Imperial Oil Limited (IMO) 10-K 27 Feb 19 2018 FY Annual report Financial data

Document And Entity Information

Document And Entity Information - CAD ($)	12 Months Ended
	Dec. 31, 2018	Feb. 13, 2019	Jun. 30, 2018
Document Information [Line Items]
Document Type	10-K
Amendment Flag	false
Document Period End Date	Dec. 31, 2018
Document Fiscal Year Focus	2,018
Document Fiscal Period Focus	FY
Entity Registrant Name	IMPERIAL OIL LTD
Entity Central Index Key	49,938
Current Fiscal Year End Date	--12-31
Entity Well-known Seasoned Issuer	Yes
Entity Voluntary Filers	No
Entity Current Reporting Status	Yes
Entity Filer Category	Large Accelerated Filer
Trading Symbol	IMO
Entity Shell Company	false
Entity Emerging Growth Company	false
Entity Small Business	false
Entity Common Stock, Shares Outstanding		777,576,359
Entity Public Float			$ 10,663,467,561

Consolidated statement of incom

Consolidated statement of income - CAD ($) $ in Millions		12 Months Ended
		Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016
Revenues and other income
Revenues	[1],[2]	$ 34,964	$ 29,125	$ 25,049
Investment and other income (note 9)		135	299	2,305
Total revenues and other income		35,099	29,424	27,354
Expenses
Exploration (note 16)	[3]	19	183	94
Purchases of crude oil and products	[4]	21,541	18,145	15,120
Production and manufacturing	[5],[6]	6,121	5,586	5,105
Selling and general	[5],[6]	908	883	1,118
Federal excise tax		1,667	1,673	1,650
Depreciation and depletion	[3],[7]	1,555	2,172	1,628
Non-service pension and postretirement benefit	[8]	107	122	130
Financing (note 13)	[9],[10]	108	78	65
Total expenses		32,026	28,842	24,910
Income (loss) before income taxes		3,073	582	2,444
Income taxes (note 4)	[11],[12]	759	92	279
Net income (loss)		$ 2,314	$ 490	$ 2,165
Per share information (Canadian dollars)
Net income (loss) per common share - basic (note 11)		$ 2.87	$ 0.58	$ 2.55
Net income (loss) per common share - diluted (note 11)		$ 2.86	$ 0.58	$ 2.55
[1]	Amounts from related parties included in revenues (note 17). 6,383 4,110 2,342
[2]	Includes export sales to the United States of $6,661 million (2017 - $4,392 million, 2016 - $3,612 million). Export sales to the United States were recorded in all operating segments, with the largest effects in the Upstream segment.
[3]	The Upstream segment in 2017 includes non-cash impairment charges of $396 million, before tax, associated with the Horn River development and $379 million, before tax, associated with the Mackenzie gas project. The impairment charges are recognized in the lines “Exploration” and “Depreciation and depletion” on the Consolidated statement of income, and the “Accumulated depreciation and depletion” line of the Consolidated balance sheet.
[4]	Amounts to related parties included in purchases of crude oil and products (note 17). 4,092 2,687 2,224
[5]	Amounts to related parties included in production and manufacturing, and selling and general expenses (note 17). 566 544 533
[6]	As part of the implementation of Accounting Standard Update, Compensation – Retirement Benefits (Topic 715), beginning January 1, 2018, Corporate and other includes all non-service pension and postretirement benefit expense. Prior to 2018, the majority of these costs were allocated to the operating segments. See note 2 for additional details.
[7]	The Downstream segment in 2018 includes a non-cash impairment charge of $46 million, before tax, associated with the Government of Ontario’s revocation of its carbon emission cap and trade regulation. The impairment charge is recognized in the “Depreciation and depletion” line on the Consolidated statement of income, and the “Other assets, including intangibles, net” line on the Consolidated balance sheet.
[8]	Prior year amounts have been reclassified (note 2).
[9]	Amounts to related parties included in financing (note 17). 89 60 89
[10]	Cash interest payments in 2018 were $88 million (2017 – $58 million, 2016 – $73 million). The weighted average interest rate on short-term borrowings in 2018 was 1.5 percent (2017 – 0.9 percent, 2016 – 0.8 percent). Average effective rate on the long-term borrowings with ExxonMobil in 2018 was 2.0 percent (2017 – 1.3 percent, 2016 – 1.0 percent).
[11]	Cash outflow from income taxes, plus investment credits earned, was $162 million (2017 - $322 million, 2016 - $172 million).
[12]	On November 2, 2017 the British Columbia government enacted a 1 percent increase in the provincial tax rate from 11 percent to 12 percent.

Consolidated statement of inc_2

Consolidated statement of income (Parenthetical) - CAD ($) $ in Millions	12 Months Ended
	Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016
Amounts from related parties included in revenues (note 17)	$ 6,383	$ 4,110	$ 2,342
Amounts to related parties included in purchases of crude oil and products (note 17)	4,092	2,687	2,224
Amounts to related parties included in production and manufacturing, and selling and general expenses (note 17)	566	544	533
Amounts to related parties included in financing (note 17)	$ 89	$ 60	$ 89

Consolidated statement of compr

Consolidated statement of comprehensive income - CAD ($) $ in Millions	12 Months Ended
	Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016
Net income (loss)	$ 2,314	$ 490	$ 2,165
Other comprehensive income (loss), net of income taxes
Postretirement benefits liability adjustment (excluding amortization)	158	(54)	(210)
Amortization of postretirement benefits liability adjustment included in net periodic benefit costs	140	136	141
Total other comprehensive income (loss)	298	82	(69)
Comprehensive income (loss)	$ 2,612	$ 572	$ 2,096

Consolidated balance sheet

Consolidated balance sheet - CAD ($) $ in Millions		Dec. 31, 2018	Dec. 31, 2017
Current assets
Cash	[1]	$ 988	$ 1,195
Accounts receivable, less estimated doubtful accounts	[2]	2,529	2,712
Inventories of crude oil and products (note 12)		1,297	1,075
Materials, supplies and prepaid expenses		541	425
Total current assets		5,355	5,407
Investments and long-term receivables	[3]	857	865
Property, plant and equipment, less accumulated depreciation and depletion	[4]	34,225	34,473
Goodwill		186	186
Other assets, including intangibles, net (note 6)		833	670
Total assets		41,456	41,601
Current liabilities
Notes and loans payable (note 13)	[5]	202	202
Accounts payable and accrued liabilities (note 12)	[2]	3,688	3,877
Income taxes payable		65	57
Total current liabilities		3,955	4,136
Long-term debt (note 15)	[6]	4,978	5,005
Other long-term obligations (note 6)	[7]	2,943	3,780
Deferred income tax liabilities (note 4)		5,091	4,245
Total liabilities		16,967	17,166
Commitments and contingent liabilities (note 10)
Shareholders' equity
Common shares at stated value (note 11)	[8]	1,446	1,536
Earnings reinvested		24,560	24,714
Accumulated other comprehensive income (loss) (note 18)		(1,517)	(1,815)
Total shareholders' equity		24,489	24,435
Total liabilities and shareholders' equity		$ 41,456	$ 41,601
[1]	Cash is composed of cash in bank and cash equivalents at cost. Cash equivalents are all highly liquid securities with maturity of three months or less when purchased.
[2]	Accounts receivable, less estimated doubtful accounts included net amounts receivable from related parties of $666 million (2017 - $509 million), (note 17).
[3]	Investments and long-term receivables included amounts from related parties of $146 million (2017 – $19 million), (note 17).
[4]	Includes property, plant and equipment under construction of $1,553 million (2017 - $1,047 million, 2016 - $2,705 million).
[5]	Notes and loans payable included amounts to related parties of $75 million (2017 – $75 million), (note 17).
[6]	Long-term debt included amounts to related parties of $4,447 million (2017 – $4,447 million), (note 17).
[7]	Other long-term obligations included amounts to related parties of $15 million (2017 – $60 million), (note 17).
[8]	Number of common shares authorized and outstanding were 1,100 million and 783 million, respectively (2017 – 1,100 million and 831 million, respectively), (note 11).

Consolidated balance sheet (Par

Consolidated balance sheet (Parenthetical) - CAD ($) $ in Millions	Dec. 31, 2018	Dec. 31, 2017
Amounts receivable (payable) from (to) related parties	$ 666	$ 509
Due to related parties, current	$ 75	$ 75
Common shares authorized	1,100,000,000	1,100,000,000
Common shares outstanding	783,000,000	831,000,000
Investments and Long Term Receivables
Due from related parties	$ 146	$ 19
Long-term debt
Due to related parties	4,447	4,447
Other long-term obligations
Due to related parties	$ 15	$ 60

Consolidated statement of share

Consolidated statement of shareholders' equity - CAD ($) $ in Millions	Total	Common shares at stated value (note 11)	Earnings reinvested	Accumulated other comprehensive income (loss) (note 18)
At beginning of year at Dec. 31, 2015		$ 1,566	$ 23,687	$ (1,828)
Net income (loss) for the year	$ 2,165		2,165
Issued under the stock option plan
Other comprehensive income (loss)	(69)			(69)
Share purchases at stated value
Dividends declared			(500)
At end of year at Dec. 31, 2016	25,021	1,566	25,352	(1,897)
Net income (loss) for the year	490		490
Issued under the stock option plan
Other comprehensive income (loss)	82			82
Share purchases in excess of stated value			(597)
Share purchases at stated value		(30)
Dividends declared			(531)
At end of year at Dec. 31, 2017	24,435	1,536	24,714	(1,815)
Net income (loss) for the year	2,314		2,314
Issued under the stock option plan
Other comprehensive income (loss)	298			298
Share purchases in excess of stated value			(1,881)
Share purchases at stated value		(90)
Dividends declared			(587)
At end of year at Dec. 31, 2018	$ 24,489	$ 1,446	$ 24,560	$ (1,517)

Consolidated statement of cash

Consolidated statement of cash flows - CAD ($) $ in Millions		12 Months Ended
		Dec. 31, 2018		Dec. 31, 2017		Dec. 31, 2016
Operating activities
Net income (loss)		$ 2,314		$ 490		$ 2,165
Adjustments for non-cash items:
Depreciation and depletion		1,509		2,172		1,628
Impairment of intangible assets		46
(Gain) loss on asset sales (note 9)	[1],[2]	(54)		(220)		(2,244)
Deferred income taxes and other		806		321		114
Changes in operating assets and liabilities:
Accounts receivable		224		(689)		(442)
Inventories, materials, supplies and prepaid expenses		(338)		(83)		197
Income taxes payable		8		(431)		36
Accounts payable and accrued liabilities		(764)		678		237
All other items - net	[3],[4]	171		525		324
Cash flows from (used in) operating activities		3,922		2,763		2,015
Investing activities
Additions to property, plant and equipment	[4]	(1,491)		(993)		(1,073)
Proceeds from asset sales (note 9)		59		232		3,021
Additional investments				(1)		(1)
Loans to equity company		(127)		(19)
Cash flows from (used in) investing activities		(1,559)		(781)		1,947
Financing activities
Short-term debt - net						(1,749)
Long-term debt - additions (note 15)						495
Long-term debt - reductions (note 15)						(2,000)
Reduction in capitalized lease obligations (note 15)		(27)		(27)		(28)
Dividends paid		(572)		(524)		(492)
Common shares purchased (note 11)		(1,971)		(627)
Cash flows from (used in) financing activities		(2,570)		(1,178)		(3,774)
Increase (decrease) in cash		(207)		804		188
Cash at beginning of year		1,195	[5]	391	[5]	203
Cash at end of year	[5]	$ 988		$ 1,195		$ 391
[1]	2016 included a gain of $2.0 billion ($1.7 billion, after tax) from the sale of company-owned Esso-branded retail sites; and a gain of $161 million ($134 million, after tax) from the sale of Imperial’s general aviation business.
[2]	2017 included a gain of $174 million ($151 million after tax) from the sale of surplus property in Ontario.
[3]	Included contribution to registered pension plans. 203 212 163
[4]	The impact of carbon emission programs are included in additions to property, plant and equipment, and all other items - net.
[5]	Cash is composed of cash in bank and cash equivalents at cost. Cash equivalents are all highly liquid securities with maturity of three months or less when purchased.

Consolidated statement of cas_2

Consolidated statement of cash flows (Parenthetical) - CAD ($) $ in Millions	12 Months Ended
	Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016
Included contribution to registered pension plans	$ 203	$ 212	$ 163
Environmental Obligations
Non-cash adjustments reversed out of accrued liabilities and all other items	$ 570

