10-K

UNITED STATES SECURITIES AND EXCHANGE COMMISSION

WASHINGTON, D.C. 20549

FORM 10-K

ANNUAL REPORT PURSUANT TO SECTION 13 OR 15 (d) OF THE

SECURITIES EXCHANGE ACT OF 1934

For the fiscal year-ended December 31, 2017	Commission file number: 0-12014
IMPERIAL OIL LIMITED (Exact name of registrant as specified in its charter)

CANADA (State or other jurisdiction of incorporation or organization)	98-0017682 (I.R.S. Employer Identification No.)
505 QUARRY PARK BOULEVARD S.E., CALGARY, AB, CANADA            (Address of principal executive offices)	T2C 5N1     (Postal Code)

Registrant’s telephone number, including area code:

1-800-567-3776

Securities registered pursuant to Section 12(b) of the Act:

Title of each class None   Name of each exchange on which registered None  

Securities registered pursuant to Section 12(g) of the Act:

Common Shares (without par value)

(Title of Class)

Indicate by check mark if the registrant is a well-known seasoned issuer (as defined in Rule 405 of the Securities Act).

Yes ✓    No......

Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or Section 15(d) of the Securities Exchange Act of 1934. Yes...... No ✓

Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. Yes ✓    No......

Indicate by check mark whether the registrant has submitted electronically and posted on its corporate web site, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files). Yes✓ No......

Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K is not contained herein, and will not be contained, to the best of registrant’s knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-K or any amendment to this Form 10-K. Yes ✓    No......

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, a smaller reporting company, or an emerging growth company. See the definitions of “large accelerated filer”, “accelerated filer”, “smaller reporting company” and “emerging growth company” in Rule 12b-2 of the Securities Exchange Act of 1934).

Large accelerated filer ✓	Smaller reporting company......
Accelerated filer......	Emerging growth company......
Non-accelerated filer......

If an emerging growth company, indicate by check mark if the registrant has elected not to use the extended transition period for complying with any new or revised financial accounting standards provided pursuant to Section 13(a) of the Exchange Act……

Indicate by check mark whether the registrant is a shell company (as defined in Rule 12 b-2 of the Securities Exchange Act of 1934). Yes.....    No ✓

As of the last business day of the 2017 second fiscal quarter, the aggregate market value of the voting stock held by non-affiliates of the registrant was Canadian $9,702,192,452 based upon the reported last sale price of such stock on the Toronto Stock Exchange on that date.

The number of common shares outstanding, as of February 7, 2018, was 831,242,307.

1

Table of contents		Page
PART 1		3
Item 1.	Business	3
	Upstream	4
	Disclosure of reserves	4
	Proved undeveloped reserves	6
	Oil and gas production, production prices and production costs	6
	Drilling and other exploratory and development activities	9
	Present activities	11
	Delivery commitments	11
	Oil and gas properties, wells, operations and acreage	12
	Downstream	14
	Supply	14
	Transportation	14
	Refining	14
	Distribution	14
	Marketing	15
	Chemical	15
	Research	16
	Environmental protection	16
	Human resources	16
	Competition	16
	Government regulation	17
	The company online	18
Item 1A.	Risk factors	19
Item 1B.	Unresolved staff comments	22
Item 2.	Properties	22
Item 3.	Legal proceedings	22
Item 4.	Mine safety disclosures	22
PART II		23
Item 5.	Market for registrant’s common equity, related stockholder matters and issuer purchases of equity securities	23
Item 6.	Selected financial data	24
Item 7.	Management’s discussion and analysis of financial condition and results of operations	24
Item 7A.	Quantitative and qualitative disclosures about market risk	24
Item 8.	Financial statements and supplementary data	25
Item 9.	Changes in and disagreements with accountants on accounting and financial disclosure	25
Item 9A.	Controls and procedures	25
Item 9B.	Other information	25
PART III		26
Item 10.	Directors, executive officers and corporate governance	26
Item 11.	Executive compensation	26
Item 12.	Security ownership of certain beneficial owners and management and related stockholder matters	27
Item 13.	Certain relationships and related transactions, and director independence	27
Item 14.	Principal accountant fees and services	28
PART IV		29
Item 15.	Exhibits, financial statement schedules	29
Item 16.	Form 10-K summary	30
SIGNATURES		31
Financial section		32
Proxy information section		92

All dollar amounts set forth in this report are in Canadian dollars, except where otherwise indicated.

Note that numbers may not add due to rounding.

The following table sets forth (i) the rates of exchange for the Canadian dollar, expressed in United States (U.S.) dollars, in effect at the end of each of the periods indicated, (ii) the average of exchange rates in effect on the last day of each month during such periods, and (iii) the high and low exchange rates during such periods, in each case based on the noon buying rate in New York City for wire transfers in Canadian dollars as certified for customs purposes by the Federal Reserve Bank of New York.

dollars	2017		2016		2015		2014		2013
Rate at end of period		0.7989		0.7448		0.7226		0.8620		0.9401
Average rate during period		0.7714		0.7559		0.7748		0.9023		0.9665
High		0.8243		0.7972		0.8529		0.9423		1.0164
Low		0.7275		0.6853		0.7148		0.8588		0.9348

On February 7, 2018, the noon buying rate in New York City for wire transfers in Canadian dollars as certified for customs purposes by the Federal Reserve Bank of New York was $0.7971 U.S. = $1.00 Canadian.

2

Forward-looking statements

Statements of future events or conditions in this report, including projections, targets, expectations, estimates, and business plans are forward-looking statements. Actual future financial and operating results, including demand growth and energy source mix; production growth and mix; project plans, dates, costs and capacities; production rates; production life and resource recoveries; cost savings; product sales; financing sources; and capital and environmental expenditures could differ materially depending on a number of factors, such as changes in the supply of and demand for crude oil, natural gas, and petroleum and petrochemical products and resulting price and margin impacts; transportation for accessing markets; political or regulatory events, including changes in law or government policy, applicable royalty rates and tax laws; the receipt, in a timely manner, of regulatory and third-party approvals; third party opposition to operations and projects; environmental risks inherent in oil and gas exploration and production activities; environmental regulation, including climate change and greenhouse gas restrictions; currency exchange rates; availability and allocation of capital; availability and performance of third party service providers; unanticipated operational disruptions; management effectiveness; commercial negotiations; project management and schedules; response to unexpected technological developments; operational hazards and risks; disaster response preparedness; the ability to develop or acquire additional reserves; and other factors discussed in Item 1A of this annual report on Form 10-K and in the management’s discussion and analysis of financial condition and results of operations contained in Item 7. Forward-looking statements are not guarantees of future performance and involve a number of risks and uncertainties, some that are similar to other oil and gas companies and some that are unique to Imperial Oil Limited. Imperial Oil Limited’s actual results may differ materially from those expressed or implied by its forward-looking statements and readers are cautioned not to place undue reliance on them. Imperial Oil Limited undertakes no obligation to update any forward-looking statements contained herein, except as required by applicable law.

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.

PART I

Item 1.     Business

Imperial Oil Limited was incorporated under the laws of Canada in 1880 and was continued under the Canada Business Corporations Act (the “CBCA”) by certificate of continuance dated April 24, 1978. The head and principal office of the company is located at 505 Quarry Park Boulevard S.E., Calgary, Alberta, Canada T2C 5N1. Exxon Mobil Corporation (ExxonMobil) owns approximately 69.6 percent of the outstanding shares of the company. In this report, unless the context otherwise indicates, reference to the “company” or “Imperial” includes Imperial Oil Limited and its subsidiaries.

The company is one of Canada’s largest integrated oil companies. It is active in all phases of the petroleum industry in Canada, including the exploration for, and production and sale of, crude oil and natural gas. In Canada, it is a major producer of crude oil, the largest petroleum refiner and a leading marketer of petroleum products. It is also a major producer of petrochemicals.

The company’s operations are conducted in three main segments: Upstream, Downstream and Chemical. Upstream operations include the exploration for, and production of, crude oil, natural gas, synthetic oil and bitumen. Downstream operations consist of the transportation and refining of crude oil, blending of refined products and the distribution and marketing of those products. Chemical operations consist of the manufacturing and marketing of various petrochemicals.

Financial information about segments and geographic areas for the company is contained in the “Financial section” of this report under note 2 to the consolidated financial statements: “Business segments”.

3

Upstream

Disclosure of reserves

Summary of oil and gas reserves at year-end

The table below summarizes the net proved reserves for the company, as at December 31, 2017, as detailed in the “Supplemental information on oil and gas exploration and production activities” part of the “Financial section”, starting on page 32 of this report.

All of the company’s reported reserves are located in Canada. The company has reported proved reserves based on the average of the first-day-of-the-month price for each month during the last 12-month period ending December 31. Natural gas is converted to an oil-equivalent basis at six million cubic feet per one thousand barrels. No major discovery or other favourable or adverse event has occurred since December 31, 2017 that would cause a significant change in the estimated proved reserves as of that date.

	Liquids (a)	Natural gas	Synthetic oil	Bitumen	Total  oil-equivalent  basis
	millions of barrels	billions of cubic feet	millions of barrels	millions of barrels	millions of barrels
Net proved reserves:
Developed	9	282	473	591	1,120
Undeveloped	35	359	-	355	450
Total net proved	44	641	473	946	1,570

(a) Liquids include crude oil, condensate and natural gas liquids (NGLs). NGL proved reserves are not material and are therefore included under liquids.

The estimation of proved reserves, which is based on the requirement of reasonable certainty, is an ongoing process based on rigorous technical evaluations, commercial and market assessments, and detailed analysis of well information such as flow rates and reservoir pressures. Furthermore, the company only records proved reserves for projects which have received significant funding commitments by management made toward the development of the reserves. Although the company is reasonably certain that proved reserves will be produced, the timing and amount recovered can be affected by a number of factors, including completion of development projects, reservoir performance, regulatory approvals, government policies, consumer preferences, royalty framework and significant changes in long-term oil and gas price levels. In addition, proved reserves could be affected by an extended period of low prices which could reduce the level of the company’s capital spending and also impact its partners’ capacity to fund their share of joint projects. The company’s operating decisions and its outlook for future production volumes are not impacted by proved reserves as disclosed under the U.S. Securities and Exchange Commission definition.

As a result of improved prices in 2017, an additional 0.3 billion barrels of bitumen at Kearl and Cold Lake now qualify as proved reserves at year-end 2017. Among the factors that would result in additional amounts being recognized as proved reserves at some point in the future are a further recovery in yearly average price levels, a further decline in costs and additional planned investment in reliability improvements. Under the terms of certain contractual arrangements or government royalty regimes, lower prices can also increase proved reserves attributable to Imperial.

4

Technologies used in establishing proved reserves estimates

Imperial’s proved reserves in 2017 were based on estimates generated through the integration of available and appropriate geological, engineering and production data, utilizing well established technologies that have been demonstrated in the field to yield repeatable and consistent results.

Data used in these integrated assessments included information obtained directly from the subsurface via wellbores, such as well logs, reservoir core samples, fluid samples, static and dynamic pressure information, production test data, and surveillance and performance information. The data utilized also included subsurface information obtained through indirect measurements, including seismic data, calibrated with available well control information. The tools used to interpret the data included proprietary seismic processing software, proprietary reservoir modeling and simulation software, and commercially available data analysis packages.

In some circumstances, where appropriate analog reservoirs were available, reservoir parameters from these analogs were used to increase the quality of and confidence in the reserves estimates.

Preparation of reserves estimates

Imperial has a dedicated reserves management group that is separate from the base operating organization. Primary responsibilities of this group include oversight of the reserves estimation process for compliance with the U.S. Securities and Exchange Commission (SEC) rules and regulations, review of annual changes in reserves estimates and the reporting of Imperial’s proved reserves. This group also maintains the official company reserves estimates for Imperial’s proved reserves. In addition, this group provides training to personnel involved in the reserve estimation and reporting processes within Imperial.

The reserves management group maintains a central database containing the official company reserves estimates. Appropriate controls, including limitations on database access and update capabilities, are in place to ensure data integrity within this central database. An annual review of the system’s controls is performed by internal audit. Key components of the reserves estimation process include technical evaluations and analysis of well and field performance, and a rigorous peer review. No changes may be made to reserves estimates in the central database, including the addition of any new initial reserves estimates or subsequent revisions, unless those changes have been thoroughly reviewed and evaluated by duly authorized personnel within the base operating organization. In addition, changes to reserves estimates that exceed certain thresholds require further review and endorsement by the operating organization and the reserves management group, culminating in reviews with and approval by senior management and the company’s board of directors.

The internal qualified reserves evaluator is a professional geoscientist registered in Alberta, Canada and has over 19 years of petroleum industry experience, including 13 years of reserves related experience. The position provides leadership to the internal reserves management group and is responsible for filing a reserves report with the Canadian securities regulatory authorities. The company’s internal reserves evaluation staff consists of 39 persons with an average of 13 years of relevant technical experience in evaluating reserves, of whom 21 persons are qualified reserves evaluators for purposes of Canadian securities regulatory requirements. The company’s internal reserves evaluation management team is made up of 20 persons with an average of 14 years of relevant experience in evaluating and managing the evaluation of reserves.

5

Proved undeveloped reserves

As at December 31, 2017, approximately 29 percent of the company’s proved reserves were proved undeveloped reserves reflecting volumes of 450 million oil-equivalent barrels. Most of the undeveloped reserves are associated with the Cold Lake field. This compared to 319 million oil-equivalent barrels of proved undeveloped reserves reported at the end of 2016. The increase of 131 million oil-equivalent barrels of proved undeveloped reserves includes 93 million oil-equivalent barrels at Cold Lake. Conversion of proved undeveloped reserves into proved developed was not material in 2017.

Proved undeveloped reserves that have remained undeveloped for five years or more represent about 65 percent (291 million oil-equivalent barrels) of proved undeveloped reserves and are associated with Cold Lake’s ongoing drilling program. These undeveloped reserves are planned to be developed in a staged approach to align with operational capacity and efficient capital spending commitment over the life of the field. The company is reasonably certain that these proved reserves will be produced; however the timing and amount recovered can be affected by a number of factors including completion of development projects, reservoir performance, regulatory approval, royalty framework, government policies, consumer preferences and significant changes in long-term oil and gas price levels.

One of the company’s requirements to report resources as proved reserves is that management has made significant funding commitments towards the development of the reserves. The company has a disciplined investment strategy and many major fields require a long lead-time in order to be developed. The company made investments of about $150 million during the year to progress the development of proved undeveloped reserves in its Montney and Duvernay unconventional assets and at Cold Lake. These investments represented about 36 percent of the $416 million in total reported Upstream capital and exploration expenditures. Investments made by the company to develop quantities which no longer meet the SEC definition of proved reserves due to 2017 average prices are included in the $416 million of Upstream capital and exploration expenditures.

Oil and gas production, production prices and production costs

Reference is made to the portion of the “Financial section” entitled “Management’s discussion and analysis of financial condition and results of operations” on page 36 of this report for a narrative discussion on the material changes.

Average daily production of oil

The company’s average daily oil production by final products sold during the three years ended December 31, 2017 was as follows. All reported production volumes were from Canada.

thousands of barrels per day (a)		2017		2016		2015
Bitumen:
Cold Lake:	- gross (b)		162		161		158
	- net (c)		132		138		139
Kearl:	- gross (b)		126		120		108
	- net (c)		123		118		106
Total bitumen:	- gross (b)		288		281		266
	- net (c)		255		256		245
Synthetic oil (d):	- gross (b)		62		68		62
	- net (c)		57		67		58
Liquids:	- gross (b)		5		15		16
	- net (c)		4		13		15
Total:	- gross (b)		355		364		344
	- net (c)		316		336		318

(a) Volume per day metrics are calculated by dividing the volume for the period by the number of calendar days in the period.

(b) Gross production is the company’s share of production (excluding purchases) before deduction of the mineral owners’ or governments’ share or both.

(c) Net production is gross production less the mineral owners’ or governments’ share or both.

(d) The company’s synthetic oil production volumes were from the company’s share of production volumes in the Syncrude joint venture.

6

Average daily production and production available for sale of natural gas

The company’s average daily production and production available for sale of natural gas during the three years ended December 31, 2017 are set forth below. All reported production volumes were from Canada. All gas volumes in this report are calculated at a pressure base of 14.73 pounds per square inch absolute at 60 degrees Fahrenheit. Reference is made to the portion of the “Financial section” entitled “Management’s discussion and analysis of financial condition and results of operations” on page 36 of this report for a narrative discussion on the material changes.

millions of cubic feet per day (a)	2017		2016		2015
Gross production (b) (c)		120		129		130
Net production (c) (d) (e)		114		122		125
Net production available for sale (f)		80		87		94

(a) Volume per day metrics are calculated by dividing the volume for the period by the number of calendar days in the period.

(b) Gross production is the company’s share of production (excluding purchases) before deduction of the mineral owners’ or governments’ share or both.

(c) Production of natural gas includes amounts used for internal consumption with the exception of the amounts reinjected.

(d) Net production is gross production less the mineral owners’ or governments’ share or both.

(e) Net production reported in the above table is consistent with production quantities in the net proved reserves disclosure.

(f) Includes sales of the company’s share of net production and excludes amounts used for internal consumption.

Total average daily oil-equivalent basis production

The company’s total average daily production expressed in an oil-equivalent basis is set forth below, with natural gas converted to an oil-equivalent basis at six million cubic feet per one thousand barrels.

thousands of barrels per day (a)	2017		2016		2015
Total production oil-equivalent basis:
- gross (b)		375		386		366
- net (c)		335		356		339

(a) Volume per day metrics are calculated by dividing the volume for the period by the number of calendar days in the period.

(b) Gross production is the company’s share of production (excluding purchases) before deduction of the mineral owners’ or governments’ share or both.

(c) Net production is gross production less the mineral owners’ or governments’ share or both.

7

Average unit sales price

The company’s average unit sales price and average unit production costs by product type for the three years ended December 31, 2017 were as follows.

Canadian dollars per barrel	2017		2016		2015
Bitumen		39.13		26.52		32.48
Synthetic oil		67.58		57.12		61.33
Liquids		38.49		28.01		30.62
dollars per thousand cubic feet
Natural gas		2.58		2.41		2.78

In 2017, Imperial’s average Canadian dollar realizations for bitumen and synthetic crudes increased generally in line with the North American benchmarks, adjusted for changes in the exchange rate and transportation costs.

In 2016, Imperial’s average Canadian dollar realizations for bitumen and synthetic crudes declined essentially in line with the North American benchmarks, adjusted for changes in the exchange rate and transportation costs.

