Husky Energy (CVE+A) 40-F 26 Feb 19 2018 FY Annual report (Canada) Financial data

DEI Document

DEI Document	12 Months Ended
	Dec. 31, 2018shares
Document Information [Abstract]
Document Type	40-F
Document Period End Date	Dec. 31, 2018
Document Fiscal Year Focus	2,018
Document Fiscal Period Focus	FY
Entity Registrant Name	Husky Energy Inc.
Entity Central Index Key	49,279
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, 2018CAD ($)	Dec. 31, 2017CAD ($)
Current assets
Cash and cash equivalents (note 4)	$ 2,866	$ 2,513
Accounts receivable (notes 5, 24)	1,355	1,186
Income taxes receivable	112	164
Inventories (note 6)	1,232	1,513
Prepaid expenses	123	145
Restricted cash (notes 7, 16)	0	95
Current assets	5,688	5,616
Non-current assets
Restricted cash (notes 7, 16)	128	97
Exploration and evaluation assets (note 8)	997	838
Property, plant and equipment, net (note 9)	25,800	24,078
Goodwill (note 10)	690	633
Investment in joint ventures (note 11)	1,319	1,238
Long-term income taxes receivable	243	242
Other assets (note 12)	360	185
Total Assets	35,225	32,927
Current liabilities
Accounts payable and accrued liabilities (note 14)	3,159	3,033
Short-term debt (note 15)	200	200
Long-term debt due within one year (note 15)	1,433	0
Asset retirement obligations (note 16)	202	274
Current liabilities	4,994	3,507
Non-current liabilities
Long-term debt (note 15)	4,114	5,240
Other long-term liabilities (note 17)	1,107	1,237
Asset retirement obligations (note 16)	2,222	2,252
Deferred tax liabilities	3,174	2,724
Total Liabilities	15,611	14,960
Shareholders’ equity
Common shares (note 19)	7,293	7,293
Preferred shares (note 19)	874	874
Contributed surplus	2	2
Retained earnings	10,273	9,207
Accumulated other comprehensive income	1,160	580
Non-controlling interest	12	11
Total Shareholders’ Equity	19,614	17,967
Total Liabilities and Shareholders’ Equity	$ 35,225	$ 32,927

Consolidated Statements of Inco

Consolidated Statements of Income - CAD ($) shares in Millions, $ in Millions	12 Months Ended
	Dec. 31, 2018	Dec. 31, 2017
Profit or loss [abstract]
Gross revenues	$ 21,919	$ 18,986
Royalties	(335)	(363)
Marketing and other	668	(40)
Revenues, net of royalties	22,252	18,583
Purchases of crude oil and products	14,555	11,566
Production, operating and transportation expenses (note 20)	2,803	2,679
Selling, general and administrative expenses (note 20)	654	650
Depletion, depreciation, amortization and impairment (note 9)	2,591	2,882
Exploration and evaluation expenses (note 8)	149	146
Gain on sale of assets (note 9)	(4)	(46)
Other – net (note 9)	(591)	(18)
Operating expense	20,157	17,859
Earnings from operating activities	2,095	724
Share of equity investment gain (note 11)	69	61
Net foreign exchange gains (losses)	14	(6)
Finance income	64	37
Finance expenses	(314)	(392)
Financial Items	(236)	(361)
Earnings before income taxes	1,928	424
Provisions for (recovery of) income taxes. current	75	(3)
Provisions for (recovery of) income taxes, deferred	396	(359)
Provisions for (recovery of) income taxes	471	(362)
Net earnings	$ 1,457	$ 786
Earnings per share (note 19)
Earnings per share – basic ($/share)	$ 1.41	$ 0.75
Earnings per share – diluted ($/share)	$ 1.40	$ 0.75
Weighted average number of common shares outstanding (note 19)
Weighted average number of common shares outstanding, basic	1,005.1	1,005.3
Weighted average number of common shares outstanding, diluted	1,006.1	1,005.3

Consolidated Statements of Comp

Consolidated Statements of Comprehensive Income (Loss) Statement - CAD ($) $ in Millions	12 Months Ended
	Dec. 31, 2018	Dec. 31, 2017
Statement of comprehensive income [abstract]
Net earnings	$ 1,457	$ 786
Items that will not be reclassified into earnings, net of tax:
Remeasurements of pension plans (note 22)	46	(7)
Items that may be reclassified into earnings, net of tax:
Derivatives designated as cash flow hedge (notes 24)	(13)	(2)
Equity investment – share of other comprehensive income (loss)	(2)	3
Exchange differences on translation of foreign operations	857	(653)
Hedge of net investment (note 24)	(262)	243
Other comprehensive income (loss)	626	(416)
Comprehensive income	$ 2,083	$ 370

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, 2016				$ 17,627			$ 11	$ 7,296	$ 874	$ 0	$ 8,457			$ 969	$ 20
Net earnings	$ 786			786							786
Remeasurements of pension plans	(7)			(7)							(7)
Derivatives designated as cash flow hedges	(2)			(2)											(2)
Equity investment - share of other comprehensive income	3			3											3
Exchange differences on translation of foreign operations	(653)			(653)										(653)
Other comprehensive income, net of tax, gains (losses) on hedging instruments that hedge investments in equity instruments				243										243
Comprehensive income	370			370							779			(410)	1
Dividends declared on common and preferred shares (note 19)		$ 0	$ 34	(34)							(34)
Share cancellation		(3)		4				(3)		2	5
Equity, ending at Dec. 31, 2017	17,967			17,967			11	7,293	874	2	9,207			559	21
Net earnings	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)
Share additions (note 19)		$ 0
Non-controlling interests				1			1
Equity, ending at Dec. 31, 2018	$ 19,614			$ 19,614			$ 12	$ 7,293	$ 874	$ 2	$ 10,273			$ 1,154	$ 6

Consolidated Statements of Ch_2

Consolidated Statements of Changes in Shareholders Equity (Parenthetical) - CAD ($) $ in Millions	12 Months Ended
	Dec. 31, 2018	Dec. 31, 2017
Statement of changes in equity [abstract]
Remeasurement of pension plans	$ (17)	$ 4
Derivatives designated as cash flow hedges	5	0
Exchange differences on translation of foreign operations	(87)	82
Hedge of net investment	$ 41	$ (38)

Consolidated Statements of Cash

Consolidated Statements of Cash Flows - CAD ($) $ in Millions	12 Months Ended
	Dec. 31, 2018	Dec. 31, 2017
Operating activities
Net earnings	$ 1,457	$ 786
Accretion (notes 16, 21)	97	112
Depletion, depreciation, amortization and impairment (note 9)	2,591	2,882
Inventory write-down to net realizable value (note 6)	60	0
Exploration and evaluation expenses (note 8)	29	6
Deferred income taxes (note 18)	396	(359)
Foreign exchange	(6)	(4)
Stock-based compensation (notes 19, 20)	44	45
Gain on sale of assets (note 9)	(4)	(46)
Unrealized mark to market loss (gain) (note 24)	(150)	56
Share of equity investment gain (note 11)	(69)	(61)
Income from reimbursements under insurance policies	(253)	0
Other	21	16
Settlement of asset retirement obligations (note 16)	(181)	(136)
Deferred revenue (note 17)	(100)	(16)
Distribution from joint ventures (note 11)	72	25
Change in non-cash working capital (note 23)	130	398
Cash flow – operating activities	4,134	3,704
Financing activities
Long-term debt issuance (note 15)	0	750
Long-term debt repayment (note 15)	0	(365)
Debt issue costs (note 15)	0	(6)
Other	(8)	18
Change in non-cash working capital (note 23)	120	0
Cash flow – financing activities	(325)	363
Investing activities
Capital expenditures	(3,578)	(2,220)
Capitalized interest (note 21)	(108)	(68)
Corporate acquisition (note 9)	(15)	(670)
Proceeds from asset sales (note 9)	4	192
Contribution payable payment (note 11)	0	(142)
Contribution to joint ventures (note 11)	(40)	(81)
Other	(19)	(40)
Change in non-cash working capital (note 23)	235	240
Cash flow – investing activities	(3,521)	(2,789)
Increase in cash and cash equivalents	288	1,278
Effect of exchange rates on cash and cash equivalents	65	(84)
Cash and cash equivalents at beginning of year	2,513	1,319
Cash and cash equivalents at end of year	2,866	2,513
Net interest paid	(285)	(344)
Net Income taxes received (paid)	(37)	41
Ordinary shares [member]
Financing activities
Dividends paid, classified as financing activities	(402)	0
Preference shares [member]
Financing activities
Dividends paid, classified as financing activities	$ (35)	$ (34)

Description of Business and Seg

Description of Business and Segmented Disclosures	12 Months Ended
	Dec. 31, 2018
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, NGLs, sulphur and petroleum coke. Additionally, it includes 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 include upgrading of heavy crude oil feedstock into synthetic crude oil in Canada (“Upgrading” ), re fining crude oil in Canada, marketing of refined petroleum products including gasoline, diesel, ethanol blended fuels, asphalt and ancillary products, and production of ethanol (“Canadian Refined Products”). It also includes refining in the U.S. of primarily crude oil to produce and market asphalt, gasoline, jet fuel and diesel fuels that meet U.S. clean fuels standards ( “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 Year ended December 31, 2018 2017 2018 2017 2018 2017 Gross revenues 4,330 4,978 2,211 1,976 6,541 6,954 Royalties (335 ) (363 ) — — (335 ) (363 ) Marketing and other — — 668 (40 ) 668 (40 ) Revenues, net of royalties 3,995 4,615 2,879 1,936 6,874 6,551 Expenses Purchases of crude oil and products — — 2,087 1,855 2,087 1,855 Production, operating and transportation expenses 1,527 1,650 23 13 1,550 1,663 Selling, general and administrative expenses 296 265 5 4 301 269 Depletion, depreciation, amortization and impairment 1,811 2,237 — 2 1,811 2,239 Exploration and evaluation expenses 149 146 — — 149 146 Loss (gain) on sale of assets (2 ) (42 ) — 1 (2 ) (41 ) Other – net (120 ) 6 2 (8 ) (118 ) (2 ) 3,661 4,262 2,117 1,867 5,778 6,129 Earnings (loss) from operating activities 334 353 762 69 1,096 422 Share of equity investment gain 51 12 18 49 69 61 Financial items Net foreign exchange gain (loss) — — — — — — Finance income 12 5 — — 12 5 Finance expenses (109 ) (131 ) — — (109 ) (131 ) (97 ) (126 ) — — (97 ) (126 ) Earnings (loss) before income taxes 288 239 780 118 1,068 357 Provisions for (recovery of) income taxes Current (484 ) (34 ) 354 — (130 ) (34 ) Deferred 549 99 (141 ) 32 408 131 65 65 213 32 278 97 Net earnings (loss) 223 174 567 86 790 260 Intersegment revenues 1,155 1,250 — — 1,155 1,250 (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 $172 million of revenue (2017 - $280 million ) and $142 million of associated costs (2017 - $234 million ) for construction contracts, inclusive of $172 million of revenue (2017 - $259 million ) and $142 million of costs (2017 - $236 million ) for contracts in progress accounted for under the percentage of completion method. (3) Eliminations relate to sales and operating revenues between segments recorded at transfer prices based on current market prices. Segment results include transactions between business segments. Segmented Financial Information Con’t Downstream Corporate and Eliminations (3) Total Upgrading Canadian Refined Products U.S. Refining and Marketing Total 2018 2017 2018 2017 2018 2017 2018 2017 2018 2017 2018 2017 1,750 1,440 3,412 2,787 11,770 9,355 16,932 13,582 (1,554 ) (1,550 ) 21,919 18,986 — — — — — — — — — — (335 ) (363 ) — — — — — — — — — — 668 (40 ) 1,750 1,440 3,412 2,787 11,770 9,355 16,932 13,582 (1,554 ) (1,550 ) 22,252 18,583 928 983 2,760 2,219 10,334 8,059 14,022 11,261 (1,554 ) (1,550 ) 14,555 11,566 195 197 265 256 795 563 1,255 1,016 (2 ) — 2,803 2,679 7 9 47 53 22 15 76 77 277 304 654 650 123 99 115 111 450 354 688 564 92 79 2,591 2,882 — — — — — — — — — — 149 146 — — (2 ) (5 ) — — (2 ) (5 ) — — (4 ) (46 ) — — (1 ) (1 ) (464 ) (21 ) (465 ) (22 ) (8 ) 6 (591 ) (18 ) 1,253 1,288 3,184 2,633 11,137 8,970 15,574 12,891 (1,195 ) (1,161 ) 20,157 17,859 497 152 228 154 633 385 1,358 691 (359 ) (389 ) 2,095 724 — — — — — — — — — — 69 61 — — — — — — — — 14 (6 ) 14 (6 ) — — — — — — — — 52 32 64 37 (1 ) (1 ) (12 ) (12 ) (14 ) (14 ) (27 ) (27 ) (178 ) (234 ) (314 ) (392 ) (1 ) (1 ) (12 ) (12 ) (14 ) (14 ) (27 ) (27 ) (112 ) (208 ) (236 ) (361 ) 496 151 216 142 619 371 1,331 664 (471 ) (597 ) 1,928 424 168 63 100 45 9 2 277 110 (72 ) (79 ) 75 (3 ) (33 ) (22 ) (42 ) (7 ) 129 135 54 106 (66 ) (596 ) 396 (359 ) 135 41 58 38 138 137 331 216 (138 ) (675 ) 471 (362 ) 361 110 158 104 481 234 1,000 448 (333 ) 78 1,457 786 290 192 109 108 — — 399 300 — — 1,554 1,550 Segmented Financial Information Upstream ($ millions) Exploration and Production (1) Infrastructure and Marketing Total Year ended December 31, 2018 2017 2018 2017 2018 2017 Expenditures on exploration and evaluation assets (2) 242 148 — — 242 148 Expenditures on property, plant and equipment (2) 2,414 1,328 — — 2,414 1,328 As at December 31, Exploration and evaluation assets 997 838 — — 997 838 Developing and producing assets at cost 44,196 41,804 — — 44,196 41,804 Accumulated depletion, depreciation, amortization and impairment (27,379 ) (26,014 ) — — (27,379 ) (26,014 ) Other property, plant and equipment at cost — — 101 89 101 89 Accumulated depletion, depreciation and amortization — — (50 ) (50 ) (50 ) (50 ) Total exploration and evaluation assets and property, plant and equipment, net 17,814 16,628 51 39 17,865 16,667 Total assets 19,175 17,920 1,301 1,364 20,476 19,284 (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 Year ended December 31, 2018 2017 2018 2017 Gross revenues (1) 9,000 8,599 11,770 9,355 Royalties (269 ) (303 ) — — Marketing and other 668 (40 ) — — Revenue, net of royalties 9,399 8,256 11,770 9,355 As at December 31, Restricted cash – non-current — — — — Exploration and evaluation assets 935 831 — — Property, plant and equipment, net 16,433 15,478 6,336 5,595 Goodwill — — 690 633 Investment in joint ventures 669 685 — — Long-term income tax receivable 243 242 — — Other assets (2) 58 64 276 21 Total non-current assets 18,338 17,300 7,302 6,249 (1) Sales to external customers are based on the location of the seller. (2) Includes insurance proceeds of $253 million (2017 - nil), related to the Superior Refinery incident. Segmented Financial Information Con’t Downstream Corporate and Eliminations Total Upgrading Canadian Refined Products U.S. Refining and Marketing Total 2018 2017 2018 2017 2018 2017 2018 2017 2018 2017 2018 2017 — — — — — — — — — — 242 148 62 230 74 87 665 313 801 630 121 114 3,336 2,072 — — — — — — — — — — 997 838 — — — — — — — — — — 44,196 41,804 — — — — — — — — — — (27,379 ) (26,014 ) 2,659 2,600 2,789 2,704 9,746 8,300 15,194 13,604 1,251 1,124 16,546 14,817 (1,585 ) (1,463 ) (1,581 ) (1,466 ) (3,410 ) (2,705 ) (6,576 ) (5,634 ) (937 ) (845 ) (7,563 ) (6,529 ) 1,074 1,137 1,208 1,238 6,336 5,595 8,618 7,970 314 279 26,797 24,916 1,149 1,263 1,431 1,548 8,566 7,580 11,146 10,391 3,603 3,252 35,225 32,927 Geographical Financial Information Con’t China Other International Total 2018 2017 2018 2017 2018 2017 1,149 1,032 — — 21,919 18,986 (66 ) (60 ) — — (335 ) (363 ) — — — — 668 (40 ) 1,083 972 — — 22,252 18,583 128 97 — — 128 97 57 3 5 4 997 838 3,030 3,005 1 — 25,800 24,078 — — — — 690 633 — — 650 553 1,319 1,238 — — — — 243 242 — 78 26 22 360 185 3,215 3,183 682 579 29,537 27,311 Disaggregation of Revenue Upstream ($ millions) Exploration and Production (1) Infrastructure and Marketing Total Year ended December 31, 2018 2017 2018 2017 2018 2017 Primary Geographical Markets Canada 3,181 3,946 2,211 1,976 5,392 5,922 United States — — — — — — China 1,149 1,032 — — 1,149 1,032 Total revenue 4,330 4,978 2,211 1,976 6,541 6,954 Major Product Lines Light & medium crude oil 948 1,273 — — 948 1,273 Heavy crude oil 527 703 — — 527 703 Bitumen 1,367 1,662 — — 1,367 1,662 Total crude oil 2,842 3,638 — — 2,842 3,638 NGL 381 276 — — 381 276 Natural gas 1,107 1,064 — — 1,107 1,064 Total exploration and production 4,330 4,978 — — 4,330 4,978 Total infrastructure and marketing — — 2,211 1,976 2,211 1,976 Synthetic crude — — — — — — Gasoline — — — — — — Diesel & distillates — — — — — — Asphalt — — — — — — Other — — — — — — Total refined products — — — — — — Total revenue 4,330 4,978 2,211 1,976 6,541 6,954 Disaggregation of Revenue Con’t Downstream Corporate and Eliminations Total Upgrading Canadian Refined Products U.S. Refining and Marketing Total 2018 2017 2018 2017 2018 2017 2018 2017 2018 2017 2018 2017 1,750 1,440 3,412 2,787 — — 5,162 4,227 (1,554 ) (1,550 ) 9,000 8,599 — — — — 11,770 9,355 11,770 9,355 — — 11,770 9,355 — — — — — — — — — — 1,149 1,032 1,750 1,440 3,412 2,787 11,770 9,355 16,932 13,582 (1,554 ) (1,550 ) 21,919 18,986 — — — — — — — — — — 948 1,273 — — — — — — — — — — 527 703 — — — — — — — — — — 1,367 1,662 — — — — — — — — — — 2,842 3,638 — — — — — — — — — — 381 276 — — — — — — — — — — 1,107 1,064 — — — — — — — — — — 4,330 4,978 — — — — — — — — — — 2,211 1,976 1,445 1,235 — — — — 1,445 1,235 — — 1,445 1,235 — — 1,070 925 6,157 5,198 7,227 6,123 — — 7,227 6,123 278 196 1,303 917 4,297 3,435 5,878 4,548 — — 5,878 4,548 — — 454 362 165 31 619 393 — — 619 393 27 9 585 583 1,151 691 1,763 1,283 — — 1,763 1,283 1,750 1,440 3,412 2,787 11,770 9,355 16,932 13,582 — — 16,932 13,582 1,750 1,440 3,412 2,787 11,770 9,355 16,932 13,582 (1,554 ) (1,550 ) 21,919 18,986

Basis of Presentation

Basis of Presentation	12 Months Ended
	Dec. 31, 2018
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 and signed by the Chair of the Audit Committee and the Chief Executive Officer on February 25, 2019 having been duly authorized to do so by the Board of Directors. 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 11), 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, 2018
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, 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. 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 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, less any estimated residual value. The useful lives of assets are estimated based upon the period the asset is expected to be available for use by the Company. Residual values are based upon the estimated amount that would be obtained on disposal, net of any costs associated with the disposal. Other property, plant and equipment held under finance leases are depreciated over the shorter of the lease term and the estimated useful life of the asset. 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. vi) Finance Leases Finance leases, which transfer substantially all of the risks and rewards incidental to ownership of the leased item to the Company, are capitalized at the commencement of the lease term at the fair value of the lease property or, if lower, at the present value of the minimum lease payments. Capitalized leased assets are depreciated over the shorter of the estimated useful life of the asset or the lease term. All other leases are accounted for as operating leases and the lease costs are expensed as incurred. 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. Acquisition costs incurred are expensed and included in selling, general and administrative expenses in the consolidated statements of income. 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 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, 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, 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. 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. 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. 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, 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 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. 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 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 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. 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 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 Comprehensive income consists of net earnings 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

Cash and Cash Equivalents

Cash and Cash Equivalents	12 Months Ended
	Dec. 31, 2018
Subclassifications of assets, liabilities and equities [abstract]
Cash and Cash Equivalents	Cash and Cash Equivalents Cash and cash equivalents at December 31, 2018 included $187 million of cash ( December 31, 2017 – $ 280 million ) and $2,679 million of short-term investments with original maturities less than three months at the time of purchase ( December 31, 2017 – $ 2,233 million ).

Accounts Receivable

Accounts Receivable	12 Months Ended
	Dec. 31, 2018
Subclassifications of assets, liabilities and equities [abstract]
Accounts Receivable	Accounts Receivable Accounts Receivable ($ millions) December 31, 2018 December 31, 2017 Trade receivables 1,146 1,170 Provision for expected credit losses (39 ) (34 ) Derivatives due within one year 43 17 Other (1) 205 33 End of year 1,355 1,186 (1) Includes insurance proceeds of $143 million (2017 - nil ), related to the Superior Refinery incident.

Inventories

Inventories	12 Months Ended
	Dec. 31, 2018
Subclassifications of assets, liabilities and equities [abstract]
Inventories	Inventories Inventories ($ millions) December 31, 2018 December 31, 2017 Crude oil, natural gas and NGL 445 539 Refined petroleum products 435 548 Trading inventories measured at fair value less costs to sell 200 237 Materials, supplies and other 152 189 End of year 1,232 1,513 Impairment of inventory to net realizable value for the year ended December 31, 2018 was $60 million ( December 31, 2017 – nil ), 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. Refer to Note 24 .

Restricted Cash

Restricted Cash	12 Months Ended
	Dec. 31, 2018
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, 2018 , the Company had deposited funds of $128 million which have been classified as non-current ( 2017 – $97 million). As at December 31, 2017, the Company deposited funds of $192 million , of which $95 million related to the Wenchang field and was classified as current. The Company’s participation in the Wenchang field expired in November 2017, and the amount of the decommissioning and disposal expenses was finalized in January 2018.

Exploration and Evaluation Cost

Exploration and Evaluation Costs	12 Months Ended
	Dec. 31, 2018
Subclassifications of assets, liabilities and equities [abstract]
Exploration and Evaluation Costs	Exploration and Evaluation Costs Exploration and Evaluation Assets ($ millions) 2018 2017 Beginning of year 838 1,066 Additions 287 224 Disposals (23 ) — Transfers to oil and gas properties (note 9) (79 ) (377 ) Expensed exploration expenditures previously capitalized (29 ) (6 ) Exchange adjustments 3 (69 ) End of year 997 838 The following exploration and evaluation expenses for the years ended December 31, 2018 and 2017 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) 2018 2017 Seismic, geological and geophysical 102 113 Expensed drilling 41 22 Expensed land 6 11 149 146

Property, Plant and Equipment

Property, Plant and Equipment	12 Months Ended
	Dec. 31, 2018
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, 2016 44,801 137 2,367 8,645 2,755 58,705 Additions (1) 1,371 11 230 561 140 2,313 Acquisitions 29 — — 577 — 606 Transfers from exploration and evaluation (note 8) 377 — — — — 377 Intersegment transfers 48 (61 ) — — 13 — Changes in asset retirement obligations (note 16) 150 — 2 13 23 188 Disposals and derecognition (4,702 ) — — (39 ) — (4,741 ) Exchange adjustments (259 ) (1 ) — (566 ) (1 ) (827 ) 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 16) 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 Accumulated depletion, depreciation, amortization and impairment December 31, 2016 (27,986 ) (96 ) (1,363 ) (2,975 ) (1,692 ) (34,112 ) Depletion, depreciation, amortization and impairment (2,238 ) (2 ) (99 ) (406 ) (137 ) (2,882 ) Intersegment transfers (37 ) 50 — — (13 ) — Disposals and derecognition 4,124 — — 16 — 4,140 Exchange adjustments 121 1 — 189 — 311 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 ) Net book value December 31, 2017 15,799 39 1,137 6,015 1,088 24,078 December 31, 2018 16,817 51 1,074 6,758 1,100 25,800 (1) Additions include assets under finance lease. Depletion, depreciation, amortization and impairment for the year ended December 31, 2018 included a $56 million derecognition of the carrying value reflected in the second and third quarter of 2018 for damage caused by an incident at the Superior Refinery in the Company’s U.S Refining and Marketing segment (December 31, 2017 – a pre-tax impairment expense of $173 million in the Upstream Exploration and Production segment). In addition, the Company accrued pre-tax recoveries for property damage, rebuild costs, business interruption and clean-up costs associated with the Superior Refinery incident of $468 million for the year ended December 31, 2018 , which is included in other-net in the consolidated statements of income. The provisions for derecognition and insurance recoveries are based on management’s best estimates as at December 31, 2018, with measurement uncertainty around the provision for property damage, and business interruption insurance recoveries. As the assessment of damage is ongoing, the provisions may be subject to changes. Costs of property, plant and equipment, including major development projects, not subject to depletion, depreciation and amortization as at December 31, 2018 were $5.2 billion ( December 31, 2017 – $ 2.8 billion ) including undeveloped land assets of $117 million as at December 31, 2018 ( December 31, 2017 – $57 million ). The net book values of assets held under finance lease within property, plant and equipment are as follows: Assets Under Finance Lease Oil and Gas Properties ($ millions) Refining Total December 31, 2017 152 335 487 December 31, 2018 141 323 464 Assets Dispositions During 2017, the Company completed the sale of select assets in Western Canada to third parties for gross proceeds of approximately $185 million , resulting in a pre-tax gain of $46 million and an after-tax gain of $36 million . The assets and related liabilities were recorded in the Upstream Exploration and Production segment. Assets Acquisitions On November 8, 2017, the Company completed the purchase of the Superior Refinery, a 50,000 bbls/day permitted capacity facility located in Superior, Wisconsin, U.S., from Calumet Specialty Products Partners, L.P. (“Calumet”) for $670 million (US$527 million). The acquisition has been accounted for as a business combination using the acquisition method. Purchase Price Allocation ($ millions) USD CAD Working capital 85 108 Property, plant and equipment 454 577 Asset retirement obligation (7 ) (9 ) Other long-term liabilities (5 ) (6 ) Net assets acquired 527 670 The fair values of accounts receivable and accounts payable approximate their carrying values due to their short-term nature. The fair value of inventory was determined using quoted prices. The fair values of property, plant and equipment were determined based on a cost and future cash flow approach. For the cost approach, key assumptions included the cost to construct the assets and the remaining useful life. For the cash flow approach, key assumptions were the discount rate and future commodity prices. The decommissioning provision was based on the fair value of estimated future reclamation costs. Key assumptions included discount rates, cost estimates and timeline to abandon and reclaim the refinery. The acquisition of Superior Refinery contributed $163 million to gross revenues and a loss of $13 million to consolidated net earnings from the acquisition date to December 31, 2017. Had the acquisition occurred on January 1, 2017, the Superior Refinery would have contributed $1.1 billion to gross revenues and $93 million to consolidated net earnings, which would have resulted in gross revenues of $19.9 billion and consolidated net earnings of $892 million for the year ended December 31, 2017.