Summary of significant accounti

Summary of significant accounting policies	12 Months Ended
	Dec. 31, 2018
Summary of significant accounting policies	1. Summary of significant accounting policies Principles of consolidation The consolidated financial statements include the accounts of subsidiaries the company controls. Intercompany accounts and transactions are eliminated. Subsidiaries include those companies in which Imperial has both an equity interest and the continuing ability to unilaterally determine strategic, operating, investing and financing policies. Imperial Oil Resources Limited is the only significant subsidiary included in the consolidated financial statements and is wholly owned by Imperial Oil Limited. The consolidated financial statements also include the company’s share of the undivided interest in certain upstream assets, liabilities, revenues and expenses, including its 25 percent interest in the Syncrude joint venture and its 70.96 percent interest in the Kearl joint venture. Revenues Imperial generally sells crude oil, natural gas and petroleum and chemical products under short-term agreements at prevailing market prices. In some cases, products may be sold under long-term agreements, with periodic price adjustments to reflect market conditions. Revenue is recognized at the amount the company expects to receive when the customer has taken control, which is typically when title transfers and the customer has assumed the risks and rewards of ownership. The prices of certain sales are based on price indices that are sometimes not available until the next period. In such cases, estimated realizations are accrued when the sale is recognized, and are finalized when final information is available. Such adjustments to revenue from performance obligations satisfied in previous periods are not significant. Payment for revenue transactions is typically due within 30 days. Revenues include amounts billed to customers for shipping and handling. Shipping and handling costs incurred up to the point of final storage prior to delivery to a customer are included in “Purchases of crude oil and products” in the Consolidated statement of income. Delivery costs from final storage to customer are recorded as a marketing expense in “Selling and general” expenses. The company does not enter into ongoing arrangements whereby it is required to repurchase its products, nor does the company provide the customer with a right of return. Future volume delivery obligations that are unsatisfied at the end of the period are expected to be fulfilled through ordinary production or purchases. These performance obligations are based on market prices at the time of the transaction and are fully constrained due to market price volatility. Purchases and sales of inventory with the same counterparty that are entered into in contemplation of one another are combined and recorded as exchanges measured at the book value of the item sold. “Revenues” and “Accounts receivable, less estimated doubtful accounts” primarily arise from contracts with customers. Long-term receivables are primarily from non-customers. Contract assets are mainly from marketing assistance programs and are not significant. Contract liabilities are mainly customer prepayments, loyalty programs and accruals of expected volume discounts, and are not significant. Consumer taxes Taxes levied on the consumer and collected by the company are excluded from the Consolidated statement of income. These are primarily provincial taxes on motor fuels, the federal goods and services tax and the federal/provincial harmonized sales tax. Derivative instruments Imperial uses derivative instruments to offset exposures associated with hydrocarbon prices that arise from existing assets, liabilities and forecasted transactions. The gains and losses resulting from changes in the fair value of derivatives are recorded under “Revenues” or “Purchases of crude oil and products” on the Consolidated statement of income. The company does not currently make use of derivative instruments to offset exposures associated with foreign currency and interest rates. Fair value Fair value is the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants. Hierarchy Levels 1, 2 and 3 are terms for the priority of inputs to valuation techniques used to measure fair value. Hierarchy Level 1 inputs are quoted prices in active markets for identical assets or liabilities. Hierarchy Level 2 inputs are inputs other than quoted prices included within Level 1 that are directly or indirectly observable for the asset or liability. Hierarchy Level 3 inputs are inputs that are not observable in the market. Inventories Inventories are recorded at the lower of current market value or cost. The cost of crude oil and products is determined primarily using the last-in, first-out (LIFO) method. LIFO was selected over the alternative first-in, first-out and average cost methods because it provides a better matching of current costs with the revenues generated in the period. Inventory costs include expenditures and other charges (including depreciation), directly or indirectly incurred in bringing the inventory to its existing condition and location. Selling and general expenses are reported as period costs and excluded from inventory costs. Investments The company’s interests in the underlying net assets of affiliates it does not control, but over which it exercises significant influence, are accounted for using the equity method. They are recorded at the original cost of the investment plus Imperial’s share of earnings since the investment was made, less dividends received. Imperial’s share of the after-tax earnings of these investments is included in “Investment and other income” in the Consolidated statement of income. Investments in equity securities, other than consolidated subsidiaries and equity method investments, are measured at fair value, with changes in the fair value recognized in net income. The company uses a modified approach for equity securities that do not have a readily determinable fair value. This modified approach measures investments at cost minus impairment, if any, plus or minus changes resulting from observable price changes in orderly transactions in similar investment of the same issuer. Dividends from these investments are included in “Investment and other income”. These investments represent interests in non-publicly traded pipeline companies and a rail loading joint venture that facilitate the sale and purchase of liquids in the conduct of company operations. Other parties who also have an equity interest in these investments share in the risks and rewards according to their percentage of ownership. Imperial does not invest in these investments in order to remove liabilities from its balance sheet. Property, plant and equipment Cost basis Imperial uses the “successful efforts” method to account for its exploration and production activities. Under this method, costs are accumulated on a field-by-field basis. Costs incurred to purchase, lease, or otherwise acquire a property (whether unproved or proved) are capitalized when incurred. Exploratory well costs are carried as an asset when the well has found a sufficient quantity of reserves to justify its completion as a producing well and where the company is making sufficient progress assessing the reserves and the economic and operating viability of the project. Exploratory well costs not meeting these criteria are charged to expense. Other exploratory expenditures, including geophysical costs and annual lease rentals, are expensed as incurred. Development costs, including costs of productive wells and development dryholes, are capitalized. Maintenance and repair costs, including planned major maintenance, are expensed as incurred. Improvements that increase or prolong the service life or capacity of an asset are capitalized. Depreciation, depletion and amortization Depreciation, depletion and amortization are primarily determined under either the unit-of-production method or the straight-line method, which is based on estimated asset service life taking obsolescence into consideration. Depreciation and depletion for assets associated with producing properties begin at the time when production commences on a regular basis. Depreciation for other assets begins when the asset is in place and ready for its intended use. Assets under construction are not depreciated or depleted. Acquisition costs of proved properties are amortized using a unit-of-production method, computed on the basis of total proved oil and gas reserves. Capitalized exploratory drilling and development costs associated with productive depletable extractive properties are amortized using the unit-of-production rates based on the amount of proved developed reserves of oil and gas that are estimated to be recoverable from existing facilities using current operating methods. Under the unit-of-production method, oil and gas volumes are considered produced once they have been measured through meters at custody transfer or sales transaction points at the outlet valve on the lease or field storage tank. In the event that the unit-of-production method does not result in an equitable allocation of cost over the economic life of an upstream asset, an alternative method is used. The straight-line method is used in limited situations where the expected life of the asset does not reasonably correlate with that of the underlying reserves. For example, certain assets used in the production of oil and natural gas have a shorter life than the reserves, and as such, the company uses straight-line depreciation to ensure the asset is fully depreciated by the end of its useful life. Investments in mining heavy equipment and certain ore processing plant assets at oil sands mining properties are depreciated on a straight-line basis over a maximum of 15 years and 50 years respectively. Depreciation of other plant and equipment is calculated using the straight-line method, based on the estimated service life of the asset. To the extent that proved reserves for a property are substantially de-booked and that property continues to produce such that the resulting depreciation charge does not result in an equitable allocation of cost over the expected life, assets will be depreciated using a unit-of-production method based on reserves determined at the most recent SEC price which results in a more meaningful quantity of proved reserves, appropriately adjusted for production and technical changes. This approach was applied in 2017 and 2018, with the corresponding effect on depreciation expense immaterial when compared to the prior periods. In 2019, all properties have sufficient reserves at current SEC prices which will enable equitable allocation of cost over the economic lives of the Upstream assets. The effect of this approach on the company’s 2019 depreciation expense compared to 2018 is anticipated to be immaterial. Investments in refinery, chemical process, and lubes basestock manufacturing equipment are generally depreciated on a straight-line basis over a 25-year life. Maintenance and repairs, including planned major maintenance, are expensed as incurred. Major renewals and improvements are capitalized and the assets replaced are retired. Impairment assessment The company tests assets or groups of assets for recoverability on an ongoing basis whenever events or changes in circumstances indicate the carrying amounts may not be recoverable. Among the events or changes in circumstances which could indicate that the carrying value of an asset or asset group may not be recoverable are the following: ● A significant decrease in the market price of a long-lived asset; ● A significant adverse change in the extent or manner in which an asset is being used or in its physical condition including a significant decrease in the company’s current and projected reserve volumes; ● A significant adverse change in legal factors or in the business climate that could affect the value, including a significant adverse action or assessment by a regulator; ● An accumulation of project costs significantly in excess of the amount originally expected; ● A current-period operating loss combined with a history and forecast of operating or cash flow losses; and ● A current expectation that, more likely than not, a long-lived asset will be sold or otherwise disposed of significantly before the end of its previously estimated useful life. Asset valuation analyses performed as part of the company’s asset management program and other profitability reviews assist Imperial in assessing whether events or changes in circumstances indicate the carrying amounts of any of its assets may not be recoverable. In general, Imperial does not view temporarily low prices or margins as an indication of impairment. Management believes prices over the long-term must be sufficient to generate investments in energy supply to meet global demand. Although prices will occasionally drop significantly, industry prices over the long-term will continue to be driven by market supply and demand fundamentals. On the supply side, industry production from mature fields is declining. This is being offset by investments to generate production from new discoveries, field developments and technological and efficiency advancements. OPEC investment activities and production policies also have an impact on world oil supplies. The demand side is largely a function of general economic activities and levels of prosperity. Because the lifespans of the company’s major assets are measured in decades, the value of these assets is predominantly based on long-term views of future commodity prices and production costs. During the lifespan of these major assets, the company expects that oil and gas prices will experience significant volatility, and consequently these assets will experience periods of higher earnings and periods of lower earnings, or even losses. In assessing whether the events or changes in circumstances indicate the carrying value of an asset may not be recoverable, the company considers recent periods of operating losses in the context of its longer-term view of prices. While near-term prices are subject to wide fluctuations, longer term price views are more stable and meaningful for purposes of assessing future cash flows. When the industry experiences a prolonged and deep reduction in commodity prices, the market supply and demand conditions may result in changes to the company’s long-term price or margin assumptions it uses for its capital investment decisions. To the extent those changes result in a significant reduction to its long-term oil prices or natural gas prices or margin ranges, the company may consider that situation, in conjunction with other events or changes in circumstances such as a history of operating losses, as an indicator of potential impairment for certain assets. In the upstream, the standardized measure of discounted cash flows included in the “Supplemental information on oil and gas exploration and production activities” is required to use prices based on the yearly average of first-of-month prices. These prices represent discrete points in time and could be higher or lower than the company’s long-term price assumptions which are used for impairment assessments. The company believes the standardized measure does not provide a reliable estimate of the expected future cash flows to be obtained from the development and production of its oil and gas properties or of the value of its oil and gas reserves and therefore does not consider it relevant in determining whether events or changes in circumstances indicate the need for an impairment assessment. If events or changes in circumstances indicate that the carrying value of an asset may not be recoverable, the company estimates the future undiscounted cash flows of the affected properties to judge the recoverability of carrying amounts. In performing this assessment, assets are grouped at the lowest level for which there are identifiable cash flows that are largely independent of the cash flows of other groups of assets. Cash flows used in recoverability assessments are based on the company’s assumptions which are developed in the annual planning and budgeting process, and are consistent with the criteria management uses to evaluate investment opportunities. These evaluations make use of the company’s assumptions of future capital allocations, crude oil and natural gas commodity prices, refining and chemical margins, volumes, costs, foreign currency exchange rates and inflation rates. Volumes are based on projected field and facility production profiles, throughput, or sales. Where unproved reserves exist, an appropriately risk-adjusted amount of these reserves may be included in the evaluation. Cash flow estimates for impairment testing exclude the effects of derivative instruments. An asset group is impaired if its estimated future undiscounted cash flows are less than the asset group’s carrying value. Impairments are measured by the amount by which the carrying value exceeds fair value. Fair value is based on market prices if an active market exists for the asset group or discounted cash flows using a discount rate commensurate with the risk. Significant unproved properties are assessed for impairment individually, and valuation allowances against the capitalized costs would be recorded based on the estimated economic chance of success and the length of time that the company expects to hold the properties. Properties that are not individually significant are aggregated by groups and amortized based on development risk and average holding period. Gains on sales of proved and unproved properties are only recognized when there is neither uncertainty about the recovery of costs applicable to any interest retained nor any substantial obligation for future performance by the company. Losses on properties sold are recognized when incurred or when the properties are held for sale and the fair value of the properties is less than the carrying value. Gains or losses on assets sold are included in “Investment and other income” in the Consolidated statement of income. Interest capitalization Interest costs incurred to finance expenditures during the construction phase of projects are capitalized as part of property, plant and equipment and are depreciated over the service life of the related assets. The project construction phase commences with the development of the detailed engineering design and ends when the constructed assets are ready for their intended use. Goodwill and other intangible assets Goodwill is not subject to amortization. Goodwill is tested for impairment annually or more frequently if events or circumstances indicate it might be impaired. Impairment losses are recognized in current period earnings. The evaluation for impairment of goodwill is based on a comparison of the carrying values of goodwill and associated operating assets with the estimated present value of net cash flows from those operating assets. Intangible assets with determinable useful lives are amortized over the estimated service lives of the assets. Computer software development costs are amortized over a maximum of 15 years and customer lists are amortized over a maximum of 10 years. The amortization is included in “Depreciation and depletion” in the Consolidated statement of income. Asset retirement obligations and other environmental liabilities Legal obligations associated with site restoration on the retirement of assets with determinable useful lives are recognized when they are incurred, which is typically at the time the assets are installed. These obligations primarily relate to soil reclamation and remediation, and costs of abandonment and demolition of oil and gas wells and related facilities. The company uses estimates, assumptions and judgments regarding such factors as the existence of a legal obligation for an asset retirement obligation, technical assessments of the assets, estimated amounts and timing of settlements, the credit-adjusted risk-free rate to be used, and inflation rates. The obligations are initially measured at fair value and discounted to present value. A corresponding amount equal to that of the initial obligation is added to the capitalized costs of the related asset. Over time, the discounted asset retirement obligation amount will be accreted for the change in its present value, and the initial capitalized costs will be depreciated over the useful lives of the related assets. No asset retirement obligations are set up for those manufacturing, distribution, marketing and office facilities with an indeterminate useful life. Asset retirement obligations for these facilities generally become firm at the time the facilities are permanently shut down and dismantled. These obligations may include the costs of asset disposal and additional soil remediation. However, these sites have indeterminate lives based on plans for continued operations, and as such, the fair value of the conditional legal obligations cannot be measured, since it is impossible to estimate the future settlement dates of such obligations. Provision for environmental liabilities of these assets is made when it is probable that obligations have been incurred and the amount can be reasonably estimated. Provisions for environmental liabilities are determined based on engineering estimated costs, taking into account the anticipated method and extent of remediation consistent with legal requirements, current technology and the possible use of the location. These provisions are not reduced by possible recoveries from third parties and projected cash expenditures are not discounted. Foreign-currency translation Monetary assets and liabilities in foreign currencies have been translated at the rates of exchange prevailing on December 31. Any exchange gains or losses are recognized in income. Share-based compensation The company awards share-based compensation to certain employees in the form of restricted stock units. Compensation expense is measured each reporting period based on the company’s current stock price and is recorded as “Selling and general” expenses in the Consolidated statement of income over the requisite service period of each award. See note 8 to the consolidated financial statements on page 84 for further details. Recently issued accounting standards Effective January 1, 2019, Imperial adopted the Financial Accounting Standards Board’s standard, Leases (Topic 842)

Accounting changes

Accounting changes	12 Months Ended
	Dec. 31, 2018
Accounting changes	2. Accounting changes Effective January 1, 2018, Imperial adopted the Financial Accounting Standards Board’s standard, Revenue from Contracts with Customers (Topic 606), Effective January 1, 2018, Imperial adopted the Financial Accounting Standards Board’s standard update, Compensation – Retirement Benefits (Topic 715): Improving the Presentation of Net Periodic Pension Cost and Net Periodic Postretirement Benefit Cost The impact of the retrospective presentation change on Imperial’s Consolidated statement of income for the years ended December 31, is shown below. millions of Canadian dollars 2017 2016 As reported Change As adjusted As reported Change As adjusted Production and manufacturing 5,698 (112 ) 5,586 5,224 (119 ) 5,105 Selling and general 893 (10 ) 883 1,129 (11 ) 1,118 Non-service pension and postretirement benefit - 122 122 - 130 130 Effective January 1, 2018, Imperial adopted the Financial Accounting Standards Board’s standard update, Financial Instruments - Overall (Subtopic 825-10): Recognition and Measurement of Financial Assets and Financial Liabilities

Business segments

Business segments	12 Months Ended
	Dec. 31, 2018
Business segments	3. Business segments The company operates its business in Canada. The Upstream, Downstream and Chemical functions best define the operating segments of the business that are reported separately. The factors used to identify these reportable segments are based on the nature of the operations that are undertaken by each segment and the structure of the company’s internal organization. The Upstream segment is organized and operates to explore for and ultimately produce crude oil and its equivalent, and natural gas. The Downstream segment is organized and operates to refine crude oil into petroleum products and to distribute and market these products. The Chemical segment is organized and operates to manufacture and market hydrocarbon-based chemicals and chemical products. The above segmentation has been the long-standing practice of the company and is broadly understood across the petroleum and petrochemical industries. These functions have been defined as the operating segments of the company because they are the segments (a) that engage in business activities from which revenues are earned and expenses are incurred; (b) whose operating results are regularly reviewed by the company’s chief operating decision maker to make decisions about resources to be allocated to each segment and assess its performance; and (c) for which discrete financial information is available. Corporate and other includes assets and liabilities that do not specifically relate to business segments – primarily cash, capitalized interest costs, short-term borrowings, long-term debt and liabilities associated with incentive compensation and postretirement benefits liability adjustment. Net earnings effects under Corporate and other activities primarily include debt-related financing, corporate governance costs, non-service pension and postretirement benefit costs, share-based incentive compensation expenses and interest income. Segment accounting policies are the same as those described in the summary of significant accounting policies. Upstream, Downstream and Chemical expenses include amounts allocated from Corporate and other activities. The allocation is based on proportional segment expenses. Transfers of assets between segments are recorded at book amounts. Intersegment sales are made essentially at prevailing market prices. Assets and liabilities that are not identifiable by segment are allocated. Upstream Downstream Chemical millions of Canadian dollars 2018 2017 2016 2018 2017 2016 2018 2017 2016 Revenues and other income Revenues (a) 8,525 7,302 5,492 25,200 20,714 18,511 1,239 1,109 1,046 Intersegment sales 2,634 2,264 2,215 1,542 1,155 1,007 279 262 212 Investment and other income (note 9) 11 16 13 95 269 2,278 - - - 11,170 9,582 7,720 26,837 22,138 21,796 1,518 1,371 1,258 Expenses Exploration (b) (note 16) 19 183 94 - - - - - - Purchases of crude oil and products 5,833 4,526 3,666 19,326 16,543 14,178 831 751 705 Production and manufacturing (c) 4,305 3,913 3,591 1,606 1,576 1,428 210 209 205 Selling and general (c) - - (5 ) 773 772 972 87 78 83 Federal excise tax - - - 1,667 1,673 1,650 - - - Depreciation and depletion (b) (d) 1,278 1,939 1,396 242 202 206 14 12 10 Non-service pension and postretirement benefit (c) - - - - - - - - - Financing (note 13) 1 13 (7 ) 2 - - - - - Total expenses 11,436 10,574 8,735 23,616 20,766 18,434 1,142 1,050 1,003 Income (loss) before income taxes (266 ) (992 ) (1,015 ) 3,221 1,372 3,362 376 321 255 Income taxes Current (184 ) 484 (491 ) 189 (504 ) 674 21 (32 ) 68 Deferred 56 (770 ) 137 666 836 (66 ) 80 118 - Total income tax expense (benefit) (128 ) (286 ) (354 ) 855 332 608 101 86 68 Net income (loss) (138 ) (706 ) (661 ) 2,366 1,040 2,754 275 235 187 Cash flows from (used in) operating activities 916 1,257 402 2,749 1,396 1,574 354 235 203 Capital and exploration expenditures 991 416 896 383 200 190 25 17 26 Property, plant and equipment Cost 46,435 45,542 45,850 5,900 5,683 6,166 916 888 872 Accumulated depreciation and depletion (15,050 ) (13,844 ) (12,312 ) (3,763 ) (3,594 ) (4,037 ) (662 ) (644 ) (629 ) Net property, plant and equipment 31,385 31,698 33,538 2,137 2,089 2,129 254 244 243 Total assets 34,829 35,044 36,840 5,119 4,890 3,958 438 399 346 Corporate and other Eliminations Consolidated millions of Canadian dollars 2018 2017 2016 2018 2017 2016 2018 2017 2016 Revenues and other income Revenues (a) - - - - - - 34,964 29,125 25,049 Intersegment sales - - - (4,455 ) (3,681 ) (3,434 ) - - - Investment and other income (note 9) 29 14 14 - - - 135 299 2,305 29 14 14 (4,455 ) (3,681 ) (3,434 ) 35,099 29,424 27,354 Expenses Exploration (b) (note 16) - - - - - - 19 183 94 Purchases of crude oil and products - - - (4,449 ) (3,675 ) (3,429 ) 21,541 18,145 15,120 Production and manufacturing (c) - - - - - - 6,121 5,698 5,224 Selling and general (c) 54 49 84 (6 ) (6 ) (5 ) 908 893 1,129 Federal excise tax - - - - - - 1,667 1,673 1,650 Depreciation and depletion (b) (d) 21 19 16 - - - 1,555 2,172 1,628 Non-service pension and postretirement benefit (c) 107 - - - - - 107 - - Financing (note 13) 105 65 72 - - - 108 78 65 Total expenses 287 133 172 (4,455 ) (3,681 ) (3,434 ) 32,026 28,842 24,910 Income (loss) before income taxes (258 ) (119 ) (158 ) - - - 3,073 582 2,444 Income taxes Current (40 ) (6 ) (51 ) - - - (14 ) (58 ) 200 Deferred (29 ) (34 ) 8 - - - 773 150 79 Total income tax expense (benefit) (69 ) (40 ) (43 ) - - - 759 92 279 Net income (loss) (189 ) (79 ) (115 ) - - - 2,314 490 2,165 Cash flows from (used in) operating activities (116 ) (125 ) (143 ) 19 - (21 ) 3,922 2,763 2,015 Capital and exploration expenditures 28 38 49 - - - 1,427 671 1,161 Property, plant and equipment Cost 693 665 627 - - - 53,944 52,778 53,515 Accumulated depreciation and depletion (244 ) (223 ) (204 ) - - - (19,719 ) (18,305 ) (17,182 ) Net property, plant and equipment 449 442 423 - - - 34,225 34,473 36,333 Total assets 1,548 1,703 894 (478 ) (435 ) (384 ) 41,456 41,601 41,654 (a) Includes export sales to the United States of $6,661 million (2017 - $4,392 million, 2016 - $3,612 million). Export sales to the United States were recorded in all operating segments, with the largest effects in the Upstream segment. (b) The Upstream segment in 2017 includes non-cash impairment charges of $396 million, before tax, associated with the Horn River development and $379 million, before tax, associated with the Mackenzie gas project. The impairment charges are recognized in the lines “Exploration” and “Depreciation and depletion” on the Consolidated statement of income, and the “Accumulated depreciation and depletion” line of the Consolidated balance sheet. (c) As part of the implementation of Accounting Standard Update, Compensation – Retirement Benefits (Topic 715), beginning January 1, 2018, Corporate and other includes all non-service pension and postretirement benefit expense. Prior to 2018, the majority of these costs were allocated to the operating segments. See note 2 for additional details. (d) The Downstream segment in 2018 includes a non-cash impairment charge of $46 million, before tax, associated with the Government of Ontario’s revocation of its carbon emission cap and trade regulation. The impairment charge is recognized in the “Depreciation and depletion” line on the Consolidated statement of income, and the “Other assets, including intangibles, net” line on the Consolidated balance sheet. (e) Capital and exploration expenditures (CAPEX) include exploration expenses, additions to property, plant and equipment, additions to capital leases, additional investments and acquisitions. CAPEX excludes the purchase of carbon emission credits. (f) Includes property, plant and equipment under construction of $1,553 million (2017 - $1,047 million, 2016 - $2,705 million).

Income taxes

Income taxes	12 Months Ended
	Dec. 31, 2018
Income taxes	4. Income taxes millions of Canadian dollars 2018 2017 2016 Current income tax expense (a) (14 ) (58 ) 200 Deferred income tax expense (a) 773 150 79 Total income tax expense (a) (b) 759 92 279 Statutory corporate tax rate (percent) 26.9 26.9 26.8 Increase (decrease) resulting from: Disposals (c) (0.3 ) (5.3 ) (11.6 ) Enacted tax rate change (a) - 0.9 - Other (1.9 ) (6.6 ) (3.8 ) Effective income tax rate 24.7 15.9 11.4 (a) On November 2, 2017 the British Columbia government enacted a 1 percent increase in the provincial tax rate from 11 percent to 12 percent. (b) Cash outflow from income taxes, plus investment credits earned, was $162 million (2017 - $322 million, 2016 - $172 million). (c) 2017 disposals are primarily associated with the sale of surplus property in Ontario. 2016 disposals are primarily associated with the sales of company-owned Esso retail sites and the general aviation business. Capital gains tax treatment was applied on the majority of disposals. In 2018, 2017 and 2016, the decrease in the statutory tax rate in the other category mainly represents prior year adjustments and re-assessments. Deferred income taxes are based on differences between the accounting and tax values of assets and liabilities. These differences in value are re-measured at each year-end using the tax rates and tax laws expected to apply when those differences are realized or settled in the future. Components of deferred income tax liabilities and assets as at December 31 were: millions of Canadian dollars 2018 2017 2016 Depreciation and amortization 5,726 5,564 5,361 Successful drilling and land acquisitions 856 762 891 Pension and benefits (336 ) (422 ) (457 ) Asset retirement obligation (381 ) (376 ) (396 ) Capitalized interest 121 118 114 LIFO inventory valuation (107 ) (318 ) (240 ) Tax loss carryforwards (658 ) (936 ) (1,056 ) Other (150 ) (196 ) (212 ) Net deferred income tax liabilities 5,071 4,196 4,005 Unrecognized tax benefits Unrecognized tax benefits reflect the difference between positions taken or expected to be taken on income tax returns and the amounts recognized in the financial statements. The following table summarizes the movement in unrecognized tax benefits: millions of Canadian dollars 2018 2017 2016 Balance as of January 1 78 106 132 Additions for prior years’ tax position 9 2 2 Reductions for prior years’ tax positions (2 ) - (18 ) Reductions due to lapse of the statute of limitations - - (5 ) Settlements with tax authorities (49 ) (30 ) (5 ) Balance as of December 31 36 78 106 The unrecognized tax benefit balances shown above are predominately related to tax positions that would reduce the company’s effective tax rate if the positions are favourably resolved. Unfavourable resolution of these tax positions generally would not increase the effective tax rate. The 2018, 2017 and 2016 changes in unrecognized tax benefits did not have a material effect on the company’s net income or cash flow. The company’s tax filings from 2011 to 2018 are subject to examination by the tax authorities. Tax filings from 2003 to 2010 have open objections and therefore are also subject to examination by the tax authorities. The Canada Revenue Agency has proposed certain adjustments to the company’s filings. Management is currently evaluating those proposed adjustments and believes that a number of outstanding matters are expected to be resolved in 2019. The impact on unrecognized tax benefits and the company’s effective income tax rate from these matters is not expected to be material. Resolution of the related tax positions could take many years to complete. It is difficult to predict the timing of resolution for tax positions since such timing is not entirely within the control of the company. The company classifies interest on income tax related balances as interest expense or interest income and classifies tax related penalties as operating expense.