Average unit production costs

Canadian dollars per barrel	2017		2016		2015
Bitumen		26.81		24.24		25.16
Synthetic oil		58.96		46.24		54.81
Total oil-equivalent basis (a)		32.96		28.52		30.60

(a) Includes liquids, bitumen, synthetic oil and natural gas.

In 2017, synthetic oil unit production costs were higher, primarily driven by impacts of the fire at the Syncrude Mildred Lake upgrader.

In 2016, synthetic oil unit production costs were lower, primarily driven by increased volumes and cost management.

8

Drilling and other exploratory and development activities

The company has been involved in the exploration for and development of crude oil and natural gas in Canada only.

Wells drilled

The following table sets forth the net exploratory and development wells that were drilled or participated in by the company during the three years ended December 31, 2017.

wells	2017		2016		2015
Net productive exploratory		-		-		-
Net dry exploratory		-		-		-
Net productive development		5		6		46
Net dry development		-		-		-
Total		5		6		46

In 2017 and 2016, wells were drilled to add productive capacity, associated primarily with the Montney and Duvernay unconventional assets.

In 2015, the following wells were drilled to add productive capacity: 41 development wells at Cold Lake, of which 36 development wells relate to the Cold Lake Nabiye expansion project and five net other wells.

Wells drilling

At December 31, 2017, the company was participating in the drilling of the following exploratory and development wells, located primarily within the Montney and Duvernay unconventional assets. All wells were located in Canada.

	2017
wells	Gross		Net
Total		21		9

Exploratory and development activities regarding oil and gas resources

Cold Lake

To maintain production at Cold Lake, capital expenditures for additional production wells and associated facilities are required periodically.

The company also conducts experimental pilot operations to improve recovery of bitumen from wells by means of new drilling, production or recovery techniques.

Aspen, Cold Lake expansion and other oil sands activities

The company filed a regulatory application for a new in-situ oil sands project at Aspen in December 2013, using steam-assisted gravity drainage (SAGD) technology to develop the project in three phases producing about 45,000 barrels per day before royalties, per phase.

In 2015, the company amended the regulatory application to develop the Aspen project using solvent-assisted, steam-assisted gravity drainage (SA-SAGD) technology. The technology significantly improves capital efficiency and lowers greenhouse gas intensity versus the existing SAGD technologies. The project is proposed to be executed in two phases producing about 75,000 barrels per day before royalties, per phase. Development timing is subject to regulatory approvals and market conditions. In April 2016, Imperial was notified by the Alberta Energy Regulator that the project’s environment impact assessment was deemed complete. No final investment decision has been made.

In March 2016, Imperial filed a regulatory application for the Cold Lake Expansion project to develop the Grand Rapids interval using SA-SAGD technology. The project is proposed to produce 50,000 barrels per day, before royalties. Development timing is subject to regulatory approval and market conditions. In March 2017, Imperial was notified by the Alberta Energy Regulator that the project’s environmental impact assessment was deemed complete. No final investment decision has been made.

9

Work continues on technical evaluations to support potential Corner and Clyden in-situ development regulatory applications.

The company also has interests in other oil sands leases in the Athabasca and Peace River areas of northern Alberta. Evaluation wells completed on these leased areas established the presence of bitumen. The company continues to evaluate these leases to determine their potential for future development.

Other activities

The company is continuing to evaluate, develop and produce resources in its Montney and Duvernay unconventional assets in the western provinces.

A decision has been made not to proceed at this time with Horn River development which resulted in a 2017 impairment charge of $396 million, before tax, associated with the write-off of the net book value of the Horn River assets.

Mackenzie Delta

In 1999, the company and three other companies entered into an agreement to study the feasibility of developing Mackenzie Delta gas, anchored by three large onshore natural gas fields.

In 2017, a decision was made not to proceed at this time with the Mackenzie gas project (MGP) which resulted in an impairment charge of $379 million, before tax, associated with the write-off of the net book value of the MGP assets. The company retains a 100 percent interest in the largest of these fields.

Beaufort Sea

In 2007, the company acquired a 50 percent interest in an exploration licence in the Beaufort Sea. As part of the evaluation, a 3-D seismic survey was conducted in 2008 and the company has since carried out data collection programs to support environmental studies and safe exploration drilling operations.

In 2010, the company executed an agreement to cross-convey interests with another company to acquire a 25 percent interest in an additional Beaufort Sea exploration licence. As a result of that agreement, the company operates both licences and its interest in the original licence was reduced to 25 percent. The exploration licences are held through 2019 and 2020, respectively.

In 2013, the company and its joint venture partners filed a project description, initiating the formal regulatory review of the project.

In December 2016, the Federal Government of Canada declared Arctic waters off limits to new offshore oil and gas licences for five years subject to review at the end of that period. Existing licences will not be impacted. The Federal Government continues to consult with existing leaseholders, including Imperial. Current activities continue to focus on data gathering and community consultation. Imperial is seeking extended terms for the Beaufort Sea exploration licences with the Federal Government. No final investment decision has been made.

Liquefied natural gas (LNG) activity

WCC LNG Ltd., jointly owned by the company (20 percent) and ExxonMobil Canada Ltd. (80 percent), was granted an export licence in 2013 for up to 30 million tonnes of LNG per year for a period of 25 years. In 2016, the licence period was extended to 40 years. The project is currently in the pre-application phase in a British Columbia environmental assessment process. No final investment decision has been made.

Exploratory and development activities regarding oil and gas resources extracted by mining methods

The company continues to evaluate other undeveloped, mineable oil sands acreage in the Athabasca region.

10

Present activities

Review of principal ongoing activities

Cold Lake

Cold Lake is an in-situ heavy oil bitumen operation. The product, a blend of bitumen and diluent, is shipped to the company’s refineries, Exxon Mobil Corporation refineries and to other third parties. Diluent is natural gas condensate or other light hydrocarbons added to the crude bitumen to facilitate transportation by pipeline and rail.

During 2017, net production at Cold Lake was about 132,000 barrels per day and gross production was about 162,000 barrels per day.

Kearl

Kearl is a joint venture established to recover shallow deposits of oil sands using open-pit mining methods to extract the crude bitumen, which is processed through extraction and froth treatment trains. The company holds a 70.96 percent participating interest in the joint venture and ExxonMobil Canada Properties holds the other 29.04 percent. The product, a blend of bitumen and diluent, is shipped to the company’s refineries, Exxon Mobil Corporation refineries and to other third parties.

During 2017, the company’s share of Kearl’s net bitumen production was about 123,000 barrels per day and gross production was about 126,000 barrels per day. Increased 2017 production reflects improved reliability associated with the mining and ore preparation operations.

Imperial continues to progress work to increase Kearl annual average production to 240,000 barrels of bitumen per day (Imperial’s share would be about 170,000 barrels of bitumen per day), through planned investment including supplemental crushing capacity and flow distribution interconnects at Kearl to enhance reliability, increase redundancy and reduce downtime. The work is expected to be complete by year-end 2019.

Syncrude

Syncrude is a joint venture established to recover shallow deposits of oil sands using open-pit mining methods to extract crude bitumen, and then upgrade it to produce a high-quality, light (32 degrees API), sweet, synthetic crude oil. The company holds a 25 percent participating interest in the joint venture. The produced synthetic crude oil is shipped to the company’s refineries, Exxon Mobil Corporation refineries and to other third parties.

In 2017, the company’s share of Syncrude’s net production of synthetic crude oil was about 57,000 barrels per day and gross production was about 62,000 barrels per day.

The Province of Alberta, in its capacity as lessor of Cold Lake, Kearl and Syncrude oil sands leases, is entitled to a royalty on production. Royalties are subject to the oil sands royalty regulations which are based upon a sliding scale determined largely by the price of crude oil.

Total Upstream capital and exploration expenditures were $416 million in 2017. Investments were primarily related to sustaining activity in support of oil sands and unconventional assets.

Delivery commitments

The company has no material commitments to provide a fixed and determinable quantity of oil or gas under existing contracts and agreements.

11

Oil and gas properties, wells, operations and acreage

Production wells

The company’s production of liquids, bitumen and natural gas is derived from wells located exclusively in Canada. The total number of wells capable of production, in which the company had interests at December 31, 2017 and December 31, 2016, is set forth in the following table. The statistics in the table are determined in part from information received from other operators.

Year ended December 31, 2017

Year ended December 31, 2016

Crude Oil

Natural gas

Crude Oil

Natural gas

wells

Gross (a)

Net (b)

Gross (a)

Net (b)

Gross (a)

Net (b)

Gross (a)

Net (b)

Total (c)

4,603

4,494

3,460

1,160

4,752

4,647

3,546

1,188

 (a) Gross wells are wells in which the company owns a working interest.

 (b) Net wells are the sum of the fractional working interest owned by the company in gross wells, rounded to the nearest whole number.

 (c) Multiple completion wells are permanently equipped to produce separately from two or more distinctly different geological formations. At year-end 2017, the company had an interest in 17 gross wells with multiple completions (2016 - 16 gross wells).

Land holdings

At December 31, 2017 and December 31, 2016, the company held the following oil and gas rights, and bitumen and synthetic oil leases, all of which are located in Canada, specifically in the western provinces, in the Canada lands and in the Atlantic offshore.

		Developed				Undeveloped				Total
thousands of acres		2017		2016		2017		2016		2017		2016
Western provinces (a):
Liquids and gas	- gross (b)		1,492		1,464		825		876		2,317		2,340
	- net (c)		718		703		455		482		1,173		1,185
Bitumen	- gross (b)		197		197		674		674		871		871
	- net (c)		182		182		319		319		501		501
Synthetic oil	- gross (b)		118		118		136		136		254		254
	- net (c)		29		29		34		34		63		63
Canada lands (d):
Liquids and gas	- gross (b)		4		4		1,831		1,831		1,835		1,835
	- net (c)		2		2		498		498		500		500
Atlantic offshore:
Liquids and gas	- gross (b)		65		65		288		288		353		353
	- net (c)		6		6		46		46		52		52
Total (e):	- gross (b)		1,876		1,848		3,754		3,805		5,630		5,653
	- net (c)		937		922		1,352		1,379		2,289		2,301

 (a) Western provinces include British Columbia, Alberta and Saskatchewan.

 (b) Gross acres include the interests of others.

 (c) Net acres exclude the interests of others.

 (d) Canada lands include the Arctic Islands, Beaufort Sea / Mackenzie Delta, and other Northwest Territories, Nunavut and Yukon regions.

 (e) Certain land holdings are subject to modification under agreements whereby others may earn interests in the company’s holdings by performing certain exploratory work (farm-out) and whereby the company may earn interests in others’ holdings by performing certain exploratory work (farm-in).

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Western provinces

The company’s bitumen leases include about 194,000 net acres of oil sands leases near Cold Lake and an area of about 34,000 net acres at Kearl. The company also has about 80,000 net acres of undeveloped, mineable oil sands acreage in the Athabasca region. In addition, the company has interests in other bitumen oil sands leases in the Athabasca areas totalling about 193,000 net acres, which include about 62,000 net acres of oil sands leases in the Clyden area, about 34,000 net acres of oil sands leases in the Aspen area and about 30,000 net acres of oil sands leases in the Corner area. These 193,000 net acres are suitable for in-situ recovery techniques.

The company’s share of Syncrude joint venture leases covering about 63,000 net acres accounts for the entire synthetic oil acreage.

Oil sands leases have an exploration period of 15 years and are continued beyond that point by meeting the minimum level of evaluation, by payment of escalating rentals, or by production. The majority of the acreage in Cold Lake, Kearl and Syncrude is continued by production.

The company holds interests in an additional 1,173,000 net acres of developed and undeveloped land in the western provinces related to crude oil and natural gas.

Crude oil and natural gas leases and licences from the western provinces have exploration periods ranging from two to 15 years and are continued beyond that point by proven production capability.

Canada lands

Land holdings in Canada lands primarily include exploration licence (EL) acreage in the Beaufort Sea of about 252,000 net acres and significant discovery licence (SDL) acreage in the Mackenzie Delta and Beaufort Sea areas of about 183,000 net acres.

Exploration licences on Canada lands and Atlantic offshore have a finite term. If a significant discovery is made, a SDL may be granted that holds the acreage under the SDL indefinitely, subject to certain conditions.

The company’s net acreage in Canada lands is either continued by production or held through ELs and SDLs.

Atlantic offshore

The Atlantic offshore acreage is continued by production or held by SDLs.

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Downstream

Supply

The company supplements its own production of crude oil, condensate and petroleum products with substantial purchases from a number of other sources at negotiated market prices. Purchases are made under both spot and term contracts from domestic and foreign sources, including ExxonMobil.

Transportation

Imperial currently transports the company’s crude oil production and third party crude oil required to supply refineries by contracted pipelines, common carrier pipelines and rail. To mitigate uncertainty associated with the timing of industry pipeline projects and pipeline capacity constraints, the company has developed rail infrastructure. The Edmonton rail terminal commenced operation in 2015 and has total capacity to ship up to 210,000 barrels per day of crude oil.

Refining

The company owns and operates three refineries, which process predominantly Canadian crude oil. In 2017, Imperial decided to discontinue manufacturing base stocks, associated waxes and finished lubricants at its Strathcona Refinery lube complex and lube oil blend plant. Continued operations are planned at the refinery lube complex until the end of February 2018 and at the blend plant until mid-2018. In addition to crude oil, the company purchases finished products to supplement its refinery production.

In 2017, capital expenditures of about $139 million were made at the company’s refineries. Capital expenditures focused mainly on refinery projects to improve reliability, feedstock flexibility, energy efficiency and environmental performance.

The approximate average daily volumes of refinery throughput during the three years ended December 31, 2017, and the daily rated capacities of the refineries as at December 31, 2017, were as follows.

	Refinery throughput (a) Year ended December 31						Rated capacities (b)  at December 31
thousands of barrels per day	2017		2016		2015		2017
Strathcona, Alberta		185		168		181		191
Sarnia, Ontario		103		108		103		119
Nanticoke, Ontario		95		86		102		113
Total		383		362		386		423

(a) Refinery throughput is the volume of crude oil and feedstocks that is processed in the refinery atmospheric distillation units.

(b) Rated capacities are based on definite specifications as to types of crude oil and feedstocks that are processed in the refinery atmospheric distillation units, the products to be obtained and the refinery process, adjusted to include an estimated allowance for normal maintenance shutdowns. Accordingly, actual capacities may be higher or lower than rated capacities due to changes in refinery operation and the type of crude oil available for processing.

Refinery throughput averaged 383,000 barrels per day in 2017, up from 362,000 barrels per day in 2016. Capacity utilization increased to 91 percent from 86 percent in 2016, reflecting reduced turnaround maintenance activity.

Refinery throughput averaged 362,000 barrels per day in 2016, compared to 386,000 barrels per day in 2015. Capacity utilization decreased to 86 percent from 92 percent in 2015, reflecting the more significant scope of turnaround maintenance activity in 2016.

Distribution

The company maintains a nationwide distribution system, to handle bulk and packaged petroleum products moving from refineries to market by pipeline, tanker, rail and road transport. The company owns and operates natural gas liquids and products pipelines in Alberta, Manitoba and Ontario and has interests in the capital stock of one crude oil and two products pipeline companies.

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Marketing

The company markets petroleum products throughout Canada under well-known brand names, most notably Esso and Mobil, to all types of customers.

Imperial supplies petroleum products to the motoring public through Esso and Mobil-branded retail sites and independent marketers. On average during the year, there were more than 1,800 retail sites operating under a branded wholesaler model whereby Imperial supplies fuel to independent third parties who own and operate retail sites in alignment with Esso and Mobil brand standards. The Mobil fuels brand was launched in Canada in 2017 with the announcement of plans to convert more than 200 existing unbranded third party retail sites. Completion of this Mobil conversion is anticipated in 2018.

Imperial sells petroleum products to large industrial and transportation customers, independent marketers, resellers, as well as other refiners. The company serves agriculture, residential heating and commercial markets through branded resellers. In 2017, as part of Imperial’s truck transport business transition to a branded wholesaler model, the company announced plans to convert over 70 commercial third party sites to the Esso brand.

The approximate daily volumes of net petroleum products (excluding purchases / sales contracts with the same counterparty) sold during the three years ended December 31, 2017, are set out in the following table.

thousands of barrels per day	2017		2016		2015
Gasolines		257		261		247
Heating, diesel and jet fuels		177		170		170
Heavy fuel oils (a)		18		16		16
Lube oils and other products		40		37		45
Net petroleum product sales (a)		492		484		478

(a) In 2017, carbon black product sales are reported under Net petroleum product sales – Heavy fuel oils; in 2016 and 2015, they were reported under Total petrochemical sales – Polymers and basic chemicals.

Total Downstream capital expenditures were $200 million in 2017.

Chemical

The company’s Chemical operations manufacture and market benzene, aromatic and aliphatic solvents, plasticizer intermediates and polyethylene resin. Its petrochemical and polyethylene manufacturing operations are located in Sarnia, Ontario, adjacent to the company’s petroleum refinery.

The company’s total sales volumes of petrochemicals during the three years ended December 31, 2017, were as follows.

thousands of tonnes	2017		2016		2015
Total sales of petrochemicals (a)		774		908		945

(a) In 2017, carbon black product sales are reported under Net petroleum product sales – Heavy fuel oils; in 2016 and 2015, they were reported under Total petrochemical sales – Polymers and basic chemicals.

Lower sales volumes in 2017 were primarily due to the reclassification of carbon black product sales.

Total Chemical capital expenditures were $17 million in 2017.

15

Research

The approximate total gross research expenditures, before credits, during the three years ended December 31, 2017, were as follows.

millions of Canadian dollars	2017		2016		2015
Gross research expenditures, before credits		154		195		195

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 (GHG) 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 licensing 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.

Environmental protection

The company regards protecting the environment in connection with its various operations as a priority. The company works in cooperation with government agencies, industry associations and communities to address existing, and to anticipate potential, environmental protection issues. In the past five years, the company has made capital and operating expenditures of about $5.7 billion on environmental protection and facilities. In 2017, the company’s environmental capital and operating expenditures totalled approximately $0.6 billion, which was spent primarily on activities to protect the air, land and water, including remediation projects. Capital and operating expenditures relating to environmental protection are expected to be about $0.6 billion in 2018.

Human resources

career employees (a)	2017		2016		2015
Total		5,400		5,600		5,700

(a) Rounded. Career employees are defined as active executive, management, professional, technical, administrative and wage employees who work full time or part time for the company and are covered by the company’s benefit plans.