Goodwill

Goodwill	12 Months Ended
	Dec. 31, 2018
Subclassifications of assets, liabilities and equities [abstract]
Goodwill	Goodwill Goodwill ($ millions) December 31, 2018 December 31, 2017 Beginning of year 633 679 Exchange adjustments 57 (46 ) End of year 690 633 As at December 31, 2018, 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 higher of FVLCS and VIU methodology based on cash flows expected over a 50 -year period and discounted using an after-tax discount rate of 8 percent . Management used the higher of FVLCS and VIU calculations for the Lima Refinery CGU, which are sensitive to changes in discount rate, forecasted crack spreads and growth rate. 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. 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 percent and 2 percent , 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 percent and adjusted for throughput capacity constraints (2017 – 2 percent ). As at December 31, 2018, 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, 2018
Subclassifications of assets, liabilities and equities [abstract]
Joint Arrangements	Joint Arrangements Joint Operations BP-Husky Refining LLC The Company holds a 50 percent ownership interest in BP-Husky Refining LLC, which owns and operates the BP-Husky Toledo Refinery in Ohio. On March 31, 2008, the Company completed a transaction with BP whereby BP contributed the BP-Husky Toledo Refinery plus inventories and other related net assets and the Company contributed US $250 million in cash and a contribution payable of US $2.6 billion . The Company amended the terms of payment of the Company’s contribution payable with BP-Husky Refining LLC in the first quarter of 2015. In accordance with the amendment, US $1 billion of the net contribution payable was paid on February 2, 2015. Subsequent to the payment, BP-Husky Refining LLC distributed US $1 billion to each of the joint arrangement partners, which resulted in the creation of a deferred tax asset and deferred tax recovery of $203 million . As a result of the prepayment, the accretion rate was reduced from 6 percent to 2.5 percent for the future term of the agreement and the remaining maturity date was extended to December 31, 2017. The remaining net contribution payable amount of approximately US $110 million (CDN $142 million ) was repaid in 2017. Sunrise Oil Sands Partnership The Company holds a 50 percent interest in the Sunrise Oil Sands Partnership, which is engaged in operating an oil sands project in Northern Alberta. Joint Venture Husky-CNOOC Madura Ltd. The Company currently holds 40 percent joint control in Husky-CNOOC Madura Ltd., which is engaged in the exploration for and production of oil and gas resources in Indonesia. Results of the joint venture are included in the consolidated statements of income in Exploration and Production in the Upstream segment. Summarized below is the financial information for Husky-CNOOC Madura Ltd. accounted for using the equity method: Results of Operations ($ millions, except share of equity investment) 2018 2017 Revenues 441 97 Expenses (273 ) (80 ) Net earnings 168 17 Share of equity investment (percent) 40 % 40 % Proportionate share of equity investment 51 12 Balance Sheets ($ millions, except share of equity investment) December 31, 2018 December 31, 2017 Current assets (1) 373 152 Non-current assets 2,072 1,993 Current liabilities (123 ) (106 ) Non-current liabilities (2) (1,917 ) (1,813 ) Net assets 405 226 Share of net assets (percent) 40 % 40 % Carrying amount in balance sheet 650 553 (1) Includes cash and cash equivalents of $ 203 million ( 2017 – $ 26 million ). (2) Includes deferred revenue of $ 2 million (2017 - nil ) 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 percent 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 On July 15, 2016, the Company completed the sale of its ownership interest in select midstream assets in the Lloydminster region of Alberta and Saskatchewan. The assets are held by a newly-formed limited partnership, HMLP, of which Husky owns 35 percent , Power Assets Holdings Ltd. (“PAH”) owns 48.75 percent and CK Infrastructure Holdings Ltd. (“CKI”) owns 16.25 percent . Results of the joint venture are included in the consolidated statements of income 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) 2018 2017 Revenues 296 294 Expenses (177 ) (107 ) Net earnings 119 187 Share of equity investment (percent) 35 % 35 % Proportionate share of equity investment 18 49 Balance Sheet ($ millions, except share of net assets) December 31, 2018 December 31, 2017 Current assets (1) 115 152 Non-current assets 2,849 2,617 Current liabilities (153 ) (75 ) Non-current liabilities (825 ) (690 ) Net assets 1,986 2,004 Share of net assets (percent) 35 % 35 % Carrying amount in balance sheet 669 685 (1) Current assets include cash and cash equivalents of $ 16 million ( 2017 – $28 million ). The Company’s share of equity investment and carrying amount of share of net assets does not equal the 35 percent 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, 2018
Miscellaneous non-current assets [abstract]
Other Assets	Other Assets Other Assets ($ millions) December 31, 2018 December 31, 2017 Long-term receivables (1) 319 144 Leasehold incentives — 2 Precious metals 23 21 Other 18 18 End of year 360 185 (1) Includes insurance proceeds of $253 million (2017 – nil ), related to the Superior Refinery incident.

Bank Operating Loans

Bank Operating Loans	12 Months Ended
	Dec. 31, 2018
Subclassifications of assets, liabilities and equities [abstract]
Bank Operating Loans	Bank Operating Loans At December 31, 2018 , the Company had unsecured short-term borrowing lines of credit with banks totalling $900 million (1) ( December 31, 2017 – $850 million ) and letters of credit under these lines of credit totalling $439 million ( December 31, 2017 – $422 million ). As at December 31, 2018 , bank operating loans were nil ( December 31, 2017 – 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, 2017 – $10 million ) available for general purposes. The Company’s proportionate share of the liability for any drawings under this credit facility is $5 million ( December 31, 2017 – $5 million ). As at December 31, 2018 , there was no balance outstanding under this credit facility ( December 31, 2017 – no balance). (1) Includes $125 million demand facilities available specifically for letters of credit only. The Company had the following available credit facilities as at December 31, 2018 : Credit Facilities ($ millions) Available Unused Operating facilities (1) (note 13) 900 461 Syndicated bank facilities (2) (note 15) 4,000 3,800 End of year 4,900 4,261 (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, 2018
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, 2018 December 31, 2017 Trade payables 1,121 950 Accrued liabilities 1,712 1,791 Dividend payable (note 19) 126 9 Stock-based compensation 32 30 Derivatives due within one year 39 115 Other 129 138 End of year 3,159 3,033

Debt and Credit Facilities

Debt and Credit Facilities	12 Months Ended
	Dec. 31, 2018
Disclosure of borrowing costs [Abstract]
Debt and Credit Facilities	Debt and Credit Facilities Short-term Debt December 31, 2018 December 31, 2017 ($ millions) Commercial paper (1) 200 200 (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, 2018 was 2.20 percent per annum ( December 31, 2017 – 1.40 percent ). Canadian $ Amount U.S. $ Denominated Long-term Debt Maturity December 31, 2018 December 31, 2017 December 31, 2018 December 31, 2017 ($ millions) Long-term debt 6.15% notes (1)(3) 2019 — 376 — 300 7.25% notes (1)(4) 2019 — 939 — 750 5.00% notes (5) 2020 400 400 — — 3.95% notes (1)(4) 2022 682 626 500 500 4.00% notes (1)(4) 2024 1,023 939 750 750 3.55% notes (5) 2025 750 750 — — 3.60% notes (5) 2027 750 750 — — 6.80% notes (1)(4) 2037 528 484 387 387 Debt issue costs (2) (19 ) (24 ) — — Long-term debt 4,114 5,240 1,637 2,687 Long-term debt due within one year 6.15% notes (1)(3) 2019 410 — 300 — 7.25% notes (1)(4) 2019 1,023 — 750 — Long-term debt due within one year 1,433 — 1,050 — (1) All of the Company’s 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 24 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% 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 On November 30, 2017, the maturity date for one of the Company’s $2.0 billion revolving syndicated credit facilities, previously set to expire on June 19, 2018, was extended to June 19, 2022. As at December 31, 2018 the covenant under the Company’s syndicated credit facilities was a debt to capital covenant, 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. This covenant is used to assess the Company’s financial strength. If the Company does not comply with the covenants under the syndicated credit facilities, there is the risk that repayment could be accelerated. The Company was in compliance with the syndicated credit facility covenants at December 31, 2018, and assessed the risk of non-compliance to be low. As at December 31, 2018 , the Company had no borrowings under its $2.0 billion facility expiring March 9, 2020 ( December 31, 2017 – no borrowings ) and no borrowings under its $2.0 billion facility expiring June 19, 2022 ( December 31, 2017 – no borrowings ). There continues to be no difference between the terms of these facilities, other than their maturity dates. 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’s rated senior unsecured debt. Notes On March 10, 2017, the Company issued $750 million of 3.60 percent notes due March 10, 2027. This was completed by way of a prospectus supplement dated March 7, 2017 , to the Company’s universal short form base shelf prospectus dated February 23, 2015. The notes are redeemable at the option of the Company at any time, subject to a make-whole premium unless the notes are redeemed in the three month period prior to maturity. Interest is payable semi-annually on March 10 and September 10 of each year, beginning September 10, 2017. The notes are unsecured and unsubordinated and rank equally with all of the Company’s other unsecured and unsubordinated indebtedness. On March 30, 2017, the Company filed a universal short form base shelf prospectus (the “2017 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 April 30, 2019. On September 15, 2017, the Company repaid the maturing 6.20 percent notes issued under a trust indenture dated September 11, 2007. The amount paid to note holders was $365 million, including $11 million of interest. 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. Refer to Note 24. At December 31, 2018 , the Company had unused capacity of $3.0 billion under its 2017 Canadian Shelf Prospectus and US $3.0 billion under its 2018 U.S. Shelf Prospectus and related U.S. registration statement. The Company’s notes, credit facilities and short-term lines of credit rank equally in right of payment. Reconciliation of Changes of Liabilities to Cash Flows from Financing Activities Liabilities ($ millions) Short-term debt Long-term debt due within one year Long-term debt Other long-term liabilities December 31, 2017 200 — 5,240 1,237 Changes from financing cash flows Long-term debt issuance — — — — Long-term debt repayment — — — — Short-term debt issuance — — — — Short-term debt repayment — — — — Debt issue costs — — — — Total change from financing cash flows — — — — Other changes – liability-related Reclassification to short-term — 1,399 (1,399 ) — Foreign exchange — — — 32 Fair value changes — — — (67 ) Addition of finance lease obligations — — — — Payment of finance lease obligations — — — (15 ) Deferred revenue — — — (100 ) Amortization of debt issuance costs — — 4 — Foreign exchange recognized in OCI — 34 269 — Other — — — 20 Total other changes – liability related — 1,433 (1,126 ) (130 ) December 31, 2018 200 1,433 4,114 1,107

Asset Retirement Obligations

Asset Retirement Obligations	12 Months Ended
	Dec. 31, 2018
Subclassifications of assets, liabilities and equities [abstract]
Asset Retirement Obligations	Asset Retirement Obligations At December 31, 2018 , the estimated total undiscounted inflation-adjusted amount required to settle the Company’s ARO was $9.2 billion ( December 31, 2017 – $9.7 billion ). These obligations will be settled based on the useful lives of the underlying assets, which currently extend an average of 45 years ( December 31, 2017 – 42 years) into the future. This amount has been discounted using credit-adjusted risk-free rates of 3.8 percent to 5.0 percent ( December 31, 2017 – 2.9 percent to 4.8 percent ) and an inflation rate of 2 percent ( December 31, 2017 – 2 percent ). Obligations related to future environmental remediation and cleanup of oil and gas assets are included in the estimated ARO. The change in the provision in 2018 is primarily related to increased decommissioning and restoration activities and increase in the average discount rate, partially offset by an increase in the estimated cost of decommissioning activities. While the provision is based on management’s best estimates of future costs, discount rates and the economic lives of the assets, there is uncertainty regarding the amount and timing of incurring these costs. A reconciliation of the carrying amount of asset retirement obligations at December 31, 2018 and 2017 is set out below: Asset Retirement Obligations ($ millions) 2018 2017 Beginning of year 2,526 2,791 Additions 40 47 Liabilities settled (270 ) (136 ) Liabilities disposed (11 ) (420 ) Change in discount rate (68 ) 143 Change in estimates 93 (2 ) Exchange adjustment 17 (9 ) Accretion (note 21) 97 112 End of year 2,424 2,526 Expected to be incurred within 1 year 202 274 Expected to be incurred beyond 1 year 2,222 2,252 At December 31, 2018, the Company had deposited funds of $128 million into the restricted accounts for funding of future asset retirement obligations in offshore China. These amounts have been classified as non-current and included in restricted cash. At December 31, 2017, the Company had deposited funds of $192 million , of which $95 million related to the Wenchang field and was classified as current, the remaining balance of $97 million was classified as non-current. The Company’s participation in the Wenchang field expired in November 2017, and the amount of the decommissioning and disposal expenses was finalized in January 2018.

Other Long-term Liabilities

Other Long-term Liabilities	12 Months Ended
	Dec. 31, 2018
Subclassifications of assets, liabilities and equities [abstract]
Other Long-term Liabilities	Other Long-term Liabilities Other Long-term Liabilities ($ millions) December 31, 2018 December 31, 2017 Employee future benefits (note 22) 205 248 Finance lease obligations 467 498 Stock-based compensation 42 32 Deferred revenue 205 284 Leasehold incentives 96 101 Other 92 74 End of year 1,107 1,237 Finance lease obligations The future minimum lease payments under existing finance leases are payable as follows: Within 1 year After 1 year but no more than 5 years More than 5 years Total ($ millions) 2018 2017 2018 2017 2018 2017 2018 2017 Future minimum lease payments 69 69 242 258 1,014 993 1,325 1,320 Interest 48 48 175 174 613 594 836 816 Present value of minimum lease payments 66 66 180 194 243 244 489 504 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, 2018 December 31, 2017 Beginning of year 284 321 Take-or-pay payments received — 12 Revenue recognized (100 ) (28 ) Exchange adjustment 21 (21 ) End of year 205 284

Income Taxes

Income Taxes	12 Months Ended
	Dec. 31, 2018
Disclosure of income tax [Abstract]
Income Taxes	Income Taxes The major components of income tax expense for the years ended December 31, 2018 and 2017 were as follows: Income Tax Expense (Recovery) ($ millions) 2018 2017 Current income tax Current income tax charge 86 28 Adjustments to current income tax estimates (11 ) (31 ) 75 (3 ) Deferred income tax Relating to origination and reversal of temporary differences 378 83 Adjustments to deferred income tax estimates 18 (442 ) 396 (359 ) Deferred Tax Items in OCI ($ millions) 2018 2017 Deferred tax items expensed (recovered) directly in OCI Derivatives designated as cash flow hedges (5 ) — Remeasurement of pension plans 17 (4 ) Exchange differences on translation of foreign operations 87 (82 ) Hedge of net investment (41 ) 38 58 (48 ) The provision for income taxes in the consolidated statements of income reflects an effective tax rate which differs from the expected statutory tax rate. Differences for the years ended December 31, 2018 and 2017 were accounted for as follows: Reconciliation of Effective Tax Rate ($ millions, except tax rate) 2018 2017 Earnings before income taxes Canada 734 (440 ) United States 493 301 Other foreign jurisdictions 701 563 1,928 424 Statutory Canadian income tax rate (percent) 27.2 % 27.1 % Expected income tax 525 115 Effect on income tax resulting from: Foreign jurisdictions (36 ) 20 Non-taxable items (13 ) (1 ) Adjustments with respect to previous year 7 (473 ) Revaluation of foreign tax pools (4 ) (8 ) Other – net (8 ) (15 ) Income tax expense (recovery) 471 (362 ) The statutory tax rate is 27.2 percent in 2018 ( 2017 – 27.1 percent ). The 2018 and 2017 tax rates were similar due to no significant changes to tax rates. Effective January 1, 2018, the U.S. Federal corporate tax rate was reduced from 35 percent to 21 percent . Included in income tax expense for the year ended December 31, 2017 was a $436 million deferred income tax recovery related to the revaluation of the U.S. deferred tax liabilities. The following reconciles the movements in the deferred income tax liabilities and assets: Deferred Tax Liabilities and Assets ($ 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 ) Deferred Tax Liabilities and Assets ($ millions) January 1, 2017 Recognized in Earnings Recognized in OCI Other December 31, 2017 Deferred tax liabilities Exploration and evaluation assets and property, plant and equipment (3,998 ) 187 104 (20 ) (3,727 ) Foreign exchange gains taxable on realization (224 ) 85 (38 ) — (177 ) Debt issue costs (2 ) (1 ) — — (3 ) Other temporary differences (21 ) (69 ) — — (90 ) Deferred tax assets Pension plans 32 4 4 — 40 Asset retirement obligations 693 (8 ) (6 ) — 679 Loss carry-forwards 389 150 (16 ) — 523 Financial assets at fair value 20 11 — — 31 (3,111 ) 359 48 (20 ) (2,724 ) The Company has temporary differences associated with its investments in its foreign subsidiaries, branches, and interests in joint ventures. At December 31, 2018 , the Company had nil deferred tax liabilities in respect to these investments ( December 31, 2017 – nil ). At December 31, 2018 , the Company had $1,806 million ( December 31, 2017 – $2,031 million ) of tax losses that will expire between 2030 and 2037. 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, 2018
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, 2016 1,005,451,854 7,296 Share cancellation (331,842 ) (3 ) December 31, 2017 1,005,120,012 7,293 Options exercised (1) 1,726 — December 31, 2018 1,005,121,738 7,293 (1) Stock options exercised was less than $1 million. Quarterly dividends may be declared in an amount expressed in dollars per common share or could be paid by way of issuance of a fraction of a common share per outstanding common share determined by dividing the dollar amount of the dividend by the volume-weighted average trading price of the Common Shares on the principal stock exchange on which the common shares are traded. The volume-weighted average trading price of the common shares is calculated by dividing the total value by the total volume of common shares traded over the five trading day period immediately prior to the payment date of the dividend on the common shares. On February 28, 2018, the Board of Directors reinstated the quarterly common share dividends. Common Share Dividends ($ millions) 2018 2017 Declared Paid Declared Paid 402 276 — — At December 31, 2018 , Common Share dividends payable were $126 million (December 31, 2017 – nil ). Preferred Shares The Company is authorized to issue an unlimited number of no par value preferred shares. Cumulative Redeemable Preferred Shares Number of Shares Amount ($ millions) December 31, 2016 36,000,000 874 December 31, 2017 36,000,000 874 December 31, 2018 36,000,000 874 Cumulative Redeemable Preferred Shares Dividends ($ millions) 2018 2017 Declared Paid Declared Paid Series 1 Preferred Shares 6 8 6 6 Series 2 Preferred Shares 1 1 1 1 Series 3 Preferred Shares 12 14 11 11 Series 5 Preferred Shares 9 11 9 9 Series 7 Preferred Shares 7 9 7 7 35 43 34 34 At December 31, 2018 , Preferred Share dividends payable were nil (December 31, 2017 - $9 million ). 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 percent 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 percent . 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, 2018 but excluding December 31, 2018 , was 3.239 percent based on the sum of the Government of Canada 90 day Treasury bill rate on August 21, 2018 plus 1.73 percent . 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 4.50 percent annually for the initial period ending December 31, 2019 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 percent . 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, 2019 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 percent . 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 percent 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 percent . 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 percent . 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 percent 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 percent . 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 percent . 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 he or she wishes to surrender his or her 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, 2018 was $11 million ( December 31, 2017 – $21 million ) representing the estimated fair value of options outstanding. The total expense recovery recognized in selling, general and administrative expenses in the consolidated statements of income for the Option Plan for the year ended December 31, 2018 was $3 million (December 31, 2017 – expense of $13 million ). At December 31, 2018 , the intrinsic value of stock options exercisable for cash was nil ( December 31, 2017 – $12 million ). The following options to purchase common shares have been awarded to officers and certain other employees: Outstanding and Exercisable Options 2018 2017 Number of Options (thousands) Weighted Average ($) Number of Options (thousands) Weighted Average ($) Outstanding, beginning of year 22,645 23.96 25,459 26.26 Granted (1) 5,610 17.21 5,544 16.13 Exercised for common shares (2 ) 15.67 — — Surrendered for cash (1,772 ) 15.82 — — Expired or forfeited (6,514 ) 27.69 (8,358 ) 25.62 Outstanding, end of year 19,967 21.48 22,645 23.96 Exercisable, end of year 10,461 25.87 12,946 28.91 (1) Options granted during the year ended December 31, 2018 were attributed a fair value of $2.90 per option ( 2017 – $2.01 ) at grant date. Outstanding and Exercisable Options Outstanding Options Exercisable Options Range of Exercise Price Number of Options (thousands) Weighted Average Exercise Prices ($) Weighted Average (years) Number of Options (thousands) Weighted Average Exercise Prices ($) $14.20 - $29.99 16,061 18.55 2.90 6,555 21.30 $30.00 - $36.20 3,906 33.52 0.17 3,906 33.51 December 31, 2018 19,967 21.48 2.37 10,461 25.87 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, 2018 December 31, 2017 Tandem Options Tandem Options Dividend per option 0.56 0.72 Range of expected volatilities used (percent) 16.8 - 44.4 16.7 - 32.9 Range of risk-free interest rates used (percent) 1.6 - 1.9 0.9 - 1.9 Expected life of share options from vesting date (years) 1.95 1.95 Expected forfeiture rate (percent) 8.9 9.0 Weighted average exercise price 22.46 25.46 Weighted average fair value 0.65 1.15 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 In February 2010, the Compensation Committee of the Board of Directors of the Company established the 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 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 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, 2018 , the carrying amount of the liability relating to PSUs was $63 million ( December 31, 2017 – $41 million ). The total expense recognized in selling, general and administrative expenses in the consolidated statements of income for the PSUs for the year ended December 31, 2018 was $47 million ( 2017 – $32 million ). The Company paid out $24 million ( 2017 – $15 million ) for performance share units which vested in the year. The weighted average contractual life of the PSUs at December 31, 2018 was two years ( December 31, 2017 – two years). The number of PSUs outstanding was as follows: Performance Share Units 2018 2017 Beginning of year 8,361,918 4,863,690 Granted 6,108,430 5,667,970 Exercised (1,354,316 ) (966,932 ) Forfeited (1,509,388 ) (1,202,810 ) Outstanding, end of year 11,606,644 8,361,918 Vested, end of year 4,487,585 2,262,954 Earnings per Share Earnings per Share ($ millions) 2018 2017 Net earnings 1,457 786 Effect of dividends declared on preferred shares in the year (35 ) (34 ) Net earnings – basic 1,422 752 Dilutive effect of accounting for stock options (1) (13 ) 4 Net earnings – diluted 1,409 756 (millions) Weighted average common shares outstanding – basic 1,005.1 1,005.3 Effect of stock dividends declared in the year 1.0 — Weighted average common shares outstanding – diluted 1,006.1 1,005.3 Earnings per share – basic ($/share) 1.41 0.75 Earnings per share – diluted ($/share) 1.40 0.75 (1) For the year ended December 31, 2018 , equity-settlement of stock options was used to calculate diluted earnings per share as it was considered more dilutive than cash-settlement (December 31, 2017 - cash settlement method was used). Stock-based compensation recovery was $3 million based on equity-settlement for the year ended December 31, 2018 ( 2017 – expense of $9 million ). Stock-based compensation expense would have been $10 million based on cash-settlement for the year ended December 31, 2018 ( 2017 – $13 million ). For the year ended December 31, 2018 , 13 million tandem options ( 2017 – 23 million ) were excluded from the calculation of diluted earnings 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, 2018
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 for the years ended December 31, 2018 and 2017 : Production, Operating and Transportation Expenses ($ millions) 2018 2017 Services and support costs 1,039 930 Salaries and benefits 762 664 Materials, equipment rentals and leases 243 248 Energy and utility 405 453 Licensing fees 191 200 Transportation 24 26 Other 139 158 Total production, operating and transportation expenses 2,803 2,679 The following table summarizes selling, general and administrative expenses in the consolidated statements of income for the years ended December 31, 2018 and 2017 : Selling, General and Administrative Expenses ($ millions) 2018 2017 Employee costs (1) 332 395 Stock-based compensation expense (2) 44 45 Contract services 104 100 Equipment rentals and leases 39 37 Maintenance and other 135 73 Total selling, general and administrative expenses 654 650 (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, 2018
Disclosure of additional information [Abstract]
Financial Items	Financial Items Financial Items ($ millions) 2018 2017 Foreign exchange Non-cash working capital gains (3 ) (3 ) Other foreign exchange gains (losses) 17 (3 ) Net foreign exchange gains (losses) 14 (6 ) Finance income 64 37 Finance expenses Long-term debt (320 ) (342 ) Contribution payable (note 11) — (2 ) Other (5 ) (4 ) (325 ) (348 ) Interest capitalized (1) 108 68 (217 ) (280 ) Accretion of asset retirement obligations (note 16) (97 ) (112 ) Finance expenses (314 ) (392 ) Total Financial Items (236 ) (361 ) (1) Interest capitalized on project costs is calculated using the Company’s annualized effective interest rate of 5 percent ( 2017 – 5 percent).