Employee retirement benefits

Employee retirement benefits	12 Months Ended
	Dec. 31, 2018
Employee retirement benefits	5. Employee retirement benefits Retirement benefits, which cover almost all retired employees and their surviving spouses, include pension income and certain health care and life insurance benefits. They are met through funded registered retirement plans and through unfunded supplementary benefits that are paid directly to recipients. Pension income benefits consist mainly of company-paid defined benefit plans that are based on years of service and final average earnings. The company shares in the cost of health care and life insurance benefits. The company’s benefit obligations are based on the projected benefit method of valuation that includes employee service to date and present compensation levels, as well as a projection of salaries to retirement. The expense and obligations for both funded and unfunded benefits are determined in accordance with accepted actuarial practices and U.S. GAAP. The process for determining retirement-income expense and related obligations includes making certain long-term assumptions regarding the discount rate, rate of return on plan assets and rate of compensation increases. The obligation and pension expense can vary significantly with changes in the assumptions used to estimate the obligation and the expected return on plan assets. The benefit obligations and plan assets associated with the company’s defined benefit plans are measured on December 31. Pension benefits Other postretirement 2018 2017 2018 2017 Assumptions used to determine benefit obligations at December 31 (percent) Discount rate 3.90 3.40 3.90 3.40 Long-term rate of compensation increase 4.50 4.50 4.50 4.50 millions of Canadian dollars Change in projected benefit obligation Projected benefit obligation at January 1 8,785 8,356 670 706 Current service cost 239 217 17 16 Interest cost 302 313 22 23 Actuarial loss (gain) (498 ) 415 (101 ) (49 ) Benefits paid (a) (469 ) (516 ) (26 ) (26 ) Projected benefit obligation at December 31 8,359 8,785 582 670 Accumulated benefit obligation at December 31 7,661 8,043 The discount rate for the purpose of calculating year-end Pension benefits Other postretirement benefits millions of Canadian dollars 2018 2017 2018 2017 Change in plan assets Fair value at January 1 7,870 7,359 Actual return (loss) on plan assets 20 700 Company contributions 203 212 Benefits paid (b) (402 ) (401 ) Fair value at December 31 7,691 7,870 Plan assets in excess of (less than) projected benefit obligation at December 31 Funded plans (180 ) (408 ) Unfunded plans (488 ) (507 ) (582 ) (670 ) Total (c) (668 ) (915 ) (582 ) (670 ) (a) Benefit payments for funded and unfunded plans. (b) Benefit payments for funded plans only. (c) Fair value of assets less projected benefit obligation shown above. Funding of registered retirement plans complies with federal and provincial pension regulations, and the company makes contributions to the plans based on an independent actuarial valuation. In accordance with authoritative guidance relating to the accounting for defined pension and other postretirement benefits plans, the underfunded status of the company’s defined benefit postretirement plans was recorded as a liability in the Consolidated balance sheet, and the changes in that funded status in the year in which the changes occurred was recognized through other comprehensive income. Pension benefits Other postretirement benefits millions of Canadian dollars 2018 2017 2018 2017 Amounts recorded in the Consolidated balance sheet consist of: Current liabilities (27 ) (28 ) (28 ) (28 ) Other long-term obligations (641 ) (887 ) (554 ) (642 ) Total recorded (668 ) (915 ) (582 ) (670 ) Amounts recorded in accumulated other comprehensive income consist of: Net actuarial loss (gain) 2,117 2,408 33 140 Prior service cost - 4 - - Total recorded in accumulated other comprehensive income, before tax 2,117 2,412 33 140 The company establishes the long-term expected rate of return on plan assets by developing a forward-looking long-term return assumption for each asset class, taking into account factors such as the expected real return for the specific asset class and inflation. A single, long-term rate of return is then calculated as the weighted average of the target asset allocation percentages and the long-term return assumption for each asset class. The 2018 long-term expected return of 5.0 percent used in the calculations of pension expense compares to an actual rate of return of 8.2 percent and 6.6 percent over the last 10- 20-year Pension benefits Other postretirement benefits millions of Canadian dollars 2018 2017 2016 2018 2017 2016 Assumptions used to determine net periodic benefit cost for years ended December 31 (percent) Discount rate 3.40 3.75 4.00 3.40 3.75 4.00 Long-term rate of return on funded assets 5.00 5.50 5.50 - - - Long-term rate of compensation increase 4.50 4.50 4.50 4.50 4.50 4.50 millions of Canadian dollars Components of net periodic benefit cost Current service cost 239 217 203 17 16 16 Interest cost 302 313 319 22 23 27 Expected return on plan assets (402 ) (408 ) (400 ) - - - Amortization of prior service cost 4 10 9 - - - Amortization of actuarial loss (gain) 175 176 162 6 8 13 Net periodic benefit cost 318 308 293 45 47 56 Changes in amounts recorded in accumulated other comprehensive income Net actuarial loss (gain) (116 ) 123 241 (101 ) (49 ) 46 Amortization of net actuarial (loss) gain included in net periodic benefit cost (175 ) (176 ) (162 ) (6 ) (8 ) (13 ) Amortization of prior service cost included in net periodic benefit cost (4 ) (10 ) (9 ) - - - Total recorded in other comprehensive income (295 ) (63 ) 70 (107 ) (57 ) 33 Total recorded in net periodic benefit cost and other comprehensive income, before tax 23 245 363 (62 ) (10 ) 89 Costs for defined contribution plans, primarily the employee savings plan, were $41 million in 2018 (2017 - $40 million, 2016 - $44 million). A summary of the change in accumulated other comprehensive income is shown in the table below: Total pension and other millions of Canadian dollars 2018 2017 2016 (Charge) credit to other comprehensive income, before tax 402 120 (103 ) Deferred income tax (charge) credit (note 18) (104 ) (38 ) 34 (Charge) credit to other comprehensive income, after tax 298 82 (69 ) The company’s investment strategy for pension plan assets reflects a long-term view, a careful assessment of the risks inherent in various asset classes and broad diversification to reduce the risk of the portfolio. Consistent with the long-term nature of the liability, the plan assets are primarily invested in global, market-cap-weighted The 2018 fair value of the pension plan assets, including the level within the fair value hierarchy, is shown in the table below: Fair value measurements at December 31, 2018, using: millions of Canadian dollars Total Level 1 Level 2 Level 3 Net Asset Asset class Equity securities Canadian 170 - - - 170 Non-Canadian 2,035 - - - 2,035 Debt securities - Canadian Corporate 1,231 - - - 1,231 Government 3,987 - - - 3,987 Asset backed 3 - - - 3 Equities – Venture capital 226 - - - 226 Cash 39 33 - - 6 Total plan assets at fair value 7,691 33 - - 7,658 The 2017 fair value of the pension plan assets, including the level within the fair value hierarchy, is shown in the table below: Fair value measurements at December 31, 2017, using: millions of Canadian dollars Total Level 1 Level 2 Level 3 Net Asset Asset class Equity securities Canadian 182 - - - 182 Non-Canadian 2,138 - - - 2,138 Debt securities - Canadian Corporate 1,248 - - - 1,248 Government 4,016 - - - 4,016 Asset backed - - - - - Equities – Venture capital 215 - - - 215 Cash 71 34 - - 37 Total plan assets at fair value 7,870 34 - - 7,836 A summary of pension plans with accumulated benefit obligations in excess of plan assets is shown in the table below: Pension benefits millions of Canadian dollars 2018 2017 For funded pension plans with accumulated benefit obligations in excess of plan assets: Projected benefit obligation - - Accumulated benefit obligation - - Fair value of plan assets - - Accumulated benefit obligation less fair value of plan assets - - For unfunded plans covered by book reserves: Projected benefit obligation 488 507 Accumulated benefit obligation 451 480 Estimated 2019 amortization from accumulated other comprehensive income millions of Canadian dollars Pension benefits Other postretirement benefits Net actuarial loss (gain) (a) 150 2 (a) The company amortizes the net balance of actuarial loss (gain) as a component of net periodic benefit cost over the average remaining service period of active plan participants. Cash flows Benefit payments expected in: millions of Canadian dollars Pension benefits Other postretirement benefits 2019 435 28 2020 435 29 2021 440 29 2022 440 29 2023 440 29 2024 - 2028 2,170 150 In 2019, the company expects to make cash contributions of about $212 million to its pension plans. Sensitivities A one percent change in the assumptions at which retirement liabilities could be effectively settled is as follows: Increase (decrease) millions of Canadian dollars One percent increase One percent decrease Rate of return on plan assets: Effect on net benefit cost, before tax (80 ) 80 Discount rate: Effect on net benefit cost, before tax (95 ) 130 Effect on benefit obligation (1,110 ) 1,425 Rate of pay increases: Effect on net benefit cost, before tax 65 (50 ) Effect on benefit obligation 255 (215 ) A one percent change in the assumed health-care cost trend rate would have the following effects: Increase (decrease) millions of Canadian dollars One percent increase One percent decrease Effect on service and interest cost components 6 (5 ) Effect on benefit obligation 65 (50 )

Other long-term obligations

Other long-term obligations	12 Months Ended
	Dec. 31, 2018
Other long-term obligations	6. Other long-term obligations millions of Canadian dollars 2018 2017 Employee retirement benefits (a) (note 5) 1,195 1,529 Asset retirement obligations and other environmental liabilities (b) (d) 1,435 1,460 Share-based incentive compensation liabilities (note 8) 78 99 Other obligations (c) 235 692 Total other long-term obligations 2,943 3,780 (a) Total recorded employee retirement benefits obligations also included $55 million in current liabilities (2017 – $56 million). (b) Total asset retirement obligations and other environmental liabilities also included $118 million in current liabilities (2017 – $101 million). (c) Included carbon emission program obligations. Carbon emission program credits are recorded under other assets, including intangibles, net. (d) For 2018, the asset retirement obligations were discounted at 6 percent (2017 - 6 percent). Asset retirement obligations incurred in the current period were Level 3 fair value measurements. The following table summarizes the activity in the liability for asset retirement obligations: millions of Canadian dollars 2018 2017 Balance as at January 1 1,397 1,472 Additions (deductions) (5 ) (124 ) Accretion 85 92 Settlement (60 ) (43 ) Balance as at December 31 1,417 1,397

Financial and derivative instru

Financial and derivative instruments	12 Months Ended
	Dec. 31, 2018
Financial and derivative instruments	7. Financial and derivative instruments Financial instruments The fair value of the company’s financial instruments is determined by reference to various market data and other appropriate valuation techniques. There are no material differences between the fair value of the company’s financial instruments and the recorded carrying value. At December 31, 2018, the fair value of long-term debt ($4,447 million, excluding capitalized lease obligations) was primarily a level 2 measurement. Derivative instruments The company’s size, strong capital structure and the complementary nature of the Upstream, Downstream and Chemical businesses reduce the company’s enterprise-wide risk from changes in commodity prices and currency exchange rates. The company uses derivatives instruments to offset exposures associated with hydrocarbon prices that arise from existing assets, liabilities and forecasted transactions. Credit risk associated with the company’s derivative position is mitigated by several factors, including the use of derivative clearing exchanges and the quality of and financial limits placed on derivative counterparties. The company believes there are no material market or credit risks to the company’s financial position, results of operations or liquidity as a result of the derivatives. The company maintains a system of controls that includes the authorization, reporting and monitoring of derivative activity. The company does not designate derivative instruments as a hedge for hedge accounting purposes. Derivative instruments are currently not subject to a master netting agreement, and Imperial has not offset collateral against the carrying value of the derivatives. The carrying values of derivative instruments on the Consolidated balance sheet were gross assets of $31 million (2017 - $0 million) and gross liabilities of $15 million (2017 - $4 million) at year-end. At December 31, 2018, the net notional forward long / (short) position of derivative instruments was (340,000) barrels for crude and was (350,000) barrels for products. Realized and unrealized gain or (loss) on derivative instruments recognized in the Consolidated statement of income is included in the following lines on a before-tax basis: millions of Canadian dollars 2018 2017 2016 Revenues 6 - - Purchases of crude oil and products (24 ) (5 ) - Total (18 ) (5 ) -

Share-based incentive compensat

Share-based incentive compensation programs	12 Months Ended
	Dec. 31, 2018
Share-based incentive compensation programs	8. Share-based incentive compensation programs Share-based incentive compensation programs are designed to retain selected employees, reward them for high performance and promote individual contribution to sustained improvement in the company’s future business performance and shareholder value over the long-term. The nonemployee directors also participate in share-based incentive compensation programs. Restricted stock units and deferred share units Under the restricted stock unit plan, each unit entitles the recipient to the conditional right to receive from the company, upon vesting, an amount equal to the value of one common share of the company, based on the five-day average of the closing price of the company’s common shares on the Toronto Stock Exchange on and immediately prior to the vesting dates. Fifty percent of the units vest on the third anniversary of the grant date, and the remainder vest on the seventh anniversary of the grant date. The company may also issue units where either 50 percent of the units vest on the fifth anniversary of the grant date and the remainder vest on the tenth anniversary of the grant date, or where 50 percent of the units vest on the fifth anniversary of the grant date and the remainder vest on the tenth anniversary of the grant date, or date of retirement of the recipient, whichever is later. The deferred share unit plan is made available to nonemployee directors. The nonemployee directors can elect to receive all or part of their eligible directors’ fees in units. The number of units granted is determined at the end of each calendar quarter by dividing the dollar amount of the nonemployee director’s fees for that calendar quarter elected to be received as deferred share units by the average closing price of the company’s shares for the five consecutive trading days (“average closing price”) immediately prior to the last day of the calendar quarter. Additional units are granted based on the cash dividend payable on the company’s shares divided by the average closing price immediately prior to the payment date for that dividend and multiplying the resulting number by the number of deferred share units held by the recipient, as adjusted for any share splits. Deferred share units cannot be exercised until after termination of service as a director, including termination due to death, and must be exercised in their entirety in one election no later than December 31 of the year following the year of termination of service. On the exercise date, the cash value to be received for the units is determined based on the company’s average closing price immediately prior to the date of exercise, as adjusted for any share splits. All units require settlement by cash payments with the following exceptions. The restricted stock unit program provides that, for units granted to Canadian residents, the recipient may receive one common share of the company per unit or elect to receive the cash payment for the units that vest on the seventh year anniversary of the grant date. For units where 50 percent vest on the fifth anniversary of the grant date and the remainder vest on either the tenth anniversary of grant, or the later of ten years following the grant date or the retirement date of the recipient, the recipient may receive one common share of the company per unit or elect to receive cash payment for all that vest. The company accounts for all units by using the fair-value-based method. The fair value of awards in the form of restricted stock and deferred share units is the market price of the company’s stock. Under this method, compensation expense related to the units of these programs is measured each reporting period based on the company’s current stock price and is recorded in the Consolidated statement of income over the requisite service period of each award. The following table summarizes information about these units for the year ended December 31, 2018: Restricted Deferred Outstanding at January 1, 2018 5,859,050 149,408 Granted 739,870 15,540 Vested / Exercised (1,275,640 ) (13,253 ) Forfeited and cancelled (20,455 ) - Outstanding at December 31, 2018 5,302,825 151,695 In 2018, the before-tax compensation expense charged against income for these programs was $32 million (2017 - $14 million, 2016 - $83 million). Income tax benefit recognized in income related to compensation expense for the year was $9 million (2017 - $4 million, 2016 - $24 million). Cash payments of $59 million were made for these programs in 2018 (2017 - $71 million, 2016 - $79 million). As of December 31, 2018, there was $75 million of total before-tax unrecognized compensation expense related to non-vested restricted stock units based on the company’s share price at the end of the current reporting period. The weighted average vesting period of non-vested restricted stock units is 3.9 years. All units under the deferred share programs have vested as of December 31, 2018.

Investment and other income

Investment and other income	12 Months Ended
	Dec. 31, 2018
Investment and other income	9. Investment and other income Investment and other income includes gains and losses on asset sales as follows: millions of Canadian dollars 2018 2017 2016 Proceeds from asset sales 59 232 3,021 Book value of asset sales 5 12 777 Gain (loss) on asset sales, before-tax (a) (b) 54 220 2,244 Gain (loss) on asset sales, after-tax (a) (b) 38 192 1,908 (a) 2017 included a gain of $174 million ($151 million after tax) from the sale of surplus property in Ontario. (b) 2016 included a gain of $2.0 billion ($1.7 billion, after tax) from the sale of company-owned Esso-branded retail sites; and a gain of $161 million ($134 million, after tax) from the sale of Imperial’s general aviation business.

Litigation and other contingenc

Litigation and other contingencies	12 Months Ended
	Dec. 31, 2018
Litigation and other contingencies	10. Litigation and other contingencies A variety of claims have been made against Imperial and its subsidiaries in a number of lawsuits. Management has regular litigation reviews, including updates from corporate and outside counsel, to assess the need for accounting recognition or disclosure of these contingencies. The company accrues an undiscounted liability for those contingencies where the incurrence of a loss is probable and the amount can be reasonably estimated. If a range of amounts can be reasonably estimated and no amount within the range is a better estimate than any other amount, then the minimum of the range is accrued. The company does not record liabilities when the likelihood that the liability has been incurred is probable but the amount cannot be reasonably estimated or when the liability is believed to be only reasonably possible or remote. For contingencies where an unfavourable outcome is reasonably possible and which are significant, the company discloses the nature of the contingency and, where feasible, an estimate of the possible loss. For purposes of the company’s contingency disclosures, “significant” includes material matters, as well as other matters which management believes should be disclosed. Based on a consideration of all relevant facts and circumstances, the company does not believe the ultimate outcome of any currently pending lawsuits against the company will have a material adverse effect on the company’s operations, financial condition, or financial statements taken as a whole. Additionally, the company has other commitments arising in the normal course of business for operating and capital needs, all of which are expected to be fulfilled with no adverse consequences material to the company’s operations or financial condition. Unconditional purchase obligations, as defined by accounting standards, are those long-term commitments that are non-cancelable or cancelable only under certain conditions and that third parties have used to secure financing for the facilities that will provide the contracted goods and services. The company has not entered into any unconditional purchase obligations. As a result of the completed sale of Imperial’s remaining company-owned Esso retail sites, the company was contingently liable at December 31, 2018, for guarantees relating to performance under contracts of other third-party obligations totaling $35 million (2017 - $42 million). In 2018 the company entered into an indemnification arrangement, under the terms of which the company is contingently liable for up to $46 million, for costs associated with continuing a third party pipeline project development.

