfers from property, plant and equipment, net (note 9)				12
Intersegment transfers		0
Disposals and derecognition		8	586
Exchange adjustments		93	(138)
Property, plant and equipment, ending balance	(31,348)	(31,348)	(27,379)
Processing, Transportation and Storage
Disclosure of detailed information about property, plant and equipment [line items]
Property, plant and equipment, beginning balance		51
Transfers from right-of-use assets	0
Transfers from property, plant and equipment, net (note 9)				0
Property, plant and equipment, ending balance	50	50	51
Processing, Transportation and Storage | Cost
Disclosure of detailed information about property, plant and equipment [line items]
Property, plant and equipment, beginning balance		101	86
Transfers from exploration and evaluation (note 8)		0	0
Transfers from right-of-use assets		0
Transfers from property, plant and equipment, net (note 9)				0
Additions		2	12
Acquisitions		0	0
Intersegment transfers		0	0
Changes in asset retirement obligations (note 17)		1	2
Disposals and derecognition		(2)	0
Exchange adjustments		(1)	1
Property, plant and equipment, ending balance	101	101	101
Processing, Transportation and Storage | Accumulated depletion, depreciation, amortization and impairment
Disclosure of detailed information about property, plant and equipment [line items]
Property, plant and equipment, beginning balance		(50)	(47)
Depletion, depreciation, amortization and impairment		(2)	(2)
Transfers from property, plant and equipment, net (note 9)				0
Intersegment transfers		0
Disposals and derecognition		0	0
Exchange adjustments		1	(1)
Property, plant and equipment, ending balance	(51)	(51)	(50)
Upgrading
Disclosure of detailed information about property, plant and equipment [line items]
Property, plant and equipment, beginning balance		1,074
Transfers from right-of-use assets	0
Transfers from property, plant and equipment, net (note 9)				0
Property, plant and equipment, ending balance	1,021	1,021	1,074
Upgrading | Cost
Disclosure of detailed information about property, plant and equipment [line items]
Property, plant and equipment, beginning balance		2,659	2,599
Transfers from exploration and evaluation (note 8)		0	0
Transfers from right-of-use assets		0
Transfers from property, plant and equipment, net (note 9)				0
Additions		58	62
Acquisitions		0	0
Intersegment transfers		0	0
Changes in asset retirement obligations (note 17)		5	(2)
Disposals and derecognition		(1)	0
Exchange adjustments		0	0
Property, plant and equipment, ending balance	2,721	2,721	2,659
Upgrading | Accumulated depletion, depreciation, amortization and impairment
Disclosure of detailed information about property, plant and equipment [line items]
Property, plant and equipment, beginning balance		(1,585)	(1,462)
Depletion, depreciation, amortization and impairment		(115)	(123)
Transfers from property, plant and equipment, net (note 9)				0
Intersegment transfers		0
Disposals and derecognition		0	0
Exchange adjustments		0	0
Property, plant and equipment, ending balance	(1,700)	(1,700)	(1,585)
Refining
Disclosure of detailed information about property, plant and equipment [line items]
Property, plant and equipment, beginning balance		6,758
Transfers from right-of-use assets	0
Transfers from property, plant and equipment, net (note 9)				140
Property, plant and equipment, ending balance	6,282	6,282	6,758
Refining | Cost
Disclosure of detailed information about property, plant and equipment [line items]
Property, plant and equipment, beginning balance		10,691	9,191
Transfers from exploration and evaluation (note 8)		0	0
Transfers from right-of-use assets		0
Transfers from property, plant and equipment, net (note 9)				(180)
Additions		899	744
Acquisitions		0	3
Intersegment transfers		27	(5)
Changes in asset retirement obligations (note 17)		19	(5)
Disposals and derecognition		(943)	(10)
Exchange adjustments		(496)	773
Property, plant and equipment, ending balance	10,017	10,017	10,691
Refining | Accumulated depletion, depreciation, amortization and impairment
Disclosure of detailed information about property, plant and equipment [line items]
Property, plant and equipment, beginning balance		(3,933)	(3,176)
Depletion, depreciation, amortization and impairment		(736)	(503)
Transfers from property, plant and equipment, net (note 9)				40
Intersegment transfers		(17)
Disposals and derecognition		724	10
Exchange adjustments		187	(264)
Property, plant and equipment, ending balance	(3,735)	(3,735)	(3,933)
Retail and Other
Disclosure of detailed information about property, plant and equipment [line items]
Property, plant and equipment, beginning balance		1,100
Transfers from right-of-use assets	0
Transfers from property, plant and equipment, net (note 9)				0
Property, plant and equipment, ending balance	1,031	1,031	1,100
Retail and Other | Cost
Disclosure of detailed information about property, plant and equipment [line items]
Property, plant and equipment, beginning balance		3,095	2,930
Transfers from exploration and evaluation (note 8)		0	0
Transfers from right-of-use assets		0
Transfers from property, plant and equipment, net (note 9)				0
Additions		160	151
Acquisitions		0	0
Intersegment transfers		(29)	5
Changes in asset retirement obligations (note 17)		23	7
Disposals and derecognition		(2)	(1)
Exchange adjustments		(2)	3
Property, plant and equipment, ending balance	3,245	3,245	3,095
Retail and Other | Accumulated depletion, depreciation, amortization and impairment
Disclosure of detailed information about property, plant and equipment [line items]
Property, plant and equipment, beginning balance		(1,995)	(1,842)
Depletion, depreciation, amortization and impairment		(239)	(152)
Transfers from property, plant and equipment, net (note 9)				$ 0
Intersegment transfers		17
Disposals and derecognition		2	0
Exchange adjustments		1	(1)
Property, plant and equipment, ending balance	$ (2,214)	$ (2,214)	$ (1,995)

Property, Plant and Equipment_2

Property, Plant and Equipment - Narrative (Details) - CAD ($)	3 Months Ended	12 Months Ended
	Dec. 31, 2019	Dec. 31, 2019	Dec. 31, 2018
Disclosure of detailed information about property, plant and equipment [line items]
Interest expense on lease liabilities		$ 106,000,000
PPE, not subject to depletion, depreciation and amortization	$ 6,800,000,000	6,800,000,000	$ 5,200,000,000
Write-downs (reversals of write-downs) of property, plant and equipment			56,000,000
Adjustments for gain (loss) on disposals, property, plant and equipment		$ 8,000,000	4,000,000
Discount rate used in previous measurement of fair value less costs of disposal	10.00%	10.00%
Undeveloped land
Disclosure of detailed information about property, plant and equipment [line items]
Land	$ 127,000,000	$ 127,000,000	117,000,000
Lima Refining Company
Disclosure of detailed information about property, plant and equipment [line items]
Disposals and retirements, property, plant and equipment		(254,000,000)
Exploration and Production(1)
Disclosure of detailed information about property, plant and equipment [line items]
Impairment loss recognised in profit or loss		(2,240,000,000)	0
Canadian Refined Products
Disclosure of detailed information about property, plant and equipment [line items]
Impairment loss recognised in profit or loss		90,000,000	$ 0
Upstream
Disclosure of detailed information about property, plant and equipment [line items]
Recoverable amount of asset or cash-generating unit	5,600,000,000	5,600,000,000
Downstream
Disclosure of detailed information about property, plant and equipment [line items]
Recoverable amount of asset or cash-generating unit	100,000,000	$ 100,000,000
Prince George Refinery
Disclosure of detailed information about property, plant and equipment [line items]
Proceeds from disposals of property, plant and equipment, intangible assets other than goodwill, investment property and other non-current assets	$ 215,000,000
Information about sale and leaseback transactions	55
Gains (losses) arising from sale and leaseback transactions	$ 2,000,000
After tax gains from sale and leaseback transactions	1,000,000
Other assets | Prince George Refinery
Disclosure of detailed information about property, plant and equipment [line items]
Proceeds from disposals of property, plant and equipment, intangible assets other than goodwill, investment property and other non-current assets	$ 53,500,000

Property, Plant and Equipment_3

Property, Plant and Equipment - Impairment of CGUs (Details) $ in Millions	12 Months Ended
	Dec. 31, 2019CAD ($)
Downstream
Disclosure of information for cash-generating units [line items]
Impairment loss	$ 90
Upstream
Disclosure of information for cash-generating units [line items]
Impairment loss	2,240
Western Canada | Upstream
Disclosure of information for cash-generating units [line items]
Impairment loss	662
Northern | Upstream
Disclosure of information for cash-generating units [line items]
Impairment loss	421
Rainbow | Upstream
Disclosure of information for cash-generating units [line items]
Impairment loss	241
White Rose | Upstream
Disclosure of information for cash-generating units [line items]
Impairment loss	871
Sunrise | Upstream
Disclosure of information for cash-generating units [line items]
Impairment loss	707
Minnedosa Ethanol Plant | Downstream
Disclosure of information for cash-generating units [line items]
Impairment loss	78
Lloydminster Ethanol Plant | Downstream
Disclosure of information for cash-generating units [line items]
Impairment loss	$ 12

Property, Plant and Equipment_4

Property, Plant and Equipment - Forecasted Prices Used in Determining Recoverable Amounts (Details)	Dec. 31, 2019Basispoints / barrel$ / barrel$ / metric_cubic_foot$ / $
Disclosure of information for cash-generating units [line items]
2020 | $ / $	760,000
2021 | $ / $	770,000
2022 | $ / $	780,000
2023 | $ / $	790,000
2024 | $ / $	790,000
2025 | $ / $	790,000
2026 | $ / $	790,000
WTI ($US/bbl)
Disclosure of information for cash-generating units [line items]
2020	61
2021	64
2022	66
2023	68
2024	70
2025	71.40
2026	72.83
Brent ($US/bbl)
Disclosure of information for cash-generating units [line items]
2020	66
2021	68
2022	70
2023	72
2024	74
2025	75.48
2026	76.99
Edmonton Light ($CDN/bbl)
Disclosure of information for cash-generating units [line items]
2020 | Basispoints / barrel	72.37
2021 | Basispoints / barrel	76.62
2022 | Basispoints / barrel	78.85
2023 | Basispoints / barrel	80.38
2024 | Basispoints / barrel	82.91
2025 | Basispoints / barrel	84.57
2026 | Basispoints / barrel	86.26
AECO ($CDN/mcf)
Disclosure of information for cash-generating units [line items]
2020 | $ / metric_cubic_foot	2
2021 | $ / metric_cubic_foot	2.25
2022 | $ / metric_cubic_foot	2.50
2023 | $ / metric_cubic_foot	2.75
2024 | $ / metric_cubic_foot	2.80
2025 | $ / metric_cubic_foot	2.86
2026 | $ / metric_cubic_foot	2.91

Property, Plant and Equipment_5

Property, Plant and Equipment - Impact of Change in Discount Rate and Forward Price on Upstream CGUs (Details) $ in Millions	12 Months Ended
	Dec. 31, 2019CAD ($)
Subclassifications of assets, liabilities and equities [abstract]
Increase (decrease) in impairment of PP&E, assuming 1% increase in discount rate	$ 528
Increase (decrease) in impairment of PP&E, assuming 1% decrease in discount rate	(605)
Increase (decrease) in impairment of PP&E, assuming 5% increase in forward commodity price	(910)
Increase (decrease) in impairment of PP&E, assuming 5% decrease in forward commodity price	$ 904