About 7 percent of the company’s employees are members of unions.

Competition

The Canadian petroleum, natural gas and chemical industries are highly competitive. Competition exists in the search for and development of new sources of supply, the construction and operation of crude oil, natural gas and refined products pipelines and facilities and the refining, distribution and marketing of petroleum products and chemicals. The petroleum industry also competes with other industries in supplying energy, fuel and meeting other needs of consumers.

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Government regulation

Petroleum and natural gas rights

Most of the company’s petroleum and natural gas rights were acquired from governments, either federal or provincial. These rights, in the form of leases or licences, are generally acquired for cash or work commitments. A lease or licence entitles the holder to explore for petroleum and / or natural gas on the leased lands for a specified period.

In western provinces, the lease holder can produce the petroleum or natural gas discovered on the leased lands and retains the rights based on continued production. Oil sands leases are retained by meeting the minimum level of evaluation, payment of rentals, or by production.

The holder of a licence relating to Canada lands and the Atlantic offshore can apply for a SDL if a discovery is made. If granted, the SDL holds the lands indefinitely subject to certain conditions. The holder may then apply for a production licence in order to produce petroleum or natural gas from the licenced land.

Project approval

Approvals and licences from relevant provincial or federal governmental or regulatory bodies are required for the company to carry out, or make modifications to, its oil and gas activities. The project approval process for major projects can involve, among other things, environmental assessments (including relevant mitigation measures), stakeholder and Indigenous consultation and input regarding project concerns, and public hearings. Approval may be subject to various conditions and commitments arising through these processes.

Crude oil

Production

The maximum allowable gross production of crude oil from wells in Canada is subject to limitations by various regulatory authorities on the basis of engineering and conservation principles.

Exports

Export contracts of more than one year for light crude oil and petroleum products and two years for heavy crude oil (including bitumen) require the prior approval of the National Energy Board (NEB) and the Government of Canada.

Natural gas

Production

The maximum allowable gross production of natural gas from wells in Canada is subject to limitations by various regulatory authorities. These limitations are to ensure oil recovery is not adversely impacted by accelerated gas production practices. These limitations do not impact gas reserves, only the timing of production of the reserves and did not have a significant impact on Imperial’s 2017 gas production rates.

Exports

The Government of Canada has the authority to regulate the export price for natural gas and has a gas export pricing policy, which accommodates export prices for natural gas negotiated between Canadian exporters and U.S. importers.

Exports of natural gas from Canada require approval by the NEB and the Government of Canada. The Government of Canada allows the export of natural gas by NEB order without volume limitation for terms not exceeding 24 months.

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Royalties

The Government of Canada and the provinces in which the company produces crude oil and natural gas, impose royalties on production from lands where they own the mineral rights. Some producing provinces also receive revenue by imposing taxes on production from lands where they do not own the mineral rights.

Different royalties are imposed by the Government of Canada and each of the producing provinces. Royalties imposed on crude oil, natural gas and natural gas liquids vary depending on a number of parameters, including well production volumes, selling prices and recovery methods. For information with respect to royalties for Cold Lake, Syncrude and Kearl, see “Upstream” section under Item 1.

Investment Canada Act

The Investment Canada Act requires Government of Canada approval, in certain cases, of the acquisition of control of a Canadian business by an entity that is not controlled by Canadians. The acquisition of natural resource properties may, in certain circumstances, be considered a transaction that constitutes an acquisition of control of a Canadian business requiring Government of Canada approval.

The Act also requires notification of the establishment of new unrelated businesses in Canada by entities not controlled by Canadians, but does not require Government of Canada approval except when the new business is related to Canada’s cultural heritage or national identity. The Government of Canada is also authorized to take any measures that it considers advisable to protect national security, including the outright prohibition of a foreign investment in Canada. By virtue of the majority stock ownership of the company by ExxonMobil, the company is considered to be an entity which is not controlled by Canadians.

Competition Act

The Competition Bureau ensures that Canadian businesses and consumers prosper in a competitive and innovative marketplace. The Competition Bureau is responsible for the administration and enforcement of the Competition Act (the Act). A merger transaction, whether or not notifiable, is subject to examination by the Commissioner of the Competition Bureau to determine whether the merger will have, or is likely to have, the effect of preventing or lessening substantially competition in a definable market. The assessment of the competitive effects of a merger is made with reference to the factors identified under the Act.

An Advance Ruling Certificate (ARC) may be issued by the Commissioner to a party or parties to a proposed merger transaction who want to be assured that the transaction will not give rise to proceedings under section 92 of the Act. Section 102 of the Act provides that an ARC may be issued when the Commissioner is satisfied that there would not be sufficient grounds on which to apply to the Competition Tribunal for an order against a proposed merger. The issuance of an ARC is discretionary. An ARC cannot be issued for a transaction that has been completed, nor does an ARC ensure approval of the transaction by any agency other than the Competition Bureau.

The company online

The company’s website www.imperialoil.ca contains a variety of corporate and investor information which is available free of charge, including the company’s annual report on Form 10-K, quarterly reports on Form 10-Q and current reports on Form 8-K and amendments to these reports, as well as required interactive data filings. These reports are made available as soon as reasonably practicable after they are filed or furnished to the SEC.

The public may read and copy any materials the company files with the SEC at the SEC’s Public Reference Room at 100 F Street, NE., Washington, DC 20549. The public may obtain information on the operation of the Public Reference Room by calling the SEC at 1-800-SEC-0330. The SEC’s website, www.sec.gov, contains reports, proxy and information statements and other information regarding issuers that file electronically with the SEC.

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Item 1A. Risk factors

Imperial’s financial and operating results are subject to a variety of risks inherent in oil, gas and petrochemical businesses. Many of these risk factors are not within Imperial’s control and could adversely affect Imperial’s business, financial and operating results, or financial position. These risk factors include:

Volatility of commodity prices

The company’s operations and earnings may be significantly affected by changes in oil, natural gas and petrochemical prices, and by changes in margins on refined products and petrochemicals. Crude oil, natural gas, petrochemical and product prices and margins depend on local, regional, and global events or conditions that affect supply and demand for the relevant commodity. Commodity prices have been volatile, and the company expects that volatility to continue. Any material decline in crude oil prices could have a material adverse effect on Imperial’s Upstream operations, financial position, proved reserves and the amount spent to develop reserves.

Demand related factors which could impact Imperial’s results include economic conditions, where periods of low or negative economic growth will typically have an adverse impact on results; technological improvements in energy efficiency; seasonal weather patterns, which affect the demand for energy associated with heating and cooling; increased competitiveness of alternative energy sources; new product quality regulations; and changes in technology or consumer preferences that affect the market for petroleum products, such as technological advances in energy storage that make wind and solar more competitive for power generation or increased consumer demand for alternative fueled or electric vehicles.

Commodity prices and margins also vary depending on a number of factors affecting supply. For example, increased supply from the development of new oil and gas supply sources and technologies to enhance recovery from existing sources tend to reduce commodity prices to the extent such supply increases are not offset by commensurate growth in demand. Similarly, increases in industry refining or petrochemical manufacturing capacity relative to demand tend to reduce margins on affected products. World oil, gas and petrochemical supply levels can also be affected by factors that reduce available supplies, such as adherence by member countries to Organization of the Petroleum Exporting Countries (OPEC) production quotas and the occurrence of wars, hostile actions, natural disasters, disruptions in competitors’ operations, or unexpected pipeline or rail constraints that may disrupt supplies. Technological change can also alter the relative costs for competitors to find, produce, and refine oil and gas and to manufacture petrochemicals.

A significant portion of the company’s production is bitumen, which is blended with diluent to create a marketable heavy crude oil. The market price for western Canadian heavy crude oil is typically lower than light and medium grades of oil principally due to the higher transportation and refining costs. Heavy crude oil may also be subject to limits on transportation capacity to markets to a larger extent than light crude oil. Future crude price differentials are uncertain and increases in the heavy crude oil discounts could have a material adverse effect on the company’s business. Increases to diluent prices, relative to heavy crude oil prices, could also have an adverse effect on the company’s business.

Government and political factors

Imperial’s results can be adversely impacted by political or regulatory developments affecting operations. Changes in government policy or regulations, third party opposition to company or infrastructure projects, and duration of regulatory reviews could impact Imperial’s existing operations and planned projects. For example, increases in taxes or government royalty rates (including retroactive claims), changes in trade policies and agreements, changes in environmental regulations or other laws that increase the cost of compliance or reduce or delay available business opportunities, increasing and expanding stakeholder consultation (including Indigenous stakeholders) and adoption of regulations mandating efficiency standards, the use of alternative fuels or uncompetitive fuel components could affect the company’s operations.

19

Environmental risks

All phases of the Upstream, Downstream and Chemical businesses are subject to environmental regulation pursuant to a variety of Canadian federal, provincial, territorial and municipal laws and regulations, as well as international conventions (collectively, “environmental legislation”).

Environmental legislation imposes, among other things, restrictions, liabilities and obligations in connection with the generation, handling, storage, transportation, treatment and disposal of hazardous substances and waste and in connection with spills, releases and emissions of various substances into the environment. As well, environmental regulations are imposed on the qualities and compositions of the products sold and imported. Environmental legislation also requires that wells, facility sites and other properties associated with the company’s operations be operated, maintained, monitored, abandoned and reclaimed to the satisfaction of applicable regulatory authorities. In addition, certain types of operations, including exploration and development projects and significant changes to certain existing projects, may require the submission and approval of environmental impact assessments. Compliance with environmental legislation can require significant expenditures and failure to comply with environmental legislation may result in the cessation of operations, imposition of fines and penalties and liability for clean-up costs and damages.

The costs of complying with environmental legislation in the future could have a material adverse effect on the company’s financial condition or results of operations. The company anticipates that changes in environmental legislation may require, among other things, reductions in emissions from its operations to the air and water and may result in increased capital expenditures. Changes in environmental legislation (including, but not limited to, application of regulations related to air, water, land and biodiversity) may increase the cost of compliance or reduce or delay available business opportunities. Future changes in environmental legislation could occur and result in stricter standards and enforcement, larger fines and liability, and increased capital expenditures and operating costs, which could have a material adverse effect on the company’s financial condition or results of operations.

There are operational risks inherent in oil and gas exploration and production activities, as well as the potential to incur substantial financial liabilities, if those risks are not effectively managed. The ability to insure such risks is limited by the capacity of the applicable insurance markets, which may not be sufficient to cover the likely cost of a major adverse operating event. Accordingly, the company’s primary focus is on prevention, including through its rigorous operations integrity management system. The company’s future results will depend on the continued effectiveness of these efforts.

Climate change and greenhouse gas restrictions

Due to concern over the risks of climate change, a number of provinces and the Government of Canada have adopted, or are considering the adoption of, regulatory frameworks to reduce GHG emissions. These include adoption of carbon emissions pricing, cap and trade regimes, carbon taxes, emissions limits, increased efficiency standards, low carbon fuel standards and incentives or mandates for renewable energy. These requirements could make Imperial’s products more expensive, reduce or delay available business opportunities, reduce demand for hydrocarbons, and shift hydrocarbon demand toward lower GHG emission energy sources. Current and pending GHG regulations or policies may also increase compliance and abatement costs, lengthen project evaluation and implementation times, and affect operations. Increased costs may not be recoverable in the market place and could reduce the global competitiveness of the company’s crude oil, natural gas and refined products.

Currency

Prices for commodities produced by the company are commonly benchmarked in U.S. dollars. The majority of Imperial’s sales and purchases are related to these industry U.S. dollar benchmarks. As the company records and reports its financial results in Canadian dollars, to the extent that the value of the Canadian dollar strengthens, the company’s reported earnings will be negatively affected. The company does not currently make use of derivative instruments to offset exposures associated with foreign currency.

20

Other business risks

Imperial is reliant on a number of key chemicals, catalysts and third party service providers, including input and output commodity transportation (pipelines, rail, trucking, marine) and utilities providing services, including electricity and water, to various company operations. The lack of availability and capacity, and proximity of pipeline facilities and railcars could negatively impact Imperial’s ability to produce at capacity levels. Transportation disruptions could adversely affect the company’s price realizations, refining operations and sales volumes, as well as potentially limit the ability to deliver production to market. A third party utilities outage could have an adverse impact on the company’s operations and ability to produce.

Management effectiveness

In addition to external economic and political factors, Imperial’s future business results also depend on the company’s ability to manage successfully those factors that are at least in part within its control. The extent to which Imperial manages these factors will impact its performance relative to competition. For projects in which the company is not the operator, Imperial depends on the management effectiveness of one or more co-venturers whom the company does not control.

Project management

The company’s results are affected by its ability to develop and operate projects and facilities as planned. The company’s results will, therefore, be affected by events or conditions that affect the advancement, operation, cost or results of such projects or facilities. These risks include the company’s ability to obtain the necessary environmental and other regulatory approvals; changes in regulations; changes in resources and operating costs including the availability and cost of materials, equipment and qualified personnel; the impact of general economic, business and market conditions; and the occurrence of unforeseen technical difficulties.

Operational efficiency

An important component of Imperial’s competitive performance, especially given the commodity based nature of Imperial’s business, is the ability to operate efficiently, including the company’s ability to manage expenses and improve production yields on an ongoing basis. This requires continuous management focus, including technology improvements, cost control, productivity enhancements and regular reappraisal of the company’s asset portfolio. The company’s operations and results also depend on key personnel and subject matter expertise, the recruitment, development and retention of high caliber employees, and the availability of skilled labour.

Research and development

Imperial relies upon the research and development organizations of the company and ExxonMobil, with whom the company conducts shared research. To maintain the company’s competitive position, especially in light of the technological nature of Imperial’s business and the need for continuous efficiency improvement, research and development organizations must be successful and able to adapt to a changing market and policy environment, including developing technologies to help reduce GHG emissions.

Safety, business controls and environmental risk management

The scope and nature of the company’s operations present a variety of significant hazards and risks, including operational hazards and risks such as explosions, fires, pipeline ruptures and crude oil spills. Imperial’s operations are also subject to the additional hazards of pollution, releases of toxic gas and environmental hazards and risks, such as severe weather, and geological events. The company’s results depend on management’s ability to minimize these inherent risks, to effectively control business activities and to minimize the potential for human error. Imperial applies rigorous management systems, including a combined program of effective operations integrity management, ongoing upgrades, key equipment replacements, and comprehensive inspection and surveillance. The company also maintains a disciplined framework of internal controls and applies a controls management system for monitoring compliance with this framework. Substantial liabilities and other adverse impacts could result if the company’s management systems and controls do not function as intended.

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Cybersecurity

Imperial is regularly subject to attempted cybersecurity disruptions from a variety of threat actors. If systems for protecting against cybersecurity disruptions prove to be insufficient, the company, customers, employees or third parties could be adversely affected. Such cybersecurity disruptions could cause physical harm to people or the environment; damage or destroy assets; compromise business systems; result in proprietary information being altered, lost or stolen; result in employee, customer or third party information being compromised; or otherwise disrupt business operations. Imperial could incur significant costs to remedy the effects of such a cybersecurity disruption, as well as in connection with resulting regulatory actions and litigation.

Preparedness

The company’s operations may be disrupted by severe weather events, natural disasters, human error, and similar events. Imperial’s ability to mitigate the adverse impacts of these events depends in part upon the effectiveness of its rigorous disaster preparedness and response planning, as well as business continuity planning.

Reputation

Imperial’s reputation is an important corporate asset. An operating incident, significant cybersecurity disruption or other adverse events, such as those described in Item 1A, may have a negative impact on Imperial’s reputation, which in turn could make it more difficult for Imperial to compete successfully for new opportunities, obtain necessary regulatory approvals, or could reduce consumer demand for the company’s branded products.

Reserves

The company’s future production and cash flows from bitumen, synthetic oil, liquids and natural gas reserves are highly dependent upon the company’s success in exploiting its current reserve base. To maintain production and cash flows, the company must continue to replace produced reserves as they are depleted, which can be accomplished through exploration discovery of new resources, appraisal and investments in developing discovered resources, or acquisition of reserves. To the extent cash flows from operations are insufficient to fund capital expenditures and external sources of capital become limited or unavailable, the company’s ability to make the necessary capital investments to maintain and expand oil and natural gas reserves will be adversely impacted. In addition, the company may be unable to find and develop or acquire additional reserves to replace oil and natural gas production at acceptable costs.

Estimates of economically recoverable oil and natural gas reserves and future net cash flows involve many uncertainties, including factors beyond the company’s control. Key factors with uncertainty include: geological and engineering estimates; the assumed effects of regulation or changes to regulation by government agencies including royalty frameworks; future commodity prices; and operating costs. Actual production, revenues, taxes, development costs, abandonment costs, and operating expenditures with respect to reserves will likely vary from such estimates, and such variances could be material.

Item 1B.   Unresolved staff comments

None.

Item 2.      Properties

Reference is made to Item 1 above.

Item 3.      Legal proceedings

None.

Item 4.      Mine safety disclosures

Not applicable.    

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PART II

Item 5. Market for registrant’s common equity, related stockholder matters and issuer purchases of equity securities

Market information

The company’s common shares trade on the Toronto Stock Exchange and the NYSE American LLC. Reference is made to the “Quarterly financial and stock trading data” portion of the “Financial section” on page 91 of this report. The closing price for Imperial Oil Limited common shares on the Toronto Stock Exchange was $35.50 as at February 7, 2018.

Dividends

The following table sets forth the frequency and amount of all cash dividends declared by the company on its outstanding common shares for the two most recent fiscal years.

	2017								2016
Canadian dollars	Q4		Q3		Q2		Q1		Q4		Q3		Q2		Q1
Declared dividend per share		0.16		0.16		0.16		0.15		0.15		0.15		0.15		0.14

Information for security holders outside Canada

Cash dividends paid to shareholders resident in countries with which Canada has an income tax convention are usually subject to a Canadian non-resident withholding tax of 15 percent, but may vary from one tax convention to another.

The withholding tax is reduced to 5 percent on dividends paid to a corporation resident in the U.S. that owns at least 10 percent of the voting shares of the company.

The company is a qualified foreign corporation for purposes of the reduced U.S. capital gains tax rates, which are applicable to dividends paid by U.S. domestic corporations and qualified foreign corporations.

There is no Canadian tax on gains from selling shares or debt instruments owned by non-residents not carrying on business in Canada, as long as the shareholder does not, in any given 60 month period, own 25 percent or more of the shares of the company.

As of February 7, 2018 there were 10,898 holders of record of common shares of the company.