Pensions and Other Post-employm

Pensions and Other Post-employment Benefits	12 Months Ended
	Dec. 31, 2018
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 two 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 two defined benefit pension plans, which are closed to new entrants. The defined benefit pension plans provide pension benefits to certain employees based on years of service and final average earnings. The amount and timing of funding of these plans 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, 2018 . 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, 2016 for the Canadian defined benefit plan and 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, 2018 , the Company recognized a $54 million expense ( 2017 – $46 million ) for the defined contribution plan and the two U.S. 401(k) plans in net earnings. Defined Benefit Pension Plans (“DB Pension Plan”) and Other Post-employment Benefit Plans (“OPEB Plans”) Defined Benefit Obligations DB Pension Plans OPEB Plans ($ millions) 2018 2017 2018 2017 Beginning of year 76 178 244 213 Current service cost 1 1 11 15 Interest cost 3 4 8 8 Benefits paid (2 ) (9 ) (4 ) (4 ) Settlements — (140 ) — — Increase due to business combinations (1) — 34 — — Remeasurements Actuarial (gain) loss – experience 2 3 (13 ) — Actuarial loss – financial assumptions (4 ) 5 (45 ) 12 Effect of changes in foreign exchange rates 3 — (2 ) — End of year 79 76 199 244 (1) The Superior Refinery DB pension plan was transferred from Calumet GP. LLC to Husky Energy Inc. effective November 2017. Fair Value of Plan Assets DB Pension Plans OPEB Plans ($ millions) 2018 2017 2018 2017 Beginning of year 67 183 — — Contributions by employer 1 6 2 — Benefits paid (2 ) (9 ) (2 ) — Interest income 2 4 — — Return on plan assets greater than discount rate — 4 — — Settlements — (148 ) — — Increase due to business combinations (1) — 27 — — Effect of changes in foreign exchange rates 3 — — — End of year 71 67 — — (1) The Superior Refinery DB pension plan was transferred from Calumet GP. LLC to Husky Energy Inc. effective November 2017. Please refer to Note 9 for business combination. Funded status DB Pension Plans OPEB Plans ($ millions) 2018 2017 2018 2017 Net asset (liability) (8 ) (9 ) (199 ) (244 ) 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 27, 2017, the Company completed a series of transactions related to the Canadian DB Pension Plan. The most recent actuarial valuation at the transaction date was at December 31, 2016. Defined benefit assets and accrued obligations were remeasured immediately prior to the transactions. DB Pension Plan assets of $148 million , including a one-time cash contribution by the Company of $5 million , were used to settle $140 million of the defined benefit obligation related to the inactive plan members. This resulted in the Company recognizing a $8 million loss on settlement in Other – net expense. Furthermore, as part of a risk management strategy the Company also purchased a $48 million annuity, on July 27, 2017, to offset the related $42 million defined benefit obligation for the active plan members. This resulted in a $3 million actuarial loss (net of tax of $1 million ) on plan assets recorded in other comprehensive income in 2017. The Company continued to accrue service costs for the active plan members and the contribution to the plan for 2018. In November 2017, the Company also acquired a small defined benefit pension plan for the employees of the Superior Refinery which is closed to new entrants. The composition of the DB Pension Plan assets at December 31, 2018 and 2017 was as follows: DB Pension Plan Assets (percent) Target allocation range 2018 2017 Money market type funds — 5.0 0.2 Equity securities — — — Debt securities 100 95.0 99.8 The following table summarizes amounts recognized in net earnings and OCI for the DB Pension Plans and the OPEB Plans for the years ended December 31, 2018 and 2017 : DB Pension Plan OPEB Plans ($ millions) 2018 2017 2018 2017 Amounts recognized in net earnings Current service cost 1 1 11 15 Past service cost — 1 — — Net Interest cost 1 — 8 8 Settlement loss — 8 — — Benefit cost 2 10 19 23 Remeasurements Actuarial loss (gain) due to liability experience 2 3 (13 ) — Actuarial loss (gain) due to liability assumption changes (4 ) 5 (45 ) 12 Gain on plan assets — (4 ) — — Remeasurement effects recognized in OCI (2 ) 4 (58 ) 12 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 Plan OPEB Plans (percent) 2018 2017 2018 2017 Discount rate for benefit expense and obligation 3.4 - 3.6 3.4 - 3.5 3.4 - 3.7 3.4 - 3.9 Rate of compensation expense N/A 3.5 N/A N/A The average health care cost trend rate used for the benefit expense for the Canadian OPEB Plan was 6.5 percent for 2018 , grading 0.5 percent per year for 3 years to 5.0 percent in 2021 and thereafter. The average health care cost trend rate used for the obligation related to the Canadian OPEB Plan was 6.0 percent for 2018, 2019 and 2020 , grading 0.5 percent per year for 3 years to 5.0 percent 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 percent for 2018 , grading 0.25 percent per year for 5 years to 5.0 percent 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 percent for 2018 , grading 0.25 percent per year for 6 years to 5.0 percent 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 Plan OPEB Plans ($ millions) 1% increase 1% decrease 1% increase 1% decrease Discount rate (9 ) 11 (33 ) 43 Health care cost trend rate N/A N/A 32 (25 )

Cash Flows - Change in Non-cash

Cash Flows - Change in Non-cash Working Capital	12 Months Ended
	Dec. 31, 2018
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) 2018 2017 Decrease (increase) in non-cash working capital Accounts receivable 127 (329 ) Inventories 393 (264 ) Prepaid expenses 30 (38 ) Accounts payable and accrued liabilities (65 ) 1,269 Change in non-cash working capital 485 638 Relating to: Operating activities 130 398 Financing activities 120 — Investing activities 235 240

Financial Instruments and Risk

Financial Instruments and Risk Management	12 Months Ended
	Dec. 31, 2018
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 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, 2018 December 31, 2017 Commodity contracts – fair value through profit or loss (“FVTPL”) Natural gas (1) (9 ) (13 ) Crude oil (2) 89 (57 ) Foreign currency contracts – FVTPL Foreign currency forwards (1 ) 1 Other assets – FVTPL 1 1 Derivatives designated as a cash flow hedge - forward starting swaps (14 ) — Hedge of net investment (3)(4) (846 ) (584 ) End of year (780 ) (652 ) (1) Natural gas contracts includes a $10 million decrease at December 31, 2018 ( December 31, 2017 – $3 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 $15 million at December 31, 2018 ( December 31, 2017 – $5 million ). (2) Crude oil contracts includes a $67 million increase at December 31, 2018 ( December 31, 2017 – $5 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 $185 million at December 31, 2018 ( December 31, 2017 – $232 million ). (3) Hedging instruments are presented net of tax. (4) Represents the translation of the Company’s U.S. dollar denominated long-term debt designated as a hedge of the Company’s net investment in selected foreign operations with a U.S. dollar functional currency. 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, 2018 , the carrying value of the Company’s long-term debt was $5.5 billion and the estimated fair value was $5.7 billion ( December 31, 2017 – carrying value of $5.2 billion , estimated fair value of $5.6 billion ). All financial assets and liabilities are classified as Level 2 fair value measurements. During the year ended December 31, 2018, 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. Responsibility for 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 31, 2018, 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, 2018, the net unrealized gain recognized on the derivative contracts was $150 million (2017 - net unrealized loss of $56 million ). 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, 2018 , the Company had designated US $2.7 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, 2017 – US $2.7 billion ). For the year ended December 31, 2018 , the unrealized loss arising from the translation of the debt was $262 million ( December 31, 2017 – unrealized gain of $243 million ), net of tax recovery of $41 million ( December 31, 2017 – expense of $38 million ), which was recorded in hedge of net investment within OCI . III) 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. 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. There was no ineffective portion as at December 31, 2018. For the year ended December 31, 2018, the unrealized loss arising from the recognition of the swaps was $11 million (December 31, 2017 - nil ), net of tax recovery of $3 million , which was recorded in OCI. The forward starting swaps have the following terms and fair value as at December 31, 2018. As at December 31, 2018 Forward Starting Swaps Swap Rate (1) Notional Amount (U.S. $ millions) Fair Value ($ million) ($ millions) Swap Maturity December 15, 2029 2.999 % 250 (7 ) December 15, 2029 3.000 % 250 (7 ) (1) Weighted average rate. At December 31, 2018 , the balance in other reserves related to the accrued gain from unwound forward starting interest rate swaps designated as a cash flow hedge was $13 million ( December 31, 2017 – $15 million ), net of tax of $4 million ( December 31, 2017 – net of tax of $5 million ). The amortization of the accrued gain upon settling the interest rate swaps resulted in an offset to finance expense of $2 million for the year ended December 31, 2018 ( December 31, 2017 – $2 million ). Offsetting Financial Assets and Liabilities The tables below outline the financial assets and financial liabilities that are subject to set-off rights and related arrangements, and the effect of those rights and arrangements on the consolidated balance sheets: As at December 31, 2018 Offsetting Financial Assets and Liabilities ($ 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 ) As at December 31, 2017 Offsetting Financial Assets and Liabilities ($ millions) Gross Amount Amount Offset Net Amount Financial Assets Financial derivatives 150 (111 ) 40 Normal purchase and sale agreements 639 (280 ) 359 End of year 789 (391 ) 399 Financial Liabilities Financial derivatives (246 ) 122 (123 ) Normal purchase and sale agreements (933 ) 353 (581 ) End of year (1,179 ) 475 (704 ) Market Risk Sensitivity Analysis A sensitivity analysis for commodities, foreign currency exchange and interest rate risks has been calculated by increasing or decreasing commodity prices, foreign currency exchange rates or interest rates, as appropriate. These sensitivities represent the increase or decrease in earnings 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 26 (26 ) Natural gas price (9 ) 9 Foreign Exchange Rate (2) Canadian dollar Canadian dollar ($ millions) U.S. dollar per Canadian dollar 1 (1 ) Interest Rate (3) 100 basis point increase 100 basis point decrease ($ millions) LIBOR 61 (61 ) (1) Based on average crude oil and natural gas market prices as at December 31, 2018 . (2) Based on the U.S./Canadian dollar exchange rate as at December 31, 2018 . (3) Based on the U.S. LIBOR as at December 31, 2018 . 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 Upstream 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 Upstream 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, 2018 : Credit Facilities ($ millions) Available Unused Operating facilities (1) (note 13) 900 461 Syndicated bank facilities (2) (note 15) 4,000 3,800 End of year 4,900 4,261 (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 $3.0 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 percent of gross revenues during the years ended December 31, 2018 and December 31, 2017 . Sales to this customer were approximately $4.2 billion for the year ended December 31, 2018 ( December 31, 2017 – $3.3 billion ). Cash and cash equivalents include cash bank balances and short-term deposits maturing in less than three months. The Company manages the credit exposure related to short-term investments by monitoring exposures daily on a per issuer basis relative to predefined investment limits. The carrying amounts of cash and cash equivalents, accounts receivable and restricted cash represent the Company’s maximum credit exposure. The Company’s accounts receivable was aged as follows at December 31, 2018 : Accounts Receivable Aging ($ millions) December 31, 2018 Current 1,140 Past due (1 – 30 days) 139 Past due (31 – 60 days) 42 Past due (61 – 90 days) 16 Past due (more than 90 days) 57 Provision for expected credit losses (39 ) 1,355 The Company recognizes a valuation provision when collection of accounts receivable is in doubt. Accounts receivable are impaired directly when collection of accounts receivable is no longer expected. For the year ended December 31, 2018 , the Company wrote off $3 million ( December 31, 2017 – $1 million ) of uncollectible receivables.

Related Party Transactions

Related Party Transactions	12 Months Ended
	Dec. 31, 2018
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, 2018. All of the entities listed below, except as otherwise indicated, are 100 percent 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 100 Alberta Husky Downstream General Partnership 100 Alberta Husky Energy Marketing Partnership 100 Alberta Sunrise Oil Sands Partnership 50 Alberta BP-Husky Refining LLC 50 Delaware Each of the related party transactions described below was made on terms equivalent to those that prevail in arm’s length transactions. 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 percent 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, 2018 , the Company charged HMLP $448 million (December 31, 2017 – $412 million ) related to construction costs and management services. For the year ended December 31, 2018 , the Company had purchases from HMLP of $200 million (December 31, 2017 – $203 million ) related to the use of the pipeline for the Company’s blending activities, transportation and storage activities, received distributions of $139 million (December 31, 2017 – $25 million ) and paid capital contributions of $40 million (December 31, 2017 – $17 million ). At December 31, 2018 , the Company had $140 million due from HMLP, of which nil relates to unbilled revenue from construction contracts on the percentage of completion method (December 31, 2017 – $67 million and $23 million , respectively). Key management includes Directors (executive and non-executive), Executive Officers and Senior Vice – Presidents of the Company. The amounts disclosed in the table below are the amounts recognized as an expense during the reporting period related to key management personnel: Compensation of Key Management Personnel ($ millions) 2018 2017 Short-term employee benefits (1) 17 16 Stock-based compensation (2) 33 31 50 47 (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, 2018
Commitments and Contingencies [Abstract]
Commitments and Contingencies	Commitments and Contingencies At December 31, 2018 , 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 leases (1) 233 504 1,186 1,923 Firm transportation agreements (1) 497 2,066 4,013 6,576 Unconditional purchase obligations (2) 1,620 3,656 4,822 10,098 Lease rentals and exploration work agreements 49 246 930 1,225 Obligations to fund equity investee (3) 53 293 395 741 2,452 6,765 11,346 20,563 (1) Included in operating leases and firm transportation agreements are blending and storage agreements and transportation commitments of $1.1 billion and $1.9 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. 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, 2018
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 $25.4 billion as at December 31, 2018 ( December 31, 2017 – $23.4 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 capital structure and financing requirements 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 plus change in non-cash working capital . The Company’s objective is to maintain a debt to capital employed target of less than 25 percent and a debt to funds from operations ratio of less than 2.0 times. At December 31, 2018 , debt to capital employed was 22.7 percent ( December 31, 2017 – 23.2 percent ) and debt to funds from operations was 1.4 times ( December 31, 2017 – 1.6 times), within the Company’s targets. 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. The Company’s share capital is not subject to external restrictions; however, the syndicated credit facilities include a debt to capital covenant, 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. This covenant is used to assess the Company’s financial strength. If the Company does not comply with the covenants under the syndicated credit facilities, there is the risk that repayment could be accelerated. The Company was in compliance with the syndicated credit facility covenants at December 31, 2018, and assessed the risk of non-compliance to be low. 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, 2018
Disclosure of events after reporting period [Abstract]
Subsequent Events	Subsequent Event On January 8, 2019, the Company announced its intention to market and potentially sell its Prince George Refinery and Retail and Commercial Network. An estimate of the financial impact cannot be made at this time. On January 16, 2019, the Company announced that its offer to acquire all of the outstanding common shares of MEG Energy Corp. expired, as the minimum tender threshold was not satisfied, and the Company decided not to extend its offer.

Significant Accounting Polici_2

Significant Accounting Policies (Policies)	12 Months Ended
	Dec. 31, 2018
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 and signed by the Chair of the Audit Committee and the Chief Executive Officer on February 25, 2019 having been duly authorized to do so by the Board of Directors. 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 11), 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, 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. 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 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, less any estimated residual value. The useful lives of assets are estimated based upon the period the asset is expected to be available for use by the Company. Residual values are based upon the estimated amount that would be obtained on disposal, net of any costs associated with the disposal. Other property, plant and equipment held under finance leases are depreciated over the shorter of the lease term and the estimated useful life of the asset. 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. vi) Finance Leases Finance leases, which transfer substantially all of the risks and rewards incidental to ownership of the leased item to the Company, are capitalized at the commencement of the lease term at the fair value of the lease property or, if lower, at the present value of the minimum lease payments. Capitalized leased assets are depreciated over the shorter of the estimated useful life of the asset or the lease term. All other leases are accounted for as operating leases and the lease costs are expensed as incurred.
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. Acquisition costs incurred are expensed and included in selling, general and administrative expenses in the consolidated statements of income.
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 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, 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, 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. 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. 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. 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, 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 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. 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 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 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. 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 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. 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 In Canada, the Company provides a defined contribution pension plan and other post-retirement benefits to qualified employees. The Company also maintains a defined benefit pension plan for a small number of employees who did not choose to join the defined contribution pension plan in 1991. In the United States, the Company provides two defined contribution pension plans (401(k)) and one other post-retirement benefits plan. The Company also maintains a small defined benefit pension plan for the employees of the Superior Refinery. 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 country 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 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. Any interest and penalties on income taxes are recognized in interest expense and interest payable. 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 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 percent. The Company acts as the general contractor for HMLP projects for fixed price and cost plus contracts. Revenue from fixed price contracts is recognized using the percentage of completion method based on costs incurred. Revenue from cost plus contracts are recognized as services are performed. Construction services are billed and paid on a monthly basis, with unbilled percentage of completion payments billed 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 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. 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 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. 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 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 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	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 per common share is based on net earnings 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 per share is based on net earnings 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 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. As a result, net earnings 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 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 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. These transactions are on terms equivalent to those that prevail in arm’s length transactions, unless otherwise noted. 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. Revenue from fixed price construction contracts are recognized using the percentage of completion method based on costs incurred, which requires estimating the expected costs to complete a project. Changes in these assumptions may result in a material difference in the construction revenue recognized. See Note 25.
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. i) Leases In January 2016, the IASB issued IFRS 16 Leases, which replaces the current IFRS guidance on leases. Under the current guidance, lessees are required to determine if the lease is a finance or operating lease, based on specified criteria. Finance leases are recognized on the balance sheet while operating leases are recognized in the consolidated statements of income when the expense is incurred. Under IFRS 16, lessees must recognize a lease liability and a right-of-use asset for virtually all lease contracts. The recognition of the present value of minimum lease payments for certain contracts currently classified as operating leases will result in increases to assets, liabilities, depletion, depreciation and amortization, and finance expense, and a decrease to production, operating and transportation expense upon implementation. Optional exemptions to not recognize certain short-term leases or leases of low value can be applied by lessees. For lessors, the accounting remains essentially unchanged. The Company will adopt IFRS 16 on the effective date of January 1, 2019 and has selected the modified retrospective transition approach. The optional exemptions to not recognize certain short-term and low value leases will be applied. For leases implemented January 1, 2019, the Company will recognize a right-of-use asset of $1.1 billion equal to the lease liability at the present value of the remaining lease payments discounted using the Company’s incremental borrowing rate. The implementation of IFRS 16 does not have a material impact on the consolidated statements of income. Due to a change in classification of operating lease expenses, cash flow from operating activities will increase and cash flow from financing activities will decrease, with no overall impact to the cash position for the Company.
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)    Revenue from Contracts with Customers</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 September 2015, the IASB published an amendment to IFRS 15 Revenue from Contracts with Customers, deferring the effective date to annual periods beginning on or after January 1, 2018. IFRS 15 replaces existing revenue recognition guidance with a single comprehensive accounting model. The standard requires an entity to recognize revenue to reflect the transfer of goods and services for the amount it expects to receive when control is transferred to the purchaser. The Company retrospectively adopted the standard on January 1, 2018. The adoption of IFRS 15 did not require any material adjustments to the amounts recorded in the consolidated financial statements; however, additional disclosures are presented in the consolidated financial statements. </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;">Revenue is recognized when the performance obligations are satisfied and revenue can be reliably measured. Revenue is measured at the consideration specified in the contracts and represents amounts receivable for goods or services provided in the normal course of business, net of discounts, customs duties and sales taxes. Natural gas sales in Asia Pacific are under long-term, fixed price contracts. Substantially all other revenue is based on floating prices. Performance obligations associated with the sale of crude oil, crude oil equivalents, and refined products are satisfied at the point in time when the products are delivered to and title passes to the customer. Performance obligations associated with processing services, transportation, blending and storage, and marketing services are satisfied at the point in time when the services are provided. </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;">ii)    Financial Instruments</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 July 2014, the IASB issued IFRS 9 Financial Instruments to replace IAS 39, which provides a single model for classification and measurement based on how an entity manages its financial instruments in the context of its business model and the contractual cash flow characteristics of the financial instruments. For financial liabilities, the change in fair value resulting from an entity’s own credit risk is recorded in other comprehensive income rather than net earnings, unless this creates an accounting mismatch. IFRS 9 includes a new, forward-looking ‘expected loss’ impairment model that will result in a more timely recognition of expected credit losses. In addition, IFRS 9 provides a substantially-reformed approach to hedge accounting. The standard was effective for annual periods beginning on January 1, 2018. The Company retrospectively adopted the standard on January 1, 2018. The adoption of IFRS 9 did not require any material adjustments to the consolidated financial statements. </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;">Financial assets previously classified as loans and receivables (cash and cash equivalents, accounts receivable, restricted cash, and long-term receivables), as well as financial liabilities previously classified as other financial liabilities (accounts payable and accrued liabilities, short-term debt, and long-term debt) have been reclassified to amortized cost. The carrying value and measurement of all financial instruments remains unchanged. The Company’s current process for assessing short-term receivables lifetime expected credit losses collectively in groups that share similar credit risk characteristics is unadjusted with the adoption of the new impairment model and resulted in no additional impairment allowance. Additionally, long-term receivables were assessed individually under the expected credit loss model and no impairment was concluded. </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;">iii)    Amendments to IFRS 2 Share-based payment</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;">In June 2016, the IASB issued amendments to IFRS 2 to be applied prospectively for annual periods beginning on or after January 1, 2018. The amendments clarify how to account for certain types of share-based payment arrangements. The adoption of the amendments did not have a material impact on the Company’s consolidated financial statements.</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;Revenue from Contracts with Customers&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 September 2015, the IASB published an amendment to IFRS 15 Revenue from Contracts with Customers, deferring the effective date to annual periods beginning on or after January 1, 2018. IFRS 15 replaces existing revenue recognition guidance with a single comprehensive accounting model. The standard requires an entity to recognize revenue to reflect the transfer of goods and services for the amount it expects to receive when control is transferred to the purchaser. The Company retrospectively adopted the standard on January 1, 2018. The adoption of IFRS 15 did not require any material adjustments to the amounts recorded in the consolidated financial statements; however, additional disclosures are presented in the consolidated financial statements. &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;">Revenue is recognized when the performance obligations are satisfied and revenue can be reliably measured. Revenue is measured at the consideration specified in the contracts and represents amounts receivable for goods or services provided in the normal course of business, net of discounts, customs duties and sales taxes. Natural gas sales in Asia Pacific are under long-term, fixed price contracts. Substantially all other revenue is based on floating prices. Performance obligations associated with the sale of crude oil, crude oil equivalents, and refined products are satisfied at the point in time when the products are delivered to and title passes to the customer. Performance obligations associated with processing services, transportation, blending and storage, and marketing services are satisfied at the point in time when the services are provided. &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;">ii)&#160;&#160;&#160;&#160;Financial Instruments&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 July 2014, the IASB issued IFRS 9 Financial Instruments to replace IAS 39, which provides a single model for classification and measurement based on how an entity manages its financial instruments in the context of its business model and the contractual cash flow characteristics of the financial instruments. For financial liabilities, the change in fair value resulting from an entity&#8217;s own credit risk is recorded in other comprehensive income rather than net earnings, unless this creates an accounting mismatch. IFRS 9 includes a new, forward-looking &#8216;expected loss&#8217; impairment model that will result in a more timely recognition of expected credit losses. In addition, IFRS 9 provides a substantially-reformed approach to hedge accounting. The standard was effective for annual periods beginning on January 1, 2018. The Company retrospectively adopted the standard on January 1, 2018. The adoption of IFRS 9 did not require any material adjustments to the consolidated financial statements. &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;">Financial assets previously classified as loans and receivables (cash and cash equivalents, accounts receivable, restricted cash, and long-term receivables), as well as financial liabilities previously classified as other financial liabilities (accounts payable and accrued liabilities, short-term debt, and long-term debt) have been reclassified to amortized cost. The carrying value and measurement of all financial instruments remains unchanged. The Company&#8217;s current process for assessing short-term receivables lifetime expected credit losses collectively in groups that share similar credit risk characteristics is unadjusted with the adoption of the new impairment model and resulted in no additional impairment allowance. Additionally, long-term receivables were assessed individually under the expected credit loss model and no impairment was concluded. &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;">iii)&#160;&#160;&#160;&#160;Amendments to IFRS 2 Share-based payment&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;">In June 2016, the IASB issued amendments to IFRS 2 to be applied prospectively for annual periods beginning on or after January 1, 2018. The amendments clarify how to account for certain types of share-based payment arrangements. The adoption of the amendments did not have a material impact on the Company&#8217;s consolidated financial statements.&lt;/font>&lt;/div>&lt;/div>