Right-of-use Assets and Lease_3

Right-of-use Assets and Lease Liabilities - Right-of-use Assets (Details) - CAD ($) $ in Millions	12 Months Ended
	Dec. 31, 2019	Dec. 31, 2019	Jan. 01, 2019
Reconciliation Of Right-Of-Use Assets [Roll Forward]
Transfers from property, plant and equipment, net (note 9)			$ 464
Right-of-use assets, beginning balance	$ 1,767	$ 0
Additions	86
Transfers to property, plant and equipment (note 9)	(101)
Disposals and derecognition	(40)
Revaluation	(186)
Depreciation and impairment	(322)
Other	(2)
Right-of-use assets, ending balance	1,202	1,202
IFRS 16
Reconciliation Of Right-Of-Use Assets [Roll Forward]
Right-of-use assets, beginning balance	1,303
Oil and Gas Properties
Reconciliation Of Right-Of-Use Assets [Roll Forward]
Transfers from property, plant and equipment, net (note 9)			324
Right-of-use assets, beginning balance	1,045
Additions	1
Transfers to property, plant and equipment (note 9)	(101)
Disposals and derecognition	(11)
Revaluation	(194)
Depreciation and impairment	(222)
Other	2
Right-of-use assets, ending balance	520	520
Oil and Gas Properties | IFRS 16
Reconciliation Of Right-Of-Use Assets [Roll Forward]
Right-of-use assets, beginning balance	721
Processing, Transportation and Storage
Reconciliation Of Right-Of-Use Assets [Roll Forward]
Transfers from property, plant and equipment, net (note 9)			0
Right-of-use assets, beginning balance	100
Additions	0
Transfers to property, plant and equipment (note 9)	0
Disposals and derecognition	0
Revaluation	1
Depreciation and impairment	(11)
Other	0
Right-of-use assets, ending balance	90	90
Processing, Transportation and Storage | IFRS 16
Reconciliation Of Right-Of-Use Assets [Roll Forward]
Right-of-use assets, beginning balance	100
Upgrading
Reconciliation Of Right-Of-Use Assets [Roll Forward]
Transfers from property, plant and equipment, net (note 9)			0
Right-of-use assets, beginning balance	0
Additions	0
Transfers to property, plant and equipment (note 9)	0
Disposals and derecognition	0
Revaluation	0
Depreciation and impairment	0
Other	0
Right-of-use assets, ending balance	0	0
Upgrading | IFRS 16
Reconciliation Of Right-Of-Use Assets [Roll Forward]
Right-of-use assets, beginning balance	0
Refining
Reconciliation Of Right-Of-Use Assets [Roll Forward]
Transfers from property, plant and equipment, net (note 9)			140
Right-of-use assets, beginning balance	210
Additions	80
Transfers to property, plant and equipment (note 9)	0
Disposals and derecognition	(31)
Revaluation	(1)
Depreciation and impairment	(50)
Other	(4)
Right-of-use assets, ending balance	204	204
Refining | IFRS 16
Reconciliation Of Right-Of-Use Assets [Roll Forward]
Right-of-use assets, beginning balance	70
Retail and Other
Reconciliation Of Right-Of-Use Assets [Roll Forward]
Transfers from property, plant and equipment, net (note 9)			$ 0
Right-of-use assets, beginning balance	412
Additions	5
Transfers to property, plant and equipment (note 9)	0
Disposals and derecognition	2
Revaluation	8
Depreciation and impairment	(39)
Other	0
Right-of-use assets, ending balance	388	$ 388
Retail and Other | IFRS 16
Reconciliation Of Right-Of-Use Assets [Roll Forward]
Right-of-use assets, beginning balance	$ 412

Right-of-use Assets and Lease_4

Right-of-use Assets and Lease Liabilities - Narrative (Details) - CAD ($) $ in Millions	12 Months Ended
	Dec. 31, 2019	Jan. 01, 2019	Dec. 31, 2018
Disclosure of quantitative information about right-of-use assets [line items]
Lease liabilities	$ 1,462	$ 1,348	$ 489
Discounted potential lease payments excluded from lease liabilities	238
Reduction in right-of-use assets	185
Reduction in lease liabilities	185
Exploration and Production(1) | Right-of-use assets
Disclosure of quantitative information about right-of-use assets [line items]
Right-of use assets expensed related to impairment	165
Office Buildings
Disclosure of quantitative information about right-of-use assets [line items]
Lease liabilities	$ 380

Right-of-use Assets and Lease_5

Right-of-use Assets and Lease Liabilities - Lease Liabilities (Details) - CAD ($) $ in Millions	Dec. 31, 2019	Jan. 01, 2019	Dec. 31, 2018
Disclosure of finance lease and operating lease by lessee [line items]
Lease liabilities (note 10)	$ 109		$ 0
Leasehold incentives	1,353		0
Operating agreements included in commitments at December 31, 2018(1)			2,343
Expenses relating to short-term leases			(9)
Discounting			(986)
Lease liabilities	$ 1,462	$ 1,348	489
Accrued And Other Long-Term Liabilities [Member]
Disclosure of finance lease and operating lease by lessee [line items]
Lease liabilities			$ 489

Right-of-use Assets and Lease_6

Right-of-use Assets and Lease Liabilities - Maturity Analysis (Details) - CAD ($) $ in Millions	Dec. 31, 2019	Jan. 01, 2019	Dec. 31, 2018
Disclosure of maturity analysis of operating lease payments [line items]
Future lease payments	$ 3,032		$ 1,325
Interest	1,570		836
Lease liabilities	1,462	$ 1,348	489
Within 1 year
Disclosure of maturity analysis of operating lease payments [line items]
Future lease payments	205		69
Interest	96		48
Lease liabilities	109		21
After 1 year but no more than 5 years
Disclosure of maturity analysis of operating lease payments [line items]
Future lease payments	653		242
Interest	352		175
Lease liabilities	301		67
More than 5 years
Disclosure of maturity analysis of operating lease payments [line items]
Future lease payments	2,174		1,014
Interest	1,122		613
Lease liabilities	$ 1,052		$ 401

Right-of-use Assets and Lease_7

Right-of-use Assets and Lease Liabilities - Operating Results and Cash Flow Related to Leases (Details) $ in Millions	12 Months Ended
	Dec. 31, 2019CAD ($)
Disclosure of finance lease and operating lease by lessee [line items]
Interest expense on lease liabilities	$ 106
Expenses relating to short-term leases	18
Total cash flow used for leases	339
Oil and Gas Properties
Disclosure of finance lease and operating lease by lessee [line items]
Interest expense on lease liabilities	$ 5

Goodwill - Goodwill Rollforward

Goodwill - Goodwill Rollforward (Details) - CAD ($) $ in Millions	12 Months Ended
	Dec. 31, 2019	Dec. 31, 2018
Disclosure of information for cash-generating units [line items]
Goodwill, beginning balance	$ 690	$ 633
Exchange adjustments	(34)	57
Goodwill, ending balance	$ 656	$ 690
Goodwill [member]
Disclosure of information for cash-generating units [line items]
Discount rate (as a percent)	9.00%	8.00%

Goodwill (Details)

Goodwill (Details)	12 Months Ended
	Dec. 31, 2019	Dec. 31, 2018
Disclosure of reconciliation of changes in goodwill [line items]
Average expected rates of inflation	2.00%	2.00%
Goodwill [member]
Disclosure of reconciliation of changes in goodwill [line items]
Discount rate applied to cash flow projections, term	50 years
Discount rate (as a percent)	9.00%	8.00%
Discount rate applied to cash flow projections, term, period one	10 years
Expected rate of inflation, future EBITDA	1.00%
Expected rate of inflation, capital expenditures	2.00%
Average expected rates of inflation	2.00%	2.00%
Discount rate applied to cash flow projections, term, period two	40 years

Joint Arrangements - BP-Husky R

Joint Arrangements - BP-Husky Refining LLC (Details) - CAD ($) $ in Millions	12 Months Ended
	Dec. 31, 2019	Dec. 31, 2018
Contribution Payable
Distribution from joint operation	$ 187	$ 72
BP-Husky Refining LLC
Disclosure of joint operations [line items]
Proportion of ownership interest in joint operation	50.00%

Joint Arrangements - Husky-CNOO

Joint Arrangements - Husky-CNOOC Madura Ltd. (Details) - CAD ($)	12 Months Ended
	Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017
Disclosure of joint ventures [line items]
Cash and cash equivalents (note 4)	$ 1,775,000,000	$ 2,866,000,000	$ 2,513,000,000
Results of Operations
Revenues	19,983,000,000	22,252,000,000
Expenses	(21,978,000,000)	(20,157,000,000)
Proportionate share of net loss	(1,370,000,000)	1,457,000,000
Equity	17,296,000,000	19,614,000,000
Balance Sheets
Current assets	4,938,000,000	5,688,000,000
Non-current assets	28,184,000,000	29,537,000,000
Current liabilities	4,636,000,000	4,994,000,000
Total Assets	33,122,000,000	35,225,000,000
Carrying amount in balance sheet	1,182,000,000	1,319,000,000
Deferred income	152,000,000	205,000,000	$ 284,000,000
Husky-CNOOC Madura Ltd.
Disclosure of joint ventures [line items]
Cash and cash equivalents (note 4)	$ 42,000,000	$ 203,000,000
Share of equity investment	40.00%	40.00%
Results of Operations
Revenues	$ 424,000,000	$ 441,000,000
Expenses	(267,000,000)	(273,000,000)
Proportionate share of net loss	$ 157,000,000	$ 168,000,000
Share of equity investment	40.00%	40.00%
Equity	$ 50,000,000	$ 51,000,000
Balance Sheets
Current assets	208,000,000	373,000,000
Non-current assets	1,840,000,000	2,072,000,000
Current liabilities	(70,000,000)	(123,000,000)
Non-current liabilities	(1,427,000,000)	(1,917,000,000)
Total Assets	$ 551,000,000	$ 405,000,000
Proportion Of Net Assets In Joint Venture	40.00%	40.00%
Carrying amount in balance sheet	$ 516,000,000	$ 650,000,000
Deferred income	$ 0	$ 2,000,000

Joint Arrangements - Husky Mids

Joint Arrangements - Husky Midstream Limited Partnership (Details) - CAD ($) $ in Millions	12 Months Ended
	Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017
Disclosure of joint ventures [line items]
Cash and cash equivalents (note 4)	$ 1,775	$ 2,866	$ 2,513
Results of Operations
Revenues	19,983	22,252
Expenses	21,978	20,157
Proportionate share of net loss	(1,370)	1,457
Equity	17,296	19,614
Balance Sheets
Current assets	4,938	5,688
Non-current assets	28,184	29,537
Current liabilities	4,636	4,994
Total Assets	33,122	35,225
Carrying amount in balance sheet	1,182	1,319
Husky Midstream Limited Partnership
Disclosure of joint ventures [line items]
Cash and cash equivalents (note 4)	86	16
Results of Operations
Revenues	316	296
Expenses	(228)	(177)
Proportionate share of net loss	$ 88	$ 119
Share of equity investment	35.00%	35.00%
Equity	$ 9	$ 18
Balance Sheets
Current assets	171	115
Non-current assets	3,031	2,849
Current liabilities	(163)	(153)
Non-current liabilities	(1,059)	(825)
Total Assets	$ 1,980	$ 1,986
Proportion Of Net Assets In Joint Venture	35.00%	35.00%
Carrying amount in balance sheet	$ 666	$ 669
Power Assets Holding Ltd. | Husky Midstream Limited Partnership
Results of Operations
Share of equity investment	48.75%
Cheung Kong Infrastructure Holdings Ltd. | Husky Midstream Limited Partnership
Results of Operations
Share of equity investment	16.25%

Joint Arrangements - Sunrise Oi

Joint Arrangements - Sunrise Oil Sands Partnership (Details)	12 Months Ended
	Dec. 31, 2019
Sunrise Oil Sands Partnership
Disclosure of joint ventures [line items]
Proportion of ownership interest in joint operation	50.00%

Other Assets (Details)

Other Assets (Details) - CAD ($) $ in Millions	12 Months Ended
	Dec. 31, 2019	Dec. 31, 2018
Term Classification [Line Items]
Insurance recoveries for property damage, rebuild, business interruption and clean-up costs	$ 630	$ 468
Long-term receivables(1)	489	319
Precious metals	22	23
Other	13	18
Other non-current assets	524	360
Later than one year
Term Classification [Line Items]
Receivables and payables related to insurance contracts	$ 435	$ 253

Bank Operating Loans (Details)

Bank Operating Loans (Details) - CAD ($)	Dec. 31, 2019	Dec. 31, 2018
Disclosure of detailed information about borrowings [line items]
Line of credit, maximum borrowing capacity	$ 4,900,000,000
Bank operating loan
Disclosure of detailed information about borrowings [line items]
Line of credit, maximum borrowing capacity	900,000,000	$ 900,000,000
Letter of credit, maximum borrowing capacity	436,000,000	439,000,000
Unsecured bank loans received	0	0
Sunrise Oil Sands Partnership | Unsecured demand credit facility
Disclosure of detailed information about borrowings [line items]
Line of credit, maximum borrowing capacity	10,000,000	10,000,000
Husky Energy Inc. | Sunrise Oil Sands Partnership | Unsecured demand credit facility
Disclosure of detailed information about borrowings [line items]
Line of credit, maximum borrowing capacity	$ 5,000,000	$ 5,000,000

Accounts Payable and Accrued _3

Accounts Payable and Accrued Liabilities (Details) - CAD ($) $ in Millions	Dec. 31, 2019	Dec. 31, 2018
Subclassifications of assets, liabilities and equities [abstract]
Trade payables	$ 1,178	$ 1,121
Accrued liabilities	1,954	1,712
Dividend payable (note 20)	126	126
Stock-based compensation	19	32
Derivatives due within one year	21	39
Other	167	129
Accounts payable and accrued liabilities	$ 3,465	$ 3,159

Debt and Credit Facilities - Sh

Debt and Credit Facilities - Short-term Debt (Details) - CAD ($)	Dec. 31, 2019	Dec. 31, 2018
Disclosure of borrowing costs [Abstract]
Commercial paper	$ 550,000,000	$ 200,000,000
Commercial paper, maximum authorized amount	$ 1,000,000,000
Commercial paper
Disclosure of detailed information about borrowings [line items]
Interest rate, weighted average	1.98%	2.20%