Common shares

Common shares	12 Months Ended
	Dec. 31, 2018
Common shares	11. Common shares thousands of shares At December 31 2018 2017 Authorized 1,100,000 1,100,000 Common shares outstanding 782,565 831,242 The current 12-month normal course issuer bid program came into effect June 27, 2018, under which Imperial will continue its existing share purchase program. The program enables the company to purchase up to a maximum of 40,391,196 common shares (5 percent of the total shares on June 13, 2018) which includes shares purchased under the normal course issuer bid and from Exxon Mobil Corporation concurrent with, but outside of the normal course issuer bid. As in the past, Exxon Mobil Corporation has advised the company that it intends to participate to maintain its ownership percentage at approximately 69.6 percent. The excess of the purchase cost over the stated value of shares purchased has been recorded as a distribution of earnings reinvested. The company’s common share activities are summarized below: Thousands of Millions of Balance as at January 1, 2016 847,599 1,566 Issued under employee share-based awards 1 - Purchases at stated value (1 ) - Balance as at December 31, 2016 847,599 1,566 Issued under employee share-based awards 2 - Purchases at stated value (16,359 ) (30 ) Balance as at December 31, 2017 831,242 1,536 Issued under employee share-based awards 2 - Purchases at stated value (48,679 ) (90 ) Balance as at December 31, 2018 782,565 1,446 The following table provides the calculation of basic and diluted earnings per common share and the dividends declared 2018 2017 2016 Net income (loss) per common share – basic Net income (loss) (millions of Canadian dollars) 2,314 490 2,165 Weighted average number of common shares outstanding (millions of shares) 807.5 842.9 847.6 Net income (loss) per common share (dollars) 2.87 0.58 2.55 Net income (loss) per common share – diluted Net income (loss) (millions of Canadian dollars) 2,314 490 2,165 Weighted average number of common shares outstanding (millions of shares) 807.5 842.9 847.6 Effect of employee share-based awards (millions of shares) 2.6 2.8 2.9 Weighted average number of common shares outstanding, assuming dilution (millions of shares) 810.1 845.7 850.5 Net income (loss) per common share (dollars) 2.86 0.58 2.55 Dividends per common share – declared 0.73 0.63 0.59

Miscellaneous financial informa

Miscellaneous financial information	12 Months Ended
	Dec. 31, 2018
Miscellaneous financial information	12. Miscellaneous financial information In 2018, net income included an after-tax gain of $16 million (2017 – $5 million gain, 2016 – $5 million gain) attributable to the effect of changes in last-in, first-out (LIFO) inventories. The replacement cost of inventories was estimated to exceed their LIFO carrying values at December 31, 2018 by about $0.9 billion (2017 – $1.4 billion). Inventories of crude oil and products at year-end consisted of the following: millions of Canadian dollars 2018 2017 Crude oil 731 690 Petroleum products 473 307 Chemical products 72 42 Natural gas and other 21 36 Total inventories of crude oil and products 1,297 1,075 Research expenditures are mainly spent on developing technologies to improve bitumen recovery, reduce costs and reduce the environmental impact of upstream operations, including technologies to reduce greenhouse gas emissions intensity, supporting environmental and process improvements in the refineries, as well as accessing ExxonMobil’s research worldwide. The company has scientific research agreements with affiliates of ExxonMobil, which provide for technical and engineering work to be performed by all parties, the exchange of technical information and the assignment and licencing of patents, and patent rights. These agreements provide mutual access to scientific and operating data related to nearly every phase of the petroleum and petrochemical operations of the parties. Net research and development costs charged to expenses in 2018 were $110 million (2017 – $111 million, 2016 – $152 million). These costs are included in expenses due to the uncertainty of future benefits. Accounts payable and accrued liabilities included accrued taxes other than income taxes of $413 million at December 31, 2018 (2017 – $437 million).

Financing and additional notes

Financing and additional notes and loans payable information	12 Months Ended
	Dec. 31, 2018
Financing and additional notes and loans payable information	13. Financing and additional notes and loans payable information millions of Canadian dollars 2018 2017 2016 Debt-related interest (a) 133 103 121 Capitalized interest (28 ) (38 ) (49) Net interest expense 105 65 72 Other interest 3 13 (7) Total financing (b) 108 78 65 (a) Includes related party interest with ExxonMobil. (b) Cash interest payments in 2018 were $88 million (2017 – $58 million, 2016 – $73 million). The weighted average interest rate on short-term borrowings in 2018 was 1.5 percent (2017 – 0.9 percent, 2016 – 0.8 percent). Average effective rate on the long-term borrowings with ExxonMobil in 2018 was 2.0 percent (2017 – 1.3 percent, 2016 – 1.0 percent). As at December 31, 2018, the company had borrowed $75 million under an arrangement with an affiliated company of ExxonMobil that provides for a non-interest In November 2018, the company extended the maturity date of its existing $250 million committed long-term line of credit to November 2020. The company has not drawn on the facility. In December 2018, the company extended the maturity date of its existing $250 million committed short-term line of credit to December 2019. The company has not drawn on the facility.

Leased facilities

Leased facilities	12 Months Ended
	Dec. 31, 2018
Leased facilities	14. Leased facilities At December 31, 2018, the company held non-cancelable operating leases covering primarily storage tanks, rail cars and marine vessels, with minimum undiscounted lease commitments totaling $291 million as indicated in the following table: Payments due by period millions of Canadian dollars 2019 2020 2021 2022 2023 After Total Lease payments under minimum commitments (a) 130 82 43 13 11 12 291 (a) Net rental cost under cancelable and non-cancelable operating leases incurred in 2018 was $221 million (2017 - $206 million, 2016 - $253 million). Related rental income was not material.

Long-term debt

Long-term debt	12 Months Ended
	Dec. 31, 2018
Long-term debt	15. Long-term debt millions of Canadian dollars At December 31 2018 2017 Long-term debt (a) 4,447 4,447 Capital leases (b) 531 558 Total long-term debt 4,978 5,005 (a) Borrowed under an existing agreement with an affiliated company of ExxonMobil that provides for a long-term, variable-rate, Canadian dollar loan from ExxonMobil to the company of up to $7.75 billion at interest equivalent to Canadian market rates. The agreement is effective until July 31, 2020, cancelable if ExxonMobil provides at least 370 days advance written notice. (b) Capital leases are primarily associated with transportation facilities and services agreements. The average imputed rate was 7.1 percent in 2018 (2017 – 7.0 percent). Total capitalized lease obligations also include $27 million in current liabilities (2017 - $27 million). Principal payments on capital leases of approximately $14 million on average per year are due in each of the next four years after December 31, 2019.

Accounting for suspended explor

Accounting for suspended exploratory well costs	12 Months Ended
	Dec. 31, 2018
Accounting for suspended exploratory well costs	16. Accounting for suspended exploratory well costs The company continues capitalization of exploratory well costs when the well has found a sufficient quantity of reserves to justify its completion as a producing well and the company is making sufficient progress assessing the reserves and the economic and operating viability of the project. The term “project” as used in this report can refer to a variety of different activities and does not necessarily have the same meaning as in any government payment transparency reports. Exploratory well costs at year-end 2016 that were capitalized as part of the Horn River project for a period greater than 12 months were expensed in 2017. The following two tables provide details of the changes in the balance of suspended exploratory well costs, as well as an aging summary of those costs. Change in capitalized suspended exploratory well costs: millions of Canadian dollars 2018 2017 2016 Balance as at January 1 - 143 167 Additions pending the determination of proved reserves - - - Charged to expense - (143 ) (24 ) Reclassification to wells, facilities and equipment based on the determination of proved reserves - - - Balance as at December 31 - - 143 Period end capitalized suspended exploratory well costs: millions of Canadian dollars 2018 2017 2016 Capitalized for a period of one year or less - - - Capitalized for a period of between one and ten years - - 143 Capitalized for a period of greater than one year - - 143 Total - - 143 Exploration activity often involves drilling multiple wells, over a number of years, to fully evaluate a project. The table below provides a breakdown of the number of projects with exploratory well costs capitalized in the preceding 12 months and those that have had exploratory well costs capitalized for a period greater than 12 months. 2018 2017 2016 Number of projects with first capitalized well drilled in the preceding 12 months - - - Number of projects that have exploratory well costs capitalized for a period of greater than 12 months - - 1 Total - - 1

Transactions with related parti

Transactions with related parties	12 Months Ended
	Dec. 31, 2018
Transactions with related parties	17. Transactions with related parties Revenues and expenses of the company also include the results of transactions with affiliated companies of ExxonMobil in the normal course of operations. These were conducted on terms comparable to those which would have been conducted with unrelated parties and primarily consisted of the purchase and sale of crude oil, natural gas, petroleum and chemical products, as well as technical, engineering and research, and development costs. Transactions with ExxonMobil also included amounts paid and received in connection with the company’s participation in a number of upstream activities conducted jointly in Canada. In addition, the company has existing agreements with ExxonMobil: a) To provide computer and customer support services to the company and to share common business and operational support services that allow the companies to consolidate duplicate work and systems; b) To operate certain western Canada production properties owned by ExxonMobil, as well as provide for the delivery of management, business and technical services to ExxonMobil in Canada. These agreements are designed to provide organizational efficiencies and to reduce costs. No separate legal entities were created from these arrangements. Separate books of account continue to be maintained for the company and ExxonMobil. The company and ExxonMobil retain ownership of their respective assets, and there is no impact on operations or reserves; c) To provide for the delivery of management, business and technical services to Syncrude Canada Ltd. by ExxonMobil; d) To provide for the option of equal participation in new upstream opportunities; and e) To enter into derivative agreements on the company’s behalf. Certain charges from ExxonMobil have been capitalized; they are not material in the aggregate. The amounts of purchases and sales by Imperial in 2018, with ExxonMobil, were $4,036 million and $6,364 million respectively (2017 - $2,648 million and $4,080 million respectively). The amount of financing costs with ExxonMobil were $87 million (2017 - $57 million). As at December 31, 2018, the company had outstanding long-term loans of $4,447 million (2017 – $4,447 million) and short-term loans of $75 million (2017 – $75 million) from ExxonMobil (see note 15, Long-term debt, on page 88 and note 13, Financing and additional notes and loans payable information, on page 87 for further details). Imperial has other related party transactions not detailed above in note 17, as they are not significant.

Other comprehensive income (los

Other comprehensive income (loss) information	12 Months Ended
	Dec. 31, 2018
Other comprehensive income (loss) information	18. Other comprehensive income (loss) information Changes in accumulated other comprehensive income (loss): millions of Canadian dollars 2018 2017 2016 Balance at January 1 (1,815 ) (1,897 ) (1,828 ) Postretirement benefits liability adjustment: Current period change excluding amounts reclassified from accumulated other comprehensive income 158 (54 ) (210 ) Amounts reclassified from accumulated other comprehensive income 140 136 141 Balance at December 31 (1,517 ) (1,815 ) (1,897 ) Amounts reclassified out of accumulated other comprehensive income (loss) - before-tax income (expense): millions of Canadian dollars 2018 2017 2016 Amortization of postretirement benefits liability adjustment included in net periodic benefit cost (a) (185 ) (194 ) (184 ) (a)  This accumulated other comprehensive income component is included in the computation of net periodic benefit cost (note 5).    Income tax expense (credit) for components of other comprehensive income (loss): millions of Canadian dollars 2018 2017 2016 Postretirement benefits liability adjustments: Postretirement benefits liability adjustment (excluding amortization) 59 (20 ) (77 ) Amortization of postretirement benefits liability adjustment included in net periodic benefit cost 45 58 43 Total 104 38 (34 )

Summary of significant accoun_2

Summary of significant accounting policies (Policies)	12 Months Ended
	Dec. 31, 2018
Principles of consolidation	Principles of consolidation The consolidated financial statements include the accounts of subsidiaries the company controls. Intercompany accounts and transactions are eliminated. Subsidiaries include those companies in which Imperial has both an equity interest and the continuing ability to unilaterally determine strategic, operating, investing and financing policies. Imperial Oil Resources Limited is the only significant subsidiary included in the consolidated financial statements and is wholly owned by Imperial Oil Limited. The consolidated financial statements also include the company’s share of the undivided interest in certain upstream assets, liabilities, revenues and expenses, including its 25 percent interest in the Syncrude joint venture and its 70.96 percent interest in the Kearl joint venture.
Revenues	Revenues Imperial generally sells crude oil, natural gas and petroleum and chemical products under short-term agreements at prevailing market prices. In some cases, products may be sold under long-term agreements, with periodic price adjustments to reflect market conditions. Revenue is recognized at the amount the company expects to receive when the customer has taken control, which is typically when title transfers and the customer has assumed the risks and rewards of ownership. The prices of certain sales are based on price indices that are sometimes not available until the next period. In such cases, estimated realizations are accrued when the sale is recognized, and are finalized when final information is available. Such adjustments to revenue from performance obligations satisfied in previous periods are not significant. Payment for revenue transactions is typically due within 30 days. Revenues include amounts billed to customers for shipping and handling. Shipping and handling costs incurred up to the point of final storage prior to delivery to a customer are included in “Purchases of crude oil and products” in the Consolidated statement of income. Delivery costs from final storage to customer are recorded as a marketing expense in “Selling and general” expenses. The company does not enter into ongoing arrangements whereby it is required to repurchase its products, nor does the company provide the customer with a right of return. Future volume delivery obligations that are unsatisfied at the end of the period are expected to be fulfilled through ordinary production or purchases. These performance obligations are based on market prices at the time of the transaction and are fully constrained due to market price volatility. Purchases and sales of inventory with the same counterparty that are entered into in contemplation of one another are combined and recorded as exchanges measured at the book value of the item sold. “Revenues” and “Accounts receivable, less estimated doubtful accounts” primarily arise from contracts with customers. Long-term receivables are primarily from non-customers. Contract assets are mainly from marketing assistance programs and are not significant. Contract liabilities are mainly customer prepayments, loyalty programs and accruals of expected volume discounts, and are not significant.
Consumer taxes	Consumer taxes Taxes levied on the consumer and collected by the company are excluded from the Consolidated statement of income. These are primarily provincial taxes on motor fuels, the federal goods and services tax and the federal/provincial harmonized sales tax.
Derivative instruments	Derivative instruments Imperial uses derivative instruments to offset exposures associated with hydrocarbon prices that arise from existing assets, liabilities and forecasted transactions. The gains and losses resulting from changes in the fair value of derivatives are recorded under “Revenues” or “Purchases of crude oil and products” on the Consolidated statement of income. The company does not currently make use of derivative instruments to offset exposures associated with foreign currency and interest rates.
Fair value	Fair value Fair value is the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants. Hierarchy Levels 1, 2 and 3 are terms for the priority of inputs to valuation techniques used to measure fair value. Hierarchy Level 1 inputs are quoted prices in active markets for identical assets or liabilities. Hierarchy Level 2 inputs are inputs other than quoted prices included within Level 1 that are directly or indirectly observable for the asset or liability. Hierarchy Level 3 inputs are inputs that are not observable in the market.
Inventories	Inventories Inventories are recorded at the lower of current market value or cost. The cost of crude oil and products is determined primarily using the last-in, first-out (LIFO) method. LIFO was selected over the alternative first-in, first-out and average cost methods because it provides a better matching of current costs with the revenues generated in the period. Inventory costs include expenditures and other charges (including depreciation), directly or indirectly incurred in bringing the inventory to its existing condition and location. Selling and general expenses are reported as period costs and excluded from inventory costs.
Investments	Investments The company’s interests in the underlying net assets of affiliates it does not control, but over which it exercises significant influence, are accounted for using the equity method. They are recorded at the original cost of the investment plus Imperial’s share of earnings since the investment was made, less dividends received. Imperial’s share of the after-tax earnings of these investments is included in “Investment and other income” in the Consolidated statement of income. Investments in equity securities, other than consolidated subsidiaries and equity method investments, are measured at fair value, with changes in the fair value recognized in net income. The company uses a modified approach for equity securities that do not have a readily determinable fair value. This modified approach measures investments at cost minus impairment, if any, plus or minus changes resulting from observable price changes in orderly transactions in similar investment of the same issuer. Dividends from these investments are included in “Investment and other income”. These investments represent interests in non-publicly traded pipeline companies and a rail loading joint venture that facilitate the sale and purchase of liquids in the conduct of company operations. Other parties who also have an equity interest in these investments share in the risks and rewards according to their percentage of ownership. Imperial does not invest in these investments in order to remove liabilities from its balance sheet.
Property, plant and equipment	Property, plant and equipment Cost basis Imperial uses the “successful efforts” method to account for its exploration and production activities. Under this method, costs are accumulated on a field-by-field basis. Costs incurred to purchase, lease, or otherwise acquire a property (whether unproved or proved) are capitalized when incurred. Exploratory well costs are carried as an asset when the well has found a sufficient quantity of reserves to justify its completion as a producing well and where the company is making sufficient progress assessing the reserves and the economic and operating viability of the project. Exploratory well costs not meeting these criteria are charged to expense. Other exploratory expenditures, including geophysical costs and annual lease rentals, are expensed as incurred. Development costs, including costs of productive wells and development dryholes, are capitalized. Maintenance and repair costs, including planned major maintenance, are expensed as incurred. Improvements that increase or prolong the service life or capacity of an asset are capitalized. Depreciation, depletion and amortization Depreciation, depletion and amortization are primarily determined under either the unit-of-production method or the straight-line method, which is based on estimated asset service life taking obsolescence into consideration. Depreciation and depletion for assets associated with producing properties begin at the time when production commences on a regular basis. Depreciation for other assets begins when the asset is in place and ready for its intended use. Assets under construction are not depreciated or depleted. Acquisition costs of proved properties are amortized using a unit-of-production method, computed on the basis of total proved oil and gas reserves. Capitalized exploratory drilling and development costs associated with productive depletable extractive properties are amortized using the unit-of-production rates based on the amount of proved developed reserves of oil and gas that are estimated to be recoverable from existing facilities using current operating methods. Under the unit-of-production method, oil and gas volumes are considered produced once they have been measured through meters at custody transfer or sales transaction points at the outlet valve on the lease or field storage tank. In the event that the unit-of-production method does not result in an equitable allocation of cost over the economic life of an upstream asset, an alternative method is used. The straight-line method is used in limited situations where the expected life of the asset does not reasonably correlate with that of the underlying reserves. For example, certain assets used in the production of oil and natural gas have a shorter life than the reserves, and as such, the company uses straight-line depreciation to ensure the asset is fully depreciated by the end of its useful life. Investments in mining heavy equipment and certain ore processing plant assets at oil sands mining properties are depreciated on a straight-line basis over a maximum of 15 years and 50 years respectively. Depreciation of other plant and equipment is calculated using the straight-line method, based on the estimated service life of the asset. To the extent that proved reserves for a property are substantially de-booked and that property continues to produce such that the resulting depreciation charge does not result in an equitable allocation of cost over the expected life, assets will be depreciated using a unit-of-production method based on reserves determined at the most recent SEC price which results in a more meaningful quantity of proved reserves, appropriately adjusted for production and technical changes. This approach was applied in 2017 and 2018, with the corresponding effect on depreciation expense immaterial when compared to the prior periods. In 2019, all properties have sufficient reserves at current SEC prices which will enable equitable allocation of cost over the economic lives of the Upstream assets. The effect of this approach on the company’s 2019 depreciation expense compared to 2018 is anticipated to be immaterial. Investments in refinery, chemical process, and lubes basestock manufacturing equipment are generally depreciated on a straight-line basis over a 25-year life. Maintenance and repairs, including planned major maintenance, are expensed as incurred. Major renewals and improvements are capitalized and the assets replaced are retired. Impairment assessment The company tests assets or groups of assets for recoverability on an ongoing basis whenever events or changes in circumstances indicate the carrying amounts may not be recoverable. Among the events or changes in circumstances which could indicate that the carrying value of an asset or asset group may not be recoverable are the following: ● A significant decrease in the market price of a long-lived asset; ● A significant adverse change in the extent or manner in which an asset is being used or in its physical condition including a significant decrease in the company’s current and projected reserve volumes; ● A significant adverse change in legal factors or in the business climate that could affect the value, including a significant adverse action or assessment by a regulator; ● An accumulation of project costs significantly in excess of the amount originally expected; ● A current-period operating loss combined with a history and forecast of operating or cash flow losses; and ● A current expectation that, more likely than not, a long-lived asset will be sold or otherwise disposed of significantly before the end of its previously estimated useful life. Asset valuation analyses performed as part of the company’s asset management program and other profitability reviews assist Imperial in assessing whether events or changes in circumstances indicate the carrying amounts of any of its assets may not be recoverable. In general, Imperial does not view temporarily low prices or margins as an indication of impairment. Management believes prices over the long-term must be sufficient to generate investments in energy supply to meet global demand. Although prices will occasionally drop significantly, industry prices over the long-term will continue to be driven by market supply and demand fundamentals. On the supply side, industry production from mature fields is declining. This is being offset by investments to generate production from new discoveries, field developments and technological and efficiency advancements. OPEC investment activities and production policies also have an impact on world oil supplies. The demand side is largely a function of general economic activities and levels of prosperity. Because the lifespans of the company’s major assets are measured in decades, the value of these assets is predominantly based on long-term views of future commodity prices and production costs. During the lifespan of these major assets, the company expects that oil and gas prices will experience significant volatility, and consequently these assets will experience periods of higher earnings and periods of lower earnings, or even losses. In assessing whether the events or changes in circumstances indicate the carrying value of an asset may not be recoverable, the company considers recent periods of operating losses in the context of its longer-term view of prices. While near-term prices are subject to wide fluctuations, longer term price views are more stable and meaningful for purposes of assessing future cash flows. When the industry experiences a prolonged and deep reduction in commodity prices, the market supply and demand conditions may result in changes to the company’s long-term price or margin assumptions it uses for its capital investment decisions. To the extent those changes result in a significant reduction to its long-term oil prices or natural gas prices or margin ranges, the company may consider that situation, in conjunction with other events or changes in circumstances such as a history of operating losses, as an indicator of potential impairment for certain assets. In the upstream, the standardized measure of discounted cash flows included in the “Supplemental information on oil and gas exploration and production activities” is required to use prices based on the yearly average of first-of-month prices. These prices represent discrete points in time and could be higher or lower than the company’s long-term price assumptions which are used for impairment assessments. The company believes the standardized measure does not provide a reliable estimate of the expected future cash flows to be obtained from the development and production of its oil and gas properties or of the value of its oil and gas reserves and therefore does not consider it relevant in determining whether events or changes in circumstances indicate the need for an impairment assessment. If events or changes in circumstances indicate that the carrying value of an asset may not be recoverable, the company estimates the future undiscounted cash flows of the affected properties to judge the recoverability of carrying amounts. In performing this assessment, assets are grouped at the lowest level for which there are identifiable cash flows that are largely independent of the cash flows of other groups of assets. Cash flows used in recoverability assessments are based on the company’s assumptions which are developed in the annual planning and budgeting process, and are consistent with the criteria management uses to evaluate investment opportunities. These evaluations make use of the company’s assumptions of future capital allocations, crude oil and natural gas commodity prices, refining and chemical margins, volumes, costs, foreign currency exchange rates and inflation rates. Volumes are based on projected field and facility production profiles, throughput, or sales. Where unproved reserves exist, an appropriately risk-adjusted amount of these reserves may be included in the evaluation. Cash flow estimates for impairment testing exclude the effects of derivative instruments. An asset group is impaired if its estimated future undiscounted cash flows are less than the asset group’s carrying value. Impairments are measured by the amount by which the carrying value exceeds fair value. Fair value is based on market prices if an active market exists for the asset group or discounted cash flows using a discount rate commensurate with the risk. Significant unproved properties are assessed for impairment individually, and valuation allowances against the capitalized costs would be recorded based on the estimated economic chance of success and the length of time that the company expects to hold the properties. Properties that are not individually significant are aggregated by groups and amortized based on development risk and average holding period. Gains on sales of proved and unproved properties are only recognized when there is neither uncertainty about the recovery of costs applicable to any interest retained nor any substantial obligation for future performance by the company. Losses on properties sold are recognized when incurred or when the properties are held for sale and the fair value of the properties is less than the carrying value. Gains or losses on assets sold are included in “Investment and other income” in the Consolidated statement of income.
Interest capitalization	Interest capitalization Interest costs incurred to finance expenditures during the construction phase of projects are capitalized as part of property, plant and equipment and are depreciated over the service life of the related assets. The project construction phase commences with the development of the detailed engineering design and ends when the constructed assets are ready for their intended use.
Goodwill and other intangible assets	Goodwill and other intangible assets Goodwill is not subject to amortization. Goodwill is tested for impairment annually or more frequently if events or circumstances indicate it might be impaired. Impairment losses are recognized in current period earnings. The evaluation for impairment of goodwill is based on a comparison of the carrying values of goodwill and associated operating assets with the estimated present value of net cash flows from those operating assets. Intangible assets with determinable useful lives are amortized over the estimated service lives of the assets. Computer software development costs are amortized over a maximum of 15 years and customer lists are amortized over a maximum of 10 years. The amortization is included in “Depreciation and depletion” in the Consolidated statement of income.
Asset retirement obligations and other environmental liabilities	Asset retirement obligations and other environmental liabilities Legal obligations associated with site restoration on the retirement of assets with determinable useful lives are recognized when they are incurred, which is typically at the time the assets are installed. These obligations primarily relate to soil reclamation and remediation, and costs of abandonment and demolition of oil and gas wells and related facilities. The company uses estimates, assumptions and judgments regarding such factors as the existence of a legal obligation for an asset retirement obligation, technical assessments of the assets, estimated amounts and timing of settlements, the credit-adjusted risk-free rate to be used, and inflation rates. The obligations are initially measured at fair value and discounted to present value. A corresponding amount equal to that of the initial obligation is added to the capitalized costs of the related asset. Over time, the discounted asset retirement obligation amount will be accreted for the change in its present value, and the initial capitalized costs will be depreciated over the useful lives of the related assets. No asset retirement obligations are set up for those manufacturing, distribution, marketing and office facilities with an indeterminate useful life. Asset retirement obligations for these facilities generally become firm at the time the facilities are permanently shut down and dismantled. These obligations may include the costs of asset disposal and additional soil remediation. However, these sites have indeterminate lives based on plans for continued operations, and as such, the fair value of the conditional legal obligations cannot be measured, since it is impossible to estimate the future settlement dates of such obligations. Provision for environmental liabilities of these assets is made when it is probable that obligations have been incurred and the amount can be reasonably estimated. Provisions for environmental liabilities are determined based on engineering estimated costs, taking into account the anticipated method and extent of remediation consistent with legal requirements, current technology and the possible use of the location. These provisions are not reduced by possible recoveries from third parties and projected cash expenditures are not discounted.
Foreign-currency translation	Foreign-currency translation Monetary assets and liabilities in foreign currencies have been translated at the rates of exchange prevailing on December 31. Any exchange gains or losses are recognized in income.
Share-based compensation	Share-based compensation The company awards share-based compensation to certain employees in the form of restricted stock units. Compensation expense is measured each reporting period based on the company’s current stock price and is recorded as “Selling and general” expenses in the Consolidated statement of income over the requisite service period of each award. See note 8 to the consolidated financial statements on page 84 for further details.
Leases (Topic 842)
Accounting changes	Recently issued accounting standards Effective January 1, 2019, Imperial adopted the Financial Accounting Standards Board’s standard, Leases (Topic 842)