Description of Business and S_2

Description of Business and Segmented Disclosures (Tables)	12 Months Ended
	Dec. 31, 2018
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 Year ended December 31, 2018 2017 2018 2017 2018 2017 Gross revenues 4,330 4,978 2,211 1,976 6,541 6,954 Royalties (335 ) (363 ) — — (335 ) (363 ) Marketing and other — — 668 (40 ) 668 (40 ) Revenues, net of royalties 3,995 4,615 2,879 1,936 6,874 6,551 Expenses Purchases of crude oil and products — — 2,087 1,855 2,087 1,855 Production, operating and transportation expenses 1,527 1,650 23 13 1,550 1,663 Selling, general and administrative expenses 296 265 5 4 301 269 Depletion, depreciation, amortization and impairment 1,811 2,237 — 2 1,811 2,239 Exploration and evaluation expenses 149 146 — — 149 146 Loss (gain) on sale of assets (2 ) (42 ) — 1 (2 ) (41 ) Other – net (120 ) 6 2 (8 ) (118 ) (2 ) 3,661 4,262 2,117 1,867 5,778 6,129 Earnings (loss) from operating activities 334 353 762 69 1,096 422 Share of equity investment gain 51 12 18 49 69 61 Financial items Net foreign exchange gain (loss) — — — — — — Finance income 12 5 — — 12 5 Finance expenses (109 ) (131 ) — — (109 ) (131 ) (97 ) (126 ) — — (97 ) (126 ) Earnings (loss) before income taxes 288 239 780 118 1,068 357 Provisions for (recovery of) income taxes Current (484 ) (34 ) 354 — (130 ) (34 ) Deferred 549 99 (141 ) 32 408 131 65 65 213 32 278 97 Net earnings (loss) 223 174 567 86 790 260 Intersegment revenues 1,155 1,250 — — 1,155 1,250 (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 $172 million of revenue (2017 - $280 million ) and $142 million of associated costs (2017 - $234 million ) for construction contracts, inclusive of $172 million of revenue (2017 - $259 million ) and $142 million of costs (2017 - $236 million ) for contracts in progress accounted for under the percentage of completion method. (3) Eliminations relate to sales and operating revenues between segments recorded at transfer prices based on current market prices. Segment results include transactions between business segments. Segmented Financial Information Con’t Downstream Corporate and Eliminations (3) Total Upgrading Canadian Refined Products U.S. Refining and Marketing Total 2018 2017 2018 2017 2018 2017 2018 2017 2018 2017 2018 2017 1,750 1,440 3,412 2,787 11,770 9,355 16,932 13,582 (1,554 ) (1,550 ) 21,919 18,986 — — — — — — — — — — (335 ) (363 ) — — — — — — — — — — 668 (40 ) 1,750 1,440 3,412 2,787 11,770 9,355 16,932 13,582 (1,554 ) (1,550 ) 22,252 18,583 928 983 2,760 2,219 10,334 8,059 14,022 11,261 (1,554 ) (1,550 ) 14,555 11,566 195 197 265 256 795 563 1,255 1,016 (2 ) — 2,803 2,679 7 9 47 53 22 15 76 77 277 304 654 650 123 99 115 111 450 354 688 564 92 79 2,591 2,882 — — — — — — — — — — 149 146 — — (2 ) (5 ) — — (2 ) (5 ) — — (4 ) (46 ) — — (1 ) (1 ) (464 ) (21 ) (465 ) (22 ) (8 ) 6 (591 ) (18 ) 1,253 1,288 3,184 2,633 11,137 8,970 15,574 12,891 (1,195 ) (1,161 ) 20,157 17,859 497 152 228 154 633 385 1,358 691 (359 ) (389 ) 2,095 724 — — — — — — — — — — 69 61 — — — — — — — — 14 (6 ) 14 (6 ) — — — — — — — — 52 32 64 37 (1 ) (1 ) (12 ) (12 ) (14 ) (14 ) (27 ) (27 ) (178 ) (234 ) (314 ) (392 ) (1 ) (1 ) (12 ) (12 ) (14 ) (14 ) (27 ) (27 ) (112 ) (208 ) (236 ) (361 ) 496 151 216 142 619 371 1,331 664 (471 ) (597 ) 1,928 424 168 63 100 45 9 2 277 110 (72 ) (79 ) 75 (3 ) (33 ) (22 ) (42 ) (7 ) 129 135 54 106 (66 ) (596 ) 396 (359 ) 135 41 58 38 138 137 331 216 (138 ) (675 ) 471 (362 ) 361 110 158 104 481 234 1,000 448 (333 ) 78 1,457 786 290 192 109 108 — — 399 300 — — 1,554 1,550 Segmented Financial Information Upstream ($ millions) Exploration and Production (1) Infrastructure and Marketing Total Year ended December 31, 2018 2017 2018 2017 2018 2017 Expenditures on exploration and evaluation assets (2) 242 148 — — 242 148 Expenditures on property, plant and equipment (2) 2,414 1,328 — — 2,414 1,328 As at December 31, Exploration and evaluation assets 997 838 — — 997 838 Developing and producing assets at cost 44,196 41,804 — — 44,196 41,804 Accumulated depletion, depreciation, amortization and impairment (27,379 ) (26,014 ) — — (27,379 ) (26,014 ) Other property, plant and equipment at cost — — 101 89 101 89 Accumulated depletion, depreciation and amortization — — (50 ) (50 ) (50 ) (50 ) Total exploration and evaluation assets and property, plant and equipment, net 17,814 16,628 51 39 17,865 16,667 Total assets 19,175 17,920 1,301 1,364 20,476 19,284 (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 Year ended December 31, 2018 2017 2018 2017 Gross revenues (1) 9,000 8,599 11,770 9,355 Royalties (269 ) (303 ) — — Marketing and other 668 (40 ) — — Revenue, net of royalties 9,399 8,256 11,770 9,355 As at December 31, Restricted cash – non-current — — — — Exploration and evaluation assets 935 831 — — Property, plant and equipment, net 16,433 15,478 6,336 5,595 Goodwill — — 690 633 Investment in joint ventures 669 685 — — Long-term income tax receivable 243 242 — — Other assets (2) 58 64 276 21 Total non-current assets 18,338 17,300 7,302 6,249 (1) Sales to external customers are based on the location of the seller. (2) Includes insurance proceeds of $253 million (2017 - nil), related to the Superior Refinery incident. Segmented Financial Information Con’t Downstream Corporate and Eliminations Total Upgrading Canadian Refined Products U.S. Refining and Marketing Total 2018 2017 2018 2017 2018 2017 2018 2017 2018 2017 2018 2017 — — — — — — — — — — 242 148 62 230 74 87 665 313 801 630 121 114 3,336 2,072 — — — — — — — — — — 997 838 — — — — — — — — — — 44,196 41,804 — — — — — — — — — — (27,379 ) (26,014 ) 2,659 2,600 2,789 2,704 9,746 8,300 15,194 13,604 1,251 1,124 16,546 14,817 (1,585 ) (1,463 ) (1,581 ) (1,466 ) (3,410 ) (2,705 ) (6,576 ) (5,634 ) (937 ) (845 ) (7,563 ) (6,529 ) 1,074 1,137 1,208 1,238 6,336 5,595 8,618 7,970 314 279 26,797 24,916 1,149 1,263 1,431 1,548 8,566 7,580 11,146 10,391 3,603 3,252 35,225 32,927 Geographical Financial Information Con’t China Other International Total 2018 2017 2018 2017 2018 2017 1,149 1,032 — — 21,919 18,986 (66 ) (60 ) — — (335 ) (363 ) — — — — 668 (40 ) 1,083 972 — — 22,252 18,583 128 97 — — 128 97 57 3 5 4 997 838 3,030 3,005 1 — 25,800 24,078 — — — — 690 633 — — 650 553 1,319 1,238 — — — — 243 242 — 78 26 22 360 185 3,215 3,183 682 579 29,537 27,311 Disaggregation of Revenue Upstream ($ millions) Exploration and Production (1) Infrastructure and Marketing Total Year ended December 31, 2018 2017 2018 2017 2018 2017 Primary Geographical Markets Canada 3,181 3,946 2,211 1,976 5,392 5,922 United States — — — — — — China 1,149 1,032 — — 1,149 1,032 Total revenue 4,330 4,978 2,211 1,976 6,541 6,954 Major Product Lines Light & medium crude oil 948 1,273 — — 948 1,273 Heavy crude oil 527 703 — — 527 703 Bitumen 1,367 1,662 — — 1,367 1,662 Total crude oil 2,842 3,638 — — 2,842 3,638 NGL 381 276 — — 381 276 Natural gas 1,107 1,064 — — 1,107 1,064 Total exploration and production 4,330 4,978 — — 4,330 4,978 Total infrastructure and marketing — — 2,211 1,976 2,211 1,976 Synthetic crude — — — — — — Gasoline — — — — — — Diesel & distillates — — — — — — Asphalt — — — — — — Other — — — — — — Total refined products — — — — — — Total revenue 4,330 4,978 2,211 1,976 6,541 6,954 Disaggregation of Revenue Con’t Downstream Corporate and Eliminations Total Upgrading Canadian Refined Products U.S. Refining and Marketing Total 2018 2017 2018 2017 2018 2017 2018 2017 2018 2017 2018 2017 1,750 1,440 3,412 2,787 — — 5,162 4,227 (1,554 ) (1,550 ) 9,000 8,599 — — — — 11,770 9,355 11,770 9,355 — — 11,770 9,355 — — — — — — — — — — 1,149 1,032 1,750 1,440 3,412 2,787 11,770 9,355 16,932 13,582 (1,554 ) (1,550 ) 21,919 18,986 — — — — — — — — — — 948 1,273 — — — — — — — — — — 527 703 — — — — — — — — — — 1,367 1,662 — — — — — — — — — — 2,842 3,638 — — — — — — — — — — 381 276 — — — — — — — — — — 1,107 1,064 — — — — — — — — — — 4,330 4,978 — — — — — — — — — — 2,211 1,976 1,445 1,235 — — — — 1,445 1,235 — — 1,445 1,235 — — 1,070 925 6,157 5,198 7,227 6,123 — — 7,227 6,123 278 196 1,303 917 4,297 3,435 5,878 4,548 — — 5,878 4,548 — — 454 362 165 31 619 393 — — 619 393 27 9 585 583 1,151 691 1,763 1,283 — — 1,763 1,283 1,750 1,440 3,412 2,787 11,770 9,355 16,932 13,582 — — 16,932 13,582 1,750 1,440 3,412 2,787 11,770 9,355 16,932 13,582 (1,554 ) (1,550 ) 21,919 18,986

Accounts Receivable (Tables)

Accounts Receivable (Tables)	12 Months Ended
	Dec. 31, 2018
Subclassifications of assets, liabilities and equities [abstract]
Accounts Receivable	Accounts Receivable ($ millions) December 31, 2018 December 31, 2017 Trade receivables 1,146 1,170 Provision for expected credit losses (39 ) (34 ) Derivatives due within one year 43 17 Other (1) 205 33 End of year 1,355 1,186 (1) Includes insurance proceeds of $143 million (2017 - nil ), related to the Superior Refinery incident.

Inventories (Tables)

Inventories (Tables)	12 Months Ended
	Dec. 31, 2018
Subclassifications of assets, liabilities and equities [abstract]
Schedule of Inventories	Inventories ($ millions) December 31, 2018 December 31, 2017 Crude oil, natural gas and NGL 445 539 Refined petroleum products 435 548 Trading inventories measured at fair value less costs to sell 200 237 Materials, supplies and other 152 189 End of year 1,232 1,513

Exploration and Evaluation Co_2

Exploration and Evaluation Costs (Tables)	12 Months Ended
	Dec. 31, 2018
Subclassifications of assets, liabilities and equities [abstract]
Disclosure of detailed information about exploration and evaluation assets	Exploration and Evaluation Assets ($ millions) 2018 2017 Beginning of year 838 1,066 Additions 287 224 Disposals (23 ) — Transfers to oil and gas properties (note 9) (79 ) (377 ) Expensed exploration expenditures previously capitalized (29 ) (6 ) Exchange adjustments 3 (69 ) End of year 997 838 Property, Plant and Equipment Oil and Gas Properties Processing, Upgrading Refining Retail and Other Total ($ millions) Cost December 31, 2016 44,801 137 2,367 8,645 2,755 58,705 Additions (1) 1,371 11 230 561 140 2,313 Acquisitions 29 — — 577 — 606 Transfers from exploration and evaluation (note 8) 377 — — — — 377 Intersegment transfers 48 (61 ) — — 13 — Changes in asset retirement obligations (note 16) 150 — 2 13 23 188 Disposals and derecognition (4,702 ) — — (39 ) — (4,741 ) Exchange adjustments (259 ) (1 ) — (566 ) (1 ) (827 ) 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 16) 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 Accumulated depletion, depreciation, amortization and impairment December 31, 2016 (27,986 ) (96 ) (1,363 ) (2,975 ) (1,692 ) (34,112 ) Depletion, depreciation, amortization and impairment (2,238 ) (2 ) (99 ) (406 ) (137 ) (2,882 ) Intersegment transfers (37 ) 50 — — (13 ) — Disposals and derecognition 4,124 — — 16 — 4,140 Exchange adjustments 121 1 — 189 — 311 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 ) Net book value December 31, 2017 15,799 39 1,137 6,015 1,088 24,078 December 31, 2018 16,817 51 1,074 6,758 1,100 25,800 (1) Additions include assets under finance lease.
Disclosure of exploration and evaluation expenses	The following exploration and evaluation expenses for the years ended December 31, 2018 and 2017 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) 2018 2017 Seismic, geological and geophysical 102 113 Expensed drilling 41 22 Expensed land 6 11 149 146

Property, Plant and Equipment (

Property, Plant and Equipment (Tables)	12 Months Ended
	Dec. 31, 2018	Dec. 31, 2017
Subclassifications of assets, liabilities and equities [abstract]
Disclosure of detailed information about property, plant and equipment	Exploration and Evaluation Assets ($ millions) 2018 2017 Beginning of year 838 1,066 Additions 287 224 Disposals (23 ) — Transfers to oil and gas properties (note 9) (79 ) (377 ) Expensed exploration expenditures previously capitalized (29 ) (6 ) Exchange adjustments 3 (69 ) End of year 997 838 Property, Plant and Equipment Oil and Gas Properties Processing, Upgrading Refining Retail and Other Total ($ millions) Cost December 31, 2016 44,801 137 2,367 8,645 2,755 58,705 Additions (1) 1,371 11 230 561 140 2,313 Acquisitions 29 — — 577 — 606 Transfers from exploration and evaluation (note 8) 377 — — — — 377 Intersegment transfers 48 (61 ) — — 13 — Changes in asset retirement obligations (note 16) 150 — 2 13 23 188 Disposals and derecognition (4,702 ) — — (39 ) — (4,741 ) Exchange adjustments (259 ) (1 ) — (566 ) (1 ) (827 ) 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 16) 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 Accumulated depletion, depreciation, amortization and impairment December 31, 2016 (27,986 ) (96 ) (1,363 ) (2,975 ) (1,692 ) (34,112 ) Depletion, depreciation, amortization and impairment (2,238 ) (2 ) (99 ) (406 ) (137 ) (2,882 ) Intersegment transfers (37 ) 50 — — (13 ) — Disposals and derecognition 4,124 — — 16 — 4,140 Exchange adjustments 121 1 — 189 — 311 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 ) Net book value December 31, 2017 15,799 39 1,137 6,015 1,088 24,078 December 31, 2018 16,817 51 1,074 6,758 1,100 25,800 (1) Additions include assets under finance lease.
Disclosure of assets under finance lease	The net book values of assets held under finance lease within property, plant and equipment are as follows: Assets Under Finance Lease Oil and Gas Properties ($ millions) Refining Total December 31, 2017 152 335 487 December 31, 2018 141 323 464
Disclosure of purchase price allocation		Purchase Price Allocation ($ millions) USD CAD Working capital 85 108 Property, plant and equipment 454 577 Asset retirement obligation (7 ) (9 ) Other long-term liabilities (5 ) (6 ) Net assets acquired 527 670

Goodwill (Tables)

Goodwill (Tables)	12 Months Ended
	Dec. 31, 2018
Subclassifications of assets, liabilities and equities [abstract]
Disclosure of reconciliation of changes in goodwill	Goodwill ($ millions) December 31, 2018 December 31, 2017 Beginning of year 633 679 Exchange adjustments 57 (46 ) End of year 690 633

Joint Arrangements (Tables)

Joint Arrangements (Tables)	12 Months Ended
	Dec. 31, 2018
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, 2018. All of the entities listed below, except as otherwise indicated, are 100 percent 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 100 Alberta Husky Downstream General Partnership 100 Alberta Husky Energy Marketing Partnership 100 Alberta Sunrise Oil Sands Partnership 50 Alberta BP-Husky Refining LLC 50 Delaware
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) 2018 2017 Revenues 441 97 Expenses (273 ) (80 ) Net earnings 168 17 Share of equity investment (percent) 40 % 40 % Proportionate share of equity investment 51 12 Balance Sheets ($ millions, except share of equity investment) December 31, 2018 December 31, 2017 Current assets (1) 373 152 Non-current assets 2,072 1,993 Current liabilities (123 ) (106 ) Non-current liabilities (2) (1,917 ) (1,813 ) Net assets 405 226 Share of net assets (percent) 40 % 40 % Carrying amount in balance sheet 650 553 (1) Includes cash and cash equivalents of $ 203 million ( 2017 – $ 26 million ). (2) Includes deferred revenue of $ 2 million (2017 - nil ) 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) 2018 2017 Revenues 296 294 Expenses (177 ) (107 ) Net earnings 119 187 Share of equity investment (percent) 35 % 35 % Proportionate share of equity investment 18 49 Balance Sheet ($ millions, except share of net assets) December 31, 2018 December 31, 2017 Current assets (1) 115 152 Non-current assets 2,849 2,617 Current liabilities (153 ) (75 ) Non-current liabilities (825 ) (690 ) Net assets 1,986 2,004 Share of net assets (percent) 35 % 35 % Carrying amount in balance sheet 669 685 (1) Current assets include cash and cash equivalents of $ 16 million ( 2017 – $28 million ).

Other Assets (Tables)

Other Assets (Tables)	12 Months Ended
	Dec. 31, 2018
Miscellaneous non-current assets [abstract]
Schedule of other assets	Other Assets ($ millions) December 31, 2018 December 31, 2017 Long-term receivables (1) 319 144 Leasehold incentives — 2 Precious metals 23 21 Other 18 18 End of year 360 185 (1) Includes insurance proceeds of $253 million (2017 – nil ), related to the Superior Refinery incident.

Accounts Payable and Accrued _2

Accounts Payable and Accrued Liabilities (Tables)	12 Months Ended
	Dec. 31, 2018
Subclassifications of assets, liabilities and equities [abstract]
Schedule of accounts payable and accrued liabilities	Accounts Payable and Accrued Liabilities ($ millions) December 31, 2018 December 31, 2017 Trade payables 1,121 950 Accrued liabilities 1,712 1,791 Dividend payable (note 19) 126 9 Stock-based compensation 32 30 Derivatives due within one year 39 115 Other 129 138 End of year 3,159 3,033

Debt and Credit Facilities (Tab

Debt and Credit Facilities (Tables)	12 Months Ended
	Dec. 31, 2018
Disclosure of borrowing costs [Abstract]
Schedule of short-term debt	Short-term Debt December 31, 2018 December 31, 2017 ($ millions) Commercial paper (1) 200 200 (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, 2018 was 2.20 percent per annum ( December 31, 2017 – 1.40 percent ).
Schedule of long-term debt	Canadian $ Amount U.S. $ Denominated Long-term Debt Maturity December 31, 2018 December 31, 2017 December 31, 2018 December 31, 2017 ($ millions) Long-term debt 6.15% notes (1)(3) 2019 — 376 — 300 7.25% notes (1)(4) 2019 — 939 — 750 5.00% notes (5) 2020 400 400 — — 3.95% notes (1)(4) 2022 682 626 500 500 4.00% notes (1)(4) 2024 1,023 939 750 750 3.55% notes (5) 2025 750 750 — — 3.60% notes (5) 2027 750 750 — — 6.80% notes (1)(4) 2037 528 484 387 387 Debt issue costs (2) (19 ) (24 ) — — Long-term debt 4,114 5,240 1,637 2,687 Long-term debt due within one year 6.15% notes (1)(3) 2019 410 — 300 — 7.25% notes (1)(4) 2019 1,023 — 750 — Long-term debt due within one year 1,433 — 1,050 — (1) All of the Company’s 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 24 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% 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 December 31, 2017 200 — 5,240 1,237 Changes from financing cash flows Long-term debt issuance — — — — Long-term debt repayment — — — — Short-term debt issuance — — — — Short-term debt repayment — — — — Debt issue costs — — — — Total change from financing cash flows — — — — Other changes – liability-related Reclassification to short-term — 1,399 (1,399 ) — Foreign exchange — — — 32 Fair value changes — — — (67 ) Addition of finance lease obligations — — — — Payment of finance lease obligations — — — (15 ) Deferred revenue — — — (100 ) Amortization of debt issuance costs — — 4 — Foreign exchange recognized in OCI — 34 269 — Other — — — 20 Total other changes – liability related — 1,433 (1,126 ) (130 ) December 31, 2018 200 1,433 4,114 1,107

Asset Retirement Obligations (T

Asset Retirement Obligations (Tables)	12 Months Ended
	Dec. 31, 2018
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, 2018 and 2017 is set out below: Asset Retirement Obligations ($ millions) 2018 2017 Beginning of year 2,526 2,791 Additions 40 47 Liabilities settled (270 ) (136 ) Liabilities disposed (11 ) (420 ) Change in discount rate (68 ) 143 Change in estimates 93 (2 ) Exchange adjustment 17 (9 ) Accretion (note 21) 97 112 End of year 2,424 2,526 Expected to be incurred within 1 year 202 274 Expected to be incurred beyond 1 year 2,222 2,252

Other Long-term Liabilities (Ta

Other Long-term Liabilities (Tables)	12 Months Ended
	Dec. 31, 2018
Subclassifications of assets, liabilities and equities [abstract]
Schedule of other long-term liabilities	Other Long-term Liabilities ($ millions) December 31, 2018 December 31, 2017 Employee future benefits (note 22) 205 248 Finance lease obligations 467 498 Stock-based compensation 42 32 Deferred revenue 205 284 Leasehold incentives 96 101 Other 92 74 End of year 1,107 1,237
Schedule of finance lease obligations	The future minimum lease payments under existing finance leases are payable as follows: Within 1 year After 1 year but no more than 5 years More than 5 years Total ($ millions) 2018 2017 2018 2017 2018 2017 2018 2017 Future minimum lease payments 69 69 242 258 1,014 993 1,325 1,320 Interest 48 48 175 174 613 594 836 816 Present value of minimum lease payments 66 66 180 194 243 244 489 504
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, 2018 December 31, 2017 Beginning of year 284 321 Take-or-pay payments received — 12 Revenue recognized (100 ) (28 ) Exchange adjustment 21 (21 ) End of year 205 284

Income Taxes (Tables)

Income Taxes (Tables)	12 Months Ended
	Dec. 31, 2018
Disclosure of income tax [Abstract]
Disclosure of income tax expense (recovery)	The major components of income tax expense for the years ended December 31, 2018 and 2017 were as follows: Income Tax Expense (Recovery) ($ millions) 2018 2017 Current income tax Current income tax charge 86 28 Adjustments to current income tax estimates (11 ) (31 ) 75 (3 ) Deferred income tax Relating to origination and reversal of temporary differences 378 83 Adjustments to deferred income tax estimates 18 (442 ) 396 (359 )
Disclosure of deferred tax items in OCI	Deferred Tax Items in OCI ($ millions) 2018 2017 Deferred tax items expensed (recovered) directly in OCI Derivatives designated as cash flow hedges (5 ) — Remeasurement of pension plans 17 (4 ) Exchange differences on translation of foreign operations 87 (82 ) Hedge of net investment (41 ) 38 58 (48 )
Disclosure of reconciliation of effective tax rate	The provision for income taxes in the consolidated statements of income reflects an effective tax rate which differs from the expected statutory tax rate. Differences for the years ended December 31, 2018 and 2017 were accounted for as follows: Reconciliation of Effective Tax Rate ($ millions, except tax rate) 2018 2017 Earnings before income taxes Canada 734 (440 ) United States 493 301 Other foreign jurisdictions 701 563 1,928 424 Statutory Canadian income tax rate (percent) 27.2 % 27.1 % Expected income tax 525 115 Effect on income tax resulting from: Foreign jurisdictions (36 ) 20 Non-taxable items (13 ) (1 ) Adjustments with respect to previous year 7 (473 ) Revaluation of foreign tax pools (4 ) (8 ) Other – net (8 ) (15 ) Income tax expense (recovery) 471 (362 )
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, 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 ) Deferred Tax Liabilities and Assets ($ millions) January 1, 2017 Recognized in Earnings Recognized in OCI Other December 31, 2017 Deferred tax liabilities Exploration and evaluation assets and property, plant and equipment (3,998 ) 187 104 (20 ) (3,727 ) Foreign exchange gains taxable on realization (224 ) 85 (38 ) — (177 ) Debt issue costs (2 ) (1 ) — — (3 ) Other temporary differences (21 ) (69 ) — — (90 ) Deferred tax assets Pension plans 32 4 4 — 40 Asset retirement obligations 693 (8 ) (6 ) — 679 Loss carry-forwards 389 150 (16 ) — 523 Financial assets at fair value 20 11 — — 31 (3,111 ) 359 48 (20 ) (2,724 )

Share Capital (Tables)