Debt and Credit Facilities - Lo

Debt and Credit Facilities - Long-term Debt (Details) $ in Millions, $ in Millions	Dec. 16, 2019CAD ($)	Jun. 17, 2019CAD ($)	Dec. 31, 2019CAD ($)	Dec. 31, 2018CAD ($)	Dec. 31, 2019USD ($)	Mar. 15, 2019CAD ($)	Dec. 31, 2018USD ($)
Disclosure of detailed information about borrowings [line items]
Long-term debt			$ 4,570	$ 4,114	$ 2,387		$ 1,637
Long-term debt due within one year			400	1,433	$ 0		1,050
Long-term debt repayment			$ 1,389	0
6.15% Notes Due 2019
Disclosure of detailed information about borrowings [line items]
Borrowings, interest rate		6.15%	6.15%		6.15%
Long-term debt repayment	$ 987	$ 402
7.25% Notes Due 2019
Disclosure of detailed information about borrowings [line items]
Borrowings, interest rate	7.25%		7.25%		7.25%
5.00% Notes Due 2020
Disclosure of detailed information about borrowings [line items]
Borrowings, interest rate			5.00%		5.00%
3.95% Notes Due 2022
Disclosure of detailed information about borrowings [line items]
Borrowings, interest rate			3.95%		3.95%
4.00 Notes Due 2024
Disclosure of detailed information about borrowings [line items]
Borrowings, interest rate			4.00%		4.00%
3.55% Notes Due 2025
Disclosure of detailed information about borrowings [line items]
Borrowings, interest rate			3.55%		3.55%
3.60% Notes Due 2027
Disclosure of detailed information about borrowings [line items]
Borrowings, interest rate			3.60%		3.60%
6.80% Notes Due 2037
Disclosure of detailed information about borrowings [line items]
Borrowings, interest rate			6.80%		6.80%
Non-current debt due within one year [Member]
Disclosure of detailed information about borrowings [line items]
Long-term debt due within one year			$ 400	1,433
Long-term debt
Disclosure of detailed information about borrowings [line items]
Long-term debt			$ 4,570	4,114
Four Point Four Zero Percent Notes Due 2029 [Member] [Domain]
Disclosure of detailed information about borrowings [line items]
Borrowings						$ 750
Borrowings, interest rate			4.40%		4.40%
3.60% Notes Due 2027
Disclosure of detailed information about borrowings [line items]
Borrowings, interest rate						4.40%
Cost | 6.15% Notes Due 2019
Disclosure of detailed information about borrowings [line items]
Long-term debt due within one year			$ 0	410	$ 0		300
Cost | 7.25% Notes Due 2019
Disclosure of detailed information about borrowings [line items]
Long-term debt due within one year			0	1,023	0		750
Cost | 5.00% Notes Due 2020
Disclosure of detailed information about borrowings [line items]
Long-term debt			0	400	0		0
Long-term debt due within one year			400	0	0		0
Cost | 3.95% Notes Due 2022
Disclosure of detailed information about borrowings [line items]
Long-term debt			648	682	500		500
Cost | 4.00 Notes Due 2024
Disclosure of detailed information about borrowings [line items]
Long-term debt			973	1,023	750		750
Cost | 3.55% Notes Due 2025
Disclosure of detailed information about borrowings [line items]
Long-term debt			750	750	0		0
Cost | 3.60% Notes Due 2027
Disclosure of detailed information about borrowings [line items]
Long-term debt			750	750	0		0
Cost | 6.80% Notes Due 2037
Disclosure of detailed information about borrowings [line items]
Long-term debt			501	528	387		387
Cost | Four Point Four Zero Percent Notes Due 2029 [Member] [Domain]
Disclosure of detailed information about borrowings [line items]
Long-term debt			973	0	750		0
Deferred financing costs
Disclosure of detailed information about borrowings [line items]
Long-term debt			$ (25)	$ (19)	$ 0		$ 0

Debt and Credit Facilities - Cr

Debt and Credit Facilities - Credit Facilities (Details) $ in Billions	Dec. 31, 2019CAD ($)	Dec. 31, 2019USD ($)	Dec. 16, 2019	Mar. 15, 2019CAD ($)	Dec. 31, 2018CAD ($)	Jan. 30, 2018CAD ($)
Disclosure of detailed information about borrowings [line items]
Borrowings, maximum borrowing capacity	$ 4,900,000,000
Four Point Four Zero Percent Notes Due 2029 [Member] [Domain]
Disclosure of detailed information about borrowings [line items]
Borrowings, interest rate	4.40%	4.40%
Borrowings				$ 750,000,000
3.60% Notes Due 2027
Disclosure of detailed information about borrowings [line items]
Borrowings, interest rate				4.40%
7.25% Notes Due 2019
Disclosure of detailed information about borrowings [line items]
Borrowings, interest rate	7.25%	7.25%	7.25%
Revolving syndicated credit facility, March 9, 2020
Disclosure of detailed information about borrowings [line items]
Borrowings, maximum borrowing capacity	$ 2,000,000,000
Borrowings	0				$ 0
Revolving syndicated credit facility, June 19, 2022
Disclosure of detailed information about borrowings [line items]
Borrowings, maximum borrowing capacity	2,000,000,000
Borrowings	0				$ 0
2018 U.S Shelf Prospectus
Disclosure of detailed information about borrowings [line items]
Authorised capital commitments, pre-registration	$ 3,000,000,000	$ 2.3				$ 3,000,000,000

Debt and Credit Facilities - No

Debt and Credit Facilities - Notes (Details) $ in Millions, $ in Millions	Dec. 16, 2019CAD ($)	Jun. 17, 2019CAD ($)	Dec. 31, 2019CAD ($)	Dec. 31, 2018CAD ($)	Dec. 31, 2019USD ($)	May 01, 2019CAD ($)	Mar. 15, 2019CAD ($)	Jan. 30, 2018CAD ($)	Mar. 30, 2017CAD ($)
Disclosure of detailed information about borrowings [line items]
Hedged item, liabilities					$ 500
Long-term debt repayment			$ 1,389	$ 0
Four Point Four Zero Percent Notes Due 2029 [Member] [Domain]
Disclosure of detailed information about borrowings [line items]
Borrowings, interest rate			4.40%		4.40%
Borrowings							$ 750
3.60% Notes Due 2027
Disclosure of detailed information about borrowings [line items]
Borrowings, interest rate							4.40%
6.15% Notes Due 2019
Disclosure of detailed information about borrowings [line items]
Borrowings, interest rate		6.15%	6.15%		6.15%
Long-term debt repayment	$ 987	$ 402
2017 Canadian Shelf Prospectus
Disclosure of detailed information about borrowings [line items]
Authorised capital commitments, pre-registration									$ 3,000
2018 U.S Shelf Prospectus
Disclosure of detailed information about borrowings [line items]
Authorised capital commitments, pre-registration			$ 3,000		$ 2,300			$ 3,000
2019 Canadian Shelf Prospectus [Member] [Domain]
Disclosure of detailed information about borrowings [line items]
Authorised capital commitments, pre-registration						$ 3,000

Debt and Credit Facilities - Re

Debt and Credit Facilities - Reconciliation of Changes of Liabilities to Cash Flows from Financing Activities (Details) $ in Millions, $ in Millions	12 Months Ended
	Dec. 31, 2019CAD ($)	Dec. 31, 2018CAD ($)	Dec. 31, 2019USD ($)	Jan. 01, 2019CAD ($)	Dec. 31, 2018USD ($)
Disclosure of detailed information about borrowings [line items]
Lease liabilities (note 10)	$ 109	$ 0
Leasehold incentives	1,353	0
Short-term debt	550	200
Long-term debt due within one year	400	1,433	$ 0		$ 1,050
Long-term debt	4,570	4,114	$ 2,387		$ 1,637
Other non-current financial liabilities	454	1,107
Long-term debt issuance	1,000	0
Long-term debt repayment	(1,389)	0
Repayments of current borrowings	350	0
Debt issue costs	(9)	0
Proceeds from non-current borrowings, net of debt issuance costs	991
Other	(1)	(8)
Increase (Decrease) In Lease Liabilities	(185)
Payment of finance lease obligations	(233)	0
Deferred revenue	(42)	(100)
Foreign exchange recognized in OCI	(146)	262
Non-current debt due within one year [Member]
Disclosure of detailed information about borrowings [line items]
Long-term debt due within one year	400	1,433
Total other changes - liability related, Current portion of non-current borrowings	356
Increase Decrease Through Reclassification From Long Term Debt To Current Portion Of Long Term Debt Liabilities Arising From Financing Activities	400
Foreign exchange recognized in OCI	(44)
Long-term debt
Disclosure of detailed information about borrowings [line items]
Long-term debt	4,570	$ 4,114
Increase Decrease Through Reclassification From Long Term Debt To Current Portion Of Long Term Debt Liabilities Arising From Financing Activities	(400)
Foreign exchange, other long-term liabilities	(8)
Adjustments for finance costs	5
Foreign exchange recognized in OCI	(132)
Total other changes - liability related, Long-term debt	535
Other long-term liabilities [Member]
Disclosure of detailed information about borrowings [line items]
Other non-current financial liabilities	454
Other	(14)
Increase Decrease Through Reclassification From Long Term Debt To Current Portion Of Long Term Debt Liabilities Arising From Financing Activities	(114)
Foreign exchange, other long-term liabilities	(12)
Fair value changes	(4)
Net additions of lease liabilities	(42)
Total other changes - liability related, Other long-term liabilities	(653)
Current lease liabilities [Member]
Disclosure of detailed information about borrowings [line items]
Lease liabilities (note 10)	109
Financial assets, carrying amount immediately after initial application of IFRS 9				$ 22
Other	1
Increase Decrease Through Reclassification From Long Term Debt To Current Portion Of Long Term Debt Liabilities Arising From Financing Activities	319
Adjustments For Other Changes, Current Lease liabilities	342
Lease liabilities [member]
Disclosure of detailed information about borrowings [line items]
Financial assets, carrying amount immediately after initial application of IFRS 9				1,815
Other	11
Increase Decrease Through Reclassification From Long Term Debt To Current Portion Of Long Term Debt Liabilities Arising From Financing Activities	(319)
Foreign exchange, other long-term liabilities	(3)
Fair value changes	(240)
Increase (Decrease) In Lease Liabilities	89
Adjustments For Other Changes, Lease liabilities	$ 1,353
At cost or in accordance with IFRS 16 within fair value model [member]
Disclosure of detailed information about borrowings [line items]
Other non-current financial liabilities				$ (467)

Asset Retirement Obligations -

Asset Retirement Obligations - Carrying amount of ARO (Details) - CAD ($) $ in Millions	12 Months Ended
	Dec. 31, 2019	Dec. 31, 2018
Disclosure of other provisions [line items]
Asset Retirement Obligations, Expected to be incurred within 1 year	$ 112	$ 202
Asset Retirement Obligations, Expected to be incurred beyond 1 year	2,643	2,222
Asset Retirement Obligations
Disclosure of other provisions [line items]
Asset Retirement Obligation, Beginning balance	2,424	2,526
Additions	76	40
Liabilities settled	(276)	(270)
Liabilities disposed	(6)	(11)
Change in discount rate	285	(68)
Change in estimates	156	93
Exchange adjustment	(10)	17
Accretion (note 21)	106	97
Asset Retirement Obligation, Ending balance	$ 2,755	$ 2,424

Asset Retirement Obligations _2

Asset Retirement Obligations - Narrative (Details) - CAD ($) $ in Millions	12 Months Ended
	Dec. 31, 2019	Dec. 31, 2018
Disclosure of other provisions [line items]
Average expected rates of inflation	2.00%	2.00%
Restricted cash (notes 7, 17)	$ 142	$ 128
Asset Retirement Obligations
Disclosure of other provisions [line items]
Undiscounted inflation-adjusted ARO	$ 10,000	$ 9,200
Expected timing	45 years	45 years
Peoples Republic of China
Disclosure of other provisions [line items]
Restricted cash and cash equivalents	$ 142	$ 128
Minimum | Asset Retirement Obligations
Disclosure of other provisions [line items]
Discount rate, adjusted risk-free rate (as a percent)	3.90%	3.80%
Maximum | Asset Retirement Obligations
Disclosure of other provisions [line items]
Discount rate, adjusted risk-free rate (as a percent)	4.40%	5.00%

Other Long-term Liabilities - O

Other Long-term Liabilities - Other Long-Term Liabilities (Details) - CAD ($) $ in Millions	Dec. 31, 2019	Dec. 31, 2018
Subclassifications of assets, liabilities and equities [abstract]
Employee future benefits (note 23)	$ 214	$ 205
Finance lease obligations (note 10)	0	467
Stock-based compensation	19	42
Deferred revenue	152	205
Leasehold incentives	1,353	0
Other	69	188
Other non-current financial liabilities	$ 454	$ 1,107