Between October 1, 2017 and December 31, 2017, pursuant to the company’s restricted stock unit plan, there were no shares issued to employees outside the U.S. in reliance on Regulation S under the Securities Act, and 1,750 shares were issued to a seconded employee in reliance on the section 4(a)(2) exemption under the Securities Act.

Securities authorized for issuance under equity compensation plans

Sections of the company’s management proxy circular are contained in the “Proxy information section”, starting on page 92. The company’s management proxy circular is prepared in accordance with Canadian securities regulations.

Reference is made to the section under the “Company executives and executive compensation”:

● Entitled “Performance graph” within the “Compensation discussion and analysis” section on page 142 of this report; and

● Entitled “Equity compensation plan information”, within the “Compensation discussion and analysis”, on page 147 of this report.

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Issuer purchases of equity securities

	Total number of shares purchased		Average price paid per share (Canadian dollars)		Total number of shares purchased as part of publicly announced plans or programs		Maximum number of shares that may yet be purchased under the plans or programs (a)
October 2017 (October 1 - October 31)		-		-		-		18,664,257
November 2017 (November 1 - November 30)		3,554,591		39.87		3,554,591		15,109,666
December 2017 (December 1 - December 31)		2,786,181		38.91		2,786,181		12,323,485	(b)

(a) On June 22, 2017, the company announced by news release that it had received final approval from the Toronto Stock Exchange for a new normal course issuer bid and will continue its existing share purchase program. The program enables the company to purchase up to a maximum of 25,395,927 common shares during the period June 27, 2017 to June 26, 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 program will end should the company purchase the maximum allowable number of shares, or on June 26, 2018.

(b) In its most recent quarterly earnings release, the company stated that first quarter 2018 share purchases are anticipated to equal approximately $250 million. Purchase plans may be modified at any time without prior notice.

Item 6. Selected financial data

millions of Canadian dollars	2017		2016		2015		2014		2013
Operating revenues		29,125		25,049		26,756		36,231		32,722
Net income (loss)		490		2,165		1,122		3,785		2,828
Total assets at year-end		41,601		41,654		43,170		40,830		37,218
Long-term debt at year-end		5,005		5,032		6,564		4,913		4,444
Total debt at year-end		5,207		5,234		8,516		6,891		6,287
Other long-term obligations at year-end		3,780		3,656		3,597		3,565		3,091
Canadian dollars
Net income (loss) per common share - basic		0.58		2.55		1.32		4.47		3.34
Net income (loss) per common share - diluted		0.58		2.55		1.32		4.45		3.32
Dividends per share - declared		0.63		0.59		0.54		0.52		0.49

Reference is made to the table setting forth exchange rates for the Canadian dollar, expressed in U.S. dollars, on page 2 of this report.

Item 7. Management’s discussion and analysis of financial condition and results of operations

Reference is made to the section entitled “Management’s discussion and analysis of financial condition and results of operations” in the “Financial section”, starting on page 36 of this report.

Item 7A. Quantitative and qualitative disclosures about market risk

Reference is made to the section entitled “Market risks and other uncertainties” in the “Financial section”, starting on page 49 of this report. All statements other than historical information incorporated in this Item 7A are forward-looking statements. The actual impact of future market changes could differ materially due to, among other things, factors discussed in this report.

24

Item 8. Financial statements and supplementary data

Reference is made to the table of contents in the “Financial section” on page 32 of this report:

● Consolidated financial statements, together with the report thereon of PricewaterhouseCoopers LLP (PwC) dated February 28, 2018 beginning with the section entitled “Report of independent registered public accounting firm” on page 57 and continuing through note 17, “Other comprehensive income (loss) information” on page 86;

● “Supplemental information on oil and gas exploration and production activities” (unaudited) starting on page 87; and

● “Quarterly financial and stock trading data” on page 91.

Item 9. Changes in and disagreements with accountants on accounting and financial disclosure

None.

Item 9A. Controls and procedures

As indicated in the certifications in Exhibit 31 of this report, the company’s principal executive officer and principal financial officer have evaluated the company’s disclosure controls and procedures as of December 31, 2017. Based on that evaluation, these officers have concluded that the company’s disclosure controls and procedures are effective in ensuring that information required to be disclosed by the company in the reports that it files or submits under the Securities Exchange Act of 1934, as amended, is accumulated and communicated to them in a manner that allows for timely decisions regarding required disclosures and are effective in ensuring that such information is recorded, processed, summarized and reported within the time periods specified in the SEC’s rules and forms.

Reference is made to page 56 of this report for “Management’s report on internal control over financial reporting” and page 57 for the “Report of independent registered public accounting firm” on the company’s internal control over financial reporting as of December 31, 2017.

There has not been any change in the company’s internal control over financial reporting during the last fiscal quarter that has materially affected, or is reasonably likely to materially affect, the company’s internal control over financial reporting.

Item 9B. Other information

None.

25

PART III

Item 10. Directors, executive officers and corporate governance

Sections of the company’s management proxy circular are contained in the “Proxy information section”, starting on page 92. The company’s management proxy circular is prepared in accordance with Canadian securities regulations.

The company currently has eight directors. The articles of the company require that the board have between five and fifteen directors. Each director is elected to hold office until the close of the next annual meeting. Each of the seven individuals listed in the section entitled “Nominees for director” on pages 93 to 97 of this report have been nominated for election at the annual meeting of shareholders to be held April 27, 2018. All of the nominees are directors and have been since the dates indicated. V.L. Young is currently a director and is not standing for re-election in 2018 as he will reach the company’s mandatory retirement age for directors in 2018.

Reference is made to the section under “Nominees for director”:

● “Director nominee tables”, on pages 93 to 97 of this report;

Reference is made to the sections under “Corporate governance disclosure”:

● “Other public company directorships of our board members”, on page 103 of this report.

● The table entitled “Audit committee” under “Board and committee structure”, on page 107 of this report;

● “Ethical business conduct”, starting on page 119 of this report; and

● “Largest shareholder”, on page 121 of this report.

Reference is made to the sections under “Company executives and executive compensation”:

● “Named executive officers of the company” and “Other executive officers of the company”, on pages 123 to 125 of this report.

Item 11. Executive compensation

Sections of the company’s management proxy circular are contained in the “Proxy information section”, starting on page 92. The company’s management proxy circular is prepared in accordance with Canadian securities regulations.

Reference is made to the sections under “Corporate governance disclosure”:

● “Director compensation”, on pages 111 to 117 of this report; and

● “Share ownership guidelines of independent directors and chairman, president and chief executive officer”, on page 118 of this report.

Reference is made to the following sections under “Company executives and executive compensation”:

● “Letter to shareholders from the executive resources committee on executive compensation”, starting on page 126 of this report; and

● “Compensation discussion and analysis”, on pages 128 to 149 of this report.

26

Item 12. Security ownership of certain beneficial owners and management and related stockholder matters

Sections of the company’s management proxy circular are contained in the “Proxy information section”, starting on page 92. The company’s management proxy circular is prepared in accordance with Canadian securities regulations.

Reference is made to the section under “Company executives and executive compensation” entitled “Equity compensation plan information”, within the “Compensation discussion and analysis” section, on page 147 of this report.

Reference is made to the section under “Corporate governance disclosure” entitled “Largest shareholder”, on page 121 of this report.

Reference is also made to the security ownership information for directors and executive officers of the company under the preceding Items 10 and 11. With respect to named executive officers who are not directors of the company, as of February 7, 2018, B.A. Babcock was the owner of 27,139 common shares and held 111,000 restricted stock units of the company, and was the owner of 352 common shares of Exxon Mobil Corporation. J.R. Whelan held 22,000 restricted stock units of the company, and was the owner of 24,125 common shares and held 30,200 restricted stock of Exxon Mobil Corporation. T.B. Redburn was the owner of 3,267 common shares and held 83,850 restricted stock units of the company. P.M. Dinnick held 10,400 restricted stock units of the company, and was the owner of 860 common shares and held 13,200 restricted stock of Exxon Mobil Corporation.

The directors and the executive officers of the company, whose compensation for the year-ended December 31, 2017 is described in the sections under “Nominees for director” starting on page 93, “Director compensation” starting on page 111 and “Company executives and executive compensation” starting on page 123, consist of 19 persons, who, as a group, as of February 7, 2018, beneficially own 180,181 common shares of the company, being approximately 0.02 percent of the total number of outstanding shares of the company, and 457,990 shares of Exxon Mobil Corporation (including 390,700 restricted shares). This information not being within the knowledge of the company has been provided by the directors and the executive officers individually. As a group, the directors and executive officers of the company held restricted stock units to acquire 719,745 common shares of the company, as of February 7, 2018.

Item 13. Certain relationships and related transactions, and director independence

Sections of the company’s management proxy circular are contained in the “Proxy information section”, starting on page 92. The company’s management proxy circular is prepared in accordance with Canadian securities regulations.

Reference is made to the section under “Corporate governance disclosure” entitled “Independence of our board members”, on page 101 of this report.

Reference is made to the section under “Corporate governance disclosure” entitled “Transactions with Exxon Mobil Corporation”, on page 121 of this report.

D.G. (Jerry) Wascom is deemed a non-independent member of the board of directors and the executive resources committee, environmental, health and safety committee, nominations and corporate governance committee and contributions committee under the relevant standards. As an employee of Exxon Mobil Corporation, D.G. (Jerry) Wascom is independent of the company’s management and is able to assist these committees by reflecting the perspective of the company’s shareholders.

27

Item 14. Principal accountant fees and services

Auditor information

The audit committee of the board of directors recommends that PwC be reappointed as the auditor of the company until the close of the next annual meeting. PwC has been the auditor of the company for more than five years and are located in Calgary, Alberta. PwC is a participating audit firm with the Canadian Public Accountability Board.

Auditor fees

The aggregate fees of PwC for professional services rendered for the audit of the company’s financial statements and other services for the fiscal years ended December 31, 2017 and December 31, 2016 were as follows:

thousands of Canadian dollars	2017		2016
Audit fees		1,756		1,500
Audit-related fees		94		104
Tax fees		-		-
All other fees		-		-
Total fees		1,850		1,604

Audit fees included the audit of the company’s annual financial statements, internal control over financial reporting, and a review of the first three quarterly financial statements in 2017. Audit-related fees consisted of other assurance services including the audit of the company’s retirement plan and royalty statement audits for oil and gas producing entities. The company did not engage the auditor for any other services.

The audit committee formally and annually evaluates the performance of the external auditor, recommends the external auditor to be appointed by the shareholders, recommends their remuneration and oversees their work. The audit committee also approves the proposed current year audit program of the external auditor, assesses the results of the program after the end of the program period and approves in advance any non-audit services to be performed by the external auditor after considering the effect of such services on their independence.

All of the services rendered by the auditor to the company were approved by the audit committee.

Auditor independence

The audit committee continually discusses with PwC their independence from the company and from management. PwC have confirmed that they are independent with respect to the company within the meaning of the Rules of Professional Conduct of the Chartered Professional Accountants of Alberta, the Public Company Accounting Oversight Board (United States) (PCAOB) and the rules of the U.S. Securities and Exchange Commission. The company has concluded that the auditor’s independence has been maintained.

28

PART IV

Item 15. Exhibits, financial statement schedules

Reference is made to the table of contents in the “Financial section” on page 32 of this report.

The following exhibits, numbered in accordance with Item 601 of Regulation S-K, are filed as part of this report:

(3)	(i)	Restated certificate and articles of incorporation of the company (Incorporated herein by reference to Exhibit  (3.1) to the company’s Form 8-K filed on May 3, 2006 (File No. 0-12014)).
	(ii)	By-laws of the company (Incorporated herein by reference to Exhibit (3)(ii) to the company’s Quarterly Report on Form 10-Q for the quarter ended March 31, 2003 (File No. 0-12014)).
(10)	(ii)	(1)	Syncrude Ownership and Management Agreement, dated February 4, 1975 (Incorporated herein by reference to Exhibit 13(b) of the company’s Registration Statement on Form S-1, as filed with the Securities and Exchange Commission on August 21, 1979 (File No. 2-65290)).
		(2)	Letter Agreement, dated February 8, 1982, between the Government of Canada and Esso Resources Canada Limited, amending Schedule “C” to the Syncrude Ownership and Management Agreement filed as Exhibit (10)(ii)(2) (Incorporated herein by reference to Exhibit (20) of the company’s Annual Report on Form 10-K for the year ended December 31, 1981 (File No. 2-9259)).
		(3)	Alberta Cold Lake Crown Agreement, dated June 25, 1984, relating to the royalties payable and the assurances given in respect of the Cold Lake production project (Incorporated herein by reference to Exhibit (10)(ii)(11) of the company’s Annual Report on Form 10-K for the year ended December 31, 1986 (File No. 0-12014)).
		(4)	Amendment to Syncrude Ownership and Management Agreement, dated March 10, 1982 (Incorporated herein by reference to Exhibit (10)(ii)(14) of the company’s Annual Report on Form 10-K for the year ended December 31, 1989 (File No. 0-12014)).
		(5)	Alberta Cold Lake Transition Agreement, effective January 1, 2000, relating to the royalties payable in respect of the Cold Lake production project and terminating the Alberta Cold Lake Crown Agreement. (Incorporated herein by reference to Exhibit (10)(ii)(20) of the company’s Annual Report on Form 10-K for the year ended December 31, 2001 (File No. 0-12014)).
		(6)	Amendment to Syncrude Ownership and Management Agreement effective January 1, 2001 (Incorporated herein by reference to Exhibit (10)(ii)(22) of the company’s Quarterly Report on Form 10-Q for the quarter ended June 30, 2002 (File No. 0-12014)).
		(7)	Amendment to Syncrude Ownership and Management Agreement effective September 16, 1994 (Incorporated herein by reference to Exhibit (10)(ii)(23) of the company’s Quarterly Report on Form 10-Q for the quarter ended June 30, 2002 (File No. 0-12014)).
		(8)	Syncrude Bitumen Royalty Option Agreement, dated November  18, 2008, setting out the terms of the exercise by the Syncrude Joint Venture owners of the option contained in the existing Crown Agreement to convert to a royalty payable on the value of bitumen, effective January  1, 2009 (Incorporated herein by reference to Exhibit 1.01(10)(ii)(2) of the company’s Form 8-K filed on November 19, 2008 (File No. 0-12014)).
(iii)	(A)	(1)	Form of Letter relating to Supplemental Retirement Income (Incorporated herein by reference to Exhibit (10)(c)(3) of the company’s Annual Report on Form 10-K for the year ended December 31, 1980 (File No. 2-9259)).
		(2)	Deferred Share Unit Plan for Nonemployee Directors. (Incorporated herein by reference to Exhibit (10)(iii)(A)(6) of the company’s Annual Report on Form 10-K for the year ended December 31, 1998 (File No. 0-12014)).
		(3)	Amended Restricted Stock Unit Plan with respect to Restricted Stock Units granted in 2008 and subsequent years, as amended effective November 20, 2008 (Incorporated herein by reference to Exhibit 9.01(c)[10(iii)(A)(5)] of the company’s Form 8-K filed on November 25, 2008 (File No. 0-12014)).
		(4)	Short Term Incentive Program for selected executives effective February  2, 2012 (Incorporated herein by reference to Exhibit 9.01(c)[10(iii)(A)(1)] of the company’s Form 8-K filed on February 7, 2012 (File No. 0-12014)).

29

	(5)	Amended Restricted Stock Unit Plan with respect to Restricted Stock Units granted in 2011 and subsequent years, as amended effective November 14, 2011 (Incorporated herein by reference to Exhibit 9.01(c)[10(iii)(A)(1)] of the company’s Form 8-K filed on February 23, 2012 (File No. 0-12014)).
	(6)	Amended Restricted Stock Unit Plan with respect to Restricted Stock Units granted in 2016 and subsequent years, as amended effective October 26, 2016 (Incorporated herein by reference to Exhibit 9.01(c)[10(iii)(A)(1)] of the company’s Form 8-K filed on October 31, 2016 (File No. 0-12014)).
	(7)	Amended Short Term Incentive Program with respect to awards granted in 2016 and subsequent years, as amended effective October  26, 2016 (Incorporated herein by reference to Exhibit 9.01(c)[10(iii)(A)(1)] of the company’s Form 8-K filed on October 31, 2016 (File No. 0-12014)).
(21)		Imperial Oil Resources Limited is incorporated in Canada, and is a wholly-owned subsidiary of the company. The names of all other subsidiaries of the company are omitted because, considered in the aggregate as a single subsidiary, they would not constitute a significant subsidiary as of December 31, 2017.
(31.1)		Certification by principal executive officer of Periodic Financial Report pursuant to Rule 13a-14(a).
(31.2)		Certification by principal financial officer of Periodic Financial Report pursuant to Rule 13a-14(a).
(32.1)		Certification by chief executive officer of Periodic Financial Report pursuant to Rule 13a-14(b) and 18 U.S.C. Section 1350.
(32.2)		Certification by chief financial officer of Periodic Financial Report pursuant to Rule 13a-14(b) and 18 U.S.C. Section 1350.

Copies of Exhibits may be acquired upon written request of any shareholder to the investor relations manager, Imperial Oil Limited, 505 Quarry Park Boulevard S.E., Calgary, Alberta T2C 5N1, and payment of processing and mailing costs.

Item 16. Form 10-K summary

Not applicable.

30

SIGNATURES

Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf on February 28, 2018 by the undersigned, thereunto duly authorized.

        Imperial Oil Limited

        by          /s/ Richard M. Kruger

(Richard M. Kruger)

Chairman, president and chief executive officer

Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below on February 28, 2018 by the following persons on behalf of the registrant and in the capacities indicated.