Share Capital (Tables)	12 Months Ended
	Dec. 31, 2018
Disclosure of share capital, reserves and other equity interest [Abstract]
Disclosure of classes of share capital	The number of PSUs outstanding was as follows: Performance Share Units 2018 2017 Beginning of year 8,361,918 4,863,690 Granted 6,108,430 5,667,970 Exercised (1,354,316 ) (966,932 ) Forfeited (1,509,388 ) (1,202,810 ) Outstanding, end of year 11,606,644 8,361,918 Vested, end of year 4,487,585 2,262,954 Earnings per Share ($ millions) 2018 2017 Net earnings 1,457 786 Effect of dividends declared on preferred shares in the year (35 ) (34 ) Net earnings – basic 1,422 752 Dilutive effect of accounting for stock options (1) (13 ) 4 Net earnings – diluted 1,409 756 (millions) Weighted average common shares outstanding – basic 1,005.1 1,005.3 Effect of stock dividends declared in the year 1.0 — Weighted average common shares outstanding – diluted 1,006.1 1,005.3 Earnings per share – basic ($/share) 1.41 0.75 Earnings per share – diluted ($/share) 1.40 0.75 (1) For the year ended December 31, 2018 , equity-settlement of stock options was used to calculate diluted earnings per share as it was considered more dilutive than cash-settlement (December 31, 2017 - cash settlement method was used). Stock-based compensation recovery was $3 million based on equity-settlement for the year ended December 31, 2018 ( 2017 – expense of $9 million ). Stock-based compensation expense would have been $10 million based on cash-settlement for the year ended December 31, 2018 ( 2017 – $13 million ). The Company is authorized to issue an unlimited number of no par value common shares. Common Shares Number of Shares Amount ($ millions) December 31, 2016 1,005,451,854 7,296 Share cancellation (331,842 ) (3 ) December 31, 2017 1,005,120,012 7,293 Options exercised (1) 1,726 — December 31, 2018 1,005,121,738 7,293 (1) Stock options exercised was less than $1 million. Quarterly dividends may be declared in an amount expressed in dollars per common share or could be paid by way of issuance of a fraction of a common share per outstanding common share determined by dividing the dollar amount of the dividend by the volume-weighted average trading price of the Common Shares on the principal stock exchange on which the common shares are traded. The volume-weighted average trading price of the common shares is calculated by dividing the total value by the total volume of common shares traded over the five trading day period immediately prior to the payment date of the dividend on the common shares. On February 28, 2018, the Board of Directors reinstated the quarterly common share dividends. Common Share Dividends ($ millions) 2018 2017 Declared Paid Declared Paid 402 276 — — 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, 2016 36,000,000 874 December 31, 2017 36,000,000 874 December 31, 2018 36,000,000 874 Cumulative Redeemable Preferred Shares Dividends ($ millions) 2018 2017 Declared Paid Declared Paid Series 1 Preferred Shares 6 8 6 6 Series 2 Preferred Shares 1 1 1 1 Series 3 Preferred Shares 12 14 11 11 Series 5 Preferred Shares 9 11 9 9 Series 7 Preferred Shares 7 9 7 7 35 43 34 34 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, 2018 December 31, 2017 Tandem Options Tandem Options Dividend per option 0.56 0.72 Range of expected volatilities used (percent) 16.8 - 44.4 16.7 - 32.9 Range of risk-free interest rates used (percent) 1.6 - 1.9 0.9 - 1.9 Expected life of share options from vesting date (years) 1.95 1.95 Expected forfeiture rate (percent) 8.9 9.0 Weighted average exercise price 22.46 25.46 Weighted average fair value 0.65 1.15 The following options to purchase common shares have been awarded to officers and certain other employees: Outstanding and Exercisable Options 2018 2017 Number of Options (thousands) Weighted Average ($) Number of Options (thousands) Weighted Average ($) Outstanding, beginning of year 22,645 23.96 25,459 26.26 Granted (1) 5,610 17.21 5,544 16.13 Exercised for common shares (2 ) 15.67 — — Surrendered for cash (1,772 ) 15.82 — — Expired or forfeited (6,514 ) 27.69 (8,358 ) 25.62 Outstanding, end of year 19,967 21.48 22,645 23.96 Exercisable, end of year 10,461 25.87 12,946 28.91 (1) Options granted during the year ended December 31, 2018 were attributed a fair value of $2.90 per option ( 2017 – $2.01 ) at grant date. Outstanding and Exercisable Options Outstanding Options Exercisable Options Range of Exercise Price Number of Options (thousands) Weighted Average Exercise Prices ($) Weighted Average (years) Number of Options (thousands) Weighted Average Exercise Prices ($) $14.20 - $29.99 16,061 18.55 2.90 6,555 21.30 $30.00 - $36.20 3,906 33.52 0.17 3,906 33.51 December 31, 2018 19,967 21.48 2.37 10,461 25.87

Production, Operating and Tra_2

Production, Operating and Transportation and Selling, General, and Administrative Expenses (Tables)	12 Months Ended
	Dec. 31, 2018
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 for the years ended December 31, 2018 and 2017 : Production, Operating and Transportation Expenses ($ millions) 2018 2017 Services and support costs 1,039 930 Salaries and benefits 762 664 Materials, equipment rentals and leases 243 248 Energy and utility 405 453 Licensing fees 191 200 Transportation 24 26 Other 139 158 Total production, operating and transportation expenses 2,803 2,679
Disclosure of general and administrative expense	The following table summarizes selling, general and administrative expenses in the consolidated statements of income for the years ended December 31, 2018 and 2017 : Selling, General and Administrative Expenses ($ millions) 2018 2017 Employee costs (1) 332 395 Stock-based compensation expense (2) 44 45 Contract services 104 100 Equipment rentals and leases 39 37 Maintenance and other 135 73 Total selling, general and administrative expenses 654 650 (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, 2018
Disclosure of additional information [Abstract]
Schedule of financial items	Financial Items ($ millions) 2018 2017 Foreign exchange Non-cash working capital gains (3 ) (3 ) Other foreign exchange gains (losses) 17 (3 ) Net foreign exchange gains (losses) 14 (6 ) Finance income 64 37 Finance expenses Long-term debt (320 ) (342 ) Contribution payable (note 11) — (2 ) Other (5 ) (4 ) (325 ) (348 ) Interest capitalized (1) 108 68 (217 ) (280 ) Accretion of asset retirement obligations (note 16) (97 ) (112 ) Finance expenses (314 ) (392 ) Total Financial Items (236 ) (361 ) (1) Interest capitalized on project costs is calculated using the Company’s annualized effective interest rate of 5 percent ( 2017 – 5 percent).

Pensions and Other Post-emplo_2

Pensions and Other Post-employment Benefits (Tables)	12 Months Ended
	Dec. 31, 2018
Disclosure of employee benefits [Abstract]
Disclosure of net benefit obligation	Defined Benefit Obligations DB Pension Plans OPEB Plans ($ millions) 2018 2017 2018 2017 Beginning of year 76 178 244 213 Current service cost 1 1 11 15 Interest cost 3 4 8 8 Benefits paid (2 ) (9 ) (4 ) (4 ) Settlements — (140 ) — — Increase due to business combinations (1) — 34 — — Remeasurements Actuarial (gain) loss – experience 2 3 (13 ) — Actuarial loss – financial assumptions (4 ) 5 (45 ) 12 Effect of changes in foreign exchange rates 3 — (2 ) — End of year 79 76 199 244 (1) The Superior Refinery DB pension plan was transferred from Calumet GP. LLC to Husky Energy Inc. effective November 2017. Fair Value of Plan Assets DB Pension Plans OPEB Plans ($ millions) 2018 2017 2018 2017 Beginning of year 67 183 — — Contributions by employer 1 6 2 — Benefits paid (2 ) (9 ) (2 ) — Interest income 2 4 — — Return on plan assets greater than discount rate — 4 — — Settlements — (148 ) — — Increase due to business combinations (1) — 27 — — Effect of changes in foreign exchange rates 3 — — — End of year 71 67 — — (1) The Superior Refinery DB pension plan was transferred from Calumet GP. LLC to Husky Energy Inc. effective November 2017. Please refer to Note 9 for business combination. Funded status DB Pension Plans OPEB Plans ($ millions) 2018 2017 2018 2017 Net asset (liability) (8 ) (9 ) (199 ) (244 )
Disclosure of pension plan assets	The composition of the DB Pension Plan assets at December 31, 2018 and 2017 was as follows: DB Pension Plan Assets (percent) Target allocation range 2018 2017 Money market type funds — 5.0 0.2 Equity securities — — — Debt securities 100 95.0 99.8
Disclosure of a defined benefit amount recognized in net earnings and OCI	The following table summarizes amounts recognized in net earnings and OCI for the DB Pension Plans and the OPEB Plans for the years ended December 31, 2018 and 2017 : DB Pension Plan OPEB Plans ($ millions) 2018 2017 2018 2017 Amounts recognized in net earnings Current service cost 1 1 11 15 Past service cost — 1 — — Net Interest cost 1 — 8 8 Settlement loss — 8 — — Benefit cost 2 10 19 23 Remeasurements Actuarial loss (gain) due to liability experience 2 3 (13 ) — Actuarial loss (gain) due to liability assumption changes (4 ) 5 (45 ) 12 Gain on plan assets — (4 ) — — Remeasurement effects recognized in OCI (2 ) 4 (58 ) 12
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 Plan OPEB Plans ($ millions) 1% increase 1% decrease 1% increase 1% decrease Discount rate (9 ) 11 (33 ) 43 Health care cost trend rate N/A N/A 32 (25 ) 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 Plan OPEB Plans (percent) 2018 2017 2018 2017 Discount rate for benefit expense and obligation 3.4 - 3.6 3.4 - 3.5 3.4 - 3.7 3.4 - 3.9 Rate of compensation expense N/A 3.5 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, 2018
Disclosure of cash flow statement [Abstract]
Disclosure Of Changes In Non-Cash Working Capital	Non-cash Working Capital ($ millions) 2018 2017 Decrease (increase) in non-cash working capital Accounts receivable 127 (329 ) Inventories 393 (264 ) Prepaid expenses 30 (38 ) Accounts payable and accrued liabilities (65 ) 1,269 Change in non-cash working capital 485 638 Relating to: Operating activities 130 398 Financing activities 120 — Investing activities 235 240

Financial Instruments and Ris_2

Financial Instruments and Risk Management (Tables)	12 Months Ended
	Dec. 31, 2018
Disclosure of financial instruments by type of interest rate [line items]
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, 2018 December 31, 2017 Commodity contracts – fair value through profit or loss (“FVTPL”) Natural gas (1) (9 ) (13 ) Crude oil (2) 89 (57 ) Foreign currency contracts – FVTPL Foreign currency forwards (1 ) 1 Other assets – FVTPL 1 1 Derivatives designated as a cash flow hedge - forward starting swaps (14 ) — Hedge of net investment (3)(4) (846 ) (584 ) End of year (780 ) (652 ) (1) Natural gas contracts includes a $10 million decrease at December 31, 2018 ( December 31, 2017 – $3 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 $15 million at December 31, 2018 ( December 31, 2017 – $5 million ). (2) Crude oil contracts includes a $67 million increase at December 31, 2018 ( December 31, 2017 – $5 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 $185 million at December 31, 2018 ( December 31, 2017 – $232 million ). (3) Hedging instruments are presented net of tax. (4) Represents the translation of the Company’s U.S. dollar denominated long-term debt designated as a hedge of the Company’s net investment in selected foreign operations with a U.S. dollar functional currency.
Disclosure of offsetting of financial assets and financial liabilities [text block]	The tables below outline the financial assets and financial liabilities that are subject to set-off rights and related arrangements, and the effect of those rights and arrangements on the consolidated balance sheets: As at December 31, 2018 Offsetting Financial Assets and Liabilities ($ 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 ) As at December 31, 2017 Offsetting Financial Assets and Liabilities ($ millions) Gross Amount Amount Offset Net Amount Financial Assets Financial derivatives 150 (111 ) 40 Normal purchase and sale agreements 639 (280 ) 359 End of year 789 (391 ) 399 Financial Liabilities Financial derivatives (246 ) 122 (123 ) Normal purchase and sale agreements (933 ) 353 (581 ) End of year (1,179 ) 475 (704 )
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 26 (26 ) Natural gas price (9 ) 9 Foreign Exchange Rate (2) Canadian dollar Canadian dollar ($ millions) U.S. dollar per Canadian dollar 1 (1 ) Interest Rate (3) 100 basis point increase 100 basis point decrease ($ millions) LIBOR 61 (61 ) (1) Based on average crude oil and natural gas market prices as at December 31, 2018 . (2) Based on the U.S./Canadian dollar exchange rate as at December 31, 2018 . (3) Based on the U.S. LIBOR as at December 31, 2018 .
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, 2018 : Accounts Receivable Aging ($ millions) December 31, 2018 Current 1,140 Past due (1 – 30 days) 139 Past due (31 – 60 days) 42 Past due (61 – 90 days) 16 Past due (more than 90 days) 57 Provision for expected credit losses (39 ) 1,355
Disclosure of available credit facilities	Bank Operating Loans At December 31, 2018 , the Company had unsecured short-term borrowing lines of credit with banks totalling $900 million (1) ( December 31, 2017 – $850 million ) and letters of credit under these lines of credit totalling $439 million ( December 31, 2017 – $422 million ). As at December 31, 2018 , bank operating loans were nil ( December 31, 2017 – 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, 2017 – $10 million ) available for general purposes. The Company’s proportionate share of the liability for any drawings under this credit facility is $5 million ( December 31, 2017 – $5 million ). As at December 31, 2018 , there was no balance outstanding under this credit facility ( December 31, 2017 – no balance). (1) Includes $125 million demand facilities available specifically for letters of credit only. The Company had the following available credit facilities as at December 31, 2018 : Credit Facilities ($ millions) Available Unused Operating facilities (1) (note 13) 900 461 Syndicated bank facilities (2) (note 15) 4,000 3,800 End of year 4,900 4,261 (1) Consists of demand credit facilities. (2) Commercial paper outstanding is supported by the Company’s Syndicated credit facilities.
Interest rate swap contract [member]
Disclosure of financial instruments by type of interest rate [line items]
Disclosure of fair value of financial instruments [text block]	The forward starting swaps have the following terms and fair value as at December 31, 2018. As at December 31, 2018 Forward Starting Swaps Swap Rate (1) Notional Amount (U.S. $ millions) Fair Value ($ million) ($ millions) Swap Maturity December 15, 2029 2.999 % 250 (7 ) December 15, 2029 3.000 % 250 (7 ) (1) Weighted average rate.

Related Party Transactions (Tab

Related Party Transactions (Tables)	12 Months Ended
	Dec. 31, 2018
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, 2018. All of the entities listed below, except as otherwise indicated, are 100 percent 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 100 Alberta Husky Downstream General Partnership 100 Alberta Husky Energy Marketing Partnership 100 Alberta Sunrise Oil Sands Partnership 50 Alberta BP-Husky Refining LLC 50 Delaware
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) 2018 2017 Short-term employee benefits (1) 17 16 Stock-based compensation (2) 33 31 50 47 (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, 2018
Commitments and Contingencies [Abstract]
Minimum Future Payments For Commitments	At December 31, 2018 , 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 leases (1) 233 504 1,186 1,923 Firm transportation agreements (1) 497 2,066 4,013 6,576 Unconditional purchase obligations (2) 1,620 3,656 4,822 10,098 Lease rentals and exploration work agreements 49 246 930 1,225 Obligations to fund equity investee (3) 53 293 395 741 2,452 6,765 11,346 20,563 (1) Included in operating leases and firm transportation agreements are blending and storage agreements and transportation commitments of $1.1 billion and $1.9 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.

Description of Business and S_3

Description of Business and Segmented Disclosures - Income Statement (Details) - CAD ($) $ in Millions	12 Months Ended
	Dec. 31, 2018	Dec. 31, 2017
Disclosure of operating segments [line items]
Gross revenues	$ 21,919	$ 18,986
Royalties	(335)	(363)
Marketing and other	668	(40)
Revenues, net of royalties	22,252	18,583
Purchases of crude oil and products	14,555	11,566
Production, operating and transportation expenses (note 20)	2,803	2,679
Selling, general and administrative expenses (note 20)	654	650
Depletion, depreciation, amortization and impairment (note 9)	2,591	2,882
Expense arising from exploration for and evaluation of mineral resources	149	146
Loss (gain) on sale of assets	4	46
Other – net (note 9)	(591)	(18)
Expenses	20,157	17,859
Earnings from operating activities	2,095	724
Share of equity investment gain (note 11)	69	61
Net foreign exchange gains (losses)	14	(6)
Finance income	64	37
Finance expenses	(314)	(392)
Financial Items	(236)	(361)
Earnings before income taxes	1,928	424
Current tax expense (income) and adjustments for current tax of prior periods	75	(3)
Deferred tax expense (income)	396	(359)
Tax expense (income)	471	(362)
Net earnings	1,457	786
Intersegment revenues	1,554	1,550
Exploration and Production(1)
Disclosure of operating segments [line items]
Gross revenues	4,330	4,978
Infrastructure and Marketing(2)
Disclosure of operating segments [line items]
Gross revenues	2,211	1,976
Upgrading
Disclosure of operating segments [line items]
Gross revenues	1,750	1,440
Canadian Refined Products
Disclosure of operating segments [line items]
Gross revenues	3,412	2,787
U.S. Refining and Marketing
Disclosure of operating segments [line items]
Gross revenues	11,770	9,355
Upstream
Disclosure of operating segments [line items]
Gross revenues	6,541	6,954
Royalties	(335)	(363)
Marketing and other	668	(40)
Revenues, net of royalties	6,874	6,551
Purchases of crude oil and products	2,087	1,855
Production, operating and transportation expenses (note 20)	1,550	1,663
Selling, general and administrative expenses (note 20)	301	269
Depletion, depreciation, amortization and impairment (note 9)	1,811	2,239
Expense arising from exploration for and evaluation of mineral resources	149	146
Loss (gain) on sale of assets	2	41
Other – net (note 9)	(118)	(2)
Expenses	5,778	6,129
Earnings from operating activities	1,096	422
Share of equity investment gain (note 11)	69	61
Net foreign exchange gains (losses)	0	0
Finance income	12	5
Finance expenses	(109)	(131)
Financial Items	(97)	(126)
Earnings before income taxes	1,068	357
Current tax expense (income) and adjustments for current tax of prior periods	(130)	(34)
Deferred tax expense (income)	408	131
Tax expense (income)	278	97
Net earnings	790	260
Intersegment revenues	1,155	1,250
Upstream | Exploration and Production(1)
Disclosure of operating segments [line items]
Gross revenues	4,330	4,978
Royalties	(335)	(363)
Marketing and other	0	0
Revenues, net of royalties	3,995	4,615
Purchases of crude oil and products	0	0
Production, operating and transportation expenses (note 20)	1,527	1,650
Selling, general and administrative expenses (note 20)	296	265
Depletion, depreciation, amortization and impairment (note 9)	1,811	2,237
Expense arising from exploration for and evaluation of mineral resources	149	146
Loss (gain) on sale of assets	2	42
Other – net (note 9)	(120)	6
Expenses	3,661	4,262
Earnings from operating activities	334	353
Share of equity investment gain (note 11)	51	12
Net foreign exchange gains (losses)	0	0
Finance income	12	5
Finance expenses	(109)	(131)
Financial Items	(97)	(126)
Earnings before income taxes	288	239
Current tax expense (income) and adjustments for current tax of prior periods	(484)	(34)
Deferred tax expense (income)	549	99
Tax expense (income)	65	65
Net earnings	223	174
Intersegment revenues	1,155	1,250
Upstream | Infrastructure and Marketing(2)
Disclosure of operating segments [line items]
Gross revenues	2,211	1,976
Royalties	0	0
Marketing and other	668	(40)
Revenues, net of royalties	2,879	1,936
Purchases of crude oil and products	2,087	1,855
Production, operating and transportation expenses (note 20)	23	13
Selling, general and administrative expenses (note 20)	5	4
Depletion, depreciation, amortization and impairment (note 9)	0	2
Expense arising from exploration for and evaluation of mineral resources	0	0
Loss (gain) on sale of assets	0	(1)
Other – net (note 9)	2	(8)
Expenses	2,117	1,867
Earnings from operating activities	762	69
Share of equity investment gain (note 11)	18	49
Net foreign exchange gains (losses)	0	0
Finance income	0	0
Finance expenses	0	0
Financial Items	0	0
Earnings before income taxes	780	118
Current tax expense (income) and adjustments for current tax of prior periods	354	0
Deferred tax expense (income)	(141)	32
Tax expense (income)	213	32
Net earnings	567	86
Intersegment revenues	0	0
Revenue from construction contracts	172	280
Costs of construction contracts	142	234
Revenue from construction contracts, percentage of completion method	172	259
Costs of construction contracts, percentage of completion method	142	236
Downstream | Reportable segments
Disclosure of operating segments [line items]
Gross revenues	16,932	13,582
Royalties	0	0
Marketing and other	0	0
Revenues, net of royalties	16,932	13,582
Purchases of crude oil and products	14,022	11,261
Production, operating and transportation expenses (note 20)	1,255	1,016
Selling, general and administrative expenses (note 20)	76	77
Depletion, depreciation, amortization and impairment (note 9)	688	564
Expense arising from exploration for and evaluation of mineral resources	0	0
Loss (gain) on sale of assets	2	5
Other – net (note 9)	(465)	(22)
Expenses	15,574	12,891
Earnings from operating activities	1,358	691
Share of equity investment gain (note 11)	0	0
Net foreign exchange gains (losses)	0	0
Finance income	0	0
Finance expenses	(27)	(27)
Financial Items	(27)	(27)
Earnings before income taxes	1,331	664
Current tax expense (income) and adjustments for current tax of prior periods	277	110
Deferred tax expense (income)	54	106
Tax expense (income)	331	216
Net earnings	1,000	448
Intersegment revenues	399	300
Downstream | Upgrading
Disclosure of operating segments [line items]
Gross revenues	1,750	1,440
Royalties	0	0
Marketing and other	0	0
Revenues, net of royalties	1,750	1,440
Purchases of crude oil and products	928	983
Production, operating and transportation expenses (note 20)	195	197
Selling, general and administrative expenses (note 20)	7	9
Depletion, depreciation, amortization and impairment (note 9)	123	99
Expense arising from exploration for and evaluation of mineral resources	0	0
Loss (gain) on sale of assets	0	0
Other – net (note 9)	0	0
Expenses	1,253	1,288
Earnings from operating activities	497	152
Share of equity investment gain (note 11)	0	0
Net foreign exchange gains (losses)	0	0
Finance income	0	0
Finance expenses	(1)	(1)
Financial Items	(1)	(1)
Earnings before income taxes	496	151
Current tax expense (income) and adjustments for current tax of prior periods	168	63
Deferred tax expense (income)	(33)	(22)
Tax expense (income)	135	41
Net earnings	361	110
Intersegment revenues	290	192
Downstream | Canadian Refined Products
Disclosure of operating segments [line items]
Gross revenues	3,412	2,787
Royalties	0	0
Marketing and other	0	0
Revenues, net of royalties	3,412	2,787
Purchases of crude oil and products	2,760	2,219
Production, operating and transportation expenses (note 20)	265	256
Selling, general and administrative expenses (note 20)	47	53
Depletion, depreciation, amortization and impairment (note 9)	115	111
Expense arising from exploration for and evaluation of mineral resources	0	0
Loss (gain) on sale of assets	2	5
Other – net (note 9)	(1)	(1)
Expenses	3,184	2,633
Earnings from operating activities	228	154
Share of equity investment gain (note 11)	0	0
Net foreign exchange gains (losses)	0	0
Finance income	0	0
Finance expenses	(12)	(12)
Financial Items	(12)	(12)
Earnings before income taxes	216	142
Current tax expense (income) and adjustments for current tax of prior periods	100	45
Deferred tax expense (income)	(42)	(7)
Tax expense (income)	58	38
Net earnings	158	104
Intersegment revenues	109	108
Downstream | U.S. Refining and Marketing
Disclosure of operating segments [line items]
Gross revenues	11,770	9,355
Royalties	0	0
Marketing and other	0	0
Revenues, net of royalties	11,770	9,355
Purchases of crude oil and products	10,334	8,059
Production, operating and transportation expenses (note 20)	795	563
Selling, general and administrative expenses (note 20)	22	15
Depletion, depreciation, amortization and impairment (note 9)	450	354
Expense arising from exploration for and evaluation of mineral resources	0	0
Loss (gain) on sale of assets	0	0
Other – net (note 9)	(464)	(21)
Expenses	11,137	8,970
Earnings from operating activities	633	385
Share of equity investment gain (note 11)	0	0
Net foreign exchange gains (losses)	0	0
Finance income	0	0
Finance expenses	(14)	(14)
Financial Items	(14)	(14)
Earnings before income taxes	619	371
Current tax expense (income) and adjustments for current tax of prior periods	9	2
Deferred tax expense (income)	129	135
Tax expense (income)	138	137
Net earnings	481	234
Intersegment revenues	0	0
Corporate and Eliminations(3)
Disclosure of operating segments [line items]
Gross revenues	(1,554)	(1,550)
Royalties	0	0
Marketing and other	0	0
Revenues, net of royalties	(1,554)	(1,550)
Purchases of crude oil and products	(1,554)	(1,550)
Production, operating and transportation expenses (note 20)	(2)	0
Selling, general and administrative expenses (note 20)	277	304
Depletion, depreciation, amortization and impairment (note 9)	92	79
Expense arising from exploration for and evaluation of mineral resources	0	0
Loss (gain) on sale of assets	0	0
Other – net (note 9)	(8)	6
Expenses	(1,195)	(1,161)
Earnings from operating activities	(359)	(389)
Share of equity investment gain (note 11)	0	0
Net foreign exchange gains (losses)	14	(6)
Finance income	52	32
Finance expenses	(178)	(234)
Financial Items	(112)	(208)
Earnings before income taxes	(471)	(597)
Current tax expense (income) and adjustments for current tax of prior periods	(72)	(79)
Deferred tax expense (income)	(66)	(596)
Tax expense (income)	(138)	(675)
Net earnings	(333)	78
Intersegment revenues	$ 0	$ 0