Other Long-term Liabilities - D

Other Long-term Liabilities - Deferred Revenue (Details) - CAD ($) $ in Millions	12 Months Ended
	Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017
Schedule of Deferred Revenue [Line Items]
Deferred income	$ 152	$ 205	$ 284
Decrease through performance obligation being satisfied, contract liabilities	(42)	(100)
Increase (decrease) through net exchange difference, deferred revenue liability	$ (11)	$ 21

Income Taxes - Income Tax Expen

Income Taxes - Income Tax Expense (Details) - CAD ($) $ in Millions	12 Months Ended
	Dec. 31, 2019	Dec. 31, 2018
Disclosure of income tax [Abstract]
Current income tax charge	$ 174	$ 86
Adjustments to current income tax estimates	1	(11)
Provisions for (recovery of) income taxes. current	175	75
Relating to origination and reversal of temporary differences	(723)	378
Adjustments to deferred income tax estimates	(251)	18
Provisions for (recovery of) income taxes, deferred	$ (974)	$ 396

Income Taxes - Deferred Tax Ite

Income Taxes - Deferred Tax Items in OCI (Details) - CAD ($) $ in Millions	12 Months Ended
	Dec. 31, 2019	Dec. 31, 2018
Income tax relating to components of other comprehensive income [abstract]
Derivatives designated as cash flow hedges	$ (3)	$ (5)
Remeasurement of pension plans	1	17
Exchange differences on translation of foreign operations	(58)	87
Hedge of net investment	30	(41)
Income tax relating to components of other comprehensive income	$ (30)	$ 58

Income Taxes - Reconciliation o

Income Taxes - Reconciliation of Effective Tax Rate (Details) - CAD ($) $ in Millions	12 Months Ended
	Dec. 31, 2019	Dec. 31, 2018
Disclosure of geographical areas [line items]
Average effective tax rate	26.80%	27.20%
Reconciliation of Effective Tax Rate
Earnings before income taxes	$ (2,169)	$ 1,928
Expected income tax	(582)	525
Foreign jurisdictions	61	(36)
Non-taxable items	(25)	(13)
Adjustments with respect to previous year	(250)	7
Revaluation of foreign tax pools	(4)	(4)
Other – net	1	(8)
Provisions for (recovery of) income taxes	(799)	471
Canada
Reconciliation of Effective Tax Rate
Earnings before income taxes	(3,170)	734
United States
Reconciliation of Effective Tax Rate
Earnings before income taxes	337	493
Other foreign jurisdictions
Reconciliation of Effective Tax Rate
Earnings before income taxes	$ 664	$ 701
Changes in tax rates or tax laws enacted or announced | ALBERTA
Disclosure of geographical areas [line items]
Applicable tax rate	0.50%

Income Taxes - Deferred Tax Lia

Income Taxes - Deferred Tax Liabilities and Assets (Details) - CAD ($)	12 Months Ended
	Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017
Disclosure of temporary difference, unused tax losses and unused tax credits [line items]
Deferred tax liabilities	$ (2,170,000,000)	$ (3,174,000,000)
Deferred tax liability	(2,170,000,000)	(3,174,000,000)	$ (2,724,000,000)
Deferred income taxes	974,000,000	(396,000,000)
Income tax relating to components of other comprehensive income	30,000,000	(58,000,000)
Increase (decrease) other differences deferred tax liability (asset)	0	4,000,000
Exploration and evaluation assets and property, plant and equipment
Disclosure of temporary difference, unused tax losses and unused tax credits [line items]
Deferred tax liabilities	(3,053,000,000)	(4,089,000,000)	(3,727,000,000)
Deferred income taxes	967,000,000	(260,000,000)
Income tax relating to components of other comprehensive income	69,000,000	(106,000,000)
Increase (decrease) other differences deferred tax liability (asset)	0	4,000,000
Foreign exchange gains taxable on realization
Disclosure of temporary difference, unused tax losses and unused tax credits [line items]
Deferred tax liabilities	(150,000,000)	(174,000,000)	(177,000,000)
Deferred income taxes	51,000,000	(43,000,000)
Income tax relating to components of other comprehensive income	(27,000,000)	46,000,000
Increase (decrease) other differences deferred tax liability (asset)	0	0
Debt issue costs
Disclosure of temporary difference, unused tax losses and unused tax credits [line items]
Deferred tax liabilities	(5,000,000)	(4,000,000)	(3,000,000)
Deferred income taxes	(1,000,000)	(1,000,000)
Income tax relating to components of other comprehensive income	0	0
Increase (decrease) other differences deferred tax liability (asset)	0	0
Other temporary differences
Disclosure of temporary difference, unused tax losses and unused tax credits [line items]
Deferred tax liabilities	(152,000,000)	(28,000,000)	(90,000,000)
Deferred income taxes	(124,000,000)	62,000,000
Income tax relating to components of other comprehensive income	0	0
Increase (decrease) other differences deferred tax liability (asset)	0	0
Pension plans
Disclosure of temporary difference, unused tax losses and unused tax credits [line items]
Deferred tax assets	(16,000,000)	(8,000,000)	(40,000,000)
Deferred income taxes	9,000,000	(15,000,000)
Income tax relating to components of other comprehensive income	(1,000,000)	(17,000,000)
Increase (decrease) other differences deferred tax liability (asset)	0	0
Asset retirement obligations
Disclosure of temporary difference, unused tax losses and unused tax credits [line items]
Deferred tax assets	(666,000,000)	(654,000,000)	(679,000,000)
Deferred income taxes	16,000,000	(29,000,000)
Income tax relating to components of other comprehensive income	(4,000,000)	4,000,000
Increase (decrease) other differences deferred tax liability (asset)	0	0
Loss carry-forwards
Disclosure of temporary difference, unused tax losses and unused tax credits [line items]
Deferred tax assets	(517,000,000)	(468,000,000)	(523,000,000)
Deferred income taxes	56,000,000	(70,000,000)
Income tax relating to components of other comprehensive income	(7,000,000)	15,000,000
Increase (decrease) other differences deferred tax liability (asset)	0	0
Financial assets at fair value
Disclosure of temporary difference, unused tax losses and unused tax credits [line items]
Deferred tax assets	9,000,000	9,000,000	$ (31,000,000)
Deferred income taxes	0	(40,000,000)
Income tax relating to components of other comprehensive income	0	0
Increase (decrease) other differences deferred tax liability (asset)	0	0
Foreign subsidiaries, branches and interest in join ventures
Disclosure of temporary difference, unused tax losses and unused tax credits [line items]
Deferred tax liabilities	0	0
Unused tax losses, expire between 2030 and 2037
Disclosure of temporary difference, unused tax losses and unused tax credits [line items]
Deferred tax assets	$ (2,105,000,000)	$ (1,806,000,000)

Share Capital - Common Shares (

Share Capital - Common Shares (Details)	12 Months Ended
	Dec. 31, 2019CAD ($)shares	Dec. 31, 2018CAD ($)shares
Disclosure of classes of share capital [line items]
Number of share options exercised (in options) | shares	0	2,000
Ordinary shares [member]
Disclosure of classes of share capital [line items]
Equity, beginning, shares | shares	1,005,121,738	1,005,120,012
Shares cancellation (in shares) | shares		(1,726)
Equity, ending, shares | shares	1,005,121,738	1,005,121,738
Issued capital, beginning balance (in shares)	$ 7,293,000,000	$ 7,293,000,000
Share cancellation		0
Issued capital, ending balance (in shares)	7,293,000,000	7,293,000,000
Dividend payables (in CAD per share)	126,000,000	126,000,000
Dividends declared on common shares	503,000,000	402,000,000
Dividends recognised as distributions to owners	$ 503,000,000	$ 276,000,000
Preference shares [member]
Disclosure of classes of share capital [line items]
Equity, beginning, shares | shares	36,000,000	36,000,000
Equity, ending, shares | shares	36,000,000	36,000,000
Issued capital, beginning balance (in shares)	$ 874,000,000	$ 874,000,000
Issued capital, ending balance (in shares)	874,000,000	874,000,000
Dividend payables (in CAD per share)	0	0
Dividends declared on common shares	35,000,000	35,000,000
Dividends recognised as distributions to owners	$ 35,000,000	$ 43,000,000

Share Capital - Preferred Share

Share Capital - Preferred Shares (Details) - shares	Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017
Preference shares [member]
Disclosure of classes of share capital [line items]
Equity, shares	36,000,000	36,000,000	36,000,000

Share Capital - Preferred Sha_2

Share Capital - Preferred Shares Textual (Details) - CAD ($)	12 Months Ended
	Dec. 31, 2019	Dec. 31, 2018
Preference shares [member]
Disclosure of classes of share capital [line items]
Dividend payables	$ 0	$ 0
Redeemable preferred shares, series 1 preferred shares
Disclosure of classes of share capital [line items]
Dividend yield, quarterly	2.404%
Dividend yield, term	5 years
Dividend yield, term two	5 years
Redeemable preferred shares, series 2 preferred shares
Disclosure of classes of share capital [line items]
Dividend yield, quarterly	3.368%
Dividend yield, term	5 years
Dividend yield, term two	3 months
Conversion conditions, term	5 years
Redeemable preferred shares, series 3 preferred shares
Disclosure of classes of share capital [line items]
Dividend yield, quarterly	4.689%
Dividend yield, term two	5 years
Redeemable preferred shares, series 4 preferred shares
Disclosure of classes of share capital [line items]
Dividend yield, term two	5 years
Redeemable preferred shares, series 5 preferred shares
Disclosure of classes of share capital [line items]
Dividend yield, quarterly	4.50%
Dividend yield, term two	5 years
Dividend rate, basis spread on variable rate	3.57%
Redeemable preferred shares, series 6 preferred shares
Disclosure of classes of share capital [line items]
Dividend yield, term two	5 years
Redeemable preferred shares, series 7 preferred shares
Disclosure of classes of share capital [line items]
Dividend yield, quarterly	4.60%
Dividend yield, term two	5 years
Dividend rate, basis spread on variable rate	3.52%
Redeemable preferred shares, series 8 preferred shares
Disclosure of classes of share capital [line items]
Conversion conditions, term	5 years
Government of Canada Bond | Redeemable preferred shares, series 1 preferred shares
Disclosure of classes of share capital [line items]
Dividend rate, basis spread on variable rate	1.73%
Debt instrument, term	5 years
Government of Canada Bond | Redeemable preferred shares, series 3 preferred shares
Disclosure of classes of share capital [line items]
Dividend rate, basis spread on variable rate	3.13%
Debt instrument, term	5 years
Government of Canada Bond | Redeemable preferred shares, series 5 preferred shares
Disclosure of classes of share capital [line items]
Debt instrument, term	5 years
Government of Canada Bond | Redeemable preferred shares, series 7 preferred shares
Disclosure of classes of share capital [line items]
Debt instrument, term	5 years
90-day Government of Canada Treasury Bills | Redeemable preferred shares, series 2 preferred shares
Disclosure of classes of share capital [line items]
Dividend rate, basis spread on variable rate	1.73%
90-day Government of Canada Treasury Bills | Redeemable preferred shares, series 4 preferred shares
Disclosure of classes of share capital [line items]
Dividend rate, basis spread on variable rate	3.13%
90-day Government of Canada Treasury Bills | Redeemable preferred shares, series 6 preferred shares
Disclosure of classes of share capital [line items]
Dividend rate, basis spread on variable rate	3.57%
90-day Government of Canada Treasury Bills | Redeemable preferred shares, series 8 preferred shares
Disclosure of classes of share capital [line items]
Dividend rate, basis spread on variable rate	3.52%

Share Capital - Redeemable Pref

Share Capital - Redeemable Preferred Shares Dividends (Details) - Preference shares [member] - CAD ($) $ in Millions	12 Months Ended
	Dec. 31, 2019	Dec. 31, 2018
Disclosure of classes of share capital [line items]
Dividends declared on preferred shares	$ 35	$ 35
Dividends recognised as distributions to owners	35	43
Series 1 Preferred Shares
Disclosure of classes of share capital [line items]
Dividends declared on preferred shares	6	6
Dividends recognised as distributions to owners	6	8
Series 2 Preferred Shares
Disclosure of classes of share capital [line items]
Dividends declared on preferred shares	1	1
Dividends recognised as distributions to owners	1	1
Series 3 Preferred Shares
Disclosure of classes of share capital [line items]
Dividends declared on preferred shares	12	12
Dividends recognised as distributions to owners	12	14
Series 5 Preferred Shares
Disclosure of classes of share capital [line items]
Dividends declared on preferred shares	9	9
Dividends recognised as distributions to owners	9	11
Series 7 Preferred Shares
Disclosure of classes of share capital [line items]
Dividends declared on preferred shares	7	7
Dividends recognised as distributions to owners	$ 7	$ 9