Accounting changes (Tables)

Accounting changes (Tables)	12 Months Ended
	Dec. 31, 2018
Presentation Change on Consolidated Statement of Income	The impact of the retrospective presentation change on Imperial’s Consolidated statement of income for the years ended December 31, is shown below. millions of Canadian dollars 2017 2016 As reported Change As adjusted As reported Change As adjusted Production and manufacturing 5,698 (112 ) 5,586 5,224 (119 ) 5,105 Selling and general 893 (10 ) 883 1,129 (11 ) 1,118 Non-service pension and postretirement benefit - 122 122 - 130 130

Business segments (Tables)

Business segments (Tables)	12 Months Ended
	Dec. 31, 2018
Business Segments	Upstream Downstream Chemical millions of Canadian dollars 2018 2017 2016 2018 2017 2016 2018 2017 2016 Revenues and other income Revenues (a) 8,525 7,302 5,492 25,200 20,714 18,511 1,239 1,109 1,046 Intersegment sales 2,634 2,264 2,215 1,542 1,155 1,007 279 262 212 Investment and other income (note 9) 11 16 13 95 269 2,278 - - - 11,170 9,582 7,720 26,837 22,138 21,796 1,518 1,371 1,258 Expenses Exploration (b) (note 16) 19 183 94 - - - - - - Purchases of crude oil and products 5,833 4,526 3,666 19,326 16,543 14,178 831 751 705 Production and manufacturing (c) 4,305 3,913 3,591 1,606 1,576 1,428 210 209 205 Selling and general (c) - - (5 ) 773 772 972 87 78 83 Federal excise tax - - - 1,667 1,673 1,650 - - - Depreciation and depletion (b) (d) 1,278 1,939 1,396 242 202 206 14 12 10 Non-service pension and postretirement benefit (c) - - - - - - - - - Financing (note 13) 1 13 (7 ) 2 - - - - - Total expenses 11,436 10,574 8,735 23,616 20,766 18,434 1,142 1,050 1,003 Income (loss) before income taxes (266 ) (992 ) (1,015 ) 3,221 1,372 3,362 376 321 255 Income taxes Current (184 ) 484 (491 ) 189 (504 ) 674 21 (32 ) 68 Deferred 56 (770 ) 137 666 836 (66 ) 80 118 - Total income tax expense (benefit) (128 ) (286 ) (354 ) 855 332 608 101 86 68 Net income (loss) (138 ) (706 ) (661 ) 2,366 1,040 2,754 275 235 187 Cash flows from (used in) operating activities 916 1,257 402 2,749 1,396 1,574 354 235 203 Capital and exploration expenditures 991 416 896 383 200 190 25 17 26 Property, plant and equipment Cost 46,435 45,542 45,850 5,900 5,683 6,166 916 888 872 Accumulated depreciation and depletion (15,050 ) (13,844 ) (12,312 ) (3,763 ) (3,594 ) (4,037 ) (662 ) (644 ) (629 ) Net property, plant and equipment 31,385 31,698 33,538 2,137 2,089 2,129 254 244 243 Total assets 34,829 35,044 36,840 5,119 4,890 3,958 438 399 346 Corporate and other Eliminations Consolidated millions of Canadian dollars 2018 2017 2016 2018 2017 2016 2018 2017 2016 Revenues and other income Revenues (a) - - - - - - 34,964 29,125 25,049 Intersegment sales - - - (4,455 ) (3,681 ) (3,434 ) - - - Investment and other income (note 9) 29 14 14 - - - 135 299 2,305 29 14 14 (4,455 ) (3,681 ) (3,434 ) 35,099 29,424 27,354 Expenses Exploration (b) (note 16) - - - - - - 19 183 94 Purchases of crude oil and products - - - (4,449 ) (3,675 ) (3,429 ) 21,541 18,145 15,120 Production and manufacturing (c) - - - - - - 6,121 5,698 5,224 Selling and general (c) 54 49 84 (6 ) (6 ) (5 ) 908 893 1,129 Federal excise tax - - - - - - 1,667 1,673 1,650 Depreciation and depletion (b) (d) 21 19 16 - - - 1,555 2,172 1,628 Non-service pension and postretirement benefit (c) 107 - - - - - 107 - - Financing (note 13) 105 65 72 - - - 108 78 65 Total expenses 287 133 172 (4,455 ) (3,681 ) (3,434 ) 32,026 28,842 24,910 Income (loss) before income taxes (258 ) (119 ) (158 ) - - - 3,073 582 2,444 Income taxes Current (40 ) (6 ) (51 ) - - - (14 ) (58 ) 200 Deferred (29 ) (34 ) 8 - - - 773 150 79 Total income tax expense (benefit) (69 ) (40 ) (43 ) - - - 759 92 279 Net income (loss) (189 ) (79 ) (115 ) - - - 2,314 490 2,165 Cash flows from (used in) operating activities (116 ) (125 ) (143 ) 19 - (21 ) 3,922 2,763 2,015 Capital and exploration expenditures 28 38 49 - - - 1,427 671 1,161 Property, plant and equipment Cost 693 665 627 - - - 53,944 52,778 53,515 Accumulated depreciation and depletion (244 ) (223 ) (204 ) - - - (19,719 ) (18,305 ) (17,182 ) Net property, plant and equipment 449 442 423 - - - 34,225 34,473 36,333 Total assets 1,548 1,703 894 (478 ) (435 ) (384 ) 41,456 41,601 41,654 (a) Includes export sales to the United States of $6,661 million (2017 - $4,392 million, 2016 - $3,612 million). Export sales to the United States were recorded in all operating segments, with the largest effects in the Upstream segment. (b) The Upstream segment in 2017 includes non-cash impairment charges of $396 million, before tax, associated with the Horn River development and $379 million, before tax, associated with the Mackenzie gas project. The impairment charges are recognized in the lines “Exploration” and “Depreciation and depletion” on the Consolidated statement of income, and the “Accumulated depreciation and depletion” line of the Consolidated balance sheet. (c) As part of the implementation of Accounting Standard Update, Compensation – Retirement Benefits (Topic 715), beginning January 1, 2018, Corporate and other includes all non-service pension and postretirement benefit expense. Prior to 2018, the majority of these costs were allocated to the operating segments. See note 2 for additional details. (d) The Downstream segment in 2018 includes a non-cash impairment charge of $46 million, before tax, associated with the Government of Ontario’s revocation of its carbon emission cap and trade regulation. The impairment charge is recognized in the “Depreciation and depletion” line on the Consolidated statement of income, and the “Other assets, including intangibles, net” line on the Consolidated balance sheet. (e) Capital and exploration expenditures (CAPEX) include exploration expenses, additions to property, plant and equipment, additions to capital leases, additional investments and acquisitions. CAPEX excludes the purchase of carbon emission credits. (f) Includes property, plant and equipment under construction of $1,553 million (2017 - $1,047 million, 2016 - $2,705 million).

Income taxes (Tables)

Income taxes (Tables)	12 Months Ended
	Dec. 31, 2018
Summary of Income Tax Expense (Benefit)	millions of Canadian dollars 2018 2017 2016 Current income tax expense (a) (14 ) (58 ) 200 Deferred income tax expense (a) 773 150 79 Total income tax expense (a) (b) 759 92 279 Statutory corporate tax rate (percent) 26.9 26.9 26.8 Increase (decrease) resulting from: Disposals (c) (0.3 ) (5.3 ) (11.6 ) Enacted tax rate change (a) - 0.9 - Other (1.9 ) (6.6 ) (3.8 ) Effective income tax rate 24.7 15.9 11.4 (a) On November 2, 2017 the British Columbia government enacted a 1 percent increase in the provincial tax rate from 11 percent to 12 percent. (b) Cash outflow from income taxes, plus investment credits earned, was $162 million (2017 - $322 million, 2016 - $172 million). (c) 2017 disposals are primarily associated with the sale of surplus property in Ontario. 2016 disposals are primarily associated with the sales of company-owned Esso retail sites and the general aviation business. Capital gains tax treatment was applied on the majority of disposals.
Components of Deferred Income Tax Liabilities and Assets	Components of deferred income tax liabilities and assets as at December 31 were: millions of Canadian dollars 2018 2017 2016 Depreciation and amortization 5,726 5,564 5,361 Successful drilling and land acquisitions 856 762 891 Pension and benefits (336 ) (422 ) (457 ) Asset retirement obligation (381 ) (376 ) (396 ) Capitalized interest 121 118 114 LIFO inventory valuation (107 ) (318 ) (240 ) Tax loss carryforwards (658 ) (936 ) (1,056 ) Other (150 ) (196 ) (212 ) Net deferred income tax liabilities 5,071 4,196 4,005
Unrecognized Tax Benefits	The following table summarizes the movement in unrecognized tax benefits: millions of Canadian dollars 2018 2017 2016 Balance as of January 1 78 106 132 Additions for prior years’ tax position 9 2 2 Reductions for prior years’ tax positions (2 ) - (18 ) Reductions due to lapse of the statute of limitations - - (5 ) Settlements with tax authorities (49 ) (30 ) (5 ) Balance as of December 31 36 78 106

Employee retirement benefits (T

Employee retirement benefits (Tables)	12 Months Ended
	Dec. 31, 2018
Assumptions Used to Determine Benefit Obligations	The benefit obligations and plan assets associated with the company’s defined benefit plans are measured on December 31. Pension benefits Other postretirement 2018 2017 2018 2017 Assumptions used to determine benefit obligations at December 31 (percent) Discount rate 3.90 3.40 3.90 3.40 Long-term rate of compensation increase 4.50 4.50 4.50 4.50 millions of Canadian dollars Change in projected benefit obligation Projected benefit obligation at January 1 8,785 8,356 670 706 Current service cost 239 217 17 16 Interest cost 302 313 22 23 Actuarial loss (gain) (498 ) 415 (101 ) (49 ) Benefits paid (a) (469 ) (516 ) (26 ) (26 ) Projected benefit obligation at December 31 8,359 8,785 582 670 Accumulated benefit obligation at December 31 7,661 8,043
Change in Plan Assets of Pension and Other Postretirement Benefits	Pension benefits Other postretirement benefits millions of Canadian dollars 2018 2017 2018 2017 Change in plan assets Fair value at January 1 7,870 7,359 Actual return (loss) on plan assets 20 700 Company contributions 203 212 Benefits paid (b) (402 ) (401 ) Fair value at December 31 7,691 7,870 Plan assets in excess of (less than) projected benefit obligation at December 31 Funded plans (180 ) (408 ) Unfunded plans (488 ) (507 ) (582 ) (670 ) Total (c) (668 ) (915 ) (582 ) (670 ) (a) Benefit payments for funded and unfunded plans. (b) Benefit payments for funded plans only. (c) Fair value of assets less projected benefit obligation shown above.
Amounts Recorded in Consolidated Balance Sheet and Accumulated Other Comprehensive Income	Pension benefits Other postretirement benefits millions of Canadian dollars 2018 2017 2018 2017 Amounts recorded in the Consolidated balance sheet consist of: Current liabilities (27 ) (28 ) (28 ) (28 ) Other long-term obligations (641 ) (887 ) (554 ) (642 ) Total recorded (668 ) (915 ) (582 ) (670 ) Amounts recorded in accumulated other comprehensive income consist of: Net actuarial loss (gain) 2,117 2,408 33 140 Prior service cost - 4 - - Total recorded in accumulated other comprehensive income, before tax 2,117 2,412 33 140
Assumptions Used to Determine Periodic Benefit Cost	Pension benefits Other postretirement benefits millions of Canadian dollars 2018 2017 2016 2018 2017 2016 Assumptions used to determine net periodic benefit cost for years ended December 31 (percent) Discount rate 3.40 3.75 4.00 3.40 3.75 4.00 Long-term rate of return on funded assets 5.00 5.50 5.50 - - - Long-term rate of compensation increase 4.50 4.50 4.50 4.50 4.50 4.50 millions of Canadian dollars Components of net periodic benefit cost Current service cost 239 217 203 17 16 16 Interest cost 302 313 319 22 23 27 Expected return on plan assets (402 ) (408 ) (400 ) - - - Amortization of prior service cost 4 10 9 - - - Amortization of actuarial loss (gain) 175 176 162 6 8 13 Net periodic benefit cost 318 308 293 45 47 56 Changes in amounts recorded in accumulated other comprehensive income Net actuarial loss (gain) (116 ) 123 241 (101 ) (49 ) 46 Amortization of net actuarial (loss) gain included in net periodic benefit cost (175 ) (176 ) (162 ) (6 ) (8 ) (13 ) Amortization of prior service cost included in net periodic benefit cost (4 ) (10 ) (9 ) - - - Total recorded in other comprehensive income (295 ) (63 ) 70 (107 ) (57 ) 33 Total recorded in net periodic benefit cost and other comprehensive income, before tax 23 245 363 (62 ) (10 ) 89
Summary of Change in Accumulated Other Comprehensive Income	A summary of the change in accumulated other comprehensive income is shown in the table below: Total pension and other millions of Canadian dollars 2018 2017 2016 (Charge) credit to other comprehensive income, before tax 402 120 (103 ) Deferred income tax (charge) credit (note 18) (104 ) (38 ) 34 (Charge) credit to other comprehensive income, after tax 298 82 (69 )
Fair Value of Pension Plan Assets Including Level within Fair Value Hierarchy	The 2018 fair value of the pension plan assets, including the level within the fair value hierarchy, is shown in the table below: Fair value measurements at December 31, 2018, using: millions of Canadian dollars Total Level 1 Level 2 Level 3 Net Asset Asset class Equity securities Canadian 170 - - - 170 Non-Canadian 2,035 - - - 2,035 Debt securities - Canadian Corporate 1,231 - - - 1,231 Government 3,987 - - - 3,987 Asset backed 3 - - - 3 Equities – Venture capital 226 - - - 226 Cash 39 33 - - 6 Total plan assets at fair value 7,691 33 - - 7,658 The 2017 fair value of the pension plan assets, including the level within the fair value hierarchy, is shown in the table below: Fair value measurements at December 31, 2017, using: millions of Canadian dollars Total Level 1 Level 2 Level 3 Net Asset Asset class Equity securities Canadian 182 - - - 182 Non-Canadian 2,138 - - - 2,138 Debt securities - Canadian Corporate 1,248 - - - 1,248 Government 4,016 - - - 4,016 Asset backed - - - - - Equities – Venture capital 215 - - - 215 Cash 71 34 - - 37 Total plan assets at fair value 7,870 34 - - 7,836
Pension Plans with Accumulated Benefit Obligations in Excess of Plan Assets	A summary of pension plans with accumulated benefit obligations in excess of plan assets is shown in the table below: Pension benefits millions of Canadian dollars 2018 2017 For funded pension plans with accumulated benefit obligations in excess of plan assets: Projected benefit obligation - - Accumulated benefit obligation - - Fair value of plan assets - - Accumulated benefit obligation less fair value of plan assets - - For unfunded plans covered by book reserves: Projected benefit obligation 488 507 Accumulated benefit obligation 451 480
Estimated 2019 Amortization from Accumulated Other Comprehensive Income	Estimated 2019 amortization from accumulated other comprehensive income millions of Canadian dollars Pension benefits Other postretirement benefits Net actuarial loss (gain) (a) 150 2 (a) The company amortizes the net balance of actuarial loss (gain) as a component of net periodic benefit cost over the average remaining service period of active plan participants.
Benefit Payments Expected	Benefit payments expected in: millions of Canadian dollars Pension benefits Other postretirement benefits 2019 435 28 2020 435 29 2021 440 29 2022 440 29 2023 440 29 2024 - 2028 2,170 150
Effect of One Percent Change in Assumptions at Which Retirement Liabilities Could be Effectively Settled	A one percent change in the assumptions at which retirement liabilities could be effectively settled is as follows: Increase (decrease) millions of Canadian dollars One percent increase One percent decrease Rate of return on plan assets: Effect on net benefit cost, before tax (80 ) 80 Discount rate: Effect on net benefit cost, before tax (95 ) 130 Effect on benefit obligation (1,110 ) 1,425 Rate of pay increases: Effect on net benefit cost, before tax 65 (50 ) Effect on benefit obligation 255 (215 )
Effect of One Percent Change in Assumed Health-Care Cost Trend Rate	A one percent change in the assumed health-care cost trend rate would have the following effects: Increase (decrease) millions of Canadian dollars One percent increase One percent decrease Effect on service and interest cost components 6 (5 ) Effect on benefit obligation 65 (50 )