Description of Business and S_4

Description of Business and Segmented Disclosures - Segmented Financial Information (Details) - CAD ($) $ in Millions	12 Months Ended
	Dec. 31, 2018	Dec. 31, 2017
Disclosure of disaggregation of revenue from contracts with customers [line items]
Expense arising from exploration for and evaluation of mineral resources	$ 242	$ 148
Expenditures on property, plant and equipment(2)	3,336	2,072
Exploration and evaluation assets (note 8)	997	838
Total exploration and evaluation assets and property, plant and equipment, net	26,797	24,916
Total Assets	35,225	32,927
Upstream
Disclosure of disaggregation of revenue from contracts with customers [line items]
Expense arising from exploration for and evaluation of mineral resources	242	148
Expenditures on property, plant and equipment(2)	2,414	1,328
Exploration and evaluation assets (note 8)	997	838
Total exploration and evaluation assets and property, plant and equipment, net	17,865	16,667
Total Assets	20,476	19,284
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)	801	630
Exploration and evaluation assets (note 8)	0	0
Total exploration and evaluation assets and property, plant and equipment, net	8,618	7,970
Total Assets	11,146	10,391
Corporate and Eliminations
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)	121	114
Exploration and evaluation assets (note 8)	0	0
Total exploration and evaluation assets and property, plant and equipment, net	314	279
Total Assets	3,603	3,252
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	242	148
Expenditures on property, plant and equipment(2)	2,414	1,328
Exploration and evaluation assets (note 8)	997	838
Total exploration and evaluation assets and property, plant and equipment, net	17,814	16,628
Total Assets	19,175	17,920
Infrastructure and Marketing(2) | Upstream
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)	0	0
Exploration and evaluation assets (note 8)	0	0
Total exploration and evaluation assets and property, plant and equipment, net	51	39
Total Assets	1,301	1,364
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)	62	230
Exploration and evaluation assets (note 8)	0	0
Total exploration and evaluation assets and property, plant and equipment, net	1,074	1,137
Total Assets	1,149	1,263
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)	74	87
Exploration and evaluation assets (note 8)	0	0
Total exploration and evaluation assets and property, plant and equipment, net	1,208	1,238
Total Assets	1,431	1,548
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)	665	313
Exploration and evaluation assets (note 8)	0	0
Total exploration and evaluation assets and property, plant and equipment, net	6,336	5,595
Total Assets	8,566	7,580
Cost
Disclosure of disaggregation of revenue from contracts with customers [line items]
Developing and producing assets	44,196	41,804
Other property, plant and equipment	16,546	14,817
Cost | Upstream
Disclosure of disaggregation of revenue from contracts with customers [line items]
Developing and producing assets	44,196	41,804
Other property, plant and equipment	101	89
Cost | Downstream
Disclosure of disaggregation of revenue from contracts with customers [line items]
Developing and producing assets	0	0
Other property, plant and equipment	15,194	13,604
Cost | Corporate and Eliminations
Disclosure of disaggregation of revenue from contracts with customers [line items]
Developing and producing assets	0	0
Other property, plant and equipment	1,251	1,124
Cost | Exploration and Production(1) | Upstream
Disclosure of disaggregation of revenue from contracts with customers [line items]
Developing and producing assets	44,196	41,804
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	89
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	2,659	2,600
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	2,789	2,704
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	9,746	8,300
Accumulated depletion, depreciation, amortization and impairment
Disclosure of disaggregation of revenue from contracts with customers [line items]
Developing and producing assets	(27,379)	(26,014)
Other property, plant and equipment	(7,563)	(6,529)
Accumulated depletion, depreciation, amortization and impairment | Upstream
Disclosure of disaggregation of revenue from contracts with customers [line items]
Developing and producing assets	(27,379)	(26,014)
Other property, plant and equipment	(50)	(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	(6,576)	(5,634)
Accumulated depletion, depreciation, amortization and impairment | Corporate and Eliminations
Disclosure of disaggregation of revenue from contracts with customers [line items]
Developing and producing assets	0	0
Other property, plant and equipment	(937)	(845)
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	(27,379)	(26,014)
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	(50)	(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	(1,585)	(1,463)
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	(1,581)	(1,466)
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	$ (3,410)	$ (2,705)

Description of Business and S_5

Description of Business and Segmented Disclosures - Geographical (Details) - CAD ($) $ in Millions	12 Months Ended
	Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016
Disclosure of disaggregation of revenue from contracts with customers [line items]
Gross revenues	$ 21,919	$ 18,986
Royalties	(335)	(363)
Marketing and other	668	(40)
Revenues, net of royalties	22,252	18,583
Restricted cash – non-current	128	97
Exploration and evaluation assets (note 8)	997	838
Property, plant and equipment, net	25,800	24,078
Goodwill (note 10)	690	633	$ 679
Investment in joint ventures (note 11)	1,319	1,238
Long-term income taxes receivable	243	242
Other assets (note 12)	360	185
Non-current assets	29,537	27,311
Canada
Disclosure of disaggregation of revenue from contracts with customers [line items]
Gross revenues	9,000	8,599
Royalties	(269)	(303)
Marketing and other	668	(40)
Revenues, net of royalties	9,399	8,256
Restricted cash – non-current	0	0
Exploration and evaluation assets (note 8)	935	831
Property, plant and equipment, net	16,433	15,478
Goodwill (note 10)	0	0
Investment in joint ventures (note 11)	669	685
Long-term income taxes receivable	243	242
Other assets (note 12)	58	64
Non-current assets	18,338	17,300
United States
Disclosure of disaggregation of revenue from contracts with customers [line items]
Gross revenues	11,770	9,355
Royalties	0	0
Marketing and other	0	0
Revenues, net of royalties	11,770	9,355
Restricted cash – non-current	0	0
Exploration and evaluation assets (note 8)	0	0
Property, plant and equipment, net	6,336	5,595
Goodwill (note 10)	690	633
Investment in joint ventures (note 11)	0	0
Long-term income taxes receivable	0	0
Other assets (note 12)	276	21
Non-current assets	7,302	6,249
China
Disclosure of disaggregation of revenue from contracts with customers [line items]
Gross revenues	1,149	1,032
Royalties	(66)	(60)
Marketing and other	0	0
Revenues, net of royalties	1,083	972
Restricted cash – non-current	128	97
Exploration and evaluation assets (note 8)	57	3
Property, plant and equipment, net	3,030	3,005
Goodwill (note 10)	0	0
Investment in joint ventures (note 11)	0	0
Long-term income taxes receivable	0	0
Other assets (note 12)	0	78
Non-current assets	3,215	3,183
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	4
Property, plant and equipment, net	1	0
Goodwill (note 10)	0	0
Investment in joint ventures (note 11)	650	553
Long-term income taxes receivable	0	0
Other assets (note 12)	26	22
Non-current assets	$ 682	$ 579

Description of Business and S_6

Description of Business and Segmented Disclosures Disaggregation of Revenue (Details) - CAD ($) $ in Millions	12 Months Ended
	Dec. 31, 2018	Dec. 31, 2017
Disclosure of disaggregation of revenue from contracts with customers [line items]
Gross revenues	$ 21,919	$ 18,986
Upgrading
Disclosure of disaggregation of revenue from contracts with customers [line items]
Gross revenues	1,750	1,440
Canadian Refined Products
Disclosure of disaggregation of revenue from contracts with customers [line items]
Gross revenues	3,412	2,787
U.S. Refining and Marketing
Disclosure of disaggregation of revenue from contracts with customers [line items]
Gross revenues	11,770	9,355
Downstream
Disclosure of disaggregation of revenue from contracts with customers [line items]
Gross revenues	16,932	13,582
Corporate and Eliminations(3)
Disclosure of disaggregation of revenue from contracts with customers [line items]
Gross revenues	(1,554)	(1,550)
Upstream
Disclosure of disaggregation of revenue from contracts with customers [line items]
Gross revenues	6,541	6,954
Exploration and Production(1)
Disclosure of disaggregation of revenue from contracts with customers [line items]
Gross revenues	4,330	4,978
Infrastructure and Marketing(2)
Disclosure of disaggregation of revenue from contracts with customers [line items]
Gross revenues	2,211	1,976
Canada
Disclosure of disaggregation of revenue from contracts with customers [line items]
Gross revenues	9,000	8,599
Canada | Upgrading
Disclosure of disaggregation of revenue from contracts with customers [line items]
Gross revenues	1,750	1,440
Canada | Canadian Refined Products
Disclosure of disaggregation of revenue from contracts with customers [line items]
Gross revenues	3,412	2,787
Canada | Downstream
Disclosure of disaggregation of revenue from contracts with customers [line items]
Gross revenues	5,162	4,227
Canada | Corporate and Eliminations(3)
Disclosure of disaggregation of revenue from contracts with customers [line items]
Gross revenues	(1,554)	(1,550)
Canada | Upstream
Disclosure of disaggregation of revenue from contracts with customers [line items]
Gross revenues	5,392	5,922
Canada | Exploration and Production(1)
Disclosure of disaggregation of revenue from contracts with customers [line items]
Gross revenues	3,181	3,946
Canada | Infrastructure and Marketing(2)
Disclosure of disaggregation of revenue from contracts with customers [line items]
Gross revenues	2,211	1,976
United States
Disclosure of disaggregation of revenue from contracts with customers [line items]
Gross revenues	11,770	9,355
United States | U.S. Refining and Marketing
Disclosure of disaggregation of revenue from contracts with customers [line items]
Gross revenues	11,770	9,355
United States | Downstream
Disclosure of disaggregation of revenue from contracts with customers [line items]
Gross revenues	11,770	9,355
China
Disclosure of disaggregation of revenue from contracts with customers [line items]
Gross revenues	1,149	1,032
China | Upstream
Disclosure of disaggregation of revenue from contracts with customers [line items]
Gross revenues	1,149	1,032
China | Exploration and Production(1)
Disclosure of disaggregation of revenue from contracts with customers [line items]
Gross revenues	1,149	1,032
Light and Medium Crude Oil [Member]
Disclosure of disaggregation of revenue from contracts with customers [line items]
Gross revenues	948	1,273
Light and Medium Crude Oil [Member] | Upstream
Disclosure of disaggregation of revenue from contracts with customers [line items]
Gross revenues	948	1,273
Light and Medium Crude Oil [Member] | Exploration and Production(1)
Disclosure of disaggregation of revenue from contracts with customers [line items]
Gross revenues	948	1,273
Heavy Crude Oil [Member]
Disclosure of disaggregation of revenue from contracts with customers [line items]
Gross revenues	527	703
Heavy Crude Oil [Member] | Upstream
Disclosure of disaggregation of revenue from contracts with customers [line items]
Gross revenues	527	703
Heavy Crude Oil [Member] | Exploration and Production(1)
Disclosure of disaggregation of revenue from contracts with customers [line items]
Gross revenues	527	703
Bitumen [Member]
Disclosure of disaggregation of revenue from contracts with customers [line items]
Gross revenues	1,367	1,662
Bitumen [Member] | Upstream
Disclosure of disaggregation of revenue from contracts with customers [line items]
Gross revenues	1,367	1,662
Bitumen [Member] | Exploration and Production(1)
Disclosure of disaggregation of revenue from contracts with customers [line items]
Gross revenues	1,367	1,662
Crude Oil [Member]
Disclosure of disaggregation of revenue from contracts with customers [line items]
Gross revenues	2,842	3,638
Crude Oil [Member] | Upstream
Disclosure of disaggregation of revenue from contracts with customers [line items]
Gross revenues	2,842	3,638
Crude Oil [Member] | Exploration and Production(1)
Disclosure of disaggregation of revenue from contracts with customers [line items]
Gross revenues	2,842	3,638
Natural Gas Liquids [Member]
Disclosure of disaggregation of revenue from contracts with customers [line items]
Gross revenues	381	276
Natural Gas Liquids [Member] | Upstream
Disclosure of disaggregation of revenue from contracts with customers [line items]
Gross revenues	381	276
Natural Gas Liquids [Member] | Exploration and Production(1)
Disclosure of disaggregation of revenue from contracts with customers [line items]
Gross revenues	381	276
Natural Gas [Member]
Disclosure of disaggregation of revenue from contracts with customers [line items]
Gross revenues	1,107	1,064
Natural Gas [Member] | Upstream
Disclosure of disaggregation of revenue from contracts with customers [line items]
Gross revenues	1,107	1,064
Natural Gas [Member] | Exploration and Production(1)
Disclosure of disaggregation of revenue from contracts with customers [line items]
Gross revenues	1,107	1,064
Synthetic Oil [Member]
Disclosure of disaggregation of revenue from contracts with customers [line items]
Gross revenues	1,445	1,235
Synthetic Oil [Member] | Upgrading
Disclosure of disaggregation of revenue from contracts with customers [line items]
Gross revenues	1,445	1,235
Synthetic Oil [Member] | Downstream
Disclosure of disaggregation of revenue from contracts with customers [line items]
Gross revenues	1,445	1,235
Gasoline [Member]
Disclosure of disaggregation of revenue from contracts with customers [line items]
Gross revenues	7,227	6,123
Gasoline [Member] | Canadian Refined Products
Disclosure of disaggregation of revenue from contracts with customers [line items]
Gross revenues	1,070	925
Gasoline [Member] | U.S. Refining and Marketing
Disclosure of disaggregation of revenue from contracts with customers [line items]
Gross revenues	6,157	5,198
Gasoline [Member] | Downstream
Disclosure of disaggregation of revenue from contracts with customers [line items]
Gross revenues	7,227	6,123
Diesel and distillates [Member]
Disclosure of disaggregation of revenue from contracts with customers [line items]
Gross revenues	5,878	4,548
Diesel and distillates [Member] | Upgrading
Disclosure of disaggregation of revenue from contracts with customers [line items]
Gross revenues	278	196
Diesel and distillates [Member] | Canadian Refined Products
Disclosure of disaggregation of revenue from contracts with customers [line items]
Gross revenues	1,303	917
Diesel and distillates [Member] | U.S. Refining and Marketing
Disclosure of disaggregation of revenue from contracts with customers [line items]
Gross revenues	4,297	3,435
Diesel and distillates [Member] | Downstream
Disclosure of disaggregation of revenue from contracts with customers [line items]
Gross revenues	5,878	4,548
Asphalt [Member]
Disclosure of disaggregation of revenue from contracts with customers [line items]
Gross revenues	619	393
Asphalt [Member] | Canadian Refined Products
Disclosure of disaggregation of revenue from contracts with customers [line items]
Gross revenues	454	362
Asphalt [Member] | U.S. Refining and Marketing
Disclosure of disaggregation of revenue from contracts with customers [line items]
Gross revenues	165	31
Asphalt [Member] | Downstream
Disclosure of disaggregation of revenue from contracts with customers [line items]
Gross revenues	619	393
Other Refined Products [Member]
Disclosure of disaggregation of revenue from contracts with customers [line items]
Gross revenues	1,763	1,283
Other Refined Products [Member] | Upgrading
Disclosure of disaggregation of revenue from contracts with customers [line items]
Gross revenues	27	9
Other Refined Products [Member] | Canadian Refined Products
Disclosure of disaggregation of revenue from contracts with customers [line items]
Gross revenues	585	583
Other Refined Products [Member] | U.S. Refining and Marketing
Disclosure of disaggregation of revenue from contracts with customers [line items]
Gross revenues	1,151	691
Other Refined Products [Member] | Downstream
Disclosure of disaggregation of revenue from contracts with customers [line items]
Gross revenues	1,763	1,283
Refined Products [Member]
Disclosure of disaggregation of revenue from contracts with customers [line items]
Gross revenues	16,932	13,582
Refined Products [Member] | Upgrading
Disclosure of disaggregation of revenue from contracts with customers [line items]
Gross revenues	1,750	1,440
Refined Products [Member] | Canadian Refined Products
Disclosure of disaggregation of revenue from contracts with customers [line items]
Gross revenues	3,412	2,787
Refined Products [Member] | U.S. Refining and Marketing
Disclosure of disaggregation of revenue from contracts with customers [line items]
Gross revenues	11,770	9,355
Refined Products [Member] | Downstream
Disclosure of disaggregation of revenue from contracts with customers [line items]
Gross revenues	$ 16,932	$ 13,582

Cash and Cash Equivalents (Deta

Cash and Cash Equivalents (Details) - CAD ($) $ in Millions	Dec. 31, 2018	Dec. 31, 2017
Subclassifications of assets, liabilities and equities [abstract]
Cash	$ 187	$ 280
Short-term investments, classified as cash equivalents	$ 2,679	$ 2,233

Accounts Receivable (Details)

Accounts Receivable (Details) - CAD ($) $ in Millions	Dec. 31, 2018	Dec. 31, 2017
Document Information [Line Items]
Trade receivables	$ 1,146	$ 1,170
Provision for expected credit losses	(39)	(34)
Derivatives due within one year	43	17
Other1	205	33
Accounts receivable	1,355	1,186
Within 1 year
Document Information [Line Items]
Receivables and payables related to insurance contracts	$ 143	$ 0

Inventories (Details)

Inventories (Details) - CAD ($) $ in Millions	12 Months Ended
	Dec. 31, 2018	Dec. 31, 2017
Subclassifications of assets, liabilities and equities [abstract]
Crude oil, natural gas and NGL	$ 445	$ 539
Refined petroleum products	435	548
Trading inventories measured at fair value less costs to sell	200	237
Materials, supplies and other	152	189
Inventories	1,232	1,513
Inventory write-down to net realizable value (note 6)	$ 60	$ 0

Restricted Cash Restricted Cash

Restricted Cash Restricted Cash (Details) - CAD ($) $ in Millions	Dec. 31, 2018	Dec. 31, 2017
Peoples Republic of China
Disclosure of geographical areas [line items]
Restricted cash and cash equivalents	$ 128	$ 192

Exploration and Evaluation Co_3

Exploration and Evaluation Costs - Exploration and Evaluation Assets (Details) - CAD ($) $ in Millions	12 Months Ended
	Dec. 31, 2018	Dec. 31, 2017
Disclosure of detailed information about property, plant and equipment [line items]
Property, plant and equipment, beginning balance	$ 24,078
Expensed exploration expenditures previously capitalized	29	$ 6
Property, plant and equipment, ending balance	25,800	24,078
Tangible exploration and evaluation assets
Disclosure of detailed information about property, plant and equipment [line items]
Property, plant and equipment, beginning balance	838	1,066
Additions1	287	224
Disposals	(23)	0
Transfers to oil and gas properties (note 9)	(79)	(377)
Expensed exploration expenditures previously capitalized	(29)	(6)
Exchange adjustments	3	(69)
Property, plant and equipment, ending balance	$ 997	$ 838

Exploration and Evaluation Co_4

Exploration and Evaluation Costs - Exploration and Evaluation Expense Summary (Details) - CAD ($) $ in Millions	12 Months Ended
	Dec. 31, 2018	Dec. 31, 2017
Subclassifications of assets, liabilities and equities [abstract]
Seismic, geological and geophysical	$ 102	$ 113
Expensed drilling	41	22
Expensed land	6	11
Exploration and evaluation expenses	$ 149	$ 146

Property, Plant and Equipment -

Property, Plant and Equipment - Property, Plant and Equipment (Details) - CAD ($) $ in Millions	12 Months Ended
	Dec. 31, 2018	Dec. 31, 2017
Reconciliation of changes in property, plant and equipment [abstract]
Property, plant and equipment, beginning balance	$ 24,078
Property, plant and equipment, ending balance	25,800	$ 24,078
Oil and Gas Properties
Reconciliation of changes in property, plant and equipment [abstract]
Property, plant and equipment, beginning balance	15,799
Property, plant and equipment, ending balance	16,817	15,799
Processing, Transportation and Storage
Reconciliation of changes in property, plant and equipment [abstract]
Property, plant and equipment, beginning balance	39
Property, plant and equipment, ending balance	51	39
Upgrading
Reconciliation of changes in property, plant and equipment [abstract]
Property, plant and equipment, beginning balance	1,137
Property, plant and equipment, ending balance	1,074	1,137
Refining
Reconciliation of changes in property, plant and equipment [abstract]
Property, plant and equipment, beginning balance	6,015
Property, plant and equipment, ending balance	6,758	6,015
Retail and Other
Reconciliation of changes in property, plant and equipment [abstract]
Property, plant and equipment, beginning balance	1,088
Property, plant and equipment, ending balance	1,100	1,088
Cost
Reconciliation of changes in property, plant and equipment [abstract]
Property, plant and equipment, beginning balance	56,621	58,705
Additions1	3,434	2,313
Acquisitions	67	606
Transfers from exploration and evaluation (note 8)	79	377
Intersegment transfers	0	0
Changes in asset retirement obligations (note 16)	45	188
Disposals and derecognition	(643)	(4,741)
Exchange adjustments	1,139	(827)
Property, plant and equipment, ending balance	60,742	56,621
Cost | Oil and Gas Properties
Reconciliation of changes in property, plant and equipment [abstract]
Property, plant and equipment, beginning balance	41,815	44,801
Additions1	2,465	1,371
Acquisitions	64	29
Transfers from exploration and evaluation (note 8)	79	377
Intersegment transfers	0	48
Changes in asset retirement obligations (note 16)	43	150
Disposals and derecognition	(632)	(4,702)
Exchange adjustments	362	(259)
Property, plant and equipment, ending balance	44,196	41,815
Cost | Processing, Transportation and Storage
Reconciliation of changes in property, plant and equipment [abstract]
Property, plant and equipment, beginning balance	86	137
Additions1	12	11
Acquisitions	0	0
Transfers from exploration and evaluation (note 8)	0	0
Intersegment transfers	0	(61)
Changes in asset retirement obligations (note 16)	2	0
Disposals and derecognition	0	0
Exchange adjustments	1	(1)
Property, plant and equipment, ending balance	101	86
Cost | Upgrading
Reconciliation of changes in property, plant and equipment [abstract]
Property, plant and equipment, beginning balance	2,599	2,367
Additions1	62	230
Acquisitions	0	0
Transfers from exploration and evaluation (note 8)	0	0
Intersegment transfers	0	0
Changes in asset retirement obligations (note 16)	(2)	2
Disposals and derecognition	0	0
Exchange adjustments	0	0
Property, plant and equipment, ending balance	2,659	2,599
Cost | Refining
Reconciliation of changes in property, plant and equipment [abstract]
Property, plant and equipment, beginning balance	9,191	8,645
Additions1	744	561
Acquisitions	3	577
Transfers from exploration and evaluation (note 8)	0	0
Intersegment transfers	(5)	0
Changes in asset retirement obligations (note 16)	(5)	13
Disposals and derecognition	(10)	(39)
Exchange adjustments	773	(566)
Property, plant and equipment, ending balance	10,691	9,191
Cost | Retail and Other
Reconciliation of changes in property, plant and equipment [abstract]
Property, plant and equipment, beginning balance	2,930	2,755
Additions1	151	140
Acquisitions	0	0
Transfers from exploration and evaluation (note 8)	0	0
Intersegment transfers	5	13
Changes in asset retirement obligations (note 16)	7	23
Disposals and derecognition	(1)	0
Exchange adjustments	3	(1)
Property, plant and equipment, ending balance	3,095	2,930
Accumulated depletion, depreciation, amortization and impairment
Reconciliation of changes in property, plant and equipment [abstract]
Property, plant and equipment, beginning balance	(32,543)	(34,112)
Intersegment transfers		0
Disposals and derecognition	596	4,140
Exchange adjustments	(404)	311
Depletion, depreciation, amortization and impairment	(2,591)	(2,882)
Property, plant and equipment, ending balance	(34,942)	(32,543)
Accumulated depletion, depreciation, amortization and impairment | Oil and Gas Properties
Reconciliation of changes in property, plant and equipment [abstract]
Property, plant and equipment, beginning balance	(26,016)	(27,986)
Intersegment transfers		(37)
Disposals and derecognition	586	4,124
Exchange adjustments	(138)	121
Depletion, depreciation, amortization and impairment	(1,811)	(2,238)
Property, plant and equipment, ending balance	(27,379)	(26,016)
Accumulated depletion, depreciation, amortization and impairment | Processing, Transportation and Storage
Reconciliation of changes in property, plant and equipment [abstract]
Property, plant and equipment, beginning balance	(47)	(96)
Intersegment transfers		50
Disposals and derecognition	0	0
Exchange adjustments	(1)	1
Depletion, depreciation, amortization and impairment	(2)	(2)
Property, plant and equipment, ending balance	(50)	(47)
Accumulated depletion, depreciation, amortization and impairment | Upgrading
Reconciliation of changes in property, plant and equipment [abstract]
Property, plant and equipment, beginning balance	(1,462)	(1,363)
Intersegment transfers		0
Disposals and derecognition	0	0
Exchange adjustments	0	0
Depletion, depreciation, amortization and impairment	(123)	(99)
Property, plant and equipment, ending balance	(1,585)	(1,462)
Accumulated depletion, depreciation, amortization and impairment | Refining
Reconciliation of changes in property, plant and equipment [abstract]
Property, plant and equipment, beginning balance	(3,176)	(2,975)
Intersegment transfers		0
Disposals and derecognition	10	16
Exchange adjustments	(264)	189
Depletion, depreciation, amortization and impairment	(503)	(406)
Property, plant and equipment, ending balance	(3,933)	(3,176)
Accumulated depletion, depreciation, amortization and impairment | Retail and Other
Reconciliation of changes in property, plant and equipment [abstract]
Property, plant and equipment, beginning balance	(1,842)	(1,692)
Intersegment transfers		(13)
Disposals and derecognition	0	0
Exchange adjustments	(1)	0
Depletion, depreciation, amortization and impairment	(152)	(137)
Property, plant and equipment, ending balance	$ (1,995)	$ (1,842)

Property, Plant and Equipment_2

Property, Plant and Equipment (Details) $ in Millions, $ in Millions	12 Months Ended
	Dec. 31, 2018CAD ($)	Dec. 31, 2017CAD ($)	Nov. 08, 2017CAD ($)barrel / d	Nov. 08, 2017USD ($)barrel / d
Disclosure of detailed information about property, plant and equipment [line items]
Impairment loss (reversal of impairment loss)	$ 56	$ 173
Income from reimbursements under insurance policies	468
PPE, not subject to depletion, depreciation and amortization	5,200	2,800
Undeveloped land
Disclosure of detailed information about property, plant and equipment [line items]
Land	117	57
Superior Refinery [Member]
Disclosure of detailed information about property, plant and equipment [line items]
Crude oil, facility capacity (bbls/day) | barrel / d			50,000	50,000
Acquisition cash consideration			$ 670	$ 527
Revenue from sale of goods		163
Profit (loss)		13
Revenue of combined entity as if combination occurred at beginning of period		1,100
Profit (Loss) of acquiree if combination occurred at beginning of period		93
Revenue of combined entity as if combination occurred at beginning of period		19,900
Profit (loss) of combined entity as if combination occurred at beginning of period		$ 892
Western Canada
Disclosure of detailed information about property, plant and equipment [line items]
Proceeds on sale of assets	185
Gain on sale of assets	46
Gain on sale of assets, net of tax	$ 36

Property, Plant and Equipment_3

Property, Plant and Equipment - Assets Under Finance Lease (Details) - CAD ($) $ in Millions	Dec. 31, 2018	Dec. 31, 2017
Disclosure of detailed information about property, plant and equipment [line items]
Assets under finance lease	$ 464	$ 487
Refining
Disclosure of detailed information about property, plant and equipment [line items]
Assets under finance lease	141	152
Oil and Gas Properties
Disclosure of detailed information about property, plant and equipment [line items]
Assets under finance lease	$ 323	$ 335

Property, Plant and Equipment_4

Property, Plant and Equipment - Purchase Price Allocation (Details) (Details) - Nov. 08, 2017 - Superior Refinery [Member] $ in Millions, $ in Millions	CAD ($)	USD ($)
Disclosure of detailed information about business combination [line items]
Working Capital	$ 108	$ 85
Property, plant and equipment recognised as of acquisition date	577	454
Asset Retirement Obligation Recognized as at Acquisition Date	(9)	(7)
Employee Future Benefits Recognized as of Acquisition Date	(6)	(5)
Identifiable assets acquired (liabilities assumed)	$ 670	$ 527