Share Capital - Stock Option Pl

Share Capital - Stock Option Plan (Details)	12 Months Ended
	Dec. 31, 2019CAD ($)year	Dec. 31, 2018CAD ($)year
Disclosure of terms and conditions of share-based payment arrangement [line items]
Share option, term | year	1.97	1.95
Stock based compensation expense	$ (2,000,000)	$ 44,000,000
Weighted average fair value (in CAD per option)	$ 0.25	0.65
Stock Option Plan
Disclosure of terms and conditions of share-based payment arrangement [line items]
Share option, term | year	5
Liabilities from share-based payment transactions	$ 4,000,000	11,000,000
Stock based compensation expense	(6,000,000)	(3,000,000)
Stock option exercisable, intrinsic value	0.1	0
Weighted average fair value (in CAD per option)	$ 2.34	$ 2.90

Share Capital - Outstanding and

Share Capital - Outstanding and Exercisable Options (Details)	12 Months Ended
	Dec. 31, 2019CAD ($)shares	Dec. 31, 2018CAD ($)shares
Disclosure of share capital, reserves and other equity interest [Abstract]
Number of stock options outstanding, beginning of year (in options) | shares	19,967,000	22,645,000
Number of stock options granted (in options) | shares	4,241,000	5,610,000
Number of share options exercised in share-based payment arrangement (in options) | shares	0	(2,000)
Number of share options surrendered for cash (in options)	(4,000)	(1,772,000)
Number of stock options expired or forfeited (in options) | shares	(5,706,000)	(6,514,000)
Number of stock options outstanding, end of year (in options) | shares	18,498,000	19,967,000
Number of stock options exercisable, end of year (in options) | shares	10,596,000	10,461,000
Weighted average exercise price of stock options outstanding, beginning of year (in cad per option)	$ 21.48	$ 23.96
Weighted average exercise price of stock options granted (in cad per option)	14.31	17.21
Weighted average exercise price of share options exercised in share-based payment arrangement (in cad per option)	0	15.67
Weighted average exercise price of share options surrendered for cash (in cad per option)	15.67	15.82
Weighted average exercise price of stock options expired/forfeited (in cad per option)	28.27	27.69
Weighted average exercise price of stock options outstanding, end of year (in cad per option)	17.75	21.48
Weighted average exercise price of options exercisable (in cad per option)	19.27	25.87
Weighted average fair value (in CAD per option)	$ 0.25	$ 0.65

Share Capital - Outstanding a_2

Share Capital - Outstanding and Exercisable Options-Range of Exercise Prices (Details)	Dec. 31, 2019CAD ($)sharesyear	Dec. 31, 2018CAD ($)shares	Dec. 31, 2017CAD ($)shares
Disclosure of range of exercise prices of outstanding share options [line items]
Number of options outstanding (in options) | shares	18,498,000	19,967,000	22,645,000
Weighted average exercise price of stock options outstanding (in cad per option)	$ 17.75	$ 21.48	$ 23.96
Weighted average remaining contractual life of options outstanding (in years) | year	2.30
Number of stock options exercisable (in options) | shares	10,596,000	10,461,000
Weighted average exercise price of options exercisable (in cad per option)	$ 19.27	$ 25.87
$9.28 - $16.31
Disclosure of range of exercise prices of outstanding share options [line items]
Number of options outstanding (in options) | shares	10,341,000
Weighted average exercise price of stock options outstanding (in cad per option)	$ 15.34
Weighted average remaining contractual life of options outstanding (in years) | year	2.65
Number of stock options exercisable (in options) | shares	5,350,000
Weighted average exercise price of options exercisable (in cad per option)	$ 15.86
$9.28 - $16.31 | Minimum
Disclosure of range of exercise prices of outstanding share options [line items]
Exercise price of options (in CAD per option)	9.28
$9.28 - $16.31 | Maximum
Disclosure of range of exercise prices of outstanding share options [line items]
Exercise price of options (in CAD per option)	$ 16.31
$16.32 - $25.41
Disclosure of range of exercise prices of outstanding share options [line items]
Number of options outstanding (in options) | shares	8,157,000
Weighted average exercise price of stock options outstanding (in cad per option)	$ 20.80
Weighted average remaining contractual life of options outstanding (in years) | year	1.86
Number of stock options exercisable (in options) | shares	5,246,000
Weighted average exercise price of options exercisable (in cad per option)	$ 22.75
$16.32 - $25.41 | Minimum
Disclosure of range of exercise prices of outstanding share options [line items]
Exercise price of options (in CAD per option)	16.32
$16.32 - $25.41 | Maximum
Disclosure of range of exercise prices of outstanding share options [line items]
Exercise price of options (in CAD per option)	$ 25.41

Share Capital - Fair Value (Det

Share Capital - Fair Value (Details)	12 Months Ended
	Dec. 31, 2019CAD ($)year	Dec. 31, 2018CAD ($)year
Disclosure of terms and conditions of share-based payment arrangement [line items]
Dividend per option	$ 0.42	$ 0.56
Expected life of share options from vesting date (years) | year	1.97	1.95
Expected forfeiture rate (percent)	8.80%	8.90%
Weighted average exercise price (in CAD per option)	$ 18.19	$ 22.46
Weighted average fair value (in CAD per option)	$ 0.25	$ 0.65
Minimum
Disclosure of terms and conditions of share-based payment arrangement [line items]
Range of expected volatilities used (percent)	27.50%	16.80%
Range of risk-free interest rates used (percent)	1.70%	1.60%
Maximum
Disclosure of terms and conditions of share-based payment arrangement [line items]
Range of expected volatilities used (percent)	35.50%	44.40%
Range of risk-free interest rates used (percent)	1.70%	1.90%

Share Capital - Performance Sha

Share Capital - Performance Share Units (Details) $ in Millions	12 Months Ended
	Dec. 31, 2019CAD ($)sharesyear	Dec. 31, 2018CAD ($)sharesyear
Disclosure of terms and conditions of share-based payment arrangement [line items]
Share option, term | year	1.97	1.95
Share-based compensation expense | $	$ (9)	$ (10)
Weighted average remaining contractual life of options outstanding (in years) | year	2.30
Performance Share Units (PSUs)
Disclosure of terms and conditions of share-based payment arrangement [line items]
Share option, term | year	3
Liabilities from share-based payment transactions | $	$ 34	63
Share-based compensation expense | $	4	47
Payment for performance share units which vested in the year | $	$ 34	$ 24
Weighted average remaining contractual life of options outstanding (in years) | year	2	2
Performance Share Units, Beginning balance (in units)	11,606,644	8,361,918
Performance Share Units, Granted (in units)	7,673,960	6,108,430
Performance Share Units, Exercised (in units)	(2,429,816)	(1,354,316)
Performance Share Units, Forfeited (in units)	(2,532,146)	(1,509,388)
Performance Share Units, Ending balance (in units)	14,318,642	11,606,644
Performance Share Units, Vested (in units)	3,264,840	4,487,585

Share Capital - Earnings Per Sh

Share Capital - Earnings Per Share (Details) - CAD ($) $ / shares in Units, shares in Millions, $ in Millions	12 Months Ended
	Dec. 31, 2019	Dec. 31, 2018
Earnings per share [abstract]
Net earnings (loss)	$ (1,370)	$ 1,457
Effect of dividends declared on preferred shares in the year	(35)	(35)
Net earnings (loss) – basic	(1,405)	1,422
Dilutive effect of accounting for stock options(1)	(15)	(13)
Net earnings (loss) – diluted	$ (1,420)	$ 1,409
Weighted average number of common shares outstanding, basic	1,005.1	1,005.1
Weighted average common shares outstanding – diluted	1,005.1	1,006.1
Earnings (loss) per share – basic ($/share)	$ (1.40)	$ 1.41
Earnings (loss) per share – diluted ($/share)	$ (1.41)	$ 1.40
Stock-based compensation expense, cash-settled	$ (9)	$ (10)
Stock-based compensation expense, equity settled	$ (6)	$ (3)
Dilutive effect of share options (in options)	0	1
Stock Option Plan
Earnings per share [abstract]
Dilutive effect of share options on number of ordinary shares	18	13

Production, Operating and Tra_3

Production, Operating and Transportation and Selling, General, and Administrative Expenses - Production, Operating and Trasportation Expenses (Details) - CAD ($) $ in Millions	12 Months Ended
	Dec. 31, 2019	Dec. 31, 2018
Analysis of income and expense [abstract]
Services and support costs	$ 1,255	$ 1,039
Salaries and benefits	773	762
Materials, equipment rentals and leases	250	243
Energy and utility	482	405
Licensing fees	204	191
Transportation	17	24
Other	36	139
Total production, operating and transportation expenses	$ 3,017	$ 2,803

Production, Operating and Tra_4

Production, Operating and Transportation and Selling, General, and Administrative Expenses - Selling, general and administrative (Details) - CAD ($) $ in Millions	12 Months Ended
	Dec. 31, 2019	Dec. 31, 2018
Analysis of income and expense [abstract]
Employee costs(1)	$ 450	$ 332
Stock-based compensation expense (recovery)(2)	(2)	44
Contract services	133	104
Equipment rentals and leases	11	39
Maintenance and other	101	135
Total selling, general and administrative expenses	$ 693	$ 654

Financial Items (Details)

Financial Items (Details) - CAD ($) $ in Millions	12 Months Ended
	Dec. 31, 2019	Dec. 31, 2018
Foreign exchange gain (loss)
Non-cash working capital	$ 17	$ (3)
Other foreign exchange	27	17
Net foreign exchange gains (losses)	44	14
Finance income	74	64
Finance expenses
Interest costs incurred	245	217
Interest costs capitalised	177	108
Accretion of asset retirement obligations (note 17)	(106)	(97)
Finance expenses	(351)	(314)
Financial Items	$ (233)	$ (236)
Capitalisation rate of borrowing costs eligible for capitalisation	5.00%	5.00%
Long-term debt
Finance expenses
Interest costs incurred	$ 310	$ 320
Lease liabilities [member]
Finance expenses
Interest costs incurred	106	0
Other
Finance expenses
Interest costs incurred	6	5
Liabilities [member]
Finance expenses
Interest costs incurred	$ 422	$ 325

Pensions and Other Post-emplo_3

Pensions and Other Post-employment Benefits - Defined Contribution Pension Plan. Defined Benefit Obligation, Fair Value of Plan Assets and Funded Status (Details) - CAD ($) $ in Millions	12 Months Ended
	Dec. 31, 2019	Dec. 31, 2018
Disclosure of net defined benefit liability (asset) [line items]
Defined contribution plan expense	$ 59	$ 54
DB Pension Plans
Disclosure of net defined benefit liability (asset) [line items]
Current service cost	0	1
Interest cost	0	1
Remeasurements
Actuarial (gain) loss – experience	0	2
Actuarial (gain) loss – financial assumptions	9	(4)
Return on plan assets greater than discount rate	(16)	0
DB Pension Plans | Fair value of plan assets
Disclosure of net defined benefit liability (asset) [line items]
Defined benefit obligation, beginning balance	71	67
Interest cost	2	2
Contributions by employer	(1)	1
Benefits paid	(3)	(2)
Settlements	(52)	0
Remeasurements
Increase (decrease) through changes in foreign exchange rates, net defined benefit liability (asset)	(2)	3
Return on plan assets greater than discount rate	16	0
Defined benefit obligation, ending balance	31	71
DB Pension Plans | Defined benefit obligation
Disclosure of net defined benefit liability (asset) [line items]
Defined benefit obligation, beginning balance	79	76
Current service cost	0	1
Interest cost	2	3
Benefits paid	(3)	(2)
Settlements	(49)	0
Remeasurements
Actuarial (gain) loss – experience	0	2
Actuarial (gain) loss – financial assumptions	9	(4)
Increase (decrease) through changes in foreign exchange rates, net defined benefit liability (asset)	(2)	3
Defined benefit obligation, ending balance	39	79
OPEB Plans
Disclosure of net defined benefit liability (asset) [line items]
Current service cost	10	11
Interest cost	7	8
Remeasurements
Actuarial (gain) loss – experience	(1)	(13)
Actuarial (gain) loss – financial assumptions	20	(45)
Return on plan assets greater than discount rate	0	0
OPEB Plans | Fair value of plan assets
Disclosure of net defined benefit liability (asset) [line items]
Defined benefit obligation, beginning balance	0	0
Interest cost	0	0
Contributions by employer	2	2
Benefits paid	(2)	(2)
Settlements	0	0
Remeasurements
Increase (decrease) through changes in foreign exchange rates, net defined benefit liability (asset)	0	0
Return on plan assets greater than discount rate	0	0
Defined benefit obligation, ending balance	0	0
OPEB Plans | Defined benefit obligation
Disclosure of net defined benefit liability (asset) [line items]
Defined benefit obligation, beginning balance	199	244
Current service cost	10	11
Interest cost	7	8
Benefits paid	(4)	(4)
Settlements	0	0
Remeasurements
Actuarial (gain) loss – experience	(1)	(13)
Actuarial (gain) loss – financial assumptions	20	(45)
Increase (decrease) through changes in foreign exchange rates, net defined benefit liability (asset)	(1)	(2)
Defined benefit obligation, ending balance	201	199
Retirement Plan Funding Status [Member] | DB Pension Plans
Disclosure of net defined benefit liability (asset) [line items]
Defined benefit obligation, beginning balance	(8)
Remeasurements
Defined benefit obligation, ending balance	(8)	(8)
Retirement Plan Funding Status [Member] | OPEB Plans
Disclosure of net defined benefit liability (asset) [line items]
Defined benefit obligation, beginning balance	(199)
Remeasurements
Defined benefit obligation, ending balance	$ (201)	$ (199)