Other long-term obligations (Ta

Other long-term obligations (Tables)	12 Months Ended
	Dec. 31, 2018
Other Long-Term Obligations	millions of Canadian dollars 2018 2017 Employee retirement benefits (a) (note 5) 1,195 1,529 Asset retirement obligations and other environmental liabilities (b) (d) 1,435 1,460 Share-based incentive compensation liabilities (note 8) 78 99 Other obligations (c) 235 692 Total other long-term obligations 2,943 3,780 (a) Total recorded employee retirement benefits obligations also included $55 million in current liabilities (2017 – $56 million). (b) Total asset retirement obligations and other environmental liabilities also included $118 million in current liabilities (2017 – $101 million). (c) Included carbon emission program obligations. Carbon emission program credits are recorded under other assets, including intangibles, net. (d) For 2018, the asset retirement obligations were discounted at 6 percent (2017 - 6 percent).
Schedule of Asset Retirement Obligations	Asset retirement obligations incurred in the current period were Level 3 fair value measurements. The following table summarizes the activity in the liability for asset retirement obligations: millions of Canadian dollars 2018 2017 Balance as at January 1 1,397 1,472 Additions (deductions) (5 ) (124 ) Accretion 85 92 Settlement (60 ) (43 ) Balance as at December 31 1,417 1,397

Financial and derivative inst_2

Financial and derivative instruments (Tables)	12 Months Ended
	Dec. 31, 2018
Summary of Realized and Unrealized Gain or (Loss) on Derivative Instruments	Realized and unrealized gain or (loss) on derivative instruments recognized in the Consolidated statement of income is included in the following lines on a before-tax basis: millions of Canadian dollars 2018 2017 2016 Revenues 6 - - Purchases of crude oil and products (24 ) (5 ) - Total (18 ) (5 ) -

Share-based incentive compens_2

Share-based incentive compensation programs (Tables)	12 Months Ended
	Dec. 31, 2018
Summarized Information about Incentive Share, Deferred Share and Restricted Stock Units	The following table summarizes information about these units for the year ended December 31, 2018: Restricted Deferred Outstanding at January 1, 2018 5,859,050 149,408 Granted 739,870 15,540 Vested / Exercised (1,275,640 ) (13,253 ) Forfeited and cancelled (20,455 ) - Outstanding at December 31, 2018 5,302,825 151,695

Investment and other income (Ta

Investment and other income (Tables)	12 Months Ended
	Dec. 31, 2018
Gains and Losses on Asset Sales	Investment and other income includes gains and losses on asset sales as follows: millions of Canadian dollars 2018 2017 2016 Proceeds from asset sales 59 232 3,021 Book value of asset sales 5 12 777 Gain (loss) on asset sales, before-tax (a) (b) 54 220 2,244 Gain (loss) on asset sales, after-tax (a) (b) 38 192 1,908 (a) 2017 included a gain of $174 million ($151 million after tax) from the sale of surplus property in Ontario. (b) 2016 included a gain of $2.0 billion ($1.7 billion, after tax) from the sale of company-owned Esso-branded retail sites; and a gain of $161 million ($134 million, after tax) from the sale of Imperial’s general aviation business.

Common shares (Tables)

Common shares (Tables)	12 Months Ended
	Dec. 31, 2018
Summary of Common Shares	thousands of shares At December 31 2018 2017 Authorized 1,100,000 1,100,000 Common shares outstanding 782,565 831,242
Common Share Activities	The company’s common share activities are summarized below: Thousands of Millions of Balance as at January 1, 2016 847,599 1,566 Issued under employee share-based awards 1 - Purchases at stated value (1 ) - Balance as at December 31, 2016 847,599 1,566 Issued under employee share-based awards 2 - Purchases at stated value (16,359 ) (30 ) Balance as at December 31, 2017 831,242 1,536 Issued under employee share-based awards 2 - Purchases at stated value (48,679 ) (90 ) Balance as at December 31, 2018 782,565 1,446
Calculation of Basic and Diluted Earnings Per Share	The following table provides the calculation of basic and diluted earnings per common share and the dividends declared 2018 2017 2016 Net income (loss) per common share – basic Net income (loss) (millions of Canadian dollars) 2,314 490 2,165 Weighted average number of common shares outstanding (millions of shares) 807.5 842.9 847.6 Net income (loss) per common share (dollars) 2.87 0.58 2.55 Net income (loss) per common share – diluted Net income (loss) (millions of Canadian dollars) 2,314 490 2,165 Weighted average number of common shares outstanding (millions of shares) 807.5 842.9 847.6 Effect of employee share-based awards (millions of shares) 2.6 2.8 2.9 Weighted average number of common shares outstanding, assuming dilution (millions of shares) 810.1 845.7 850.5 Net income (loss) per common share (dollars) 2.86 0.58 2.55 Dividends per common share – declared 0.73 0.63 0.59

Miscellaneous financial infor_2

Miscellaneous financial information (Tables)	12 Months Ended
	Dec. 31, 2018
Inventories of Crude Oil and Products	Inventories of crude oil and products at year-end consisted of the following: millions of Canadian dollars 2018 2017 Crude oil 731 690 Petroleum products 473 307 Chemical products 72 42 Natural gas and other 21 36 Total inventories of crude oil and products 1,297 1,075

Financing and additional note_2

Financing and additional notes and loans payable information (Tables)	12 Months Ended
	Dec. 31, 2018
Financing and Additional Notes and Loans Payable Information	millions of Canadian dollars 2018 2017 2016 Debt-related interest (a) 133 103 121 Capitalized interest (28 ) (38 ) (49) Net interest expense 105 65 72 Other interest 3 13 (7) Total financing (b) 108 78 65 (a) Includes related party interest with ExxonMobil. (b) Cash interest payments in 2018 were $88 million (2017 – $58 million, 2016 – $73 million). The weighted average interest rate on short-term borrowings in 2018 was 1.5 percent (2017 – 0.9 percent, 2016 – 0.8 percent). Average effective rate on the long-term borrowings with ExxonMobil in 2018 was 2.0 percent (2017 – 1.3 percent, 2016 – 1.0 percent).

Leased facilities (Tables)

Leased facilities (Tables)	12 Months Ended
	Dec. 31, 2018
Schedule of Operating Leases	At December 31, 2018, the company held non-cancelable operating leases covering primarily storage tanks, rail cars and marine vessels, with minimum undiscounted lease commitments totaling $291 million as indicated in the following table: Payments due by period millions of Canadian dollars 2019 2020 2021 2022 2023 After Total Lease payments under minimum commitments (a) 130 82 43 13 11 12 291 (a) Net rental cost under cancelable and non-cancelable operating leases incurred in 2018 was $221 million (2017 - $206 million, 2016 - $253 million). Related rental income was not material.

Long-term debt (Tables)

Long-term debt (Tables)	12 Months Ended
	Dec. 31, 2018
Long-Term Debt	millions of Canadian dollars At December 31 2018 2017 Long-term debt (a) 4,447 4,447 Capital leases (b) 531 558 Total long-term debt 4,978 5,005 (a) Borrowed under an existing agreement with an affiliated company of ExxonMobil that provides for a long-term, variable-rate, Canadian dollar loan from ExxonMobil to the company of up to $7.75 billion at interest equivalent to Canadian market rates. The agreement is effective until July 31, 2020, cancelable if ExxonMobil provides at least 370 days advance written notice. (b) Capital leases are primarily associated with transportation facilities and services agreements. The average imputed rate was 7.1 percent in 2018 (2017 – 7.0 percent). Total capitalized lease obligations also include $27 million in current liabilities (2017 - $27 million). Principal payments on capital leases of approximately $14 million on average per year are due in each of the next four years after December 31, 2019.

Accounting for suspended expl_2

Accounting for suspended exploratory well costs (Tables)	12 Months Ended
	Dec. 31, 2018
Change in Capitalized Suspended Exploratory Well Costs
Schedule of Aging of Capitalized Exploratory Well Costs	Period end capitalized suspended exploratory well costs: millions of Canadian dollars 2018 2017 2016 Capitalized for a period of one year or less - - - Capitalized for a period of between one and ten years - - 143 Capitalized for a period of greater than one year - - 143 Total - - 143
Number of Projects With Suspended Exploratory Well Costs	The table below provides a breakdown of the number of projects with exploratory well costs capitalized in the preceding 12 months and those that have had exploratory well costs capitalized for a period greater than 12 months. 2018 2017 2016 Number of projects with first capitalized well drilled in the preceding 12 months - - - Number of projects that have exploratory well costs capitalized for a period of greater than 12 months - - 1 Total - - 1

Other comprehensive income (l_2

Other comprehensive income (loss) information (Tables)	12 Months Ended
	Dec. 31, 2018
Changes in Accumulated Other Comprehensive Income (Loss)	Changes in accumulated other comprehensive income (loss): millions of Canadian dollars 2018 2017 2016 Balance at January 1 (1,815 ) (1,897 ) (1,828 ) Postretirement benefits liability adjustment: Current period change excluding amounts reclassified from accumulated other comprehensive income 158 (54 ) (210 ) Amounts reclassified from accumulated other comprehensive income 140 136 141 Balance at December 31 (1,517 ) (1,815 ) (1,897 )
Amounts Reclassified Out of Accumulated Other Comprehensive Income (Loss) - Before-Tax Income (Expense)	millions of Canadian dollars 2018 2017 2016 Amortization of postretirement benefits liability adjustment included in net periodic benefit cost (a) (185 ) (194 ) (184 ) (a)  This accumulated other comprehensive income component is included in the computation of net periodic benefit cost (note 5).
Income Tax Expense (Credit) for Components of Other Comprehensive Income (Loss)	millions of Canadian dollars 2018 2017 2016 Postretirement benefits liability adjustments: Postretirement benefits liability adjustment (excluding amortization) 59 (20 ) (77 ) Amortization of postretirement benefits liability adjustment included in net periodic benefit cost 45 58 43 Total 104 38 (34 )

Summary of Significant Accoun_3

Summary of Significant Accounting Policies - Additional Information (Detail) - CAD ($) $ in Millions	12 Months Ended
	Dec. 31, 2018	Jan. 01, 2019
Significant Accounting Policies [Line Items]
Amortization of computer software development costs, in years	15 years
Amortization of customer lists, in years	10 years
Subsequent Event [Member]
Significant Accounting Policies [Line Items]
Estimated value of operating lease, Right of use asset		$ 300
Estimated value of operating lease, Liability		$ 300
Refinery Chemical Process And Lubes Basestock Manufacturing Equipment
Significant Accounting Policies [Line Items]
Property plant and equipment, useful life	25 years
Maximum | Mining Heavy Equipment
Significant Accounting Policies [Line Items]
Property plant and equipment, useful life	15 years
Maximum | Ore Processing Plant Assets
Significant Accounting Policies [Line Items]
Property plant and equipment, useful life	50 years
Syncrude Joint Venture
Significant Accounting Policies [Line Items]
Undivided interest in oil and gas activities	25.00%
Kearl Joint Venture
Significant Accounting Policies [Line Items]
Undivided interest in oil and gas activities	70.96%

Accounting changes - Presentati

Accounting changes - Presentation Change on Consolidated Statement of Income (Detail) - CAD ($) $ in Millions		12 Months Ended
		Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016
Change in Accounting Estimate [Line Items]
Production and manufacturing	[1],[2]	$ 6,121	$ 5,586	$ 5,105
Selling and general	[1],[2]	908	883	1,118
Non-service pension and postretirement benefit	[3]	$ 107	122	130
Previously reported
Change in Accounting Estimate [Line Items]
Production and manufacturing			5,698	5,224
Selling and general			893	1,129
Change higher/(lower)
Change in Accounting Estimate [Line Items]
Production and manufacturing			(112)	(119)
Selling and general			(10)	(11)
Non-service pension and postretirement benefit			$ 122	$ 130
[1]	Amounts to related parties included in production and manufacturing, and selling and general expenses (note 17). 566 544 533
[2]	As part of the implementation of Accounting Standard Update, Compensation – Retirement Benefits (Topic 715), beginning January 1, 2018, Corporate and other includes all non-service pension and postretirement benefit expense. Prior to 2018, the majority of these costs were allocated to the operating segments. See note 2 for additional details.
[3]	Prior year amounts have been reclassified (note 2).

Accounting changes - Additional

Accounting changes - Additional Information (Detail) $ in Millions	12 Months Ended
	Dec. 31, 2018CAD ($)
Change in Accounting Estimate [Abstract]
After-tax impact of change in non-service cost allocation on Corporate and financing segment	$ 78

Business Segments (Detail)

Business Segments (Detail) - CAD ($) $ in Millions		12 Months Ended
		Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016
Revenues and other income
Revenues	[1],[2]	$ 34,964	$ 29,125	$ 25,049
Intersegment sales
Investment and other income (note 9)		135	299	2,305
Total revenues and other income		35,099	29,424	27,354
Expenses
Exploration	[3]	19	183	94
Purchases of crude oil and products	[4]	21,541	18,145	15,120
Production and manufacturing	[5]	6,121	5,698	5,224
Selling and general	[5]	908	893	1,129
Federal excise tax		1,667	1,673	1,650
Depreciation and depletion	[3],[6]	1,555	2,172	1,628
Non-service pension and postretirement benefit	[5]	107
Financing (note 13)	[7],[8]	108	78	65
Total expenses		32,026	28,842	24,910
Income (loss) before income taxes		3,073	582	2,444
Income taxes (note 4)
Current	[9]	(14)	(58)	200
Deferred	[9]	773	150	79
Total income tax expense (benefit)	[9],[10]	759	92	279
Net income (loss)		2,314	490	2,165
Cash flows from (used in) operating activities		3,922	2,763	2,015
Capital and exploration expenditures	[11]	1,427	671	1,161
Property, plant and equipment Cost		53,944	52,778	53,515
Accumulated depreciation and depletion		(19,719)	(18,305)	(17,182)
Net property, plant and equipment	[12]	34,225	34,473	36,333
Total assets		41,456	41,601	41,654
Consolidation, Eliminations
Revenues and other income
Intersegment sales		(4,455)	(3,681)	(3,434)
Investment and other income (note 9)
TOTAL OPERATING REVENUES, INTERSEGMENT SALES, INVESTMENT AND OTHER INCOME		(4,455)	(3,681)	(3,434)
Expenses
Purchases of crude oil and products		(4,449)	(3,675)	(3,429)
Selling and general	[5]	(6)	(6)	(5)
Federal excise tax
Depreciation and depletion	[3],[6]
Non-service pension and postretirement benefit	[5]
Financing (note 13)
Total expenses		(4,455)	(3,681)	(3,434)
Income taxes (note 4)
Cash flows from (used in) operating activities		19		(21)
Total assets		(478)	(435)	(384)
Upstream
Revenues and other income
Revenues	[2]	8,525	7,302	5,492
Intersegment sales		2,634	2,264	2,215
Investment and other income (note 9)		11	16	13
TOTAL OPERATING REVENUES, INTERSEGMENT SALES, INVESTMENT AND OTHER INCOME		11,170	9,582	7,720
Expenses
Exploration	[3]	19	183	94
Purchases of crude oil and products		5,833	4,526	3,666
Production and manufacturing	[5],[13]	4,305	3,913	3,591
Selling and general	[5]			(5)
Depreciation and depletion	[3],[6]	1,278	1,939	1,396
Financing (note 13)		1	13	(7)
Total expenses		11,436	10,574	8,735
Income (loss) before income taxes		(266)	(992)	(1,015)
Income taxes (note 4)
Current		(184)	484	(491)
Deferred		56	(770)	137
Total income tax expense (benefit)		(128)	(286)	(354)
Net income (loss)		(138)	(706)	(661)
Cash flows from (used in) operating activities		916	1,257	402
Capital and exploration expenditures	[11]	991	416	896
Property, plant and equipment Cost		46,435	45,542	45,850
Accumulated depreciation and depletion		(15,050)	(13,844)	(12,312)
Net property, plant and equipment	[12]	31,385	31,698	33,538
Total assets		34,829	35,044	36,840
Downstream
Revenues and other income
Revenues	[2]	25,200	20,714	18,511
Intersegment sales		1,542	1,155	1,007
Investment and other income (note 9)		95	269	2,278
TOTAL OPERATING REVENUES, INTERSEGMENT SALES, INVESTMENT AND OTHER INCOME		26,837	22,138	21,796
Expenses
Purchases of crude oil and products		19,326	16,543	14,178
Production and manufacturing	[5],[13]	1,606	1,576	1,428
Selling and general	[5]	773	772	972
Federal excise tax		1,667	1,673	1,650
Depreciation and depletion	[3],[6]	242	202	206
Financing (note 13)		2
Total expenses		23,616	20,766	18,434
Income (loss) before income taxes		3,221	1,372	3,362
Income taxes (note 4)
Current		189	(504)	674
Deferred		666	836	(66)
Total income tax expense (benefit)		855	332	608
Net income (loss)		2,366	1,040	2,754
Cash flows from (used in) operating activities		2,749	1,396	1,574
Capital and exploration expenditures	[11]	383	200	190
Property, plant and equipment Cost		5,900	5,683	6,166
Accumulated depreciation and depletion		(3,763)	(3,594)	(4,037)
Net property, plant and equipment	[12]	2,137	2,089	2,129
Total assets		5,119	4,890	3,958
Chemical
Revenues and other income
Revenues	[2]	1,239	1,109	1,046
Intersegment sales		279	262	212
Investment and other income (note 9)
TOTAL OPERATING REVENUES, INTERSEGMENT SALES, INVESTMENT AND OTHER INCOME		1,518	1,371	1,258
Expenses
Purchases of crude oil and products		831	751	705
Production and manufacturing	[5]	210	209	205
Selling and general	[5]	87	78	83
Depreciation and depletion	[3],[6]	14	12	10
Total expenses		1,142	1,050	1,003
Income (loss) before income taxes		376	321	255
Income taxes (note 4)
Current		21	(32)	68
Deferred		80	118
Total income tax expense (benefit)		101	86	68
Net income (loss)		275	235	187
Cash flows from (used in) operating activities		354	235	203
Capital and exploration expenditures	[11]	25	17	26
Property, plant and equipment Cost		916	888	872
Accumulated depreciation and depletion		(662)	(644)	(629)
Net property, plant and equipment	[12]	254	244	243
Total assets		438	399	346
Corporate and Other
Revenues and other income
Investment and other income (note 9)		29	14	14
TOTAL OPERATING REVENUES, INTERSEGMENT SALES, INVESTMENT AND OTHER INCOME		29	14	14
Expenses
Selling and general	[5]	54	49	84
Federal excise tax
Depreciation and depletion	[3],[6]	21	19	16
Non-service pension and postretirement benefit	[5]	107
Financing (note 13)		105	65	72
Total expenses		287	133	172
Income (loss) before income taxes		(258)	(119)	(158)
Income taxes (note 4)
Current		(40)	(6)	(51)
Deferred		(29)	(34)	8
Total income tax expense (benefit)		(69)	(40)	(43)
Net income (loss)		(189)	(79)	(115)
Cash flows from (used in) operating activities		(116)	(125)	(143)
Capital and exploration expenditures	[11]	28	38	49
Property, plant and equipment Cost		693	665	627
Accumulated depreciation and depletion		(244)	(223)	(204)
Net property, plant and equipment	[12]	449	442	423
Total assets		$ 1,548	$ 1,703	$ 894
[1]	Amounts from related parties included in revenues (note 17). 6,383 4,110 2,342
[2]	Includes export sales to the United States of $6,661 million (2017 - $4,392 million, 2016 - $3,612 million). Export sales to the United States were recorded in all operating segments, with the largest effects in the Upstream segment.
[3]	The Upstream segment in 2017 includes non-cash impairment charges of $396 million, before tax, associated with the Horn River development and $379 million, before tax, associated with the Mackenzie gas project. The impairment charges are recognized in the lines “Exploration” and “Depreciation and depletion” on the Consolidated statement of income, and the “Accumulated depreciation and depletion” line of the Consolidated balance sheet.
[4]	Amounts to related parties included in purchases of crude oil and products (note 17). 4,092 2,687 2,224
[5]	As part of the implementation of Accounting Standard Update, Compensation – Retirement Benefits (Topic 715), beginning January 1, 2018, Corporate and other includes all non-service pension and postretirement benefit expense. Prior to 2018, the majority of these costs were allocated to the operating segments. See note 2 for additional details.
[6]	The Downstream segment in 2018 includes a non-cash impairment charge of $46 million, before tax, associated with the Government of Ontario’s revocation of its carbon emission cap and trade regulation. The impairment charge is recognized in the “Depreciation and depletion” line on the Consolidated statement of income, and the “Other assets, including intangibles, net” line on the Consolidated balance sheet.
[7]	Amounts to related parties included in financing (note 17). 89 60 89
[8]	Cash interest payments in 2018 were $88 million (2017 – $58 million, 2016 – $73 million). The weighted average interest rate on short-term borrowings in 2018 was 1.5 percent (2017 – 0.9 percent, 2016 – 0.8 percent). Average effective rate on the long-term borrowings with ExxonMobil in 2018 was 2.0 percent (2017 – 1.3 percent, 2016 – 1.0 percent).
[9]	On November 2, 2017 the British Columbia government enacted a 1 percent increase in the provincial tax rate from 11 percent to 12 percent.
[10]	Cash outflow from income taxes, plus investment credits earned, was $162 million (2017 - $322 million, 2016 - $172 million).
[11]	Capital and exploration expenditures (CAPEX) include exploration expenses, additions to property, plant and equipment, additions to capital leases, additional investments and acquisitions. CAPEX excludes the purchase of carbon emission credits.
[12]	Includes property, plant and equipment under construction of $1,553 million (2017 - $1,047 million, 2016 - $2,705 million).
[13]	Amounts to related parties included in production and manufacturing, and selling and general expenses (note 17). 566 544 533