Goodwill - Goodwill Rollforward

Goodwill - Goodwill Rollforward (Details) - CAD ($) $ in Millions	12 Months Ended
	Dec. 31, 2018	Dec. 31, 2017
Subclassifications of assets, liabilities and equities [abstract]
Goodwill, beginning balance	$ 633	$ 679
Exchange adjustments	57	(46)
Goodwill, ending balance	$ 690	$ 633

Goodwill (Details)

Goodwill (Details)	12 Months Ended
	Dec. 31, 2018	Dec. 31, 2017
Disclosure of reconciliation of changes in goodwill [line items]
Average expected rates of inflation	2.00%	2.00%
Goodwill
Disclosure of reconciliation of changes in goodwill [line items]
Discount rate applied to cash flow projections, term	50 years
Discount rate (as a percent)	8.00%
Discount rate applied to cash flow projections, term, period one	10 years
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) $ in Millions, $ in Millions	Feb. 02, 2015USD ($)	Dec. 31, 2018CAD ($)	Dec. 31, 2017CAD ($)	Dec. 31, 2017USD ($)	Dec. 31, 2017	Feb. 01, 2015	Mar. 31, 2008USD ($)
Contribution Payable
Paid		$ 0	$ (142)
Distribution from joint operation		$ 72	25
BP-Husky Refining LLC
Disclosure of joint operations [line items]
Proportion of ownership interest in joint operation		50.00%
Consideration transferred							$ 250
Contribution payable							$ 2,600
Contribution Payable
Paid	$ (1,000)		$ (142)	$ (110)
Distribution from joint operation	$ 1,000
Long-term income taxes receivable		$ 203
Rate Of Accretion, Percent					2.50%	6.00%

Joint Arrangements - Husky-CNOO

Joint Arrangements - Husky-CNOOC Madura Ltd. (Details) - CAD ($) $ in Millions	12 Months Ended
	Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016
Disclosure of joint ventures [line items]
Cash and cash equivalents (note 4)	$ 2,866	$ 2,513	$ 1,319
Results of Operations
Revenues	22,252	18,583
Expenses	(20,157)	(17,859)
Proportionate share of net loss	1,457	786
Equity	19,614	17,967
Balance Sheets
Current assets	5,688	5,616
Non-current assets	29,537	27,311
Current liabilities	4,994	3,507
Total Assets	35,225	32,927
Carrying amount in balance sheet	1,319	1,238
Deferred income	205	284	$ 321
Husky-CNOOC Madura Ltd.
Disclosure of joint ventures [line items]
Cash and cash equivalents (note 4)	$ 203	$ 26
Share of equity investment (percent)	40.00%	40.00%
Results of Operations
Revenues	$ 441	$ 97
Expenses	(273)	(80)
Proportionate share of net loss	$ 168	$ 17
Share of equity investment (percent)	40.00%	40.00%
Equity	$ 51	$ 12
Balance Sheets
Current assets	373	152
Non-current assets	2,072	1,993
Current liabilities	(123)	(106)
Non-current liabilities	(1,917)	(1,813)
Total Assets	$ 405	$ 226
Proportion Of Net Assets In Joint Venture	40.00%	40.00%
Carrying amount in balance sheet	$ 650	$ 553
Deferred income	$ 2	$ 0

Joint Arrangements - Husky Mids

Joint Arrangements - Husky Midstream Limited Partnership (Details) - CAD ($) $ in Millions	12 Months Ended
	Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016
Disclosure of joint ventures [line items]
Cash and cash equivalents (note 4)	$ 2,866	$ 2,513	$ 1,319
Results of Operations
Revenues	22,252	18,583
Expenses	20,157	17,859
Proportionate share of net loss	1,457	786
Equity	19,614	17,967
Balance Sheets
Current assets	5,688	5,616
Non-current assets	29,537	27,311
Current liabilities	4,994	3,507
Total Assets	35,225	32,927
Carrying amount in balance sheet	1,319	1,238
Husky Midstream Limited Partnership
Disclosure of joint ventures [line items]
Cash and cash equivalents (note 4)	16	28
Results of Operations
Revenues	296	294
Expenses	(177)	(107)
Proportionate share of net loss	$ 119	$ 187
Share of equity investment (percent)	35.00%	35.00%
Equity	$ 18	$ 49
Balance Sheets
Current assets	115	152
Non-current assets	2,849	2,617
Current liabilities	(153)	(75)
Non-current liabilities	(825)	(690)
Total Assets	$ 1,986	$ 2,004
Proportion Of Net Assets In Joint Venture	35.00%	35.00%
Carrying amount in balance sheet	$ 669	$ 685
Power Assets Holding Ltd. | Husky Midstream Limited Partnership
Results of Operations
Share of equity investment (percent)	48.75%
Cheung Kong Infrastructure Holdings Ltd. | Husky Midstream Limited Partnership
Results of Operations
Share of equity investment (percent)	16.25%

Joint Arrangements - Sunrise Oi

Joint Arrangements - Sunrise Oil Sands Partnership (Details)	12 Months Ended
	Dec. 31, 2018
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	Dec. 31, 2018	Dec. 31, 2017
Term Classification [Line Items]
Long-term receivables(1)	$ 319	$ 144
Leasehold incentives	0	2
Precious metals	23	21
Other	18	18
Other non-current assets	360	185
Later than one year
Term Classification [Line Items]
Receivables and payables related to insurance contracts	$ 253	$ 0

Bank Operating Loans (Details)

Bank Operating Loans (Details) - CAD ($)	Dec. 31, 2018	Dec. 31, 2017
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	$ 850,000,000
Letter of credit, maximum borrowing capacity	439,000,000	422,000,000
Unsecured bank loans received	0	0
Letter of credit, demand facility, maximum borrowing capacity	125,000,000
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, 2018	Dec. 31, 2017
Subclassifications of assets, liabilities and equities [abstract]
Trade payables	$ 1,121	$ 950
Accrued liabilities	1,712	1,791
Dividend payable (note 19)	126	9
Stock-based compensation	32	30
Derivatives due within one year	39	115
Other	129	138
Accounts payable and accrued liabilities	$ 3,159	$ 3,033

Debt and Credit Facilities - Sh

Debt and Credit Facilities - Short-term Debt (Details) - CAD ($)	Dec. 31, 2018	Dec. 31, 2017
Disclosure of borrowing costs [Abstract]
Commercial paper	$ 200,000,000	$ 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	2.20%	1.40%

Debt and Credit Facilities - Lo

Debt and Credit Facilities - Long-term Debt (Details) $ in Millions, $ in Millions	Sep. 15, 2017CAD ($)	Dec. 31, 2018CAD ($)	Dec. 31, 2017CAD ($)	Dec. 31, 2018USD ($)	Dec. 31, 2017USD ($)
Disclosure of detailed information about borrowings [line items]
Long-term debt		$ 4,114	$ 5,240	$ 1,637	$ 2,687
Long-term debt due within one year		1,433	0	$ 1,050
Long-term debt repayment		$ 0	365
6.15% Notes Due 2019
Disclosure of detailed information about borrowings [line items]
Interest rate		6.15%		6.15%
7.25% Notes Due 2019
Disclosure of detailed information about borrowings [line items]
Interest rate		7.25%		7.25%
5.00% Notes Due 2020
Disclosure of detailed information about borrowings [line items]
Interest rate		5.00%		5.00%
3.95% Notes Due 2022
Disclosure of detailed information about borrowings [line items]
Interest rate		3.95%		3.95%
4.00 Notes Due 2024
Disclosure of detailed information about borrowings [line items]
Interest rate		4.00%		4.00%
3.55% Notes Due 2025
Disclosure of detailed information about borrowings [line items]
Interest rate		3.55%		3.55%
3.60% Notes Due 2027
Disclosure of detailed information about borrowings [line items]
Interest rate		3.60%		3.60%
6.80% Notes Due 2037
Disclosure of detailed information about borrowings [line items]
Interest rate		6.80%		6.80%
6.20% Notes Due 2017
Disclosure of detailed information about borrowings [line items]
Interest rate	6.20%
Long-term debt repayment	$ 365
Non-current debt due within one year [Member]
Disclosure of detailed information about borrowings [line items]
Long-term debt due within one year		$ 1,433	0
Long-term debt
Disclosure of detailed information about borrowings [line items]
Long-term debt		4,114	5,240
Cost | 6.15% Notes Due 2019
Disclosure of detailed information about borrowings [line items]
Long-term debt		0	376	$ 0	300
Long-term debt due within one year		410	0	300	0
Cost | 7.25% Notes Due 2019
Disclosure of detailed information about borrowings [line items]
Long-term debt		0	939	0	750
Long-term debt due within one year		1,023	0	750	0
Cost | 5.00% Notes Due 2020
Disclosure of detailed information about borrowings [line items]
Long-term debt		400	400	0	0
Cost | 3.95% Notes Due 2022
Disclosure of detailed information about borrowings [line items]
Long-term debt		682	626	500	500
Cost | 4.00 Notes Due 2024
Disclosure of detailed information about borrowings [line items]
Long-term debt		1,023	939	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		528	484	387	387
Deferred financing costs
Disclosure of detailed information about borrowings [line items]
Long-term debt		$ (19)	$ (24)	$ 0	$ 0

Debt and Credit Facilities - Cr

Debt and Credit Facilities - Credit Facilities (Details) - CAD ($)	Dec. 31, 2018	Dec. 31, 2017	Nov. 30, 2017
Disclosure of detailed information about borrowings [line items]
Borrowings, maximum borrowing capacity	$ 4,900,000,000
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		$ 2,000,000,000
Borrowings	$ 0	$ 0

Debt and Credit Facilities - No

Debt and Credit Facilities - Notes (Details)	Sep. 15, 2017CAD ($)	Dec. 31, 2018CAD ($)	Dec. 31, 2017CAD ($)	Dec. 31, 2018USD ($)	Jan. 30, 2018CAD ($)	Mar. 30, 2017CAD ($)	Mar. 10, 2017CAD ($)
Disclosure of detailed information about borrowings [line items]
Hedged item, liabilities				$ 500,000,000
Long-term debt repayment		$ 0	$ 365,000,000
Authorised capital commitments, pre-registration		3,000,000,000		3,000,000,000
3.60% Notes Due 2027
Disclosure of detailed information about borrowings [line items]
Interest rate							3.60%
Borrowings							$ 750,000,000
6.20% Notes Due 2017
Disclosure of detailed information about borrowings [line items]
Interest rate	6.20%
Long-term debt repayment	$ 365,000,000
Debt repayment, interest	$ 11,000,000
2017 Canadian Shelf Prospectus
Disclosure of detailed information about borrowings [line items]
Authorised capital commitments, pre-registration		$ 3,000,000,000				$ 3,000,000,000
2018 U.S Shelf Prospectus
Disclosure of detailed information about borrowings [line items]
Authorised capital commitments, pre-registration				$ 3,000,000,000	$ 3,000,000,000

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, 2018CAD ($)	Dec. 31, 2017CAD ($)	Dec. 31, 2018USD ($)	Dec. 31, 2017USD ($)
Disclosure of detailed information about borrowings [line items]
Short-term debt	$ 200	$ 200
Long-term debt due within one year	1,433	0	$ 1,050
Long-term debt	4,114	5,240	$ 1,637	$ 2,687
Other non-current financial liabilities	1,107	1,237
Long-term debt issuance	0	750
Long-term debt repayment	0	(365)
Repayments of current borrowings	0
Debt issue costs	0	(6)
Proceeds from non-current borrowings, net of debt issuance costs	0
Other	(8)	18
Deferred revenue	(100)	(16)
Foreign exchange recognized in OCI	262	(243)
Non-current debt due within one year [Member]
Disclosure of detailed information about borrowings [line items]
Long-term debt due within one year	1,433	0
Total other changes - liability related, Current portion of non-current borrowings	1,433
Increase Decrease Through Reclassification From Long Term Debt To Current Portion Of Long Term Debt Liabilities Arising From Financing Activities	1,399
Foreign exchange recognized in OCI	34
Long-term debt
Disclosure of detailed information about borrowings [line items]
Long-term debt	4,114	$ 5,240
Increase Decrease Through Reclassification From Long Term Debt To Current Portion Of Long Term Debt Liabilities Arising From Financing Activities	(1,399)
Adjustments for finance costs	4
Foreign exchange recognized in OCI	269
Total other changes - liability related, Long-term debt	1,126
Other long-term liabilities [Member]
Disclosure of detailed information about borrowings [line items]
Other non-current financial liabilities	1,107
Other	20
Foreign exchange, other long-term liabilities	32
Fair value changes	(67)
Addition of finance lease obligations	(100)
Payment of finance lease obligations	15
Total other changes - liability related, Other long-term liabilities	$ (130)

Asset Retirement Obligations -

Asset Retirement Obligations - Carrying amount of ARO (Details) - CAD ($) $ in Millions	12 Months Ended
	Dec. 31, 2018	Dec. 31, 2017
Disclosure of other provisions [line items]
Asset Retirement Obligations, Expected to be incurred within 1 year	$ 202	$ 274
Asset Retirement Obligations, Expected to be incurred beyond 1 year	2,222	2,252
Asset Retirement Obligations
Disclosure of other provisions [line items]
Asset Retirement Obligation, Beginning balance	2,526	2,791
Additions	40	47
Liabilities settled	(270)	(136)
Liabilities disposed	(11)	(420)
Change in discount rate	(68)	143
Change in estimates	93	(2)
Exchange adjustment	17	(9)
Accretion (note 21)	97	112
Asset Retirement Obligation, Ending balance	$ 2,424	$ 2,526

Asset Retirement Obligations _2

Asset Retirement Obligations - Narrative (Details) - CAD ($) $ in Millions	12 Months Ended
	Dec. 31, 2018	Dec. 31, 2017
Disclosure of other provisions [line items]
Average expected rates of inflation	2.00%	2.00%
Restricted cash (notes 7, 16)	$ 0	$ 95
Restricted cash (notes 7, 16)	128	97
Asset Retirement Obligations
Disclosure of other provisions [line items]
Undiscounted inflation-adjusted ARO	$ 9,200	$ 9,700
Expected timing	45 years	42 years
Peoples Republic of China
Disclosure of other provisions [line items]
Restricted cash and cash equivalents	$ 128	$ 192
Restricted cash (notes 7, 16)		95
Restricted cash (notes 7, 16)		$ 97
Minimum | Asset Retirement Obligations
Disclosure of other provisions [line items]
Discount rate, adjusted risk-free rate (as a percent)	3.80%	2.90%
Maximum | Asset Retirement Obligations
Disclosure of other provisions [line items]
Discount rate, adjusted risk-free rate (as a percent)	5.00%	4.80%

Other Long-term Liabilities - O

Other Long-term Liabilities - Other Long-Term Liabilities (Details) - CAD ($) $ in Millions	Dec. 31, 2018	Dec. 31, 2017
Subclassifications of assets, liabilities and equities [abstract]
Employee future benefits (note 22)	$ 205	$ 248
Finance lease obligations	467	498
Stock-based compensation	42	32
Deferred revenue	205	284
Leasehold incentives	96	101
Other	92	74
Other non-current financial liabilities	$ 1,107	$ 1,237

Other Long-term Liabilities - F

Other Long-term Liabilities - Future Minimum Lease Payments (Details) - CAD ($) $ in Millions	Dec. 31, 2018	Dec. 31, 2017
Disclosure of finance lease and operating lease by lessee [line items]
Future minimum lease payments	$ 1,325	$ 1,320
Interest	836	816
Present value of minimum lease payments	489	504
Within 1 year
Disclosure of finance lease and operating lease by lessee [line items]
Future minimum lease payments	69	69
Interest	48	48
Present value of minimum lease payments	66	66
After 1 year but no more than 5 years
Disclosure of finance lease and operating lease by lessee [line items]
Future minimum lease payments	242	258
Interest	175	174
Present value of minimum lease payments	180	194
More than 5 years
Disclosure of finance lease and operating lease by lessee [line items]
Future minimum lease payments	1,014	993
Interest	613	594
Present value of minimum lease payments	$ 243	$ 244

Other Long-term Liabilities - D

Other Long-term Liabilities - Deferred Revenue (Details) - CAD ($) $ in Millions	12 Months Ended
	Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016
Schedule of Deferred Revenue [Line Items]
Deferred income	$ 205	$ 284	$ 321
Take-or-pay payments received	0	12
Decrease through performance obligation being satisfied, contract liabilities	(100)	(28)
Increase (decrease) through net exchange difference, deferred revenue liability	$ 21	$ (21)

Income Taxes - Income Tax Expen

Income Taxes - Income Tax Expense (Details) - CAD ($) $ in Millions	12 Months Ended
	Dec. 31, 2018	Dec. 31, 2017
Disclosure of income tax [Abstract]
Current income tax charge	$ 86	$ 28
Adjustments to current income tax estimates	(11)	(31)
Provisions for (recovery of) income taxes. current	75	(3)
Relating to origination and reversal of temporary differences	378	83
Adjustments to deferred income tax estimates	18	(442)
Provisions for (recovery of) income taxes, deferred	$ 396	$ (359)

Income Taxes - Deferred Tax Ite

Income Taxes - Deferred Tax Items in OCI (Details) - CAD ($) $ in Millions	12 Months Ended
	Dec. 31, 2018	Dec. 31, 2017
Income tax relating to components of other comprehensive income [abstract]
Derivatives designated as cash flow hedges	$ (5)	$ 0
Remeasurement of pension plans	17	(4)
Exchange differences on translation of foreign operations	87	(82)
Hedge of net investment	(41)	38
Income tax relating to components of other comprehensive income	$ 58	$ (48)

Income Taxes - Reconciliation o

Income Taxes - Reconciliation of Effective Tax Rate (Details) - CAD ($) $ in Millions	Jan. 01, 2018	Dec. 31, 2018	Dec. 31, 2017
Disclosure of geographical areas [line items]
Average effective tax rate		27.20%	27.10%
Reconciliation of Effective Tax Rate
Earnings before income taxes		$ 1,928	$ 424
Expected income tax		525	115
Foreign jurisdictions		(36)	20
Non-taxable items		(13)	(1)
Adjustments with respect to previous year		7	(473)
Revaluation of foreign tax pools		(4)	(8)
Other – net		(8)	(15)
Provisions for (recovery of) income taxes		471	(362)
Deferred income tax recovery			436
Canada
Reconciliation of Effective Tax Rate
Earnings before income taxes		734	$ (440)
United States
Disclosure of geographical areas [line items]
Applicable tax rate			35.00%
Reconciliation of Effective Tax Rate
Earnings before income taxes		493	$ 301
Other foreign jurisdictions
Reconciliation of Effective Tax Rate
Earnings before income taxes		$ 701	$ 563
Changes in tax rates or tax laws enacted or announced | United States
Disclosure of geographical areas [line items]
Applicable tax rate	21.00%

Income Taxes - Deferred Tax Lia

Income Taxes - Deferred Tax Liabilities and Assets (Details) - CAD ($)	12 Months Ended
	Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016
Disclosure of temporary difference, unused tax losses and unused tax credits [line items]
Deferred tax liabilities	$ (3,174,000,000)	$ (2,724,000,000)
Deferred tax liability	(3,174,000,000)	(2,724,000,000)	$ (3,111,000,000)
Deferred income taxes	(396,000,000)	359,000,000
Income tax relating to components of other comprehensive income	(58,000,000)	48,000,000
Increase (decrease) other differences deferred tax liability (asset)	4,000,000	(20,000,000)
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	(4,089,000,000)	(3,727,000,000)	(3,998,000,000)
Deferred income taxes	(260,000,000)	187,000,000
Income tax relating to components of other comprehensive income	(106,000,000)	104,000,000
Increase (decrease) other differences deferred tax liability (asset)	4,000,000	(20,000,000)
Foreign exchange gains taxable on realization
Disclosure of temporary difference, unused tax losses and unused tax credits [line items]
Deferred tax liabilities	(174,000,000)	(177,000,000)	(224,000,000)
Deferred income taxes	(43,000,000)	85,000,000
Income tax relating to components of other comprehensive income	46,000,000	(38,000,000)
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	(4,000,000)	(3,000,000)	(2,000,000)
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	(28,000,000)	(90,000,000)	(21,000,000)
Deferred income taxes	62,000,000	(69,000,000)
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	(8,000,000)	(40,000,000)	(32,000,000)
Deferred income taxes	(15,000,000)	4,000,000
Income tax relating to components of other comprehensive income	(17,000,000)	4,000,000
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	(654,000,000)	(679,000,000)	(693,000,000)
Deferred income taxes	(29,000,000)	(8,000,000)
Income tax relating to components of other comprehensive income	4,000,000	(6,000,000)
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	(468,000,000)	(523,000,000)	(389,000,000)
Deferred income taxes	(70,000,000)	150,000,000
Income tax relating to components of other comprehensive income	15,000,000	(16,000,000)
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	(31,000,000)	$ (20,000,000)
Deferred income taxes	(40,000,000)	11,000,000
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	$ (1,806,000,000)	$ (2,031,000,000)

Share Capital - Common Shares (

Share Capital - Common Shares (Details) $ in Millions	12 Months Ended
	Dec. 31, 2018CAD ($)shares	Dec. 31, 2017CAD ($)shares
Disclosure of classes of share capital [line items]
Number of share options exercised (in options) | shares	2,000	0
Ordinary shares [member]
Disclosure of classes of share capital [line items]
Equity, beginning, shares | shares	1,005,120,012	1,005,451,854
Shares cancellation (in shares) | shares		331,842
Number of share options exercised (in options) | shares	(1,726)
Equity, ending, shares | shares	1,005,121,738	1,005,120,012
Issued capital, beginning balance (in shares)	$ 7,293	$ 7,296
Share cancellation		3
Share additions (note 19)	0
Issued capital, ending balance (in shares)	7,293	7,293
Dividend payables (in CAD per share)	126	0
Dividends declared on common shares	402	0
Dividends recognised as distributions to owners	$ 276	$ 0
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	$ 874
Issued capital, ending balance (in shares)	874	874
Dividend payables (in CAD per share)	0	9
Dividends declared on common shares	35	34
Dividends recognised as distributions to owners	$ 43	$ 34

Share Capital - Preferred Share

Share Capital - Preferred Shares (Details) - shares	Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016
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 ($) $ in Millions	12 Months Ended
	Dec. 31, 2018	Dec. 31, 2017
Preference shares [member]
Disclosure of classes of share capital [line items]
Dividend payables	$ 0	$ 9
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	3.239%
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	4.50%
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, 2018	Dec. 31, 2017
Disclosure of classes of share capital [line items]
Dividends declared on preferred shares	$ 35	$ 34
Dividends recognised as distributions to owners	43	34
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	8	6
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	11
Dividends recognised as distributions to owners	14	11
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	11	9
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	$ 9	$ 7

Share Capital - Stock Option Pl

Share Capital - Stock Option Plan (Details)	12 Months Ended
	Dec. 31, 2018CAD ($)year	Dec. 31, 2017CAD ($)year
Disclosure of terms and conditions of share-based payment arrangement [line items]
Share option, term | year	1.95	1.95
Stock based compensation expense	$ 44,000,000	$ 45,000,000
Weighted average fair value (in CAD per option)	$ 0.65	1.15
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	$ 11,000,000	21,000,000
Stock based compensation expense	(3,000,000)	13,000,000
Stock option exercisable, intrinsic value	0	12,000,000
Weighted average fair value (in CAD per option)	$ 2.90	$ 2.01

Share Capital - Outstanding and

Share Capital - Outstanding and Exercisable Options (Details)	12 Months Ended
	Dec. 31, 2018CAD ($)shares	Dec. 31, 2017CAD ($)shares
Disclosure of share capital, reserves and other equity interest [Abstract]
Number of stock options outstanding, beginning of year (in options) | shares	22,645,000	25,459,000
Number of stock options granted (in options) | shares	5,610,000	5,544,000
Number of share options exercised in share-based payment arrangement (in options) | shares	(2,000)	0
Number of share options surrendered for cash (in options)	(1,772,000)	0
Number of stock options expired or forfeited (in options) | shares	(6,514,000)	(8,358,000)
Number of stock options outstanding, end of year (in options) | shares	19,967,000	22,645,000
Number of stock options exercisable, end of year (in options) | shares	10,461,000	12,946,000
Weighted average exercise price of stock options outstanding, beginning of year (in cad per option)	$ 23.96	$ 26.26
Weighted average exercise price of stock options granted (in cad per option)	17.21	16.13
Weighted average exercise price of share options exercised in share-based payment arrangement (in cad per option)	15.67	0
Weighted average exercise price of share options surrendered for cash (in cad per option)	15.82	0
Weighted average exercise price of stock options expired/forfeited (in cad per option)	27.69	25.62
Weighted average exercise price of stock options outstanding, end of year (in cad per option)	21.48	23.96
Weighted average exercise price of options exercisable (in cad per option)	25.87	28.91
Weighted average fair value (in CAD per option)	$ 0.65	$ 1.15

Share Capital - Outstanding a_2

Share Capital - Outstanding and Exercisable Options-Range of Exercise Prices (Details)	Dec. 31, 2018CAD ($)sharesyear	Dec. 31, 2017CAD ($)shares	Dec. 31, 2016CAD ($)shares
Disclosure of range of exercise prices of outstanding share options [line items]
Number of options outstanding (in options) | shares	19,967,000	22,645,000	25,459,000
Weighted average exercise price of stock options outstanding (in cad per option)	$ 21.48	$ 23.96	$ 26.26
Weighted average remaining contractual life of options outstanding (in years) | year	2.37
Number of stock options exercisable (in options) | shares	10,461,000	12,946,000
Weighted average exercise price of options exercisable (in cad per option)	$ 25.87	$ 28.91
$14.20 - $29.99
Disclosure of range of exercise prices of outstanding share options [line items]
Number of options outstanding (in options) | shares	16,061,000
Weighted average exercise price of stock options outstanding (in cad per option)	$ 18.55
Weighted average remaining contractual life of options outstanding (in years) | year	2.90
Number of stock options exercisable (in options) | shares	6,555,000
Weighted average exercise price of options exercisable (in cad per option)	$ 21.30
$14.20 - $29.99 | Minimum
Disclosure of range of exercise prices of outstanding share options [line items]
Exercise price of options (in CAD per option)	14.20
$14.20 - $29.99 | Maximum
Disclosure of range of exercise prices of outstanding share options [line items]
Exercise price of options (in CAD per option)	$ 29.99
$30.00 - $36.20
Disclosure of range of exercise prices of outstanding share options [line items]
Number of options outstanding (in options) | shares	3,906,000
Weighted average exercise price of stock options outstanding (in cad per option)	$ 33.52
Weighted average remaining contractual life of options outstanding (in years) | year	0.17
Number of stock options exercisable (in options) | shares	3,906,000
Weighted average exercise price of options exercisable (in cad per option)	$ 33.51
$30.00 - $36.20 | Minimum
Disclosure of range of exercise prices of outstanding share options [line items]
Exercise price of options (in CAD per option)	30
$30.00 - $36.20 | Maximum
Disclosure of range of exercise prices of outstanding share options [line items]
Exercise price of options (in CAD per option)	$ 36.20