Signature	Title
/s/ Richard M. Kruger	Chairman, president and
(Richard M. Kruger)	chief executive officer and director
	(Principal executive officer)
/s/ Beverley A. Babcock	Senior vice-president,
(Beverley A. Babcock)	finance and administration, and controller
	(Principal financial officer and principal
	accounting officer)
/s/ David W. Cornhill	Director
(David W. Cornhill)
/s/ Krystyna T. Hoeg	Director
(Krystyna T. Hoeg)
/s/ Jack M. Mintz	Director
(Jack M. Mintz)
/s/ David S. Sutherland	Director
(David S. Sutherland)
/s/ D.G. (Jerry) Wascom	Director
(D.G. (Jerry) Wascom)
/s/ Sheelagh D. Whittaker	Director
(Sheelagh D. Whittaker)
/s/ Victor L. Young	Director
(Victor L. Young)

31

Financial section

Table of contents	Page
Financial information (U.S. GAAP)	33
Frequently used terms	34
Management’s discussion and analysis of financial condition and results of operations	36
Overview	36
Business environment and risk assessment	36
Results of operations	40
Liquidity and capital resources	45
Capital and exploration expenditures	48
Market risks and other uncertainties	49
Critical accounting estimates	51
Recently issued accounting standards	55
Management’s report on internal control over financial reporting	56
Report of independent registered public accounting firm	57
Consolidated statement of income (U.S. GAAP)	59
Consolidated statement of comprehensive income (U.S. GAAP)	60
Consolidated balance sheet (U.S. GAAP)	61
Consolidated statement of shareholders’ equity (U.S. GAAP)	62
Consolidated statement of cash flows (U.S. GAAP)	63
Notes to consolidated financial statements	64
1. Summary of significant accounting policies	64
2. Business segments	70
3. Income taxes	72
4. Employee retirement benefits	73
5. Other long-term obligations	79
6. Derivatives and financial instruments	79
7. Share-based incentive compensation programs	80
8. Investment and other income	81
9. Litigation and other contingencies	81
10. Common shares	82
11. Miscellaneous financial information	83
12. Financing costs and additional notes and loans payable information	83
13. Leased facilities	83
14. Long-term debt	84
15. Accounting for suspended exploratory well costs	84
16. Transactions with related parties	85
17. Other comprehensive income (loss) information	86
Supplemental information on oil and gas exploration and production activities (unaudited)	87
Quarterly financial and stock trading data	91

32

Financial information (U.S. GAAP)

millions of Canadian dollars	2017			2016			2015			2014			2013
Operating revenues		29,125			25,049			26,756			36,231			32,722
Net income (loss):
Upstream		(706	)		(661	)		(704	)		2,059			1,712
Downstream		1,040			2,754			1,586			1,594			1,052
Chemical		235			187			287			229			162
Corporate and other		(79	)		(115	)		(47	)		(97	)		(98)
Net income (loss)		490			2,165			1,122			3,785			2,828
Cash and cash equivalents at year-end		1,195			391			203			215			272
Total assets at year-end		41,601			41,654			43,170			40,830			37,218
Long-term debt at year-end		5,005			5,032			6,564			4,913			4,444
Total debt at year-end		5,207			5,234			8,516			6,891			6,287
Other long-term obligations at year-end		3,780			3,656			3,597			3,565			3,091
Shareholders’ equity at year-end		24,435			25,021			23,425			22,530			19,524
Cash flow from operating activities		2,763			2,015			2,167			4,405			3,292
Per share information (dollars)
Net income (loss) per common share - basic		0.58			2.55			1.32			4.47			3.34
Net income (loss) per common share - diluted		0.58			2.55			1.32			4.45			3.32
Dividends per share - declared		0.63			0.59			0.54			0.52			0.49

33

Frequently used terms

Listed below are definitions of several of Imperial’s key business and financial performance measures. The definitions are provided to facilitate understanding of the terms and how they are calculated.

Capital employed

Capital employed is a measure of net investment. When viewed from the perspective of how capital is used by the business, it includes the company’s property, plant and equipment, and other assets, less liabilities, excluding both short-term and long-term debt. When viewed from the perspective of the sources of capital employed in total for the company, it includes total debt and equity. Both of these views include the company’s share of amounts applicable to equity companies, which the company believes should be included to provide a more comprehensive measurement of capital employed.

millions of Canadian dollars	2017			2016			2015
Business uses: asset and liability perspective
Total assets		41,601			41,654			43,170
Less:  Total current liabilities excluding notes and loans payable		(3,934	)		(3,681	)		(3,441)
Total long-term liabilities excluding long-term debt		(8,025	)		(7,718	)		(7,788)
Add:  Imperial’s share of equity company debt		19			17			18
Total capital employed		29,661			30,272			31,959
Total company sources: Debt and equity perspective
Notes and loans payable		202			202			1,952
Long-term debt		5,005			5,032			6,564
Shareholders’ equity		24,435			25,021			23,425
Add: Imperial’s share of equity company debt		19			17			18
Total capital employed		29,661			30,272			31,959

Return on average capital employed (ROCE)

ROCE is a financial performance ratio. From the perspective of the business segments, ROCE is annual business-segment net income divided by average business-segment capital employed (an average of the beginning and end-of-year amounts). Segment net income includes Imperial’s share of segment net income of equity companies, consistent with the definition used for capital employed, and excludes the cost of financing. The company’s total ROCE is net income excluding the after-tax cost of financing divided by total average capital employed. The company has consistently applied its ROCE definition for many years and views it as the best measure of historical capital productivity in a capital-intensive, long-term industry to both evaluate management’s performance and demonstrate to shareholders that capital has been used wisely over the long term. Additional measures, which are more cash flow based, are used to make investment decisions.

millions of Canadian dollars	2017		2016		2015
Net income		490		2,165		1,122
Financing costs (after tax), including Imperial’s share of equity companies		48		53		30
Net income excluding financing costs		538		2,218		1,152
Average capital employed		29,967		31,116		30,700
Return on average capital employed (percent) – corporate total		1.8		7.1		3.8

34

Cash flow from operating activities and asset sales

Cash flow from operating activities and asset sales is the sum of the net cash provided by operating activities and proceeds from asset sales reported in the consolidated statement of cash flows. This cash flow reflects the total sources of cash both from operating the company’s assets and from the divesting of assets. The company employs a long-standing and regular disciplined review process to ensure that all assets are contributing to the company’s strategic objectives. Assets are divested when they no longer meet these objectives or are worth considerably more to others. Because of the regular nature of this activity, the company believes it is useful for investors to consider sales proceeds together with cash provided by operating activities when evaluating cash available for investment in the business and financing activities, including shareholder distributions.

millions of Canadian dollars	2017		2016		2015
Cash from operating activities		2,763		2,015		2,167
Proceeds from asset sales		232		3,021		142
Total cash flow from operating activities and asset sales		2,995		5,036		2,309

Operating costs

Operating costs are the costs during the period to produce, manufacture, and otherwise prepare the company’s products for sale – including energy costs, staffing and maintenance costs. They exclude the cost of raw materials, taxes and interest expense and are on a before-tax basis. While the company is responsible for all revenue and expense elements of net income, operating costs represent the expenses most directly under the company’s control and therefore, are useful in evaluating the company’s performance.

 Reconciliation of operating costs

millions of Canadian dollars	2017		2016		2015
From Imperial’s consolidated statement of income
Total expenses		28,842		24,910		24,965
Less:
Purchases of crude oil and products		18,145		15,120		15,284
Federal excise tax		1,673		1,650		1,568
Financing costs		78		65		39
Subtotal		19,896		16,835		16,891
Imperial’s share of equity company expenses		62		63		40
Total operating costs		9,008		8,138		8,114
Components of operating costs
millions of Canadian dollars	2017		2016		2015
From Imperial’s consolidated statement of income
Production and manufacturing		5,698		5,224		5,434
Selling and general		893		1,129		1,117
Depreciation and depletion		2,172		1,628		1,450
Exploration		183		94		73
Subtotal		8,946		8,075		8,074
Imperial’s share of equity company expenses		62		63		40
Total operating costs		9,008		8,138		8,114

35

Management’s discussion and analysis of financial condition and results of operations

Overview

The following discussion and analysis of Imperial’s financial results, as well as the accompanying financial statements and related notes to consolidated financial statements to which they refer, are the responsibility of the management of Imperial Oil Limited.

The company’s accounting and financial reporting fairly reflect its straightforward business model involving the extracting, refining and marketing of hydrocarbons and hydrocarbon based products. The company’s business model involves the production (or purchase), manufacture and sale of physical products, and all commercial activities are directly in support of the underlying physical movement of goods.

Imperial, with its resource base, financial strength, disciplined investment approach and technology portfolio, is well positioned to participate in substantial investments to develop new Canadian energy supplies. The company’s integrated business model, with significant investments in Upstream, Downstream and Chemical segments, reduces the company’s risk from changes in commodity prices. While commodity prices are volatile on a short-term basis, depending upon supply and demand, Imperial’s investment decisions are based on its long-term business outlook, using a disciplined approach in selecting and pursuing the most attractive investment opportunities. The corporate plan is a fundamental annual management process that is the basis for setting near-term operating and capital objectives, in addition to providing the longer-term economic assumptions used for investment evaluation purposes. Volumes are based on individual field production profiles, which are also updated annually. Price ranges for crude oil, natural gas, refined products and chemical products are based on corporate plan assumptions developed annually and are utilized for investment evaluation purposes. Major investment opportunities are evaluated over a range of economic scenarios. Once major investments are made, a reappraisal process is completed to ensure relevant lessons are learned and improvements are incorporated into future projects.

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.

Business environment and risk assessment

Long-term business outlook

The basis for the “Long-term business outlook” is the Exxon Mobil Corporation’s annual Outlook for Energy, which is used to help form the company’s long-term business strategies and investment plans. By 2040, the world’s population is projected to grow to approximately 9.2 billion people, or about 1.7 billion more people than in 2016. Coincident with this population increase, the company expects worldwide economic growth to average close to 3 percent per year. As economies and populations grow, and as living standards improve for billions of people, the need for energy will continue to rise. Even with significant efficiency gains, global energy demand is projected to rise by about 25 percent from 2016 to 2040. This demand increase is expected to be concentrated in developing countries (i.e., those that are not member nations of the Organization for Economic Cooperation and Development). Canada is expected to see flat to modest local energy demand growth through to 2040 and will continue to be a large supplier of energy exports to help meet rising global energy needs.

As expanding prosperity drives global energy demand higher, increasing use of energy efficient technologies and practices, as well as lower emission fuels will continue to help significantly reduce energy consumption and emissions per unit of economic output over time. Substantial efficiency gains are likely in all key aspects of the world economy through 2040, affecting energy requirements for transportation, power generation, industrial applications and residential and commercial needs.

Energy for global transportation – including cars, trucks, ships, trains and airplanes – is expected to increase by about 30 percent from 2016 to 2040. The growth in transportation energy demand is likely to account for approximately 60 percent of the growth in liquid fuels demand worldwide over this period, even as liquids demand for light duty vehicles is relatively flat to 2040, reflecting the impact of better fleet fuel economy and significant growth in electric cars over the period. Nearly all the world’s transportation fleets are likely to continue to run on liquid fuels, which are abundant, widely available and easy to transport, and provide a large quantity of energy in small volumes.

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Demand for electricity around the world is likely to increase approximately 60 percent from 2016 to 2040, with developing countries accounting for about 85 percent of the increase. Consistent with this projection, power generation is expected to remain the largest and fastest growing major segment of global primary energy demand. Meeting the expected growth in power demand will require a diverse set of energy sources. The share of coal fired generation is likely to decline substantially and approach 25 percent of the world’s electricity by 2040, versus nearly 40 percent in 2016, in part as a result of policies to improve air quality, as well as reduce greenhouse gas emissions to address the risks of climate change. From 2016 to 2040, the amount of electricity supplied using natural gas, nuclear power, and renewables is likely to approximately double, and account for about 95 percent of the growth in electricity supplies. Renewables in total, led by wind and solar, will account for about half of the increase in electricity supplies worldwide over the period to 2040, reaching nearly 35 percent of global electricity supplies by 2040. Natural gas and nuclear will also gain share over the period to 2040, reaching about 25 percent and 12 percent respectively of global electricity supplies by 2040. Supplies of electricity by energy type will reflect significant differences across regions, reflecting a wide range of factors including the cost and availability of various energy types.

Liquid fuels provide the largest share of global energy supplies today due to their broad based availability, affordability, ease of distribution, storage and fitness as a practical solution to meet a wide variety of needs. By 2040, global demand for liquid fuels is projected to grow to approximately 118 million barrels per day, an increase of about 20 percent from 2016. Much of this demand today is met by crude production from traditional conventional sources; these supplies will remain important as significant development activity is expected to offset much of the natural declines from these fields. At the same time, a variety of emerging supply sources – including tight oil, deep water oil, oil sands, natural gas liquids and biofuels – are expected to grow to help meet rising demand. The world’s resource base is sufficient to meet projected demand through 2040 as technology advances continue to expand the availability of economic supply options. However, access to resources and timely investments will remain critical to meeting global needs with reliable, affordable supplies.

Natural gas is a versatile fuel, suitable for a wide variety of applications and it is expected to grow the most of any primary energy type from 2016 to 2040, meeting more than 35 percent of global energy demand growth. Global natural gas demand is expected to rise nearly 40 percent from 2016 to 2040, with about 45 percent of that increase in the Asia Pacific region. Helping meet these needs will lead to significant growth in supplies of unconventional gas - the natural gas found in shale and other rock formations that was once considered uneconomic to produce. In total, about 55 percent of the growth in natural gas supplies is expected to be from unconventional sources. However, it is expected conventionally produced natural gas is likely to remain the cornerstone of supply, meeting about two-thirds of global demand in 2040. Worldwide liquefied natural gas (LNG) trade will expand significantly, meeting about one-third of the increase in demand growth, with much of this supply expected to help meet rising demand in Asia Pacific.

The world’s energy mix is highly diverse and will remain so through 2040. Oil is expected to remain the largest source of energy with its share remaining close to one-third in 2040. Coal is currently the second largest source of energy, but it is likely to lose that position to natural gas in the 2020 to 2025 timeframe. The share of natural gas is expected to reach 25 percent by 2040, while the share of coal falls to about 20 percent. Nuclear power is projected to grow significantly, as many nations are likely to expand nuclear capacity to address rising electricity needs, as well as energy security and environmental issues. Total renewable energy is likely to exceed 15 percent of total global energy by 2040, with biomass, hydro and geothermal contributing a combined share of more than 10 percent. Total energy supplied from wind, solar and biofuels is expected to increase rapidly, growing nearly 250 percent from 2016 to 2040, when they will approach about 5 percent of the world’s energy.

The company anticipates that the world’s available oil and gas resource base will grow not only from new discoveries, but also from reserve increases in previously discovered fields. Technology will underpin these increases. The cost to develop and supply these resources will be significant. According to the International Energy Agency World Energy Outlook 2017, the investment required to meet oil and natural gas supply requirements worldwide over the period 2017 to 2040 will be about US$21 trillion (New Policies Scenario, measured in 2016 dollars) or approximately US$860 billion per year on average.

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International accords and underlying regional and national regulations covering greenhouse gas emissions continue to evolve with uncertain timing and outcome, making it difficult to predict their business impact. Imperial’s estimate of potential costs related to greenhouse gas emissions align with applicable provincial and federal regulations.

For the purposes of assessing Imperial’s long-term business strategies and investment evaluations, ExxonMobil’s Outlook for Energy is used as a foundation for estimating energy related greenhouse gas emissions. The climate accord reached at the Conference of the Parties (COP 21) in Paris set many new goals, and many related policies are still emerging. The ExxonMobil Outlook for Energy reflects an environment with increasingly stringent climate policies and is consistent with the aggregation of Nationally Determined Contributions which were submitted by signatories to the United Nations Framework Convention on Climate Change (UNFCCC) 2015 Paris Agreement. The ExxonMobil Outlook for Energy seeks to identify potential impacts of climate related policies, which often target specific sectors, by using various assumptions and tools including application of a proxy cost of carbon to estimate potential impacts on consumer demands. As people and nations look for ways to reduce risks of global climate change, they will continue to need practical solutions that do not jeopardize the affordability or reliability of the energy they need. Practical solutions to the world’s energy and climate challenges will benefit from market competition, well informed, well designed and transparent policy approaches that carefully weigh costs and benefits. Such policies are likely to help manage the risks of climate change while also enabling societies to pursue other high priority goals around the world – including clean air and water, access to reliable, affordable energy, and economic progress for all people. All practical and economically viable energy sources, both conventional and unconventional, will need to be pursued to continue meeting global energy demand, recognizing the scale and variety of worldwide energy needs, as well as the importance of expanding access to modern energy to promote better standards of living for billions of people.

The information provided in the “Long-term business outlook” includes internal estimates and forecasts based upon ExxonMobil’s internal data and analyses, as well as publicly available information from external sources including the International Energy Agency.

Upstream

Imperial produces crude oil and natural gas for sale predominantly into North American markets. Imperial’s Upstream business strategies guide the company’s exploration, development, production, research and gas marketing activities. These strategies include maximizing asset reliability, accelerating development and application of high impact technologies, maximizing value by capturing new business opportunities and managing the existing portfolio, as well as pursuing sustainable improvements in organizational efficiency and effectiveness. These strategies are underpinned by a relentless focus on operations integrity, commitment to innovative technologies, disciplined approach to investing and cost management, development of employees and investment in the communities within which the company operates.

Imperial has a significant oil and gas resource base and a large inventory of potential projects. The company continues to evaluate opportunities to support long-term growth. As future development projects bring new production online, Imperial expects growth from oil sands in-situ and mining, as well as unconventional resources, with the largest growth potential related to in-situ. Actual volumes will vary from year to year due to the factors described in Item 1A. “Risk factors”.

The upstream industry environment continued to recover in 2017 as crude oil prices increased in response to tighter supply and higher demand. Prices for most of the company’s crude oil sold are referenced to Western Canada Select (WCS) and West Texas Intermediate (WTI) oil markets and in 2017, the average WCS and WTI crude oil prices, in U.S. dollars, were higher versus 2016. The markets for crude oil and natural gas have a history of significant price volatility. Imperial believes prices over the long-term will continue to be driven by market supply and demand, with the demand side largely being a function of general economic activities and levels of prosperity. On the supply side, prices may be significantly impacted by political events, the actions of OPEC and other large government resource owners, and other factors. To manage the risks associated with price, Imperial evaluates annual plans and all major investments across a range of price scenarios.

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Downstream

Imperial’s Downstream serves predominantly Canadian markets with refining, logistics and marketing assets. Imperial’s Downstream business strategies competitively position the company across a range of market conditions. These strategies include targeting industry leading performance in reliability, safety and operations integrity, as well as maximizing value from advanced technologies, capitalizing on integration across Imperial’s businesses, selectively investing for resilient and advantaged returns, operating efficiently and effectively, and providing quality, valued and differentiated products and services to customers.

Imperial owns and operates three refineries in Canada, with aggregate distillation capacity of 423,000 barrels per day. Refining margins are largely driven by differences in commodity prices and are a function of the difference between what a refinery pays for its raw materials (primarily crude oil) and the market prices for the range of products produced (primarily gasoline, heating oil, diesel oil, jet fuel and fuel oil). Crude oil and many products are widely traded with published prices, including those quoted on the New York Mercantile Exchange. Prices for these commodities are determined by the global and regional marketplaces and are influenced by many factors, including global and regional supply / demand balances, inventory levels, industry refinery operations, import / export balances, currency fluctuations, seasonal demand, weather and political climate.