Business Segments (Parenthetica

Business Segments (Parenthetical) (Detail) - CAD ($) $ in Millions	12 Months Ended
	Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016
Segment Reporting Information [Line Items]
Impairment charge, before tax	$ 46
Plant and equipment under construction		$ 1,047	$ 2,705
United States Exports
Segment Reporting Information [Line Items]
Operating revenues		4,392	$ 3,612
Horn River Development
Segment Reporting Information [Line Items]
Impairment charge, before tax		396
Mackenzie Gas Project
Segment Reporting Information [Line Items]
Impairment charge, before tax		$ 379

Income Taxes (Detail)

Income Taxes (Detail) - CAD ($) $ in Millions		Nov. 02, 2017	Dec. 31, 2018	Dec. 31, 2017		Dec. 31, 2016
Schedule Of Income Tax [Line Items]
Current income tax expense	[1]		$ (14)	$ (58)		$ 200
Deferred income tax expense	[1]		773	150		79
Total income tax expense	[1],[2]		$ 759	$ 92		$ 279
Statutory corporate tax rate (percent)			26.90%	26.90%		26.80%
Disposals	[3]		(0.30%)	(5.30%)		(11.60%)
Enacted tax rate change		1.00%		0.90%	[1]
Other			(1.90%)	(6.60%)		(3.80%)
Effective income tax rate			24.70%	15.90%		11.40%
[1]	On November 2, 2017 the British Columbia government enacted a 1 percent increase in the provincial tax rate from 11 percent to 12 percent.
[2]	Cash outflow from income taxes, plus investment credits earned, was $162 million (2017 - $322 million, 2016 - $172 million).
[3]	2017 disposals are primarily associated with the sale of surplus property in Ontario. 2016 disposals are primarily associated with the sales of company-owned Esso retail sites and the general aviation business. Capital gains tax treatment was applied on the majority of disposals.

Income Taxes (Parenthetical) (D

Income Taxes (Parenthetical) (Detail) - CAD ($) $ in Millions	Nov. 02, 2017	Dec. 31, 2018	Dec. 31, 2017		Dec. 31, 2016
Schedule Of Income Tax [Line Items]
Increase in the provincial tax rate	1.00%		0.90%	[1]
Cash outflow from income taxes, plus investment credits earned		$ 162	$ 322		$ 172
Minimum
Schedule Of Income Tax [Line Items]
Provincial tax rate	11.00%
Maximum
Schedule Of Income Tax [Line Items]
Provincial tax rate	12.00%
[1]	On November 2, 2017 the British Columbia government enacted a 1 percent increase in the provincial tax rate from 11 percent to 12 percent.

Components of Deferred Income T

Components of Deferred Income Tax Liabilities and Assets (Detail) - CAD ($) $ in Millions	Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016
Components Of Deferred Tax Assets And Liabilities [Line Items]
Depreciation and amortization	$ 5,726	$ 5,564	$ 5,361
Successful drilling and land acquisitions	856	762	891
Pension and benefits	(336)	(422)	(457)
Asset retirement obligation	(381)	(376)	(396)
Capitalized interest	121	118	114
LIFO inventory valuation	(107)	(318)	(240)
Tax loss carryforwards	(658)	(936)	(1,056)
Other	(150)	(196)	(212)
Net long-term deferred income tax liabilities	$ 5,071	$ 4,196	$ 4,005

Unrecognized Tax Benefits (Deta

Unrecognized Tax Benefits (Detail) - CAD ($) $ in Millions	12 Months Ended
	Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016
Schedule of Unrecognized Tax Benefits [Line Items]
Balance as of January 1	$ 78	$ 106	$ 132
Additions for prior years' tax position	9	2	2
Reductions for prior years' tax positions	(2)		(18)
Reductions due to lapse of the statute of limitations			(5)
Settlements with tax authorities	(49)	(30)	(5)
Balance as of December 31	$ 36	$ 78	$ 106

Assumptions Used to Determine B

Assumptions Used to Determine Benefit Obligations (Detail)	Dec. 31, 2018	Dec. 31, 2017
Pension benefits
Defined Benefit Plan Disclosure [Line Items]
Discount rate	3.90%	3.40%
Long-term rate of compensation increase	4.50%	4.50%
Other postretirement benefits
Defined Benefit Plan Disclosure [Line Items]
Discount rate	3.90%	3.40%
Long-term rate of compensation increase	4.50%	4.50%

Change in Projected Benefit Obl

Change in Projected Benefit Obligation (Detail) - CAD ($) $ in Millions	12 Months Ended
	Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016
Pension benefits
Schedule Of Defined Benefit Plans Disclosures [Line Items]
Projected benefit obligation at January 1	$ 8,785	$ 8,356
Current service cost	239	217	$ 203
Interest cost	302	313	319
Actuarial loss (gain)	(498)	415
Benefits paid	(469)	(516)
Projected benefit obligation at December 31	8,359	8,785	8,356
Accumulated benefit obligation at December 31	7,661	8,043
Other postretirement benefits
Schedule Of Defined Benefit Plans Disclosures [Line Items]
Projected benefit obligation at January 1	670	706
Current service cost	17	16	16
Interest cost	22	23	27
Actuarial loss (gain)	(101)	(49)
Benefits paid	(26)	(26)
Projected benefit obligation at December 31	$ 582	$ 670	$ 706

Employee Retirement Benefits -

Employee Retirement Benefits - Additional Information (Detail) - CAD ($) $ in Millions	12 Months Ended
	Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016
Defined Benefit Plan Disclosure [Line Items]
Health care cost trend rate assumed for 2019 and subsequent years	4.50%
Long-term expected return	5.00%
Actual rate of return	8.20%	6.60%
Cost for defined contributions plans	$ 41	$ 40	$ 44
Plan assets invested in venture capital partnerships	3.00%
Cash contributions to pension plans in 2019	$ 212
Equity Securities
Defined Benefit Plan Disclosure [Line Items]
Target allocation securities	30.00%
Debt Securities
Defined Benefit Plan Disclosure [Line Items]
Target allocation securities	67.00%

Change in Plan Assets and Plan

Change in Plan Assets and Plan Assets in Excess of Less Than Projected Benefit Obligation (Detail) - CAD ($) $ in Millions		12 Months Ended
		Dec. 31, 2018	Dec. 31, 2017
Schedule Of Defined Benefit Plans Disclosures [Line Items]
Fair value at January 1		$ 7,870
Fair value at December 31		7,691	$ 7,870
Pension benefits
Schedule Of Defined Benefit Plans Disclosures [Line Items]
Fair value at January 1		7,870	7,359
Actual return (loss) on plan assets		20	700
Company contributions		203	212
Benefits paid	[1]	(402)	(401)
Fair value at December 31		7,691	7,870
Funded plans		(180)	(408)
Unfunded plans		(488)	(507)
Total	[2]	(668)	(915)
Other postretirement benefits
Schedule Of Defined Benefit Plans Disclosures [Line Items]
Unfunded plans		(582)	(670)
Total	[2]	$ (582)	$ (670)
[1]	Benefit payments for funded plans only.
[2]	Fair value of assets less projected benefit obligation shown above.

Amounts Recorded in Consolidate

Amounts Recorded in Consolidated Balance Sheet and Accumulated Other Comprehensive Income (Detail) - CAD ($) $ in Millions		Dec. 31, 2018	Dec. 31, 2017
Schedule Of Defined Benefit Plans Disclosures [Line Items]
Current liabilities		$ (55)	$ (56)
Other long-term obligations	[1]	(1,195)	(1,529)
Pension benefits
Schedule Of Defined Benefit Plans Disclosures [Line Items]
Current liabilities		(27)	(28)
Other long-term obligations		(641)	(887)
Total recorded		(668)	(915)
Net actuarial loss (gain)		2,117	2,408
Prior service cost			4
Total recorded in accumulated other comprehensive income, before tax		2,117	2,412
Other postretirement benefits
Schedule Of Defined Benefit Plans Disclosures [Line Items]
Current liabilities		(28)	(28)
Other long-term obligations		(554)	(642)
Total recorded		(582)	(670)
Net actuarial loss (gain)		33	140
Total recorded in accumulated other comprehensive income, before tax		$ 33	$ 140
[1]	Total recorded employee retirement benefits obligations also included $55 million in current liabilities (2017 – $56 million).

Assumptions Used to Determine P

Assumptions Used to Determine Periodic Benefit Cost (Detail)	12 Months Ended
	Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016
Schedule Of Defined Benefit Plans Disclosures [Line Items]
Long-term rate of return on funded assets	5.00%
Pension benefits
Schedule Of Defined Benefit Plans Disclosures [Line Items]
Discount rate	3.40%	3.75%	4.00%
Long-term rate of return on funded assets	5.00%	5.50%	5.50%
Long-term rate of compensation increase	4.50%	4.50%	4.50%
Other postretirement benefits
Schedule Of Defined Benefit Plans Disclosures [Line Items]
Discount rate	3.40%	3.75%	4.00%
Long-term rate of return on funded assets
Long-term rate of compensation increase	4.50%	4.50%	4.50%

Components of Net Periodic Bene

Components of Net Periodic Benefit Cost and Changes in Amounts Recorded in Accumulated Other Comprehensive Income (Detail) - CAD ($) $ in Millions	12 Months Ended
	Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016
Defined Benefit Plan Disclosure [Line Items]
Total recorded in other comprehensive income	$ (402)	$ (120)	$ 103
Pension benefits
Defined Benefit Plan Disclosure [Line Items]
Current service cost	239	217	203
Interest cost	302	313	319
Expected return on plan assets	(402)	(408)	(400)
Amortization of prior service cost	4	10	9
Amortization of actuarial loss (gain)	175	176	162
Net periodic benefit cost	318	308	293
Net actuarial loss (gain)	(116)	123	241
Amortization of net actuarial (loss) gain included in net periodic benefit cost	(175)	(176)	(162)
Amortization of prior service cost included in net periodic benefit cost	(4)	(10)	(9)
Total recorded in other comprehensive income	(295)	(63)	70
Total recorded in net periodic benefit cost and other comprehensive income, before tax	23	245	363
Other postretirement benefits
Defined Benefit Plan Disclosure [Line Items]
Current service cost	17	16	16
Interest cost	22	23	27
Amortization of actuarial loss (gain)	6	8	13
Net periodic benefit cost	45	47	56
Net actuarial loss (gain)	(101)	(49)	46
Amortization of net actuarial (loss) gain included in net periodic benefit cost	(6)	(8)	(13)
Total recorded in other comprehensive income	(107)	(57)	33
Total recorded in net periodic benefit cost and other comprehensive income, before tax	$ (62)	$ (10)	$ 89

Summary of Change in Accumulate

Summary of Change in Accumulated Other Comprehensive Income (Detail) - CAD ($) $ in Millions	12 Months Ended
	Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016
Defined Benefit Plan Disclosure [Line Items]
(Charge) credit to other comprehensive income, before tax	$ 402	$ 120	$ (103)
Deferred income tax (charge) credit (note 18)	(104)	(38)	34
(Charge) credit to other comprehensive income, after tax	$ 298	$ 82	$ (69)

Fair Value of Pension Plan Asse

Fair Value of Pension Plan Assets Including Level Within Fair Value Hierarchy (Detail) - CAD ($) $ in Millions	Dec. 31, 2018	Dec. 31, 2017
Defined Benefit Plan Disclosure [Line Items]
Total plan assets at fair value	$ 7,691	$ 7,870
Investments that are measured at fair value using net asset value	7,658	7,836
Canadian Equity Securities
Defined Benefit Plan Disclosure [Line Items]
Total plan assets at fair value	170	182
Investments that are measured at fair value using net asset value	170	182
Non-Canadian Equity Securities
Defined Benefit Plan Disclosure [Line Items]
Total plan assets at fair value	2,035	2,138
Investments that are measured at fair value using net asset value	2,035	2,138
Corporate Debt Securities
Defined Benefit Plan Disclosure [Line Items]
Total plan assets at fair value	1,231	1,248
Investments that are measured at fair value using net asset value	1,231	1,248
Government Debt Securities
Defined Benefit Plan Disclosure [Line Items]
Total plan assets at fair value	3,987	4,016
Investments that are measured at fair value using net asset value	3,987	4,016
Asset Backed Debt Securities
Defined Benefit Plan Disclosure [Line Items]
Total plan assets at fair value	3
Investments that are measured at fair value using net asset value	3
Equities - Venture Capital
Defined Benefit Plan Disclosure [Line Items]
Total plan assets at fair value	226	215
Investments that are measured at fair value using net asset value	226	215
Cash
Defined Benefit Plan Disclosure [Line Items]
Total plan assets at fair value	39	71
Investments that are measured at fair value using net asset value	6	37
Level 1
Defined Benefit Plan Disclosure [Line Items]
Total plan assets at fair value	33	34
Level 1 | Cash
Defined Benefit Plan Disclosure [Line Items]
Total plan assets at fair value	33	$ 34
Level 2 | Cash
Defined Benefit Plan Disclosure [Line Items]
Total plan assets at fair value
Level 3 | Cash
Defined Benefit Plan Disclosure [Line Items]
Total plan assets at fair value

Pension Plan with Accumulated B

Pension Plan with Accumulated Benefit Obligation in Excess of Plan Assets (Detail) - CAD ($) $ in Millions	Dec. 31, 2018	Dec. 31, 2017
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	$ 7,691	$ 7,870
Funded Pension Plans [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets
Accumulated benefit obligation less fair value of plan assets
Unfunded Pension Plans [Member]
Defined Benefit Plan Disclosure [Line Items]
Projected benefit obligation	488	507
Accumulated benefit obligation	$ 451	$ 480

Estimated 2019 Amortization fro

Estimated 2019 Amortization from Accumulated Other Comprehensive Income (Detail) $ in Millions	Dec. 31, 2018CAD ($)	[1]
Pension benefits
Defined Benefit Plan Disclosure [Line Items]
Net actuarial loss (gain)	$ 150
Other postretirement benefits
Defined Benefit Plan Disclosure [Line Items]
Net actuarial loss (gain)	$ 2
[1]	The company amortizes the net balance of actuarial loss (gain) as a component of net periodic benefit cost over the average remaining service period of active plan participants.

Expected Benefit Payments (Deta

Expected Benefit Payments (Detail) $ in Millions	Dec. 31, 2018CAD ($)
Pension benefits
Defined Benefit Plan Disclosure [Line Items]
2,019	$ 435
2,020	435
2,021	440
2,022	440
2,023	440
2024 - 2028	2,170
Other postretirement benefits
Defined Benefit Plan Disclosure [Line Items]
2,019	28
2,020	29
2,021	29
2,022	29
2,023	29
2024 - 2028	$ 150

Effect of One Percent Change in

Effect of One Percent Change in Assumptions at Which Retirement Liabilities Could be Effectively Settled (Detail) $ in Millions	12 Months Ended
	Dec. 31, 2018CAD ($)
Defined Benefit Plan Disclosure [Line Items]
Effect on net benefit cost, before tax, One percent increase - Rate of return on plan assets	$ (80)
Effect on net benefit cost, before tax, One percent increase - Discount rate	(95)
Effect on benefit obligation, One percent increase - Discount rate	(1,110)
Effect on net benefit cost, before tax, One percent increase- Rate of pay increases	65
Effect on benefit obligation, One percent increase - Rate of pay increases	255
Effect on net benefit cost, before tax, One percent decrease - Rate of return on plan assets	80
Effect on net benefit cost, before tax, One percent decrease - Discount rate	130
Effect on benefit obligation, One percent decrease - Discount rate	1,425
Effect on net benefit cost, before tax, One percent decrease- Rate of pay increases	(50)
Effect on benefit obligation, One percent decrease - Rate of pay increases	$ (215)

Effect of One Percent Change _2

Effect of One Percent Change in Assumed Health-Care Cost Trend Rate (Detail) $ in Millions	12 Months Ended
	Dec. 31, 2018CAD ($)
Defined Benefit Plan Disclosure [Line Items]
Effect on service and interest cost components, One percent increase	$ 6
Effect on service and interest cost components, One percent decrease	(5)
Effect on benefit obligation, One percent increase	65
Effect on benefit obligation, One percent decrease	$ (50)

Other Long-Term Obligations (De

Other Long-Term Obligations (Detail) - CAD ($) $ in Millions		Dec. 31, 2018	Dec. 31, 2017
Schedule of Other Liabilities [Line Items]
Employee retirement benefits	[1]	$ 1,195	$ 1,529
Asset retirement obligations and other environmental liabilities	[2],[3]	1,435	1,460
Share-based incentive compensation liabilities		78	99
Other obligations	[4]	235	692
Total other long-term obligations	[5]	$ 2,943	$ 3,780
[1]	Total recorded employee retirement benefits obligations also included $55 million in current liabilities (2017 – $56 million).
[2]	For 2018, the asset retirement obligations were discounted at 6 percent (2017 - 6 percent).
[3]	Total asset retirement obligations and other environmental liabilities also included $118 million in current liabilities (2017 – $101 million).
[4]	Included carbon emission program obligations. Carbon emission program credits are recorded under other assets, including intangibles, net.
[5]	Other long-term obligations included amounts to related parties of $15 million (2017 – $60 million), (note 17).