Pensions and Other Post-emplo_4

Pensions and Other Post-employment Benefits - Narrative (Details) - CAD ($) $ in Millions	12 Months Ended
	Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2021
Disclosure of defined benefit plans [line items]
Remeasurement of pension plans	$ (1)	$ (17)
DB Pension Plans
Disclosure of defined benefit plans [line items]
Actuarial gains (losses) arising from settlement of service costs	5
Actuarial gain, net of tax	1
Fair value of plan assets | DB Pension Plans
Disclosure of defined benefit plans [line items]
Contributions by employer	(1)	1
Fair value of plan assets | OPEB Plans
Disclosure of defined benefit plans [line items]
Contributions by employer	$ 2	$ 2
Canada | Fair value of plan assets | OPEB Plans
Disclosure of defined benefit plans [line items]
Actuarial assumption of medical cost trend rates	6.00%		5.00%
Actuarial assumption of medical cost trend rates, decreases per period	0.50%
Canada | Defined benefit obligation | OPEB Plans
Disclosure of defined benefit plans [line items]
Actuarial assumption of medical cost trend rates	6.00%
Actuarial assumption of medical cost trend rates, decreases per period	0.50%
United States | Fair value of plan assets | OPEB Plans
Disclosure of defined benefit plans [line items]
Actuarial assumption of medical cost trend rates	6.00%		5.00%
Actuarial assumption of medical cost trend rates, decreases per period	0.25%
United States | Defined benefit obligation | OPEB Plans
Disclosure of defined benefit plans [line items]
Actuarial assumption of medical cost trend rates	6.50%
Actuarial assumption of medical cost trend rates, decreases per period	0.25%
Actuarial assumption of average health care cost trend for 2022 and thereafter | Canada | OPEB Plans
Disclosure of defined benefit plans [line items]
Actuarial assumption of medical cost trend rates			5.00%
Actuarial assumption of average health care cost trend for 2022 and thereafter | United States | OPEB Plans
Disclosure of defined benefit plans [line items]
Actuarial assumption of medical cost trend rates			5.00%

Pensions and Other Post-emplo_5

Pensions and Other Post-employment Benefits - DB Pension Plan Assets (Details)	Dec. 31, 2019	Dec. 31, 2018
Disclosure of employee benefits [Abstract]
Target allocation, Money market type funds (percent)	0.00%
Target allocation, Equity securities (percent)	3500.00%
Target allocation, Debt securities (percent)	65.00%
Money market type funds (percent)	0.00%	5.00%
Equity securities (percent)	35.00%	0.00%
Debt securities (percent)	65.00%	95.00%

Pensions and Other Post-emplo_6

Pensions and Other Post-employment Benefits - Defined Contribution Pension Plan - Net Earnings and OCI (Details) - CAD ($) $ in Millions	12 Months Ended
	Dec. 31, 2019	Dec. 31, 2018
DB Pension Plans
Disclosure of defined benefit plans [line items]
Current service cost	$ 0	$ 1
Past service cost	3	0
Interest cost	0	1
Benefit cost	3	2
Actuarial (gain) loss – experience	0	2
Actuarial (gain) loss – financial assumptions	9	(4)
Return on plan assets greater than discount rate	(16)	0
Remeasurement effects recognized in OCI	(7)	(2)
OPEB Plans
Disclosure of defined benefit plans [line items]
Current service cost	10	11
Past service cost	(29)	0
Interest cost	7	8
Benefit cost	(12)	19
Actuarial (gain) loss – experience	(1)	(13)
Actuarial (gain) loss – financial assumptions	20	(45)
Return on plan assets greater than discount rate	0	0
Remeasurement effects recognized in OCI	$ 19	$ (58)

Pensions and Other Post-emplo_7

Pensions and Other Post-employment Benefits - Actuarial Assumptions and Sensitivity Analysis (Details) - CAD ($) $ in Millions	Dec. 31, 2019	Dec. 31, 2018
Minimum | DB Pension Plans
Disclosure of defined benefit plans [line items]
Discount rate for benefit expense and obligation	2.30%	3.40%
Minimum | OPEB Plans
Disclosure of defined benefit plans [line items]
Discount rate for benefit expense and obligation	3.00%	3.40%
Maximum | DB Pension Plans
Disclosure of defined benefit plans [line items]
Discount rate for benefit expense and obligation	4.20%	3.60%
Maximum | OPEB Plans
Disclosure of defined benefit plans [line items]
Discount rate for benefit expense and obligation	3.70%	3.70%
Discount rate | DB Pension Plans
Disclosure of defined benefit plans [line items]
Impact on defined benefit obligation, increase in assumption	$ (4)
Impact on defined benefit obligation, decrease in assumption	$ 5
Percentage of reasonably possible increase in actuarial assumption	1.00%
Percentage of reasonably possible decrease in actuarial assumption	(1.00%)
Discount rate | OPEB Plans
Disclosure of defined benefit plans [line items]
Impact on defined benefit obligation, increase in assumption	$ (23)
Impact on defined benefit obligation, decrease in assumption	$ 28
Percentage of reasonably possible increase in actuarial assumption	1.00%
Percentage of reasonably possible decrease in actuarial assumption	(1.00%)
Health care cost trend rate | DB Pension Plans
Disclosure of defined benefit plans [line items]
Percentage of reasonably possible increase in actuarial assumption	1.00%
Percentage of reasonably possible decrease in actuarial assumption	(1.00%)
Health care cost trend rate | OPEB Plans
Disclosure of defined benefit plans [line items]
Impact on defined benefit obligation, increase in assumption	$ (16)
Impact on defined benefit obligation, decrease in assumption	$ 18
Percentage of reasonably possible increase in actuarial assumption	1.00%
Percentage of reasonably possible decrease in actuarial assumption	(1.00%)

Cash Flows - Change in Non-ca_3

Cash Flows - Change in Non-cash Working Capital (Details) - CAD ($) $ in Millions	12 Months Ended
	Dec. 31, 2019	Dec. 31, 2018
Disclosure of cash flow statement [Abstract]
Accounts receivable	$ (176)	$ 127
Inventories	(502)	393
Prepaid expenses	(30)	30
Accounts payable and accrued liabilities	604	(65)
Change in non-cash working capital	(104)	485
Change in non-cash working capital, operating activities	(280)	130
Change in non-cash working capital, financing activities	3	120
Change in non-cash working capital, investing activities	$ 173	$ 235

Financial Instruments and Ris_3

Financial Instruments and Risk Management - Financial Instruments at Fair Value (Details) - CAD ($) $ in Millions	12 Months Ended
	Dec. 31, 2019	Dec. 31, 2018
Disclosure Of Financial Assets And Liabilities [Line Items]
Derivative financial liabilities	$ (39)	$ (80)
Trading inventories measured at fair value less costs to sell	155	200
Derivatives | FVTPL
Disclosure Of Financial Assets And Liabilities [Line Items]
Financial assets, at fair value	6
Derivatives | Natural gas(1) | FVTPL
Disclosure Of Financial Assets And Liabilities [Line Items]
Financial assets, at fair value	31	(9)
Derivatives | Natural gas(1) | FVTPL, held-for-trading
Disclosure Of Financial Assets And Liabilities [Line Items]
Increase (decrease) in financial assets	(4)	(10)
Trading inventories measured at fair value less costs to sell	19	15
Derivatives | Crude oil(2) | FVTPL
Disclosure Of Financial Assets And Liabilities [Line Items]
Financial assets, at fair value	11	89
Derivatives | Crude oil(2) | FVTPL, held-for-trading
Disclosure Of Financial Assets And Liabilities [Line Items]
Increase (decrease) in financial assets	12	67
Trading inventories measured at fair value less costs to sell	136	185
Derivatives | Call Option, Crude Oil [Member] | FVTPL
Disclosure Of Financial Assets And Liabilities [Line Items]
Financial assets, at fair value	(2)	0
Derivatives | Crude oil put options | FVTPL
Disclosure Of Financial Assets And Liabilities [Line Items]
Financial assets, at fair value	(4)	0
Derivatives | Foreign currency forwards | FVTPL
Disclosure Of Financial Assets And Liabilities [Line Items]
Financial assets, at fair value	2	(1)
Other financial assets | FVTPL
Disclosure Of Financial Assets And Liabilities [Line Items]
Financial assets, at fair value	1	1
Financial liabilities at amortised cost
Disclosure Of Financial Assets And Liabilities [Line Items]
Financial liabilities	5,000	5,500
Financial liabilities, at fair value	$ 5,300	$ 5,700

Financial Instruments and Ris_4

Financial Instruments and Risk Management - Market Risk (Details)	12 Months Ended
	Dec. 31, 2019CAD ($)bbl	Dec. 31, 2018CAD ($)	Dec. 31, 2019USD ($)bbl	Dec. 31, 2018USD ($)
Disclosure Of Financial Assets And Liabilities [Line Items]
Call options sold | bbl	35,714		35,714
Average Sold Call Price			$ 60.50
Gains (losses) on hedging instrument, fair value hedges	$ 16,000,000	$ 0
Unrealized mark to market loss (gain) (note 25)	44,000,000	(150,000,000)
Line of credit, maximum borrowing capacity	4,900,000,000
Hedged item, liabilities			500,000,000
Long-term debt	4,570,000,000	4,114,000,000	$ 2,387,000,000	$ 1,637,000,000
Tax relating to cash flow hedges	$ (3,000,000)	(5,000,000)
Volume hedged buying put options | bbl	36,263		36,263
Average Purchased Put Price	$ 55.61
Volume hedged selling put options | bbl	20,055		20,055
Average Sold Put Price	$ 50.77
Hedges of net investment in foreign operations [member]
Disclosure Of Financial Assets And Liabilities [Line Items]
Financial instruments designated as hedging instruments, at fair value			$ 2,400,000,000	$ 2,700,000,000
Gains (losses) on hedges of net investments in foreign operations, net of tax	146,000,000	(262,000,000)
Income tax relating to components of other comprehensive income that will not be reclassified to profit or loss	30,000,000	$ 41,000,000
Syndicated Bank Facilities [Member]
Disclosure Of Financial Assets And Liabilities [Line Items]
Line of credit, maximum borrowing capacity	$ 4,000,000,000

Financial Instruments and Ris_5

Financial Instruments and Risk Management - Earnings Impact (Details) - CAD ($) $ in Millions	12 Months Ended
	Dec. 31, 2019	Dec. 31, 2018
Disclosure Of Financial Assets And Liabilities [Line Items]
Adjustments for fair value losses (gains), net of put and call options	$ (38)
Unrealized mark to market loss (gain) (note 25)	44	$ (150)
Gains (losses) on hedging instrument, fair value hedges	$ 16	$ 0

Financial Instruments and Ris_6

Financial Instruments and Risk Management - Offsetting Financial Assets and Liabilities (Details) - CAD ($) $ in Millions	Dec. 31, 2019	Dec. 31, 2018
Offsetting financial assets [abstract]
Offsetting financial assets, Gross amount	$ 896	$ 813
Offsetting financial assets, Amount offset	(300)	(455)
Offsetting financial assets, Net amount	596	358
Offsetting financial liabilities [abstract]
Offsetting financial liabilities, Gross amount	(891)	(863)
Offsetting financial liabilities, Amount offset	306	369
Offsetting financial liabilities, Net amount	(585)	(494)
Financial liabilities, derivatives
Offsetting financial liabilities [abstract]
Offsetting financial liabilities, Gross amount	(48)	(107)
Offsetting financial liabilities, Amount offset	25	62
Offsetting financial liabilities, Net amount	(23)	(45)
Financial liabilities, normal purchase and sale agreements
Offsetting financial liabilities [abstract]
Offsetting financial liabilities, Gross amount	(843)	(756)
Offsetting financial liabilities, Amount offset	281	307
Offsetting financial liabilities, Net amount	(562)	(449)
Financial assets, derivatives
Offsetting financial assets [abstract]
Offsetting financial assets, Gross amount	79	188
Offsetting financial assets, Amount offset	(26)	(120)
Offsetting financial assets, Net amount	53	68
Financial assets, normal purchase and sale agreements
Offsetting financial assets [abstract]
Offsetting financial assets, Gross amount	817	625
Offsetting financial assets, Amount offset	(274)	(335)
Offsetting financial assets, Net amount	$ 543	$ 290