Share Capital - Fair Value (Det

Share Capital - Fair Value (Details)	12 Months Ended
	Dec. 31, 2018CAD ($)year	Dec. 31, 2017CAD ($)year
Disclosure of terms and conditions of share-based payment arrangement [line items]
Dividend per option	$ 0.56	$ 0.72
Expected life of share options from vesting date (years) | year	1.95	1.95
Expected forfeiture rate (percent)	8.90%	9.00%
Weighted average exercise price (in CAD per option)	$ 22.46	$ 25.46
Weighted average fair value (in CAD per option)	$ 0.65	$ 1.15
Minimum
Disclosure of terms and conditions of share-based payment arrangement [line items]
Range of expected volatilities used (percent)	16.80%	16.70%
Range of risk-free interest rates used (percent)	1.60%	0.90%
Maximum
Disclosure of terms and conditions of share-based payment arrangement [line items]
Range of expected volatilities used (percent)	44.40%	32.90%
Range of risk-free interest rates used (percent)	1.90%	1.90%

Share Capital - Performance Sha

Share Capital - Performance Share Units (Details) $ in Millions	12 Months Ended
	Dec. 31, 2018CAD ($)sharesyear	Dec. 31, 2017CAD ($)sharesyear
Disclosure of terms and conditions of share-based payment arrangement [line items]
Share option, term | year	1.95	1.95
Share-based compensation expense | $	$ (3)	$ 13
Weighted average remaining contractual life of options outstanding (in years) | year	2.37
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 | $	$ 63	41
Share-based compensation expense | $	47	32
Payment for performance share units which vested in the year | $	$ 24	$ 15
Weighted average remaining contractual life of options outstanding (in years) | year	2	2
Performance Share Units, Beginning balance (in units)	8,361,918	4,863,690
Performance Share Units, Granted (in units)	6,108,430	5,667,970
Performance Share Units, Exercised (in units)	(1,354,316.09)	(966,932)
Performance Share Units, Forfeited (in units)	(1,509,388)	(1,202,810)
Performance Share Units, Ending balance (in units)	11,606,643.91	8,361,918
Performance Share Units, Vested (in units)	4,487,585	2,262,954

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, 2018	Dec. 31, 2017
Earnings per share [abstract]
Net earnings	$ 1,457	$ 786
Effect of dividends declared on preferred shares in the year	(35)	(34)
Net earnings – basic	1,422	752
Dilutive effect of accounting for stock options(1)	(13)	4
Net earnings – diluted	$ 1,409	$ 756
Weighted average number of common shares outstanding, basic	1,005.1	1,005.3
Weighted average common shares outstanding – diluted	1,006.1	1,005.3
Earnings per share – basic ($/share)	$ 1.41	$ 0.75
Earnings per share – diluted ($/share)	$ 1.40	$ 0.75
Stock-based compensation expense, cash-settled	$ (3)	$ 13
Stock-based compensation expense, equity settled	$ (10)	$ (9)
Dilutive effect of share options (in options)	1	0
Stock Option Plan
Earnings per share [abstract]
Dilutive effect of share options on number of ordinary shares	13	23

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, 2018	Dec. 31, 2017
Analysis of income and expense [abstract]
Services and support costs	$ 1,039	$ 930
Salaries and benefits	762	664
Materials, equipment rentals and leases	243	248
Energy and utility	405	453
Licensing fees	191	200
Transportation	24	26
Other	139	158
Total production, operating and transportation expenses	$ 2,803	$ 2,679

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, 2018	Dec. 31, 2017
Analysis of income and expense [abstract]
Employee costs(1)	$ 332	$ 395
Stock-based compensation expense(2)	44	45
Contract services	104	100
Equipment rentals and leases	39	37
Maintenance and other	135	73
Total selling, general and administrative expenses	$ 654	$ 650

Financial Items (Details)

Financial Items (Details) - CAD ($) $ in Millions	12 Months Ended
	Dec. 31, 2018	Dec. 31, 2017
Foreign exchange
Non-cash working capital gains	$ (3)	$ (3)
Other foreign exchange gains (losses)	17	(3)
Net foreign exchange gains (losses)	14	(6)
Finance income	64	37
Finance expenses
Interest costs incurred	325	348
Interest costs capitalised	108	68
Finance costs and interest before net foreign exchange gain (loss)	(217)	(280)
Accretion of asset retirement obligations (note 16)	(97)	(112)
Finance expenses	(314)	(392)
Financial items	$ (236)	$ (361)
Capitalisation rate of borrowing costs eligible for capitalisation	5.00%	5.00%
Long-term debt
Finance expenses
Interest costs incurred	$ 320	$ 342
Contribution payable (note 11)
Finance expenses
Interest costs incurred	0	(2)
Other
Finance expenses
Interest costs incurred	$ 5	$ 4

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	Jul. 27, 2017	Dec. 31, 2018	Dec. 31, 2017
Disclosure of net defined benefit liability (asset) [line items]
Defined contribution plan expense		$ 54	$ 46
DB Pension Plans
Disclosure of net defined benefit liability (asset) [line items]
Current service cost		1	1
Interest cost		1	0
Contributions by employer	$ 5
Remeasurements
Actuarial (gain) loss – experience	$ (3)	2	3
Actuarial loss – financial assumptions		(4)	5
Return on plan assets greater than discount rate		0	(4)
DB Pension Plans | Defined benefit obligation
Disclosure of net defined benefit liability (asset) [line items]
Defined benefit obligation, beginning balance		76	178
Current service cost		1	1
Interest cost		3	4
Benefits paid		(2)	(9)
Settlements		0	(140)
Increase (decrease) through business combinations and disposals, net defined benefit liability (asset)		0	34
Remeasurements
Actuarial (gain) loss – experience		2	3
Actuarial loss – financial assumptions		(4)	5
Increase (decrease) through changes in foreign exchange rates, net defined benefit liability (asset)		3	0
Defined benefit obligation, ending balance		79	76
DB Pension Plans | Fair value of plan assets
Disclosure of net defined benefit liability (asset) [line items]
Defined benefit obligation, beginning balance		67	183
Interest cost		2	4
Contributions by employer		1	6
Benefits paid		(2)	(9)
Settlements		0	(148)
Increase (decrease) through business combinations and disposals, net defined benefit liability (asset)		0	27
Remeasurements
Increase (decrease) through changes in foreign exchange rates, net defined benefit liability (asset)		3	0
Return on plan assets greater than discount rate		0	4
Defined benefit obligation, ending balance		71	67
OPEB Plans
Disclosure of net defined benefit liability (asset) [line items]
Current service cost		11	15
Interest cost		8	8
Remeasurements
Actuarial (gain) loss – experience		(13)	0
Actuarial loss – financial assumptions		(45)	12
Return on plan assets greater than discount rate		0	0
OPEB Plans | Defined benefit obligation
Disclosure of net defined benefit liability (asset) [line items]
Defined benefit obligation, beginning balance		244	213
Current service cost		11	15
Interest cost		8	8
Benefits paid		(4)	(4)
Settlements		0	0
Increase (decrease) through business combinations and disposals, net defined benefit liability (asset)		0	0
Remeasurements
Actuarial (gain) loss – experience		(13)	0
Actuarial loss – financial assumptions		(45)	12
Increase (decrease) through changes in foreign exchange rates, net defined benefit liability (asset)		(2)	0
Defined benefit obligation, ending balance		199	244
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	0
Benefits paid		(2)	0
Settlements		0	0
Increase (decrease) through business combinations and disposals, net defined benefit liability (asset)		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
Retirement Plan Funding Status [Member] | DB Pension Plans
Disclosure of net defined benefit liability (asset) [line items]
Defined benefit obligation, beginning balance		(9)
Remeasurements
Defined benefit obligation, ending balance		(8)	(9)
Retirement Plan Funding Status [Member] | OPEB Plans
Disclosure of net defined benefit liability (asset) [line items]
Defined benefit obligation, beginning balance		(244)
Remeasurements
Defined benefit obligation, ending balance		$ (199)	$ (244)

Pensions and Other Post-emplo_4

Pensions and Other Post-employment Benefits - Narrative (Details) - CAD ($) $ in Millions	Jul. 27, 2017	Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2021
Disclosure of defined benefit plans [line items]
Remeasurement of pension plans		$ (17)	$ 4
DB Pension Plans
Disclosure of defined benefit plans [line items]
Net defined benefit asset	$ 148
Contributions by employer	5
Settlements gain (loss)	(8)	0	8
Defined benefit obligation, annuity purchased	48
Actuarial gains (losses) arising from remeasurement of plan assets	(3)	2	3
Remeasurement of pension plans	1
OPEB Plans
Disclosure of defined benefit plans [line items]
Settlements gain (loss)		0	0
Actuarial gains (losses) arising from remeasurement of plan assets		(13)	0
Defined benefit obligation, Inactive plan members | DB Pension Plans
Disclosure of defined benefit plans [line items]
Defined benefit obligation	140
Defined benefit obligation, Active plan members | DB Pension Plans
Disclosure of defined benefit plans [line items]
Defined benefit obligation	$ 42
Fair value of plan assets | DB Pension Plans
Disclosure of defined benefit plans [line items]
Contributions by employer		1	6
Fair value of plan assets | OPEB Plans
Disclosure of defined benefit plans [line items]
Contributions by employer		2	0
Defined benefit obligation | DB Pension Plans
Disclosure of defined benefit plans [line items]
Actuarial gains (losses) arising from remeasurement of plan assets		2	3
Defined benefit obligation | OPEB Plans
Disclosure of defined benefit plans [line items]
Actuarial gains (losses) arising from remeasurement of plan assets		$ (13)	$ 0
Canada | Fair value of plan assets | OPEB Plans
Disclosure of defined benefit plans [line items]
Actuarial assumption of medical cost trend rates		6.50%		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, 2018	Dec. 31, 2017
Disclosure of employee benefits [Abstract]
Target allocation, Money market type funds (percent)	0.00%
Target allocation, Equity securities (percent)	0.00%
Target allocation, Debt securities (percent)	100.00%
Money market type funds (percent)	5.00%	0.20%
Equity securities (percent)	0.00%	0.00%
Debt securities (percent)	95.00%	99.80%

Pensions and Other Post-emplo_6

Pensions and Other Post-employment Benefits - Defined Contribution Pension Plan - Net Earnings and OCI (Details) - CAD ($) $ in Millions	Jul. 27, 2017	Dec. 31, 2018	Dec. 31, 2017
DB Pension Plans
Disclosure of defined benefit plans [line items]
Current service cost		$ 1	$ 1
Past service cost		0	1
Interest cost		1	0
Settlements	$ (8)	0	8
Benefit cost		2	10
Actuarial (gain) loss – experience	$ (3)	2	3
Actuarial loss – financial assumptions		(4)	5
Return on plan assets greater than discount rate		0	(4)
Remeasurement effects recognized in OCI		(2)	4
OPEB Plans
Disclosure of defined benefit plans [line items]
Current service cost		11	15
Past service cost		0	0
Interest cost		8	8
Settlements		0	0
Benefit cost		19	23
Actuarial (gain) loss – experience		(13)	0
Actuarial loss – financial assumptions		(45)	12
Return on plan assets greater than discount rate		0	0
Remeasurement effects recognized in OCI		$ (58)	$ 12

Pensions and Other Post-emplo_7

Pensions and Other Post-employment Benefits - Actuarial Assumptions and Sensitivity Analysis (Details) - CAD ($) $ in Millions	Dec. 31, 2018	Dec. 31, 2017
DB Pension Plans
Disclosure of defined benefit plans [line items]
Rate of compensation expense		3.50%
Minimum | DB Pension Plans
Disclosure of defined benefit plans [line items]
Discount rate for benefit expense and obligation	3.40%	3.40%
Minimum | OPEB Plans
Disclosure of defined benefit plans [line items]
Discount rate for benefit expense and obligation	3.40%	3.40%
Maximum | DB Pension Plans
Disclosure of defined benefit plans [line items]
Discount rate for benefit expense and obligation	3.60%	3.50%
Maximum | OPEB Plans
Disclosure of defined benefit plans [line items]
Discount rate for benefit expense and obligation	3.70%	3.90%
Discount rate | DB Pension Plans
Disclosure of defined benefit plans [line items]
Impact on defined benefit obligation, increase in assumption	$ (9)
Impact on defined benefit obligation, decrease in assumption	$ 11
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	$ (33)
Impact on defined benefit obligation, decrease in assumption	$ 43
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	$ 32
Impact on defined benefit obligation, decrease in assumption	$ (25)
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, 2018	Dec. 31, 2017
Disclosure of cash flow statement [Abstract]
Accounts receivable	$ 127	$ (329)
Inventories	393	(264)
Prepaid expenses	30	(38)
Accounts payable and accrued liabilities	(65)	1,269
Change in non-cash working capital	485	638
Change in non-cash working capital, operating activities	130	398
Change in non-cash working capital, financing activities	120	0
Change in non-cash working capital, investing activities	$ 235	$ 240

Financial Instruments and Ris_3

Financial Instruments and Risk Management - Financial Instruments at Fair Value (Details) - CAD ($) $ in Millions	12 Months Ended
	Dec. 31, 2018	Dec. 31, 2017
Disclosure Of Financial Assets And Liabilities [Line Items]
Net amounts for pay-floating (receive-fixed) interest rate swaps for which net cash flows are exchanged	$ (14)	$ 0
Hedge of net investment(3)(4)	(846)	(584)
Derivative financial liabilities	780	652
Trading inventories measured at fair value less costs to sell	200	237
Derivatives | Natural gas(1) | FVTPL
Disclosure Of Financial Assets And Liabilities [Line Items]
Financial assets, at fair value	(9)	(13)
Derivatives | Natural gas(1) | FVTPL, held-for-trading
Disclosure Of Financial Assets And Liabilities [Line Items]
Increase (decrease) in financial assets	(10)	(3)
Trading inventories measured at fair value less costs to sell	15	5
Derivatives | Crude oil(2) | FVTPL
Disclosure Of Financial Assets And Liabilities [Line Items]
Financial assets, at fair value	89	(57)
Derivatives | Crude oil(2) | FVTPL, held-for-trading
Disclosure Of Financial Assets And Liabilities [Line Items]
Increase (decrease) in financial assets	67	5
Trading inventories measured at fair value less costs to sell	185	232
Derivatives | Foreign currency forwards | FVTPL
Disclosure Of Financial Assets And Liabilities [Line Items]
Financial assets, at fair value	(1)	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	5,500	5,200
Financial liabilities, at fair value	$ 5,700	$ 5,600

Financial Instruments and Ris_4

Financial Instruments and Risk Management - Market Risk (Details) $ in Millions	12 Months Ended
	Dec. 31, 2018CAD ($)	Dec. 31, 2017CAD ($)	Dec. 31, 2018USD ($)	Dec. 31, 2017USD ($)
Disclosure Of Financial Assets And Liabilities [Line Items]
Unrealized mark to market loss (gain) (note 24)	$ (150,000,000)	$ 56,000,000
Line of credit, maximum borrowing capacity	4,900,000,000
Hedged item, liabilities			$ 500
Long-term debt	4,114,000,000	5,240,000,000	1,637	$ 2,687
Tax relating to cash flow hedges	(5,000,000)	0
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			2,700	$ 2,700
Gains (losses) on hedges of net investments in foreign operations, net of tax	(262,000,000)	243,000,000
Income tax relating to components of other comprehensive income that will not be reclassified to profit or loss	41,000,000	38,000,000
Interest rate swap contract [member]
Disclosure Of Financial Assets And Liabilities [Line Items]
Income tax relating to components of other comprehensive income that will not be reclassified to profit or loss	(3,000,000)
Gains (losses) recognised in other comprehensive income on financial liabilities at fair value through profit or loss, designated upon initial recognition or subsequently	11,000,000	0
Two Point Nine Nine Nine Percent Swap [Member] | Interest rate swap contract [member]
Disclosure Of Financial Assets And Liabilities [Line Items]
Notional amount			250
Financial instruments designated as hedging instruments, at fair value	(7,000,000)
Syndicated Bank Facilities [Member]
Disclosure Of Financial Assets And Liabilities [Line Items]
Line of credit, maximum borrowing capacity	4,000,000,000
Three Point Zero Percent Swap [Member] | Interest rate swap contract [member]
Disclosure Of Financial Assets And Liabilities [Line Items]
Notional amount			$ 250
Financial instruments designated as hedging instruments, at fair value	(7,000,000)
Cost | Unwound interest rate swaps
Disclosure Of Financial Assets And Liabilities [Line Items]
Reserve of cash flow hedges	13,000,000	15,000,000
Tax relating to cash flow hedges	4,000,000	5,000,000
Amortization of the accrued gain upon settlement of derivative	$ 2,000,000	$ 2,000,000
Fixed interest rate [member] | Two Point Nine Nine Nine Percent Swap [Member] | Interest rate swap contract [member]
Disclosure Of Financial Assets And Liabilities [Line Items]
Interest rate, weighted average	2.999%		2.999%
Fixed interest rate [member] | Three Point Zero Percent Swap [Member] | Interest rate swap contract [member]
Disclosure Of Financial Assets And Liabilities [Line Items]
Interest rate, weighted average	3.00%		3.00%

Financial Instruments and Ris_5

Financial Instruments and Risk Management - Offsetting Financial Assets and Liabilities (Details) - CAD ($) $ in Millions	Dec. 31, 2018	Dec. 31, 2017
Offsetting financial assets [abstract]
Offsetting financial assets, Gross amount	$ 813	$ 789
Offsetting financial assets, Amount offset	(455)	(391)
Offsetting financial assets, Net amount	358	399
Offsetting financial liabilities [abstract]
Offsetting financial liabilities, Gross amount	(863)	(1,179)
Offsetting financial liabilities, Amount offset	369	475
Offsetting financial liabilities, Net amount	(494)	(704)
Financial liabilities, derivatives
Offsetting financial liabilities [abstract]
Offsetting financial liabilities, Gross amount	(107)	(246)
Offsetting financial liabilities, Amount offset	62	122
Offsetting financial liabilities, Net amount	(45)	(123)
Financial liabilities, normal purchase and sale agreements
Offsetting financial liabilities [abstract]
Offsetting financial liabilities, Gross amount	(756)	(933)
Offsetting financial liabilities, Amount offset	307	353
Offsetting financial liabilities, Net amount	(449)	(581)
Financial assets, derivatives
Offsetting financial assets [abstract]
Offsetting financial assets, Gross amount	188	150
Offsetting financial assets, Amount offset	(120)	(111)
Offsetting financial assets, Net amount	68	40
Financial assets, normal purchase and sale agreements
Offsetting financial assets [abstract]
Offsetting financial assets, Gross amount	625	639
Offsetting financial assets, Amount offset	(335)	(280)
Offsetting financial assets, Net amount	$ 290	$ 359

Financial Instruments and Ris_6

Financial Instruments and Risk Management - Market Risk Sensitivity Analysis (Details)	12 Months Ended
	Dec. 31, 2018CAD ($)
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	$ 26,000,000
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	$ (9,000,000)
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	$ (26,000,000)
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	$ 9,000,000
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
Interest rate swap contract [member] | Sensitivity analysis, increase | Interest rate risk [member]
Disclosure of nature and extent of risks arising from financial instruments [line items]
Market risk sensitivity analysis	$ 61,000,000
Sensitivity analysis for types of market risk, reasonably possible change in risk variable, percent	1.00%
Interest rate swap contract [member] | Sensitivity analysis, decrease | Interest rate risk [member]
Disclosure of nature and extent of risks arising from financial instruments [line items]
Market risk sensitivity analysis	$ (61,000,000)
Sensitivity analysis for types of market risk, reasonably possible change in risk variable, percent	1.00%

Financial Instruments and Ris_7

Financial Instruments and Risk Management - Financial Risk (Details)	12 Months Ended
	Dec. 31, 2018CAD ($)	Dec. 31, 2017CAD ($)	Dec. 31, 2018USD ($)
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	4,261,000,000
Authorised capital commitments, pre-registration	3,000,000,000		$ 3,000,000,000
Revenues	22,252,000,000	$ 18,583,000,000
Bank operating loan
Disclosure of detailed information about financial instruments [line items]
Line of credit, maximum borrowing capacity	900,000,000	850,000,000
Line of credit, current borrowing capacity	461,000,000
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	3,800,000,000
Customer concentration risk [Member]
Disclosure of detailed information about financial instruments [line items]
Revenues		$ 3,300,000,000
Single customer over 10% of revenue | Customer concentration risk [Member]
Disclosure of detailed information about financial instruments [line items]
Revenues	$ 4,200,000,000

Financial Instruments and Ris_8

Financial Instruments and Risk Management - Accounts Receivable Aging (Details) - CAD ($) $ in Millions	12 Months Ended
	Dec. 31, 2018	Dec. 31, 2017
Disclosure of financial assets that are either past due or impaired [line items]
Impairment loss, receivables	$ 3	$ 1
Trade receivables
Disclosure of financial assets that are either past due or impaired [line items]
Accounts receivable	1,355
Trade receivables | Provision for expected credit losses
Disclosure of financial assets that are either past due or impaired [line items]
Accounts receivable	(39)
Trade receivables | Current | Cost
Disclosure of financial assets that are either past due or impaired [line items]
Accounts receivable	1,140
Trade receivables | Past due (1 – 30 days) | Cost
Disclosure of financial assets that are either past due or impaired [line items]
Accounts receivable	139
Trade receivables | Past due (31 – 60 days) | Cost
Disclosure of financial assets that are either past due or impaired [line items]
Accounts receivable	42
Trade receivables | Past due (61 – 90 days) | Cost
Disclosure of financial assets that are either past due or impaired [line items]
Accounts receivable	16
Trade receivables | Past due (more than 90 days) | Cost
Disclosure of financial assets that are either past due or impaired [line items]
Accounts receivable	$ 57

Related Party Transactions - Si

Related Party Transactions - Significant Subsidiaries and Joint Operations (Details) - CAD ($)	12 Months Ended
	Dec. 31, 2018	Dec. 31, 2017
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
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
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	$ 448,000,000	$ 412,000,000
Purchases of goods, related party transactions	200,000,000	203,000,000
Distributions, Related Party Transactions	139,000,000	25,000,000
Contributions, Related Party Transactions	40,000,000	17,000,000
Due from related parties, related party transactions	$ 140,000,000	$ 67,000,000

Related Party Transactions (Det

Related Party Transactions (Details) - Husky Midstream Limited Partnership - CAD ($)	12 Months Ended
	Dec. 31, 2018	Dec. 31, 2017
Disclosure of transactions between related parties [line items]
Share of equity investment (percent)	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	$ 448,000,000	$ 412,000,000
Purchases of goods, related party transactions	200,000,000	203,000,000
Distributions, Related Party Transactions	139,000,000	25,000,000
Contributions, Related Party Transactions	40,000,000	17,000,000
Due from related parties, related party transactions	140,000,000	67,000,000
Deferred Revenue From Construction Contracts, Percentage of Completion Method	$ 0	$ 23,000,000

Related Party Transactions - Co

Related Party Transactions - Compensation of key management personnel (Details) - Key management personnel - CAD ($) $ in Millions	12 Months Ended
	Dec. 31, 2018	Dec. 31, 2017
Disclosure of transactions between related parties [line items]
Short-term employee benefits(1)	$ 17	$ 16
Stock-based compensation(2)	33	31
Key management personnel compensation	$ 50	$ 47

Commitments and Contingencies_2

Commitments and Contingencies (Details) $ in Millions	Dec. 31, 2018CAD ($)
Disclosure of maturity analysis for non-derivative financial liabilities [line items]
Operating leases(1)	$ 1,923
Firm transportation agreements(1)	6,576
Unconditional purchase obligations(2)	10,098
Lease rentals and exploration work agreements	1,225
Obligations to fund equity investee(3)	741
Minimum future payments for commitments	20,563
Within 1 year
Disclosure of maturity analysis for non-derivative financial liabilities [line items]
Operating leases(1)	233
Firm transportation agreements(1)	497
Unconditional purchase obligations(2)	1,620
Lease rentals and exploration work agreements	49
Obligations to fund equity investee(3)	53
Minimum future payments for commitments	2,452
After 1 year but no more than 5 years
Disclosure of maturity analysis for non-derivative financial liabilities [line items]
Operating leases(1)	504
Firm transportation agreements(1)	2,066
Unconditional purchase obligations(2)	3,656
Lease rentals and exploration work agreements	246
Obligations to fund equity investee(3)	293
Minimum future payments for commitments	6,765
More than 5 years
Disclosure of maturity analysis for non-derivative financial liabilities [line items]
Operating leases(1)	1,186
Firm transportation agreements(1)	4,013
Unconditional purchase obligations(2)	4,822
Lease rentals and exploration work agreements	930
Obligations to fund equity investee(3)	395
Minimum future payments for commitments	11,346
Husky Midstream Limited Partnership
Disclosure of maturity analysis for non-derivative financial liabilities [line items]
Operating leases(1)	1,100
Firm transportation agreements(1)	$ 1,900

Capital Disclosures (Details)

Capital Disclosures (Details) $ in Billions	12 Months Ended
	Dec. 31, 2018CAD ($)	Dec. 31, 2017CAD ($)
Disclosure of additional information [Abstract]
Equity and debt	$ 25.4	$ 23.4
Debt to capital ratio	0.227	0.232
Debt to capital ratio, target	0.25
Debt to funds from operation ratio	1.4	1.6
Debt to funds from operation ratio, target	2