Demand growth remained strong in 2017 causing lower inventory levels of both gasoline and distillate products. North American refineries continue to benefit from cost-competitive feedstock and energy supplies.

As described in more detail in Item 1A. “Risk factors”, proposed carbon policy and other climate related regulations, as well as continued biofuels mandates, could have negative impacts on the downstream business. Imperial’s integration across the value chain, from refining to marketing, enhances overall value across the fuels business.

Imperial supplies petroleum products to the motoring public through Esso and Mobil-branded retail sites and independent marketers. On average during the year, there were more than 1,800 retail sites operating under a branded wholesaler model whereby Imperial supplies fuel to independent third parties who own and operate retail sites in alignment with Esso and Mobil brand standards. The Mobil fuels brand was launched in Canada in 2017 with the announcement of plans to convert more than 200 existing unbranded third party retail sites. Completion of this Mobil conversion is anticipated in 2018.

The company expects to continue to expand its branded presence across Canada with the launch of Mobil-branded retail sites and the ongoing conversion of third party sites to the Esso brand, in both retail and commercial.

Chemical

North America continued to benefit from abundant supplies of natural gas and gas liquids, providing both low cost energy and feedstock for steam crackers, and a favourable margin environment for integrated chemical producers. Imperial sustained a competitive advantage through continued operational excellence, investment and cost discipline. In 2017, the company continued to capture value from the integration of its chemical plant in Sarnia with the refinery. The company also benefits from its integration within ExxonMobil’s North American chemical businesses, enabling Imperial to maintain a leadership position in its key market segments.

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Results of operations

 Consolidated

millions of Canadian dollars	2017		2016		2015
Net income (loss)		490		2,165		1,122

2017

Net income in 2017 was $490 million, or $0.58 per share on a diluted basis, reflecting impairment charges of $289 million ($0.35 per share) associated with the Horn River development and $277 million ($0.33 per share) associated with the Mackenzie gas project. This compares with net income of $2,165 million or $2.55 per share in 2016, which included a gain of $1.7 billion ($2.01 per share) from the sale of retail sites.

2016

Net income in 2016 was $2,165 million, or $2.55 per share on a diluted basis, including a gain of $1.7 billion ($2.01 per share) from the sale of retail sites, versus net income of $1,122 million or $1.32 per share in 2015. Downstream net income was $2,754 million, up from $1,586 million in 2015. Chemical net income was $187 million. Upstream recorded a net loss of $661 million in 2016, compared to a net loss of $704 million in 2015.

 Upstream

millions of Canadian dollars	2017			2016			2015
Net income (loss)		(706	)		(661	)		(704	)

2017

Upstream recorded a net loss of $706 million in 2017, reflecting impairment charges of $289 million associated with the Horn River development and $277 million associated with the Mackenzie gas project. Excluding these impairment charges, the net loss of $140 million compares to a net loss of $661 million in 2016. Results benefitted from higher Canadian crude oil realizations of about $1,190 million and higher Kearl volumes of about $60 million. Results were negatively impacted by higher royalties of about $250 million, lower Syncrude and Norman Wells volumes of about $190 million, higher operating expenses mainly associated with Syncrude and Kearl of about $150 million, higher energy costs of about $80 million and the impact of a stronger Canadian currency of about $60 million.

2016

Upstream recorded a net loss of $661 million in 2016, compared to a net loss of $704 million in 2015. The loss in 2016 reflected lower realizations of about $700 million, the impact of the northern Alberta wildfires of about $155 million and higher depreciation expense of about $120 million. These factors were partially offset by higher volumes of about $320 million, the impact of a weaker Canadian dollar of about $130 million, the favorable impact of lower royalties of about $80 million, lower field operating costs of about $80 million and lower energy cost of about $50 million. The loss in 2015 reflected the impact associated with the Alberta corporate income tax rate increase of $327 million.

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Average realizations

Canadian dollars	2017		2016		2015
Bitumen (per barrel)		39.13		26.52		32.48
Synthetic oil (per barrel)		67.58		57.12		61.33
Conventional crude oil (per barrel)		53.51		32.93		36.58
Natural gas liquids (per barrel)		31.46		15.58		14.70
Natural gas (per thousand cubic feet)		2.58		2.41		2.78

2017

West Texas Intermediate averaged US$50.85 per barrel in 2017, up from US$43.44 per barrel in the prior year. Western Canada Select averaged US$38.95 per barrel and US$29.49 per barrel respectively for the same periods. The WTI / WCS differential narrowed to 23 percent in 2017, from 32 percent in 2016. The Canadian dollar averaged US$0.77 in 2017, an increase of about US$0.02 from 2016.

Imperial’s average Canadian dollar realizations for bitumen and synthetic crudes increased generally in line with the North American benchmarks, adjusted for changes in the exchange rate and transportation costs. Bitumen realizations averaged $39.13 per barrel for 2017, an increase of $12.61 per barrel versus 2016. Synthetic crude realizations averaged $67.58 per barrel, an increase of $10.46 per barrel from 2016.

2016

West Texas Intermediate averaged US$43.44 per barrel in 2016, down from US$48.83 per barrel in 2015. Western Canada Select averaged US$29.49 per barrel and US$35.34 per barrel respectively for the same periods. The WTI / WCS differential widened to 32 percent in 2016, up from 28 percent in 2015. The Canadian dollar averaged US$0.75 in 2016, a decrease of US$0.03 from 2015.

Imperial’s average Canadian dollar realizations for bitumen and synthetic crudes declined essentially in line with the North American benchmarks, adjusted for changes in the exchange rate and transportation costs. Bitumen realizations averaged $26.52 for 2016, a decrease of $5.96 per barrel from 2015. Synthetic crude realizations averaged $57.12 per barrel, a decrease of $4.21 per barrel from 2015.

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Crude oil and NGLs - production and sales (a) thousands of barrels per day	2017				2016				2015
	gross		net		gross		net		gross		net
Bitumen		288		255		281		256		266		245
Synthetic oil (b)		62		57		68		67		62		58
Conventional crude oil		4		3		14		12		15		14
Total crude oil production		354		315		363		335		343		317
NGLs available for sale		1		1		1		1		1		1
Total crude oil and NGL production		355		316		364		336		344		318
Bitumen sales, including diluent (c)		381				374				349
NGL sales		6				5				5
Natural gas - production and production available for sale (a)
millions of cubic feet per day	2017				2016				2015
	gross		net		gross		net		gross		net
Production (d) (e)		120		114		129		122		130		125
Production available for sale (f)				80				87				94

(a) Volume per day metrics are calculated by dividing the volume for the period by the number of calendar days in the period. Gross production is the company’s share of production (excluding purchases) before deduction of the mineral owners’ or governments’ share or both. Net production excludes those shares.

(b) The company’s synthetic oil production volumes were from the company’s share of production volumes in the Syncrude joint venture.

(c) Diluent is natural gas condensate or other light hydrocarbons added to crude bitumen to facilitate transportation to market by pipeline and rail.

(d) Gross production of natural gas includes amounts used for internal consumption with the exception of the amounts re-injected.

(e) Net production is gross production less the mineral owners’ or governments’ share or both. Net production reported in the above table is consistent with production quantities in the net proved reserves disclosure.

(f) Includes sales of the company’s share of net production and excludes amounts used for internal consumption.

2017

Gross production of Cold Lake bitumen averaged 162,000 barrels per day in 2017, up from 161,000 barrels per day in 2016.

Gross production of Kearl bitumen averaged 178,000 barrels per day in 2017 (126,000 barrels Imperial’s share) up from 169,000 barrels per day (120,000 barrels Imperial’s share) in 2016. Increased 2017 production reflects improved reliability associated with the mining and ore preparation operations.

During 2017, the company’s share of gross production from Syncrude averaged 62,000 barrels per day, compared to 68,000 barrels per day in 2016. Syncrude 2017 production was impacted by the March 2017 fire at the Syncrude Mildred Lake upgrader and planned maintenance. In 2016, production was impacted by the Alberta wildfires and planned maintenance.

2016

Gross production of Cold Lake bitumen averaged 161,000 barrels per day in 2016, up from 158,000 barrels per day in 2015.

Gross production of Kearl bitumen averaged 169,000 barrels per day in 2016 (120,000 barrels Imperial’s share) compared to 152,000 barrels per day (108,000 barrels Imperial’s share) in 2015. The increase was the result of start-up of the expansion project.

During 2016, the company’s share of gross production from Syncrude averaged 68,000 barrels per day, up from 62,000 barrels per day in 2015. Increased production reflects continued efforts to improve the reliability of operations, which more than offset the impact of the Alberta wildfires.

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Downstream

millions of Canadian dollars	2017		2016		2015
Net income (loss)		1,040		2,754		1,586

2017

Downstream net income was $1,040 million, compared to $2,754 million in 2016, which included a $1,841 million gain from the sale of company-owned retail sites and the general aviation business. Excluding the impact of the 2016 asset sales, earnings increased by $127 million reflecting higher refining margins of about $340 million, lower marketing expenses of about $160 million, mainly associated with the retail divestment, and a gain of $151 million from the sale of a surplus property. These factors were partially offset by lower marketing margins of about $330 million, mainly associated with the impact of the retail divestment, and higher maintenance activity of about $130 million.

2016

Downstream net income was $2,754 million, up from $1,586 million in 2015. Earnings increased mainly due to a gain of $1,841 million from the sale of retail sites and the general aviation business, the impact of a weaker Canadian dollar of about $130 million, higher marketing sales volumes of $50 million, partially offset by lower downstream margins of about $910 million.

Refinery utilization

thousands of barrels per day (a)	2017		2016		2015
Total refinery throughput (b)		383		362		386
Refinery capacity at December 31		423		423		421
Utilization of total refinery capacity (percent)		91		86		92

Sales

thousands of barrels per day (a)	2017		2016		2015
Gasolines		257		261		247
Heating, diesel and jet fuels		177		170		170
Heavy fuel oils (c)		18		16		16
Lube oils and other products		40		37		45
Net petroleum product sales		492		484		478

(a) Volume per day metrics are calculated by dividing the volume for the period by the number of calendar days in the period.

(b) Crude oil and feedstocks sent directly to atmospheric distillation units.

(c) In 2017, carbon black product sales are reported under Net petroleum product sales – Heavy fuel oils; in 2016 and 2015, they were reported under Total petrochemical sales – Polymers and basic chemicals.

2017

Refinery throughput averaged 383,000 barrels per day in 2017, up from 362,000 barrels per day in 2016. Capacity utilization increased to 91 percent from 86 percent in 2016, reflecting reduced turnaround maintenance activity. Petroleum product sales were 492,000 barrels per day in 2017, up from 484,000 barrels per day in 2016. Sales growth continues to be driven by optimization across the full downstream value chain.

2016

Refinery throughput averaged 362,000 barrels per day in 2016, compared to 386,000 barrels per day in 2015. Capacity utilization decreased to 86 percent from 92 percent in 2015, reflecting the more significant scope of turnaround maintenance activity in the current year. Petroleum product sales were 484,000 barrels per day in 2016, up from 478,000 barrels per day in 2015. Sales growth was driven by the company’s focus on establishing long-term supply agreements.

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Chemical

millions of Canadian dollars	2017		2016		2015
Net income (loss)		235		187		287

Sales

thousands of tonnes	2017		2016		2015
Polymers and basic chemicals (a)		564		697		735
Intermediate and others		210		211		210
Total petrochemical sales		774		908		945

(a) In 2017, carbon black product sales are reported under Net petroleum product sales – Heavy fuel oils; in 2016 and 2015, they were reported under Total petrochemical sales – Polymers and basic chemicals.

2017

Chemical net income was $235 million, up from $187 million in 2016, mainly due to stronger margins.

2016

Chemical net income was $187 million, compared to $287 million in the same period of 2015, mainly due to weaker margins across all major product lines and lower volumes.

Corporate and other

millions of Canadian dollars	2017			2016			2015
Net income (loss)		(79	)		(115	)		(47	)

2017

For 2017, Corporate and other costs were $79 million, versus $115 million in 2016, mainly due to lower share-based compensation charges.

2016

In 2016, net income effects from Corporate and other were negative $115 million, versus negative $47 million in 2015, primarily due to higher share-based compensation charges, the absence of the impact from the Alberta tax rate increase in 2015 and lower capitalized interest.

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Liquidity and capital resources

Sources and uses of cash

millions of Canadian dollars	2017			2016			2015
Cash provided by (used in)
Operating activities		2,763			2,015			2,167
Investing activities		(781	)		1,947			(2,884)
Financing activities		(1,178	)		(3,774	)		705
Increase (decrease) in cash and cash equivalents		804			188			(12)
Cash and cash equivalents at end of year		1,195			391			203

The company issues long-term debt from time to time and maintains a commercial paper program. However, internally generated funds cover the majority of its financial requirements. Cash that may be temporarily surplus to the company’s immediate needs is carefully managed through counterparty quality and investment guidelines to ensure that it is secure and readily available to meet the company’s cash requirements and to optimize returns.

Cash flows from operating activities are highly dependent on crude oil and natural gas prices, as well as petroleum and chemical product margins. In addition, to provide for cash flow in future periods, the company needs to continually find and develop new resources, and continue to develop and apply new technologies to existing fields in order to maintain or increase production.

The company’s financial strength enables it to make large, long-term capital expenditures. Imperial’s portfolio of development opportunities and the complementary nature of its business segments help mitigate the overall risks for the company and its cash flows. Further, due to its financial strength, debt capacity and portfolio of opportunities, the risk associated with delay of any single project would not have a significant impact on the company’s liquidity or ability to generate sufficient cash flows for its operations and fixed commitments.

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 completed at least once every three years, or more, depending on funding status. The most recent valuation of the company’s registered retirement plans was completed as at December 31, 2016. The company contributed $212 million to the registered retirement plans in 2017. Future funding requirements are not expected to affect the company’s existing capital investment plans or its ability to pursue new investment opportunities.

Cash flow from operating activities

2017

Cash flow generated from operating activities was $2,763 million in 2017, compared with $2,015 million in 2016, reflecting higher earnings, excluding the impact of asset sales and impairment charges, partially offset by the absence of favourable working capital effects.

2016

Cash flow generated from operating activities was $2,015 million in 2016, compared with $2,167 million in 2015, reflecting lower earnings, excluding the gain on retail sites and the general aviation business.

Cash flow from investing activities

2017

Investing activities used net cash of $781 million in 2017, compared with cash generated from investing activities of $1,947 million in 2016, reflecting lower proceeds from asset sales.

2016

Investing activities generated net cash of $1,947 million in 2016, compared with cash used in investing activities of $2,884 million in 2015, reflecting proceeds from asset sales and the completion of major upstream growth projects.

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Cash flow from financing activities

2017

Cash used in financing activities was $1,178 million in 2017, compared with $3,774 million in 2016, mainly reflecting the absence of debt repayments, partially offset by share purchases under the company’s share purchase program.

At the end of 2017, total debt outstanding was $5,207 million, compared with $5,234 million at the end of 2016.

In November 2017, the company extended the maturity date of its existing $250 million committed long-term line of credit to November 2019. The company has not drawn on the facility.

In December 2017, the company extended the maturity date of its existing $250 million committed short-term line of credit to December 2018. The company has not drawn on the facility.

During 2017 the company purchased about 16.4 million shares for $627 million, including shares purchased from Exxon Mobil Corporation.

Dividends paid in 2017 were $524 million. The per share dividend paid in 2017 was $0.62, up from $0.58 in 2016.

2016

Cash used in financing activities was $3,774 million in 2016, compared with cash provided by financing activities of $705 million in 2015. Cash from operating activities and proceeds from the asset sales were used to reduce outstanding debt.

At the end of 2016, total debt outstanding was $5,234 million, compared with $8,516 million at the end of 2015.

The company repaid debt of $1,505 million from existing long-term loan facilities and $1,749 million from short-term loan facilities.

In October 2016, the company decreased the amount of its unused committed long-term line of credit from $500 million to $250 million and extended the maturity date to November 2018.

In December 2016, the company decreased the amount of its unused committed short-term line of credit from $500 million to $250 million and extended the maturity date to December 2017.

During 2016, the company did not make any share purchases except those to offset the dilutive effects from the exercise of share-based awards.

Dividends paid in 2016 were $492 million. The per share dividend paid was $0.58, up from $0.53 in 2015.

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Financial percentages and ratios

	2017		2016		2015
Total debt as a percentage of capital (a)		18		17		27
Interest coverage ratio – earnings basis (b)		7		21		20

(a) Current and long-term debt (page 61) and the company’s share of equity company debt, divided by debt and shareholders’ equity (page 61).

(b) Net income (page 59), debt-related interest before capitalization, including the company’s share of equity company interest, and income taxes (page 59), divided by debt-related interest before capitalization, including the company’s share of equity company interest.

Debt represented 18 percent of the company’s capital structure at the end of 2017.

Debt-related interest incurred in 2017, before capitalization of interest, was $103 million, compared with $121 million in 2016. The average effective interest rate on the company’s debt was 2.0 percent in 2017, compared with 1.5 percent in 2016.

The company’s financial strength represents a competitive advantage of strategic importance providing it the opportunity to readily access capital markets under the full range of market conditions and enabling the company to take on large, long-term capital commitments in the pursuit of maximizing shareholder value.

Commitments

The following table shows the company’s commitments outstanding at December 31, 2017. It combines data from the consolidated balance sheet and from individual notes to the consolidated financial statements, where appropriate.

			Payment due by period
millions of Canadian dollars	Note reference		2018		2019 to 2020		2021 to 2022		2023 and beyond		Total
Long-term debt (a)		14		-		4,492		26		487		5,005
- Due in one year				27								27
Operating leases (b)		13		120		75		3		1		199
Firm capital commitments (c)				245		154		-		-		399
Pension and other post retirement obligations (d)		4		297		116		119		1,053		1,585
Asset retirement obligations (e)		5		64		174		95		1,064		1,397
Other long-term purchase agreements (f)				746		1,553		1,461		7,712		11,472

(a) Long-term debt includes a loan from an affiliated company of ExxonMobil of $4,447 million and capital lease obligations of $585 million, $27 million of which is due in one year. The payment by period for the related party long-term loan is estimated based on the right of the related party to cancel the loan on at least 370 days advance written notice.

(b) Minimum commitments for operating leases, shown on an undiscounted basis, covers primarily storage tanks, rail cars and marine vessels.