Financial Instruments and Ris_7

Financial Instruments and Risk Management - Market Risk Sensitivity Analysis (Details) - CAD ($)	12 Months Ended
	Dec. 31, 2019	Dec. 31, 2018
Disclosure of nature and extent of risks arising from financial instruments [line items]
Unrealized Gain (Loss) On Hedging Instrument, Fair Value Hedges	$ 6,000,000	$ 0
Sensitivity analysis, increase | Currency risk
Disclosure of nature and extent of risks arising from financial instruments [line items]
Market risk sensitivity analysis	1,000,000
Sensitivity analysis, increase | Crude oil price | Commodity price risk
Disclosure of nature and extent of risks arising from financial instruments [line items]
Market risk sensitivity analysis	$ 13,000,000
Sensitivity analysis for types of market risk, reasonably possible change in risk variable, percent	10.00%
Sensitivity analysis, increase | Natural gas price | Commodity price risk
Disclosure of nature and extent of risks arising from financial instruments [line items]
Market risk sensitivity analysis	$ (2,000,000)
Sensitivity analysis for types of market risk, reasonably possible change in risk variable, percent	10.00%
Sensitivity analysis, decrease | Currency risk
Disclosure of nature and extent of risks arising from financial instruments [line items]
Market risk sensitivity analysis	$ (1,000,000)
Sensitivity analysis, decrease | Crude oil price | Commodity price risk
Disclosure of nature and extent of risks arising from financial instruments [line items]
Market risk sensitivity analysis	$ (13,000,000)
Sensitivity analysis for types of market risk, reasonably possible change in risk variable, percent	10.00%
Sensitivity analysis, decrease | Natural gas price | Commodity price risk
Disclosure of nature and extent of risks arising from financial instruments [line items]
Market risk sensitivity analysis	$ 2,000,000
Sensitivity analysis for types of market risk, reasonably possible change in risk variable, percent	10.00%
United States of America, Dollars | Sensitivity analysis, increase | Currency risk
Disclosure of nature and extent of risks arising from financial instruments [line items]
Sensitivity analysis for types of market risk, reasonably possible change in risk variable, amount	$ 0.01
United States of America, Dollars | Sensitivity analysis, decrease | Currency risk
Disclosure of nature and extent of risks arising from financial instruments [line items]
Sensitivity analysis for types of market risk, reasonably possible change in risk variable, amount	$ 0.01

Financial Instruments and Ris_8

Financial Instruments and Risk Management - Financial Risk (Details) $ in Billions	12 Months Ended
	Dec. 31, 2019CAD ($)	Dec. 31, 2018CAD ($)	Dec. 31, 2019USD ($)	Jan. 30, 2018CAD ($)
Disclosure of detailed information about financial instruments [line items]
Line of credit, maximum borrowing capacity	$ 4,900,000,000
Line of credit, current borrowing capacity	3,914,000,000
Revenues	19,983,000,000	$ 22,252,000,000
Bank operating loan
Disclosure of detailed information about financial instruments [line items]
Line of credit, maximum borrowing capacity	900,000,000	900,000,000
Line of credit, current borrowing capacity	464,000,000
Syndicated Bank Facilities [Member]
Disclosure of detailed information about financial instruments [line items]
Line of credit, maximum borrowing capacity	4,000,000,000
Line of credit, current borrowing capacity	3,450,000,000
Single customer over 10% of revenue | Customer concentration risk [Member]
Disclosure of detailed information about financial instruments [line items]
Revenues	3,900,000,000	$ 4,200,000,000
2018 U.S Shelf Prospectus
Disclosure of detailed information about financial instruments [line items]
Authorised capital commitments, pre-registration	$ 3,000,000,000		$ 2.3	$ 3,000,000,000

Financial Instruments and Ris_9

Financial Instruments and Risk Management - Accounts Receivable Aging (Details) - CAD ($) $ in Millions	12 Months Ended
	Dec. 31, 2019	Dec. 31, 2018
Disclosure of financial assets that are either past due or impaired [line items]
Impairment loss, receivables	$ 4	$ 3
Trade receivables
Disclosure of financial assets that are either past due or impaired [line items]
Accounts receivable	1,499
Trade receivables | Provision for expected credit losses
Disclosure of financial assets that are either past due or impaired [line items]
Accounts receivable	(34)
Trade receivables | Current | Cost
Disclosure of financial assets that are either past due or impaired [line items]
Accounts receivable	1,418
Trade receivables | Past due (1 - 30 days) | Cost
Disclosure of financial assets that are either past due or impaired [line items]
Accounts receivable	64
Trade receivables | Past due (31 - 60 days) | Cost
Disclosure of financial assets that are either past due or impaired [line items]
Accounts receivable	4
Trade receivables | Past due (61 - 90 days) | Cost
Disclosure of financial assets that are either past due or impaired [line items]
Accounts receivable	0
Trade receivables | Past due (more than 90 days) | Cost
Disclosure of financial assets that are either past due or impaired [line items]
Accounts receivable	$ 47

Related Party Transactions - Si

Related Party Transactions - Significant Subsidiaries and Joint Operations (Details) - CAD ($)	12 Months Ended
	Dec. 31, 2019	Dec. 31, 2018
Sunrise Oil Sands Partnership
Disclosure of transactions between related parties [line items]
Proportion of ownership interest in joint operation	50.00%
BP-Husky Refining LLC
Disclosure of transactions between related parties [line items]
Proportion of ownership interest in joint operation	50.00%
Entities with joint control or significant influence over entity | Husky Oil Operations Limited
Disclosure of transactions between related parties [line items]
Proportion of ownership interest in joint operation	100.00%
Entities with joint control or significant influence over entity | Husky Energy International Corporation
Disclosure of transactions between related parties [line items]
Proportion of ownership interest in joint operation	100.00%
Entities with joint control or significant influence over entity | Lima Refining Company
Disclosure of transactions between related parties [line items]
Proportion of ownership interest in joint operation	100.00%
Entities with joint control or significant influence over entity | Husky Marketing and Supply Company
Disclosure of transactions between related parties [line items]
Proportion of ownership interest in joint operation	100.00%
Entities with joint control or significant influence over entity | Husky Oil Limited Partnership
Disclosure of transactions between related parties [line items]
Proportion of ownership interest in joint operation	100.00%
Entities with joint control or significant influence over entity | Husky Terra Nova Partnership(1)
Disclosure of transactions between related parties [line items]
Proportion of ownership interest in joint operation	100.00%
Entities with joint control or significant influence over entity | Husky Downstream General Partnership(1)
Disclosure of transactions between related parties [line items]
Proportion of ownership interest in joint operation	100.00%
Entities with joint control or significant influence over entity | Husky Energy Marketing Partnership
Disclosure of transactions between related parties [line items]
Proportion of ownership interest in joint operation	100.00%
Entities with joint control or significant influence over entity | Sunrise Oil Sands Partnership
Disclosure of transactions between related parties [line items]
Proportion of ownership interest in joint operation	50.00%
Entities with joint control or significant influence over entity | BP-Husky Refining LLC
Disclosure of transactions between related parties [line items]
Proportion of ownership interest in joint operation	50.00%
Husky Midstream Limited Partnership | Joint ventures where entity is venturer
Disclosure of transactions between related parties [line items]
Revenue from rendering of services, related party transactions	$ 424,000,000	$ 448,000,000
Purchases of goods, related party transactions	219,000,000	200,000,000
Distributions, Related Party Transactions	94,000,000	139,000,000
Contributions, Related Party Transactions	(37,000,000)	40,000,000
Due from related parties, related party transactions	$ 143,000,000	$ 140,000,000

Related Party Transactions (Det

Related Party Transactions (Details) - Husky Midstream Limited Partnership - CAD ($)	12 Months Ended
	Dec. 31, 2019	Dec. 31, 2018
Disclosure of transactions between related parties [line items]
Share of equity investment	35.00%	35.00%
Joint ventures where entity is venturer
Disclosure of transactions between related parties [line items]
Revenue from rendering of services, related party transactions	$ 424,000,000	$ 448,000,000
Purchases of goods, related party transactions	219,000,000	200,000,000
Distributions, Related Party Transactions	94,000,000	139,000,000
Contributions, Related Party Transactions	(37,000,000)	40,000,000
Due from related parties, related party transactions	143,000,000	140,000,000
Deferred Revenue From Construction Contracts, Percentage of Completion Method	0	0
Amounts payable, related party transactions	$ 16,000,000	$ 0

Related Party Transactions - Co

Related Party Transactions - Compensation of key management personnel (Details) - Key management personnel - CAD ($) $ in Millions	12 Months Ended
	Dec. 31, 2019	Dec. 31, 2018
Disclosure of transactions between related parties [line items]
Short-term employee benefits(1)	$ 18	$ 17
Stock-based compensation(2)	26	33
Key management personnel compensation	$ 44	$ 50

Commitments and Contingencies_2

Commitments and Contingencies (Details) - CAD ($) $ in Millions	Dec. 31, 2019	Dec. 31, 2018
Disclosure of maturity analysis for non-derivative financial liabilities [line items]
Operating agreements(1)	$ 1,051
Firm transportation agreements(1)	7,156
Unconditional purchase obligations(2)	12,884
Lease rentals and exploration work agreements	1,160
Obligations to fund equity investee(3)	703
Minimum future payments for commitments	22,954
Within 1 year
Disclosure of maturity analysis for non-derivative financial liabilities [line items]
Operating agreements(1)	75
Firm transportation agreements(1)	576
Unconditional purchase obligations(2)	2,224
Lease rentals and exploration work agreements	79
Obligations to fund equity investee(3)	54
Minimum future payments for commitments	3,008
After 1 year but no more than 5 years
Disclosure of maturity analysis for non-derivative financial liabilities [line items]
Operating agreements(1)	310
Firm transportation agreements(1)	2,377
Unconditional purchase obligations(2)	5,517
Lease rentals and exploration work agreements	215
Obligations to fund equity investee(3)	290
Minimum future payments for commitments	8,709
More than 5 years
Disclosure of maturity analysis for non-derivative financial liabilities [line items]
Operating agreements(1)	666
Firm transportation agreements(1)	4,203
Unconditional purchase obligations(2)	5,143
Lease rentals and exploration work agreements	866
Obligations to fund equity investee(3)	359
Minimum future payments for commitments	11,237
Husky Midstream Limited Partnership
Disclosure of maturity analysis for non-derivative financial liabilities [line items]
Operating agreements(1)	1,100
Firm transportation agreements(1)		$ 1,800
Joint Venture, Counterparties
Disclosure of maturity analysis for non-derivative financial liabilities [line items]
Unconditional purchase obligations(2)	$ 2,200

Capital Disclosures (Details)

Capital Disclosures (Details) $ in Billions	12 Months Ended
	Dec. 31, 2019CAD ($)	Dec. 31, 2018CAD ($)
Disclosure of additional information [Abstract]
Equity and debt	$ 22.8	$ 25.4
Debt to capital ratio	0.242	0.227
Debt to capital ratio, target	0.65
Debt to funds from operation ratio	1.7	1.4
Debt to funds from operation ratio, target	2