Other Long-Term Obligations (Pa

Other Long-Term Obligations (Parenthetical) (Detail) - CAD ($) $ in Millions	12 Months Ended
	Dec. 31, 2018	Dec. 31, 2017
Schedule of Other Liabilities [Line Items]
Employee retirement benefit obligations in current liabilities	$ 55	$ 56
Asset retirement obligations and other environmental liabilities in current liabilities	$ 118	$ 101
Asset retirement obligations discount rate	6.00%	6.00%

Schedule of Asset Retirement Ob

Schedule of Asset Retirement Obligations (Detail) - CAD ($) $ in Millions	12 Months Ended
	Dec. 31, 2018	Dec. 31, 2017
Reconciliation of Changes in Asset Retirement Obligations [Line Items]
Balance as at January 1	$ 1,397	$ 1,472
Additions (deductions)	(5)	(124)
Accretion	85	92
Settlement	(60)	(43)
Balance as at December 31	$ 1,417	$ 1,397

Financial and derivative inst_3

Financial and derivative instruments - Additional Information (Detail) $ in Millions	Dec. 31, 2018CAD ($)bbl	Dec. 31, 2017CAD ($)
Financial Instruments And Derivatives [Line Items]
Fair value of long-term debt (excluding capitalized lease obligations)	$ 4,447
Fair value of derivative asset	31
Fair value of derivative liability	$ 15	$ 4
Product
Financial Instruments And Derivatives [Line Items]
Net notional forward long / (short) position of derivative instruments | bbl	(350,000)
Crude Oil
Financial Instruments And Derivatives [Line Items]
Net notional forward long / (short) position of derivative instruments | bbl	(340,000)

Summary of Realized and Unreali

Summary of Realized and Unrealized Gain or (Loss) on Derivative Instruments (Detail) - CAD ($) $ in Millions	12 Months Ended
	Dec. 31, 2018	Dec. 31, 2017
Financial Instruments And Derivatives [Line Items]
Revenues	$ 6
Purchases of crude oil and products	(24)	$ (5)
Total	$ (18)	$ (5)

Share-Based Incentive Compens_3

Share-Based Incentive Compensation Programs - Additional Information (Detail) - CAD ($) $ in Millions	12 Months Ended
	Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Compensation expense charged against income	$ 32	$ 14	$ 83
Income tax benefit recognized in income related to compensation expense	9	4	24
Cash payment for compensation expense	$ 59	$ 71	$ 79
Restricted Stock Unit Plan 1 And 2
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Number of consecutive trading days of share price to average prior to exercise date	5 days
Restricted Stock Units
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Before-tax unrecognized compensation expense related to non-vested restricted stock	$ 75
Weighted average vesting period of nonvested restricted stock	3 years 10 months 24 days
Restricted Stock Units | Restricted Stock Unit Plan 1
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Percentage restricted stock units vested on third anniversary of the grant date	50.00%
Percentage restricted stock units vested on seventh anniversary of the grant date	50.00%
Restricted Stock Units | Restricted Stock Unit Plan 2
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Percentage restricted stock units vested on fifth anniversary of the grant date	50.00%
Percentage restricted stock units vested on tenth anniversary of the grant date	50.00%
Restricted Stock Units | Restricted Stock Unit Plan 3
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Percentage restricted stock units vested on fifth anniversary of the grant date	50.00%
Percentage restricted stock units vested on tenth anniversary of the grant date	50.00%

Summarized Information About In

Summarized Information About Incentive Share, Deferred Share and Restricted Stock Units (Detail)	12 Months Ended
	Dec. 31, 2018shares
Restricted Stock Units
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Outstanding at January 1, 2018	5,859,050
Granted	739,870
Vested / Exercised	(1,275,640)
Forfeited and cancelled	(20,455)
Outstanding at December 31, 2018	5,302,825
Deferred Share Units
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Outstanding at January 1, 2018	149,408
Granted	15,540
Vested / Exercised	(13,253)
Outstanding at December 31, 2018	151,695

Gains and Losses on Asset Sales

Gains and Losses on Asset Sales (Detail) - CAD ($) $ in Millions		12 Months Ended
		Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016
Investment And Other Income [Line Items]
Proceeds from asset sales		$ 59	$ 232	$ 3,021
Book value of asset sales		5	12	777
Gain (loss) on asset sales, before-tax	[1],[2]	54	220	2,244
Gain (loss) on asset sales, after-tax	[1],[2]	$ 38	$ 192	$ 1,908
[1]	2016 included a gain of $2.0 billion ($1.7 billion, after tax) from the sale of company-owned Esso-branded retail sites; and a gain of $161 million ($134 million, after tax) from the sale of Imperial’s general aviation business.
[2]	2017 included a gain of $174 million ($151 million after tax) from the sale of surplus property in Ontario.

Gains and Losses on Asset Sal_2

Gains and Losses on Asset Sales (Parenthetical) (Detail) - CAD ($) $ in Millions		12 Months Ended
		Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016
Investment And Other Income [Line Items]
Gain (loss) on asset sales, before tax	[1],[2]	$ 54	$ 220	$ 2,244
Gain (loss) on asset sales, after tax	[1],[2]	$ 38	192	1,908
Esso Retail Sites
Investment And Other Income [Line Items]
Gain (loss) on asset sales, before tax				2,000
Gain (loss) on asset sales, after tax				1,700
General Aviation Business
Investment And Other Income [Line Items]
Gain (loss) on asset sales, before tax				161
Gain (loss) on asset sales, after tax				$ 134
Surplus Property
Investment And Other Income [Line Items]
Gain (loss) on asset sales, before tax			174
Gain (loss) on asset sales, after tax			$ 151
[1]	2016 included a gain of $2.0 billion ($1.7 billion, after tax) from the sale of company-owned Esso-branded retail sites; and a gain of $161 million ($134 million, after tax) from the sale of Imperial’s general aviation business.
[2]	2017 included a gain of $174 million ($151 million after tax) from the sale of surplus property in Ontario.

Litigation and Other Continge_2

Litigation and Other Contingencies - Additional Information (Detail) - CAD ($) $ in Millions	12 Months Ended
	Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016
Litigation And Other Contingencies [Line Items]
Total payment on unconditional purchase obligation	$ 0
Total other third party obligations payable		$ 35	$ 42
Indemnification Agreement [Member]
Litigation And Other Contingencies [Line Items]
Total other third party obligations payable	$ 46

Summary of Common Shares (Detai

Summary of Common Shares (Detail) - shares	Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Class of Stock [Line Items]
Authorized	1,100,000,000	1,100,000,000
Common shares outstanding	783,000,000	831,000,000	847,599,000	847,599,000

Common Shares - Additional Info

Common Shares - Additional Information (Detail) - shares	12 Months Ended
	Dec. 31, 2018	Jun. 27, 2018	Jun. 13, 2018
Class of Stock [Line Items]
Normal course issuer bid share repurchase shares authorized		40,391,196
Percent of total shares			5.00%
Exxon Mobil Corporation's ownership interest in Imperial	69.60%
Normal course issuer bid share repurchase term, months	12 months

Common Share Activities (Detail

Common Share Activities (Detail) - CAD ($) shares in Thousands, $ in Millions	12 Months Ended
	Dec. 31, 2018		Dec. 31, 2017		Dec. 31, 2016
Class of Stock [Line Items]
Common stock beginning balance, shares	831,000		847,599		847,599
Issued under employee share-based awards, shares	2		2		1
Purchases at stated value, shares	(48,679)		(16,359)		(1)
Common stock, ending balance, shares	783,000		831,000		847,599
Common stock beginning balance, value	$ 1,536	[1]	$ 1,566		$ 1,566
Issued under employee share-based awards, value
Common stock, ending balance, value	1,446	[1]	1,536	[1]	1,566
Common Stock
Class of Stock [Line Items]
Purchases at stated value, value	$ 90		$ 30
[1]	Number of common shares authorized and outstanding were 1,100 million and 783 million, respectively (2017 – 1,100 million and 831 million, respectively), (note 11).

Calculation of basic and dilute

Calculation of basic and diluted earnings per common share and the dividend declared by the company on its outstanding common shares (Detail) - CAD ($) $ / shares in Units, shares in Millions, $ in Millions	12 Months Ended
	Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016
Net income (loss) per common share - basic
Net income (loss)	$ 2,314	$ 490	$ 2,165
Weighted average number of common shares outstanding (millions of shares)	807.5	842.9	847.6
Net income (loss) per common share (dollars)	$ 2.87	$ 0.58	$ 2.55
Net income (loss) per common share - diluted
Net income (loss)	$ 2,314	$ 490	$ 2,165
Weighted average number of common shares outstanding (millions of shares)	807.5	842.9	847.6
Effect of employee share-based awards (millions of shares)	2.6	2.8	2.9
Weighted average number of common shares outstanding, assuming dilution (millions of shares)	810.1	845.7	850.5
Net income (loss) per common share (dollars)	$ 2.86	$ 0.58	$ 2.55
Dividends per common share - declared (dollars)	$ 0.73	$ 0.63	$ 0.59

Miscellaneous Financial Infor_3

Miscellaneous Financial Information - Additional Information (Detail) - CAD ($) $ in Millions	12 Months Ended
	Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016
Additional Financial Information [Line Items]
Effect of LIFO inventory liquidation on income	$ 16	$ 5	$ 5
Difference between LIFO carrying values and replacement cost of inventories	900	1,400
Research and development costs charged to expenses	110	111	$ 152
Accounts payable and accrued liabilities included accrued taxes other than income taxes	$ 413	$ 437

Inventories of Crude Oil and Pr

Inventories of Crude Oil and Products (Detail) - CAD ($) $ in Millions	Dec. 31, 2018	Dec. 31, 2017
Product Information [Line Items]
Crude oil	$ 731	$ 690
Petroleum products	473	307
Chemical products	72	42
Natural gas and other	21	36
Total inventories of crude oil and products	$ 1,297	$ 1,075

Financing and Additional Note_3

Financing and Additional Notes and Loans Payable Information (Detail) - CAD ($) $ in Millions		12 Months Ended
		Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016
Debt-related interest	[1]	$ 133	$ 103	$ 121
Capitalized interest		(28)	(38)	(49)
Net interest expense		105	65	72
Other interest		3	13	(7)
Total financing	[2],[3]	$ 108	$ 78	$ 65
[1]	Includes related party interest with ExxonMobil.
[2]	Amounts to related parties included in financing (note 17). 89 60 89
[3]	Cash interest payments in 2018 were $88 million (2017 – $58 million, 2016 – $73 million). The weighted average interest rate on short-term borrowings in 2018 was 1.5 percent (2017 – 0.9 percent, 2016 – 0.8 percent). Average effective rate on the long-term borrowings with ExxonMobil in 2018 was 2.0 percent (2017 – 1.3 percent, 2016 – 1.0 percent).

Financing and Additional Note_4

Financing and Additional Notes and Loans Payable Information (Parenthetical) (Detail) - CAD ($) $ in Millions	12 Months Ended
	Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016
Cash interest payments	$ 88	$ 58	$ 73
Weighted average interest rate on short-term borrowings	1.50%	0.90%	0.80%
Average effective rate for affiliate long-term borrowing	2.00%	1.30%	1.00%

Financing and Additional Note_5

Financing and Additional Notes and Loans Payable Information - Additional Information (Detail) - CAD ($)	1 Months Ended
	Dec. 31, 2018	Nov. 30, 2018
Long Term Line Of Credit
Financing Activities [Line Items]
Non-interest bearing, revolving demand loan, outstanding amount		$ 0
Debt instrument, maturity date		Nov. 30, 2020
Non-interest bearing, revolving demand loan, remaining borrowing capacity		$ 250,000,000
Short Term Line of Credit
Financing Activities [Line Items]
Non-interest bearing, revolving demand loan, outstanding amount	$ 0
Debt instrument, maturity date	Dec. 31, 2019
Non-interest bearing, revolving demand loan, remaining borrowing capacity	$ 250,000,000
Exxon Mobil | Revolving demand loan
Financing Activities [Line Items]
Non-interest bearing, revolving demand loan, maximum borrowing capacity	75,000,000
Non-interest bearing, revolving demand loan, outstanding amount	$ 75,000,000

Leased Facilities - Additional

Leased Facilities - Additional Information (Detail) $ in Millions	Dec. 31, 2018CAD ($)
Operating Leased Assets [Line Items]
Minimum undiscounted lease commitments	$ 291	[1]
[1]	Net rental cost under cancelable and non-cancelable operating leases incurred in 2018 was $221 million (2017 - $206 million, 2016 - $253 million). Related rental income was not material.

Schedule of Non Cancelable Oper

Schedule of Non Cancelable Operating Leases (Detail) $ in Millions	Dec. 31, 2018CAD ($)	[1]
Operating Leased Assets [Line Items]
Lease payments under minimum commitments, 2019	$ 130
Lease payments under minimum commitments, 2020	82
Lease payments under minimum commitments, 2021	43
Lease payments under minimum commitments, 2022	13
Lease payments under minimum commitments, 2023	11
Lease payments under minimum commitments, After 2023	12
Total lease payments under minimum commitments	$ 291
[1]	Net rental cost under cancelable and non-cancelable operating leases incurred in 2018 was $221 million (2017 - $206 million, 2016 - $253 million). Related rental income was not material.

Schedule of Non Cancelable Op_2

Schedule of Non Cancelable Operating Leases (Parenthetical) (Detail) - CAD ($) $ in Millions	12 Months Ended
	Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016
Operating Leased Assets [Line Items]
Net rental cost incurred for operating leases	$ 221	$ 206	$ 253

Long-Term Debt (Detail)

Long-Term Debt (Detail) - CAD ($) $ in Millions		Dec. 31, 2018	Dec. 31, 2017
Debt Instrument [Line Items]
Long-term debt	[1]	$ 4,447	$ 4,447
Capital leases	[2]	531	558
Total long-term debt	[3]	$ 4,978	$ 5,005
[1]	Borrowed under an existing agreement with an affiliated company of ExxonMobil that provides for a long-term, variable-rate, Canadian dollar loan from ExxonMobil to the company of up to $7.75 billion at interest equivalent to Canadian market rates. The agreement is effective until July 31, 2020, cancelable if ExxonMobil provides at least 370 days advance written notice.
[2]	Capital leases are primarily associated with transportation facilities and services agreements. The average imputed rate was 7.1 percent in 2018 (2017 – 7.0 percent). Total capitalized lease obligations also include $27 million in current liabilities (2017 - $27 million). Principal payments on capital leases of approximately $14 million on average per year are due in each of the next four years after December 31, 2019.
[3]	Long-term debt included amounts to related parties of $4,447 million (2017 – $4,447 million), (note 17).

Long-Term Debt (Parenthetical)

Long-Term Debt (Parenthetical) (Detail) - CAD ($)	12 Months Ended
	Dec. 31, 2018	Dec. 31, 2017
Debt Instrument [Line Items]
Maximum long-term borrowing from affiliate	$ 7,750,000,000
Cancellation period long-term borrowing from affiliate, days	370 days
Capitalized lease obligations for marine services, average imputed rate	7.10%	7.00%
Total capitalized lease obligations in current liabilities	$ 27,000,000	$ 27,000,000
Principal payments on capital leases, in two years	14,000,000
Principal payments on capital leases, in three years	14,000,000
Principal payments on capital leases, in four years	14,000,000
Principal payments on capital leases, in five years	$ 14,000,000

Period End Capitalized Suspende

Period End Capitalized Suspended Exploratory Well Costs (Detail) - CAD ($) $ in Millions	12 Months Ended
	Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016
Projects with Exploratory Well Costs Capitalized for More than One Year [Line Items]
Capitalized suspended exploratory well costs, total			$ 143			$ 143
Beginning Balance		143	167
Additions pending the determination of proved reserves
Charged to expense		(143)	(24)
Reclassification to wells, facilities and equipment based on the determination of proved reserves
Ending Balance			$ 143
Capitalized for a period of one year or less
Capitalized For Period Of Between One And Ten Years
Projects with Exploratory Well Costs Capitalized for More than One Year [Line Items]
Capitalized suspended exploratory well costs						143
Capitalized For A Period Of Greater Than One Year
Projects with Exploratory Well Costs Capitalized for More than One Year [Line Items]
Capitalized suspended exploratory well costs						$ 143

Number of Projects with Explora

Number of Projects with Exploratory Well Costs (Detail) - Project	12 Months Ended
	Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016
Exploratory Wells Drilled [Line Items]
Number of projects with first capitalized well drilled in the preceding 12 months
Number of projects that have exploratory well costs capitalized for a period of greater than 12 months			1
Total projects			1

Transactions with Related Par_2

Transactions with Related Parties - Additional Information (Detail) - CAD ($) $ in Millions	12 Months Ended
	Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016
Related Party Transaction [Line Items]
Amounts of sales by Imperial	$ 6,383	$ 4,110	$ 2,342
Financing costs	89	60	$ 89
Long-Term Loans
Related Party Transaction [Line Items]
Outstanding loans from an affiliate	4,447	4,447
Short-Term Loans
Related Party Transaction [Line Items]
Outstanding loans from an affiliate	75	75
Exxon Mobil
Related Party Transaction [Line Items]
Amounts of purchases by Imperial	4,036	2,648
Amounts of sales by Imperial	6,364	4,080
Financing costs	$ 87	$ 57

Changes in Accumulated Other Co

Changes in Accumulated Other Comprehensive Income (Loss) (Detail) - CAD ($) $ in Millions	12 Months Ended
	Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016
Accumulated Other Comprehensive Income (Loss) [Line Items]
Balance at January 1	$ (1,815)	$ (1,897)	$ (1,828)
Current period change excluding amounts reclassified from accumulated other comprehensive income	158	(54)	(210)
Amounts reclassified from accumulated other comprehensive income	140	136	141
Balance at December 31	$ (1,517)	$ (1,815)	$ (1,897)

Amounts Reclassified Out of Acc

Amounts Reclassified Out of Accumulated Other Comprehensive Income (Loss) (Detail) - CAD ($) $ in Millions		12 Months Ended
		Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016
Reclassification Adjustment out of Accumulated Other Comprehensive Income
Reclassification Adjustment out of Accumulated Other Comprehensive Income [Line Items]
Amortization of postretirement benefits liability adjustment included in net periodic benefit cost	[1]	$ (185)	$ (194)	$ (184)
[1]	This accumulated other comprehensive income component is included in the computation of net periodic benefit cost (note 5).

Income Tax Expense (Credit) for

Income Tax Expense (Credit) for Components of Other Comprehensive Income (Loss) (Detail) - CAD ($) $ in Millions	12 Months Ended
	Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016
Accumulated Other Comprehensive Income (Loss) [Line Items]
Postretirement benefits liability adjustment (excluding amortization)	$ 59	$ (20)	$ (77)
Amortization of postretirement benefits liability adjustment included in net periodic benefit cost	45	58	43
Total	$ 104	$ 38	$ (34)