(c) Firm capital commitments represent legally-binding payment obligations to third parties where agreements specifying all significant terms have been executed for the construction and purchase of fixed assets and other permanent investments. In certain cases where the company executes contracts requiring commitments to a work scope, those commitments have been included to the extent that the amounts and timing of payments can be reliably estimated. Firm capital commitments related to capital projects, shown on an undiscounted basis.

(d) The amount by which the benefit obligations exceeded the fair value of fund assets for pension and other post retirement plans at year-end. The payments by period include expected contributions to funded pension plans in 2018 and estimated benefit payments for unfunded plans in all years.

(e) Asset retirement obligations represent the fair value of legal obligations associated with site restoration on the retirement of assets with determinable useful lives.

(f) Other long-term purchase agreements are non-cancelable, or cancelable only under certain conditions and long-term commitments other than unconditional purchase obligations. They include primarily raw material supply and transportation services agreements. The higher 2017 balance includes a $4.5 billion increase in commitments associated with additional long-term transportation service agreements to ship crude oil and products.

Unrecognized tax benefits totaling $78 million have not been included in the company’s commitments table because the company does not expect there will be any cash impact from the final settlements as sufficient funds have been deposited with the Canada Revenue Agency. Further details on the unrecognized tax benefits can be found in note 3 to the financial statements on page 72.

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Litigation and other contingencies

As discussed in note 9 to the consolidated financial statements on page 81, a variety of claims have been made against Imperial and its subsidiaries. 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, as discussed in note 9, Imperial was contingently liable at December 31, 2017, for guarantees relating to performance under contracts of other third-party obligations. These guarantees do not have a material effect on the company’s operations, financial condition, or financial statements taken as a whole.

There are no events or uncertainties beyond those already included in reported financial information that would indicate a material change in future operating results or financial condition.

Capital and exploration expenditures

millions of Canadian dollars	2017		2016
Upstream (a)		416		896
Downstream		200		190
Chemical		17		26
Other		38		49
Total		671		1,161

(a) Exploration expenses included.    

Total capital and exploration expenditures were $671 million in 2017, a decrease of $490 million from 2016.

For the Upstream segment, capital and exploration expenditures were $416 million in 2017, compared with $896 million in 2016. Investments were primarily related to sustaining activity in support of oil sands and unconventional assets.

For the Downstream segment, capital expenditures were $200 million in 2017, compared with $190 million in 2016. In 2017, investments were primarily in support of refinery projects to improve reliability, feedstock flexibility, energy efficiency and environmental performance.

Total capital and exploration expenditures are expected to range between $1.5 billion to $1.7 billion in 2018. Planned increases in spending versus 2017 are largely driven by the Cold Lake drilling program, projects at Kearl and the Strathcona refinery, as well as the timing of other potential upstream growth investments. Actual spending could vary depending on the progress of individual projects.

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Market risks and other uncertainties

Crude oil, natural gas, petroleum product and chemical prices have fluctuated in response to changing market forces. The impacts of these price fluctuations on earnings from Upstream, Downstream and Chemical operations have varied. A significant portion of the company’s production is bitumen. Imperial’s earnings are largely influenced by heavy oil prices. At this time, Imperial is a net consumer of natural gas, used in Imperial’s Upstream operation and refineries. A decrease in the value of natural gas reduces Imperial’s operating expenses, thereby increasing Imperial’s earnings.

In the competitive downstream and chemical environments, earnings are primarily determined by margin capture rather than absolute price levels on products sold. Refining margins are a function of the difference between what a refiner pays for its raw materials (primarily crude oil) and the market prices for the range of products produced. These prices in turn depend on global and regional supply / demand balances, inventory levels, refinery operations, import / export balances and weather.

Industry crude oil and natural gas commodity prices and petroleum and chemical product prices are commonly benchmarked in U.S. dollars. The majority of Imperial’s sales and purchases are related to these industry U.S. dollar benchmarks. As the company records and reports its financial results in Canadian dollars, to the extent that the Canadian / U.S. dollar exchange rate fluctuates, the company’s earnings will be affected.

Imperial is exposed to changes in interest rates, primarily on its debt which carries floating interest rates. The impact of a quarter percent change in interest rates affecting Imperial’s debt would not be material to earnings, cash flow or fair value. Imperial has access to significant sources of long-term and short-term liquidity. Internally generated funds are expected to cover the majority of financial requirements, supplemented by long-term and short-term debt as needed.

The company’s potential exposure to commodity price and margin, and Canadian / U.S. dollar exchange rate fluctuations is summarized in the earnings sensitivities table below, which shows the estimated annual effect, under current conditions, on the company’s after-tax net income.

Earnings sensitivities (a)

millions of Canadian dollars, after tax
One dollar (U.S.) per barrel change in heavy crude oil prices	+ (-)	85
Ten cents per thousand cubic feet decrease (increase) in natural gas prices	+ (-)	5
One dollar (U.S.) per barrel change in refining 2-1-1 margins (b)	+ (-)	140
One cent (U.S.) per pound change in sales margins for polyethylene	+ (-)	7
One cent decrease (increase) in the value of the Canadian dollar versus the U.S. dollar	+ (-)	90

(a) Each sensitivity calculation shows the impact on net income resulting from a change in one factor, after tax and royalties and holding all other factors constant. These sensitivities have been updated to reflect current conditions. They may not apply proportionately to larger fluctuations.

(b) The 2-1-1 crack spread is an indicator of the refining margin generated by converting two barrels of crude oil into one barrel of gasoline and one barrel of diesel.

The global energy markets can give rise to extended periods in which market conditions are adverse to one or more of the company’s businesses. Such conditions, along with the capital-intensive nature of the industry and very long lead times associated with many of the company’s projects, underscore the importance of maintaining a strong financial position. Management views the company’s financial strength as a competitive advantage.

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In general, segment results are not dependent on the ability to sell and / or purchase products to / from other segments. However, Imperial’s integrated business model reduces the company’s risk from changes in commodity prices. Where such intersegment sales take place, they are the result of efficiencies and competitive advantages from integrated business segments and refinery / chemical complexes. For instance, heavy crude oil may be subject to limits on transportation capacity to a larger extent than light crude oil resulting in an increased heavy oil price discount. Imperial is able to partially mitigate the heavy oil discount through secured market outlets achieved through integration with Downstream investments in refineries, pipeline commitments and the Edmonton rail terminal. About 62 percent of the company’s intersegment sales are crude oil produced by the Upstream and sold to the Downstream. Other intersegment sales include those between refineries and the chemical plant related to raw materials, feedstocks and finished products. All intersegment sales are at market based prices.

The company has an active asset management program in which underperforming assets are either improved to acceptable levels or considered for divestment. The asset management program includes a disciplined, regular review to ensure that all assets are contributing to the company’s strategic objectives.

The demand for crude oil, natural gas, petroleum products and petrochemical products are generally linked closely with general economic growth activity. The occurrence of recessions or other periods of low or negative economic growth will typically have a direct adverse impact on the company’s financial results. In challenging economic times, the company follows the proven approach to continue to focus on the business elements within its control and take a long-term view.

Risk management

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 currency exchange rates and commodity prices. Imperial has the ability to use derivative 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 described in note 6 on page 79. The company maintains a system of controls that includes the authorization, reporting and monitoring of derivative activity.

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Critical accounting estimates

The company’s financial statements have been prepared in accordance with United States Generally Accepted Accounting Principles (GAAP). GAAP requires management to make estimates and judgments that affect the reported amounts of assets, liabilities, revenues and expenses, and the disclosure of contingent assets and liabilities. The company’s accounting and financial reporting fairly reflect its straightforward business model. Imperial does not use financing structures for the purpose of altering accounting outcomes or removing debt from the balance sheet. The company’s significant accounting policies are summarized in note 1 to the consolidated financial statements on page 64.

Oil and gas reserves

Evaluations of oil and natural gas reserves are important to the effective management of upstream assets. They are an integral part of investment decisions about oil and gas properties such as whether development should proceed.

The estimation of proved reserves, which is based on the requirement of reasonable certainty, is an ongoing process based on rigorous technical evaluations, commercial and market assessments and detailed analysis of well information such as flow rates and reservoir pressure declines. The estimation of proved reserves is controlled by the company through long-standing approval guidelines. Reserve changes are made within a well-established, disciplined process driven by senior level geoscience and engineering professionals, assisted by the reserves management group which has significant technical experience, culminating in reviews with and approval by senior management and the company’s board of directors. Notably, the company does not use specific quantitative reserve targets to determine compensation. Key features of the reserve estimation process are covered in “Disclosure of reserves” in Item 1.

Oil and natural gas reserves include both proved and unproved reserves.

● Proved oil and natural gas reserves are determined in accordance with Securities and Exchange Commission requirements. Proved reserves are those quantities of oil and natural gas which, by analysis of geoscience and engineering data, can be estimated with reasonable certainty to be economically producible under existing economic and operating conditions and government regulations. Proved reserves are determined using the average of first-of-month oil and natural gas prices during the reporting year.

Proved reserves can be further subdivided into developed and undeveloped reserves. Proved developed reserves include amounts which are expected to be recovered through existing wells with existing equipment and operating methods. Proved undeveloped reserves include amounts expected to be recovered from new wells on undrilled proved acreage or from existing wells where a relatively major expenditure is required for completion. Proved undeveloped reserves are recognized only if a development plan has been adopted indicating that the reserves are scheduled to be drilled within five years, unless specific circumstances support a longer period of time.

The percentage of proved developed reserves was 71 percent of total proved reserves at year-end 2017, a reduction from 77 percent in 2016. Although the company is reasonably certain that proved reserves will be produced, the timing and amount recovered can be affected by a number of factors including completion of development projects, reservoir performance, regulatory approvals and significant changes in long-term oil and natural gas prices.

● Unproved reserves are quantities of oil and natural gas with less than reasonable certainty of recoverability and include probable reserves. Probable reserves are reserves that, together with proved reserves, are as likely as not to be recovered.

Revisions can include upward or downward changes in previously estimated volumes of proved reserves for existing fields due to the evaluation or re-evaluation of already available geologic, reservoir or production data; new geologic, reservoir or production data; or changes in the average of first-of-the-month prices and year-end costs that are used in the estimation of reserves. Revisions can also result from significant changes in either development strategy or production equipment / facility capacity.

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At year-end 2016, downward revisions of proved developed and undeveloped bitumen reserves were a result of low prices. The entire 2.5 billion barrels of bitumen at Kearl and approximately 0.2 billion barrels of bitumen at Cold Lake no longer qualified as proved reserves under the U.S. Securities and Exchange Commission definition of proved reserves.

As a result of improved prices in 2017, an additional 0.3 billion barrels of bitumen at Kearl and Cold Lake now qualify as proved reserves at year-end 2017. Among the factors that would result in additional amounts being recognized as proved reserves at some point in the future are a further recovery in yearly average price levels, a further decline in costs and additional planned investment in reliability improvements. Under the terms of certain contractual arrangements or government royalty regimes, lower prices can also increase proved reserves attributable to Imperial. The company’s operating decisions and its outlook for future production volumes are not impacted by proved reserves as disclosed under the U.S. Securities and Exchange Commission definition.

Unit-of-production depreciation

The calculation of unit-of-production depreciation is a critical accounting estimate that measures the depreciation of upstream assets. Oil and natural gas reserve quantities are used as the basis to calculate unit-of-production depreciation rates for most upstream assets. Depreciation is calculated by taking the ratio of asset cost to total proved reserves or proved developed reserves applied to the actual cost of production. The volumes produced and asset cost are known, while proved reserves are based on estimates that are subject to some variability.

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.

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 the effect on depreciation expense was immaterial versus 2016. Continued application for 2018 is anticipated to be immaterial.

Impact of oil and gas reserves and prices and margins on testing for impairment

The company tests assets or groups of assets for recoverability on an ongoing basis whenever events or 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 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

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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 technology 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 and 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 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.

The decisions not to proceed, at this time, with the Horn River development and Mackenzie gas project resulted in Upstream non-cash impairment charges of $566 million, after tax, in the fourth quarter 2017.

Supplemental information regarding oil and gas results of operations, capitalized costs and reserves is provided following the notes to consolidated financial statements.

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Inventories

Crude oil, products and merchandise inventories are carried at the lower of current market value or cost (generally determined under the last-in, first-out method – LIFO).

Pension benefits

The company’s pension plan is managed in compliance with the requirements of governmental authorities and meets funding levels as determined by independent third-party actuaries. Pension accounting requires explicit assumptions regarding, among others, the discount rate for the benefit obligations, the expected rate of return on plan assets and the long-term rate of future compensation increases. All pension assumptions are reviewed annually by senior management. These assumptions are adjusted only as appropriate to reflect long-term changes in market rates and outlook. The long-term expected rate of return on plan assets of 5.5 percent used in 2017, compares to actual returns of 6.3 percent and 7.3 percent achieved over the last 10- and 20-year periods respectively, ending December 31, 2017. If different assumptions are used, the expense and obligations could increase or decrease as a result. The company’s potential exposure to changes in assumptions is summarized in note 4 to the consolidated financial statements on page 73. At Imperial, differences between actual returns on plan assets and the long-term expected returns are not recorded in pension expense in the year the differences occur. Such differences are deferred, along with other actuarial gains and losses, and are amortized into pension expense over the expected average remaining service life of employees. Employee benefit expense represented about 2 percent of total expenses in 2017.

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. The obligations are initially measured at fair value and discounted to present value. Over time, the discounted asset retirement obligation amount will be accreted for the change in its present value, with this effect included in production and manufacturing expenses. As payments to settle the obligations occur on an ongoing basis and will continue over the lives of the operating assets, which can exceed 25 years, the discount rate will be adjusted only as appropriate to reflect long-term changes in market rates and outlook. For 2017, the obligations were discounted at 6 percent and the accretion expense was $92 million, before tax, which was significantly less than 1 percent of total expenses in the year. There would be no material impact on the company’s reported financial results if a different discount rate had been used.

Asset retirement obligations are not recognized for assets 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. For these and non-operating assets, the company accrues provisions for environmental liabilities when it is probable that obligations have been incurred and the amount can be reasonably estimated.

Asset retirement obligations and other environmental liabilities are 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. Since these estimates are specific to the locations involved, there are many individual assumptions underlying the company’s total asset retirement obligations and provision for other environmental liabilities. While these individual assumptions can be subject to change, none of them is individually significant to the company’s reported financial results.

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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. Exploratory well costs not meeting these criteria are charged to expense. The facts and circumstances that support continued capitalization of suspended wells at year-end are disclosed in note 15 to the consolidated financial statements on page 84.

Tax contingencies

The operations of the company are complex, and related tax interpretations, regulations and legislation are continually changing. Significant management judgment is required in the accounting for income tax contingencies and tax disputes because the outcomes are often difficult to predict.

The benefits of uncertain tax positions that the company has taken or expects to take in its income tax returns are recognized in the financial statements if management concludes that it is more likely than not that the position will be sustained with the tax authorities. For a position that is likely to be sustained, the benefit recognized in the financial statements is measured at the largest amount that is greater than 50 percent likely of being realized. A reserve is established for the difference between a position taken or expected to be taken in an income tax return and the amount recognized in the financial statements. The company’s unrecognized tax benefits and a description of open tax years are summarized in note 3 to the consolidated financial statements on page 72.

Recently issued accounting standards

Effective January 1, 2018, Imperial adopted the Financial Accounting Standards Board (FASB) standard, Revenue from Contracts with Customers, as amended. The standard establishes a single revenue recognition model for all contracts with customers, eliminates industry and transaction specific requirements, and expands disclosure requirements. The standard was adopted using the modified retrospective method, under which prior years’ results are not restated, but supplemental information on the impact of the new standard will be included in the 2018 results if material. The standard is not expected to have a material impact on the company’s financial statements. The cumulative effect of adoption of the new standard is de minimis.

Effective January 1, 2018, Imperial adopted the FASB standard update, Compensation – Retirement Benefits (Topic 715): Improving the Presentation of Net Periodic Pension Cost and Net Periodic Postretirement Benefit Cost. The update requires the service cost component of net benefit costs to be reported in the same line in the income statement as other compensation costs and the other components of net benefit costs (non-service costs) be presented separately from the service cost component. Additionally, only the service cost component of net benefit costs is eligible for capitalization. The company expects to add a new line “Non-service pension and other postretirement benefit” expense to its consolidated statement of income, and expects to include all of these costs in the “Corporate and other” expenses. This line would reflect the non-service costs that were previously included in “Production and manufacturing” expenses, and “Selling and general” expenses. The update is not expected to have a material impact on Imperial’s financial statements.

Effective January 1, 2019, Imperial will adopt the FASB standard, Leases. The standard requires that all leases with an initial term greater than one year be recorded on the balance sheet as an asset and a lease liability. Imperial is gathering and evaluating data, and recently acquired a system to facilitate implementation. The company continues to progress an assessment of the magnitude of the effect on the company’s financial statements.

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Management’s report on internal control over financial reporting

Management, including the company’s chief executive officer and principal accounting officer and principal financial officer, is responsible for establishing and maintaining adequate internal control over the company’s financial reporting. Management conducted an evaluation of the effectiveness of internal control over financial reporting based on criteria established in Internal Control – Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission. Based on this evaluation, management concluded that Imperial Oil Limited’s internal control over financial reporting was effective as of December 31, 2017.

PricewaterhouseCoopers LLP, an independent registered public accounting firm, audited the effectiveness of the company’s internal control over financial reporting as of December 31, 2017, as stated in their report which is included herein.

/s/ Richard M. Kruger

R.M. Kruger

Chairman, president and

chief executive officer

/s/ Beverley A. Babcock

B.A. Babcock

Senior vice-president,

finance and administration, and controller

(Principal accounting officer and principal financial officer)

February 28, 2018

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Report of independent registered public accounting firm

To the Board of Directors and Shareholders of

Imperial Oil Limited

Opinions on the financial statements and internal control over financial reporting

We have audited the accompanying consolidated balance sheets of Imperial Oil Limited and its subsidiaries as of December 31, 2017 and 2016, and the related consolidated statements of income, comprehensive income, shareholders’ equity and cash flows for each of the three years in the period ended December 31, 2017, including the related notes (collectively referred to as the “consolidated financial statements”). We also have audited the Company’s internal control over financial reporting as of December 31, 2017, based on criteria established in Internal Control — Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO).