Subsequent Events - Segmented F

Subsequent Events - Segmented Financial Information Reclassified (Details) - CAD ($) $ in Millions	12 Months Ended
	Dec. 31, 2019	Dec. 31, 2018
Disclosure of non-adjusting events after reporting period [line items]
Gross revenues	$ 20,117	$ 21,919
Royalties	(323)	(335)
Marketing and other	189	668
Revenue	19,983	22,252
Purchases of crude oil and products	12,817	14,555
Production, operating and transportation expenses (note 21)	3,017	2,803
Selling, general and administrative expenses (note 21)	693	654
Depletion, depreciation, amortization and impairment (notes 9, 10)	5,496	2,591
Expense arising from exploration for and evaluation of mineral resources	547	149
Gain on sale of assets (note 9)	(8)	(4)
Other – net (note 13)	(584)	(591)
Expenses	21,978	20,157
Earnings from operating activities	(1,995)	2,095
Share of equity investment income (note 12)	59	69
Net foreign exchange gain	44	14
Finance income	74	64
Finance expenses	(351)	(314)
Financial Items	(233)	(236)
Earnings before income taxes	(2,169)	1,928
Current tax expense (income) and adjustments for current tax of prior periods	175	75
Deferred tax expense (income)	(974)	396
Tax expense (income)	(799)	471
Net earnings (loss)	(1,370)	1,457
Intersegment revenues	2,022	1,554
Expense arising from exploration for and evaluation of mineral resources	46	242
Expenditures on property, plant and equipment(2)	3,386	3,336
Assets	33,122	35,225
Canadian Refined Products
Disclosure of non-adjusting events after reporting period [line items]
Gross revenues	3,122	3,412
Eliminations
Disclosure of non-adjusting events after reporting period [line items]
Gross revenues	(2,022)	(1,554)
Reclassification of Segments
Disclosure of non-adjusting events after reporting period [line items]
Gross revenues	20,117	21,919
Royalties	(323)	(335)
Marketing and other	189	668
Revenue	19,983	22,252
Purchases of crude oil and products	12,817	14,555
Production, operating and transportation expenses (note 21)	3,017	2,803
Selling, general and administrative expenses (note 21)	693	654
Depletion, depreciation, amortization and impairment (notes 9, 10)	5,496	2,591
Expense arising from exploration for and evaluation of mineral resources	547	149
Gain on sale of assets (note 9)	(8)	(4)
Other – net (note 13)	(584)	(591)
Expenses	21,978	20,157
Earnings from operating activities	(1,995)	2,095
Share of equity investment income (note 12)	59	69
Net foreign exchange gain	44	14
Finance income	74	64
Finance expenses	(351)	(314)
Financial Items	(233)	(236)
Earnings before income taxes	(2,169)	1,928
Current tax expense (income) and adjustments for current tax of prior periods	175	75
Deferred tax expense (income)	(974)	396
Tax expense (income)	(799)	471
Net earnings (loss)	(1,370)	1,457
Intersegment revenues	664	937
Expense arising from exploration for and evaluation of mineral resources	46	242
Expenditures on property, plant and equipment(2)	3,386	3,336
Assets	33,122	35,225
Reclassification of Segments | Integrated Corridor
Disclosure of non-adjusting events after reporting period [line items]
Gross revenues	18,565	19,966
Royalties	(214)	(207)
Marketing and other	189	668
Revenue	18,540	20,427
Purchases of crude oil and products	12,841	14,503
Production, operating and transportation expenses (note 21)	2,679	2,501
Selling, general and administrative expenses (note 21)	346	313
Depletion, depreciation, amortization and impairment (notes 9, 10)	3,731	1,804
Expense arising from exploration for and evaluation of mineral resources	167	78
Gain on sale of assets (note 9)	(7)	(4)
Other – net (note 13)	(577)	(566)
Expenses	19,180	18,629
Earnings from operating activities	(640)	1,798
Share of equity investment income (note 12)	9	18
Net foreign exchange gain	0	0
Finance income	0	0
Finance expenses	(162)	(108)
Financial Items	(162)	(108)
Earnings before income taxes	(793)	1,708
Current tax expense (income) and adjustments for current tax of prior periods	25	6
Deferred tax expense (income)	(252)	433
Tax expense (income)	(227)	439
Net earnings (loss)	(566)	1,269
Intersegment revenues	664	937
Expense arising from exploration for and evaluation of mineral resources	20	117
Expenditures on property, plant and equipment(2)	2,009	2,149
Assets	22,261	22,953
Reclassification of Segments | Integrated Corridor | Lloyd Heavy Oil Value Chain
Disclosure of non-adjusting events after reporting period [line items]
Gross revenues	5,117	5,308
Royalties	(160)	(137)
Marketing and other	60	458
Revenue	5,017	5,629
Purchases of crude oil and products	1,829	2,217
Production, operating and transportation expenses (note 21)	1,209	1,121
Selling, general and administrative expenses (note 21)	154	129
Depletion, depreciation, amortization and impairment (notes 9, 10)	941	887
Expense arising from exploration for and evaluation of mineral resources	54	32
Gain on sale of assets (note 9)	0	(1)
Other – net (note 13)	103	(106)
Expenses	4,290	4,279
Earnings from operating activities	727	1,350
Share of equity investment income (note 12)	9	18
Net foreign exchange gain	0	0
Finance income	0	0
Finance expenses	(48)	(43)
Financial Items	(48)	(43)
Earnings before income taxes	688	1,325
Current tax expense (income) and adjustments for current tax of prior periods	(2)	(3)
Deferred tax expense (income)	186	365
Tax expense (income)	184	362
Net earnings (loss)	504	963
Intersegment revenues	452	693
Expense arising from exploration for and evaluation of mineral resources	17	18
Expenditures on property, plant and equipment(2)	939	1,070
Assets	8,312	7,707
Reclassification of Segments | Integrated Corridor | Oil Sands
Disclosure of non-adjusting events after reporting period [line items]
Gross revenues	931	405
Royalties	(13)	(12)
Marketing and other	4	166
Revenue	922	559
Purchases of crude oil and products	528	306
Production, operating and transportation expenses (note 21)	140	132
Selling, general and administrative expenses (note 21)	27	28
Depletion, depreciation, amortization and impairment (notes 9, 10)	938	95
Expense arising from exploration for and evaluation of mineral resources	2	18
Gain on sale of assets (note 9)	0	0
Other – net (note 13)	(28)	0
Expenses	1,607	579
Earnings from operating activities	(685)	(20)
Share of equity investment income (note 12)	0	0
Net foreign exchange gain	0	0
Finance income	0	0
Finance expenses	(59)	(21)
Financial Items	(59)	(21)
Earnings before income taxes	(744)	(41)
Current tax expense (income) and adjustments for current tax of prior periods	10	0
Deferred tax expense (income)	(209)	(11)
Tax expense (income)	(199)	(11)
Net earnings (loss)	(545)	(30)
Intersegment revenues	0	0
Expense arising from exploration for and evaluation of mineral resources	0	0
Expenditures on property, plant and equipment(2)	38	51
Assets	2,757	3,237
Reclassification of Segments | Integrated Corridor | Western Canada Production
Disclosure of non-adjusting events after reporting period [line items]
Gross revenues	506	661
Royalties	(41)	(58)
Marketing and other	101	86
Revenue	566	689
Purchases of crude oil and products	39	140
Production, operating and transportation expenses (note 21)	308	302
Selling, general and administrative expenses (note 21)	105	106
Depletion, depreciation, amortization and impairment (notes 9, 10)	1,034	292
Expense arising from exploration for and evaluation of mineral resources	111	28
Gain on sale of assets (note 9)	(2)	(1)
Other – net (note 13)	2	5
Expenses	1,597	872
Earnings from operating activities	(1,031)	(183)
Share of equity investment income (note 12)	0	0
Net foreign exchange gain	0	0
Finance income	0	0
Finance expenses	(24)	(19)
Financial Items	(24)	(19)
Earnings before income taxes	(1,055)	(202)
Current tax expense (income) and adjustments for current tax of prior periods	0	0
Deferred tax expense (income)	(283)	(55)
Tax expense (income)	(283)	(55)
Net earnings (loss)	(772)	(147)
Intersegment revenues	205	233
Expense arising from exploration for and evaluation of mineral resources	3	99
Expenditures on property, plant and equipment(2)	191	322
Assets	1,709	2,534
Reclassification of Segments | Integrated Corridor | U.S. Refining
Disclosure of non-adjusting events after reporting period [line items]
Gross revenues	10,250	11,777
Royalties	0	0
Marketing and other	24	(42)
Revenue	10,274	11,735
Purchases of crude oil and products	8,935	10,342
Production, operating and transportation expenses (note 21)	869	795
Selling, general and administrative expenses (note 21)	51	40
Depletion, depreciation, amortization and impairment (notes 9, 10)	735	450
Expense arising from exploration for and evaluation of mineral resources	0	0
Gain on sale of assets (note 9)	1	0
Other – net (note 13)	(654)	(464)
Expenses	9,937	11,163
Earnings from operating activities	337	572
Share of equity investment income (note 12)	0	0
Net foreign exchange gain	0	0
Finance income	0	0
Finance expenses	(18)	(14)
Financial Items	(18)	(14)
Earnings before income taxes	319	558
Current tax expense (income) and adjustments for current tax of prior periods	17	9
Deferred tax expense (income)	54	115
Tax expense (income)	71	124
Net earnings (loss)	248	434
Intersegment revenues	3	5
Expense arising from exploration for and evaluation of mineral resources	0	0
Expenditures on property, plant and equipment(2)	768	666
Assets	8,645	8,558
Reclassification of Segments | Integrated Corridor | Canadian Refined Products
Disclosure of non-adjusting events after reporting period [line items]
Gross revenues	2,425	2,752
Royalties	0	0
Marketing and other	0	0
Revenue	2,425	2,752
Purchases of crude oil and products	2,174	2,435
Production, operating and transportation expenses (note 21)	153	151
Selling, general and administrative expenses (note 21)	9	10
Depletion, depreciation, amortization and impairment (notes 9, 10)	83	80
Expense arising from exploration for and evaluation of mineral resources	0	0
Gain on sale of assets (note 9)	(6)	(2)
Other – net (note 13)	0	(1)
Expenses	2,413	2,673
Earnings from operating activities	12	79
Share of equity investment income (note 12)	0	0
Net foreign exchange gain	0	0
Finance income	0	0
Finance expenses	(13)	(11)
Financial Items	(13)	(11)
Earnings before income taxes	(1)	68
Current tax expense (income) and adjustments for current tax of prior periods	0	0
Deferred tax expense (income)	0	19
Tax expense (income)	0	19
Net earnings (loss)	(1)	49
Intersegment revenues	4	6
Expense arising from exploration for and evaluation of mineral resources	0	0
Expenditures on property, plant and equipment(2)	73	40
Assets	838	917
Reclassification of Segments | Integrated Corridor | Eliminations
Disclosure of non-adjusting events after reporting period [line items]
Gross revenues	(664)	(937)
Royalties	0	0
Marketing and other	0	0
Revenue	(664)	(937)
Purchases of crude oil and products	(664)	(937)
Production, operating and transportation expenses (note 21)	0	0
Selling, general and administrative expenses (note 21)	0	0
Depletion, depreciation, amortization and impairment (notes 9, 10)	0	0
Expense arising from exploration for and evaluation of mineral resources	0	0
Gain on sale of assets (note 9)	0	0
Other – net (note 13)	0	0
Expenses	(664)	(937)
Earnings from operating activities	0	0
Share of equity investment income (note 12)	0	0
Net foreign exchange gain	0	0
Finance income	0	0
Finance expenses	0	0
Financial Items	0	0
Earnings before income taxes	0	0
Current tax expense (income) and adjustments for current tax of prior periods	0	0
Deferred tax expense (income)	0	0
Tax expense (income)	0	0
Net earnings (loss)	0	0
Intersegment revenues	0	0
Expense arising from exploration for and evaluation of mineral resources	0	0
Expenditures on property, plant and equipment(2)	0	0
Assets	0	0
Reclassification of Segments | Offshore
Disclosure of non-adjusting events after reporting period [line items]
Gross revenues	1,552	1,953
Royalties	(109)	(128)
Marketing and other	0	0
Revenue	1,443	1,825
Purchases of crude oil and products	(24)	52
Production, operating and transportation expenses (note 21)	340	304
Selling, general and administrative expenses (note 21)	55	58
Depletion, depreciation, amortization and impairment (notes 9, 10)	1,661	695
Expense arising from exploration for and evaluation of mineral resources	380	71
Gain on sale of assets (note 9)	(1)	0
Other – net (note 13)	9	(19)
Expenses	2,420	1,161
Earnings from operating activities	(977)	664
Share of equity investment income (note 12)	50	51
Net foreign exchange gain	0	0
Finance income	3	12
Finance expenses	(38)	(28)
Financial Items	(35)	(16)
Earnings before income taxes	(962)	699
Current tax expense (income) and adjustments for current tax of prior periods	125	141
Deferred tax expense (income)	(393)	35
Tax expense (income)	(268)	176
Net earnings (loss)	(694)	523
Intersegment revenues	0	0
Expense arising from exploration for and evaluation of mineral resources	26	125
Expenditures on property, plant and equipment(2)	1,246	1,066
Assets	8,077	8,627
Reclassification of Segments | Corporate
Disclosure of non-adjusting events after reporting period [line items]
Gross revenues	0	0
Royalties	0	0
Marketing and other	0	0
Revenue	0	0
Purchases of crude oil and products	0	0
Production, operating and transportation expenses (note 21)	(2)	(2)
Selling, general and administrative expenses (note 21)	292	283
Depletion, depreciation, amortization and impairment (notes 9, 10)	104	92
Expense arising from exploration for and evaluation of mineral resources	0	0
Gain on sale of assets (note 9)	0	0
Other – net (note 13)	(16)	(6)
Expenses	378	367
Earnings from operating activities	(378)	(367)
Share of equity investment income (note 12)	0	0
Net foreign exchange gain	44	14
Finance income	71	52
Finance expenses	(151)	(178)
Financial Items	(36)	(112)
Earnings before income taxes	(414)	(479)
Current tax expense (income) and adjustments for current tax of prior periods	25	(72)
Deferred tax expense (income)	(329)	(72)
Tax expense (income)	(304)	(144)
Net earnings (loss)	(110)	(335)
Intersegment revenues	0	0
Expense arising from exploration for and evaluation of mineral resources	0	0
Expenditures on property, plant and equipment(2)	131	121
Assets	$ 2,784	$ 3,645

Uncategorized Items - huskf-201

Label	Element	Value
Non-controlling interests [member]
Dividends paid to non-controlling interests	ifrs-full_DividendsPaidToNoncontrollingInterests	$ 1,000,000
Equity attributable to owners of parent [member]
Dividends paid to non-controlling interests	ifrs-full_DividendsPaidToNoncontrollingInterests	$ 1,000,000