In our opinion, the consolidated financial statements referred to above present fairly, in all material respects, the financial position of the Company as of December 31, 2017 and 2016, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 2017 in conformity with accounting principles generally accepted in the United States of America. Also in our opinion, the Company maintained, in all material respects, effective internal control over financial reporting as of December 31, 2017, based on criteria established in Internal Control — Integrated Framework (2013) issued by the COSO.

Basis for opinions

The Company’s management is responsible for these consolidated financial statements, for maintaining effective internal control over financial reporting, and for its assessment of the effectiveness of internal control over financial reporting, included in the accompanying Management’s report on internal control over financial reporting. Our responsibility is to express opinions on the Company’s consolidated financial statements and on the Company’s internal control over financial reporting based on our audits. We are a public accounting firm registered with the Public Company Accounting Oversight Board (United States) (“PCAOB”) and are required to be independent with respect to the Company in accordance with the U.S. federal securities laws and the applicable rules and regulations of the Securities and Exchange Commission and the PCAOB.

We conducted our audits in accordance with the standards of the PCAOB. Those standards require that we plan and perform the audits to obtain reasonable assurance about whether the consolidated financial statements are free of material misstatement, whether due to error or fraud, and whether effective internal control over financial reporting was maintained in all material respects. Our audits of the consolidated financial statements included performing procedures to assess the risks of material misstatement of the consolidated financial statements, whether due to error or fraud, and performing procedures that respond to those risks. Such procedures included examining, on a test basis, evidence regarding the amounts and disclosures in the consolidated financial statements. Our audits also included evaluating the accounting principles used and significant estimates made by management, as well as evaluating the overall presentation of the consolidated financial statements. Our audit of internal control over financial reporting included obtaining an understanding of internal control over financial reporting, assessing the risk that a material weakness exists, and testing and evaluating the design and operating effectiveness of internal control based on the assessed risk. Our audits also included performing such other procedures, as we considered necessary in the circumstances. We believe that our audits provide a reasonable basis for our opinions.

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Definition and limitations of internal control over financial reporting

A company’s internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. A company’s internal control over financial reporting includes those policies and procedures that (i) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (ii) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the company are being made only in accordance with authorizations of management and directors of the company; and (iii) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the company’s assets that could have a material effect on the financial statements.

Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.

/s/ PricewaterhouseCoopers LLP

Chartered Professional Accountants

Calgary, Alberta, Canada

February 28, 2018

We have served as the Company’s auditor since 1934.

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Consolidated statement of income (U.S. GAAP)

millions of Canadian dollars
For the years ended December 31	2017		2016		2015
Revenues and other income
Operating revenues (a)		29,125		25,049		26,756
Investment and other income (note 8)		299		2,305		132
Total revenues and other income		29,424		27,354		26,888
Expenses
Exploration (note 15)		183		94		73
Purchases of crude oil and products (b)		18,145		15,120		15,284
Production and manufacturing (c)		5,698		5,224		5,434
Selling and general (c)		893		1,129		1,117
Federal excise tax		1,673		1,650		1,568
Depreciation and depletion		2,172		1,628		1,450
Financing costs (note 12)		78		65		39
Total expenses		28,842		24,910		24,965
Income (loss) before income taxes		582		2,444		1,923
Income taxes (note 3)		92		279		801
Net income (loss)		490		2,165		1,122
Per share information (Canadian dollars)
Net income (loss) per common share - basic (note 10)		0.58		2.55		1.32
Net income (loss) per common share - diluted (note 10)		0.58		2.55		1.32
Dividends per common share		0.63		0.59		0.54
(a)  Amounts from related parties included in operating revenues (note 16).		4,110		2,342		3,058
(b)  Amounts to related parties included in purchases of crude oil and products (note 16).		2,687		2,224		2,684
(c)   Amounts to related parties included in production and manufacturing, and selling and general expenses (note 16).		544		533		442

The information in the notes to consolidated financial statements is an integral part of these statements.

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Consolidated statement of comprehensive income (U.S. GAAP)

millions of Canadian dollars
For the years ended December 31	2017			2016			2015
Net income (loss)		490			2,165			1,122
Other comprehensive income (loss), net of income taxes
Post retirement benefits liability adjustment (excluding amortization)		(54	)		(210	)		64
Amortization of post retirement benefits liability adjustment included in net periodic benefit costs		136			141			167
Total other comprehensive income (loss)		82			(69	)		231
Comprehensive income (loss)		572			2,096			1,353

 The information in the notes to consolidated financial statements is an integral part of these statements.

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Consolidated balance sheet (U.S. GAAP)

millions of Canadian dollars
At December 31	2017			2016
Assets
Current assets
Cash		1,195			391
Accounts receivable, less estimated doubtful accounts (a)		2,712			2,023
Inventories of crude oil and products (note 11)		1,075			949
Materials, supplies and prepaid expenses		425			468
Total current assets		5,407			3,831
Investments and long-term receivables (b)		865			1,030
Property, plant and equipment, less accumulated depreciation and depletion		34,473			36,333
Goodwill		186			186
Other assets, including intangibles, net (note 5)		670			274
Total assets		41,601			41,654
Liabilities
Current liabilities
Notes and loans payable (c) (note 12)		202			202
Accounts payable and accrued liabilities (a) (note 11)		3,877			3,193
Income taxes payable		57			488
Total current liabilities		4,136			3,883
Long-term debt (d) (note 14)		5,005			5,032
Other long-term obligations (e) (note 5)		3,780			3,656
Deferred income tax liabilities (note 3)		4,245			4,062
Total liabilities		17,166			16,633
Commitments and contingent liabilities (note 9)
Shareholders’ equity
Common shares at stated value (f) (note 10)		1,536			1,566
Earnings reinvested		24,714			25,352
Accumulated other comprehensive income (loss) (note 17)		(1,815	)		(1,897)
Total shareholders’ equity		24,435			25,021
Total liabilities and shareholders’ equity		41,601			41,654

 (a) Accounts receivable, less estimated doubtful accounts included net amounts receivable from related parties of $509 million (2016 - $172 million), (note 16).

 (b) Investments and long-term receivables included amounts from related parties of $19 million (2016 – $0 million), (note 16).

 (c) Notes and loans payable included amounts to related parties of $75 million (2016 – $75 million), (note 16).

 (d) Long-term debt included amounts to related parties of $4,447 million (2016 – $4,447 million), (note 16).

 (e) Other long-term obligations included amounts to related parties of $60 million (2016 – $104 million), (note 16).

 (f) Number of common shares authorized and outstanding were 1,100 million and 831 million, respectively (2016 – 1,100 million and 848 million, respectively), (note 10).

 The information in the notes to consolidated financial statements is an integral part of these statements.

Approved by the directors.
/s/ Richard M. Kruger R.M. Kruger Chairman, president and chief executive officer	/s/ Beverley A. Babcock B.A. Babcock Senior vice-president, finance and administration, and controller

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Consolidated statement of shareholders’ equity (U.S. GAAP)

millions of Canadian dollars
At December 31	2017		2016		2015
Common shares at stated value (note 10)
At beginning of year		1,566		1,566		1,566
Issued under the stock option plan		-		-		-
Share purchases at stated value		30		-		-
At end of year		1,536		1,566		1,566
Earnings reinvested
At beginning of year		25,352		23,687		23,023
Net income (loss) for the year		490		2,165		1,122
Share purchases in excess of stated value		(597)		-		-
Dividends declared		(531)		(500)		(458)
At end of year		24,714		25,352		23,687
Accumulated other comprehensive income (loss) (note 17)
At beginning of year		(1,897)		(1,828)		(2,059)
Other comprehensive income (loss)		82		(69)		231
At end of year		(1,815)		(1,897)		(1,828)
Shareholders’ equity at end of year		24,435		25,021		23,425

 The information in the notes to consolidated financial statements is an integral part of these statements.

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Consolidated statement of cash flows (U.S. GAAP)

millions of Canadian dollars
Inflow (outflow)
For the years ended December 31	2017			2016			2015
Operating activities
Net income (loss)		490			2,165		1,122
Adjustments for non-cash items:
Depreciation and depletion		2,172			1,628		1,450
(Gain) loss on asset sales (note 8)		(220	)		(2,244	)	(97)
Inventory write-down to current market value		-			-		59
Deferred income taxes and other		321			114		367
Changes in operating assets and liabilities:
Accounts receivable		(689	)		(442	)	(42)
Inventories, materials, supplies and prepaid expenses		(83	)		197		(172)
Income taxes payable		(431	)		36		418
Accounts payable and accrued liabilities		678			237		(1,030)
All other items - net (a) (b)		525			324		92
Cash flows from (used in) operating activities		2,763			2,015		2,167
Investing activities
Additions to property, plant and equipment (b)		(993	)		(1,073	)	(2,994)
Proceeds from asset sales (note 8)		232			3,021		142
Additional investments		(1	)		(1	)	(32)
Loans to equity company		(19	)		-		-
Cash flows from (used in) investing activities		(781	)		1,947		(2,884)
Financing activities
Short-term debt - net		-			(1,749	)	(32)
Long-term debt - additions (note 14)		-			495		1,206
Long-term debt - reductions (note 14)		-			(2,000	)	-
Reduction in capitalized lease obligations (note 14)		(27	)		(28	)	(20)
Dividends paid		(524	)		(492	)	(449)
Common shares purchased (note 10)		(627	)		-		-
Cash flows from (used in) financing activities		(1,178	)		(3,774	)	705
Increase (decrease) in cash		804			188		(12)
Cash at beginning of year		391			203		215
Cash at end of year (c)		1,195			391		203
(a)  Included contribution to registered pension plans.		212			163		225

(b) The impact of carbon emission programs are included in additions to property, plant and equipment, and all other items - net.

(c) 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.

Non-cash transactions

In 2015, a capital lease of approximately $480 million was not included in “Additions to property, plant and equipment” or “Long-term debt - additions” lines on the Consolidated statement of cash flows.

The information in the notes to consolidated financial statements is an integral part of these statements.

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Notes to consolidated financial statements

The accompanying consolidated financial statements and the supporting and supplemental material are the responsibility of the management of Imperial Oil Limited.

The company’s principal business is energy, involving the exploration, production, transportation and sale of crude oil and natural gas, and the manufacture, transportation and sale of petroleum products. The company is also a major manufacturer and marketer of petrochemicals.

The consolidated financial statements have been prepared in accordance with United States Generally Accepted Accounting Principles, which requires management to make estimates and judgments that affect the reported amounts of assets, liabilities, revenues and expenses, and the disclosure of contingent assets and liabilities. Actual results could differ from these estimates. Prior years’ data has been reclassified in certain cases to conform to the 2017 presentation basis. All amounts are in Canadian dollars unless otherwise indicated.

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

Revenues associated with sales of crude oil, natural gas, petroleum and chemical products and other items are recorded when the products are delivered. Delivery occurs when the customer has taken title and has assumed the risks and rewards of ownership, prices are fixed or determinable and collectability is reasonably assured. 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.

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.

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.

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 has the ability to use 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 “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.

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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. Other investments are recorded at cost. Dividends from these other 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.

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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. The effect of this approach on the company’s 2018 depreciation expense compared to 2017 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 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 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

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production from mature fields is declining. This is being offset by investments to generate production from new discoveries, field developments and technology 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 and 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 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.

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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 7 to the consolidated financial statements on page 80 for further details.

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Recently issued accounting standards

Effective January 1, 2018, Imperial adopted the Financial Accounting Standards Board (FASB) standard, Revenue from Contracts with Customers, as amended. The standard establishes a single revenue recognition model for all contracts with customers, eliminates industry and transaction specific requirements, and expands disclosure requirements. The standard was adopted using the modified retrospective method, under which prior years’ results are not restated, but supplemental information on the impact of the new standard will be included in the 2018 results if material. The standard is not expected to have a material impact on the company’s financial statements. The cumulative effect of adoption of the new standard is de minimis.

Effective January 1, 2018, Imperial adopted the FASB standard update, Compensation – Retirement Benefits (Topic 715): Improving the Presentation of Net Periodic Pension Cost and Net Periodic Postretirement Benefit Cost. The update requires the service cost component of net benefit costs to be reported in the same line in the income statement as other compensation costs and the other components of net benefit costs (non-service costs) be presented separately from the service cost component. Additionally, only the service cost component of net benefit costs is eligible for capitalization. The company expects to add a new line “Non-service pension and other postretirement benefit” expense to its consolidated statement of income, and expects to include all of these costs in the “Corporate and other” expenses. This line would reflect the non-service costs that were previously included in “Production and manufacturing” expenses, and “Selling and general” expenses. The update is not expected to have a material impact on Imperial’s financial statements.

Effective January 1, 2019, Imperial will adopt the FASB standard, Leases. The standard requires that all leases with an initial term greater than one year be recorded on the balance sheet as an asset and a lease liability. Imperial is gathering and evaluating data, and recently acquired a system to facilitate implementation. The company continues to progress an assessment of the magnitude of the effect on the company’s financial statements.

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2. 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 post retirement benefits liability adjustment. Net earnings effects under Corporate and other activities primarily include debt-related financing, corporate governance 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.

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	Upstream									Downstream									Chemical
millions of Canadian dollars	2017			2016			2015			2017			2016			2015			2017			2016			2015
Revenues and other income
Operating revenues (a)		7,302			5,492			5,776			20,714			18,511			19,796			1,109			1,046			1,184
Intersegment sales		2,264			2,215			2,486			1,155			1,007			1,019			262			212			234
Investment and other income (note 8)		16			13			22			269			2,278			104			-			-			-
		9,582			7,720			8,284			22,138			21,796			20,919			1,371			1,258			1,418
Expenses
Exploration (b) (note 15)		183			94			73			-			-			-			-			-			-
Purchases of crude oil and products		4,526			3,666			3,768			16,543			14,178			14,526			751			705			725
Production and manufacturing		3,913			3,591			3,766			1,576			1,428			1,461			209			205			207
Selling and general		-			(5	)		(2	)		772			972			986			78			83			87
Federal excise tax		-			-			-			1,673			1,650			1,568			-			-			-
Depreciation and depletion (b)		1,939			1,396			1,193			202			206			233			12			10			11
Financing costs (note 12)		13			(7	)		5			-			-			-			-			-			-
Total expenses		10,574			8,735			8,803			20,766			18,434			18,774			1,050			1,003			1,030
Income (loss) before income taxes		(992	)		(1,015	)		(519	)		1,372			3,362			2,145			321			255			388
Income taxes (note 3)
Current		484			(491	)		(77	)		(504	)		674			476			(32	)		68			97
Deferred		(770	)		137			262			836			(66	)		83			118			-			4
Total income tax expense (benefit)		(286	)		(354	)		185			332			608			559			86			68			101
Net income (loss)		(706	)		(661	)		(704	)		1,040			2,754			1,586			235			187			287
Cash flows from (used in) operating activities		1,257			402			224			1,396			1,574			1,686			235			203			383
Capital and exploration expenditures (c)		416			896			3,135			200			190			340			17			26			52
Property, plant and equipment
Cost		45,542			45,850			45,171			5,683			6,166			7,596			888			872			857
Accumulated depreciation and depletion		(13,844	)		(12,312	)		(11,016	)		(3,594	)		(4,037	)		(4,584	)		(644	)		(629	)		(616	)
Net property, plant and equipment (b) (d)		31,698			33,538			34,155			2,089			2,129			3,012			244			243			241
Total assets		35,044			36,840			36,971			4,890			3,958			5,574			399			346			394
	Corporate and other									Eliminations									Consolidated
millions of Canadian dollars	2017			2016			2015			2017			2016			2015			2017			2016			2015
Revenues and other income
Operating revenues (a)		-			-			-			-			-			-			29,125			25,049			26,756
Intersegment sales		-			-			-			(3,681	)		(3,434	)		(3,739	)		-			-			-
Investment and other income (note 8)		14			14			6			-			-			-			299			2,305			132
		14			14			6			(3,681	)		(3,434	)		(3,739	)		29,424			27,354			26,888
Expenses
Exploration (b) (note 15)		-			-			-			-			-			-			183			94			73
Purchases of crude oil and products		-			-			-			(3,675	)		(3,429	)		(3,735	)		18,145			15,120			15,284
Production and manufacturing		-			-			-			-			-			-			5,698			5,224			5,434
Selling and general		49			84			50			(6	)		(5	)		(4	)		893			1,129			1,117
Federal excise tax		-			-			-			-			-			-			1,673			1,650			1,568
Depreciation and depletion (b)		19			16			13			-			-			-			2,172			1,628			1,450
Financing costs (note 12)		65			72			34			-			-			-			78			65			39
Total expenses		133			172			97			(3,681	)		(3,434	)		(3,739	)		28,842			24,910			24,965
Income (loss) before income taxes		(119	)		(158	)		(91	)		-			-			-			582			2,444			1,923
Income taxes (note 3)
Current		(6	)		(51	)		(45	)		-			-			-			(58	)		200			451
Deferred		(34	)		8			1			-			-			-			150			79			350
Total income tax expense (benefit)		(40	)		(43	)		(44	)		-			-			-			92			279			801
Net income (loss)		(79	)		(115	)		(47	)		-			-			-			490			2,165			1,122
Cash flows from (used in) operating activities		(125	)		(143	)		(124	)		-			(21	)		(2	)		2,763			2,015			2,167
Capital and exploration expenditures (c)		38			49			68			-			-			-			671			1,161			3,595
Property, plant and equipment
Cost		665			627			579			-			-			-			52,778			53,515			54,203
Accumulated depreciation and depletion		(223	)		(204	)		(188	)		-			-			-			(18,305	)		(17,182	)		(16,404	)
Net property, plant and equipment (b) (d)		442			423			391			-			-			-			34,473			36,333			37,799
Total assets		1,703			894			579			(435	)		(384	)		(348	)		41,601			41,654			43,170

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(a) Includes export sales to the United States of $4,392 million (2016 - $3,612 million, 2015 - $4,157 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) 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.

(d) Includes property, plant and equipment under construction of $1,047 million (2016 - $2,705 million, 2015 - $3,719 million).

3. Income taxes

millions of Canadian dollars	2017			2016			2015
Current income tax expense (a)		(58	)		200			451
Deferred income tax expense (a) (b)		150			79			350
Total income tax expense (a) (c)		92			279			801
Statutory corporate tax rate (percent)		26.9			26.8			27.2
Increase (decrease) resulting from:
Disposals (d)		(5.3	)		(11.6	)		(0.4	)
Enacted tax rate change (a)		0.9			-			16.1
Other		(6.6	)		(3.8	)		(1.2	)
Effective income tax rate		15.9			11.4			41.7

(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. On June 30, 2015 the Alberta government enacted a 2 percent increase in the provincial tax rate, from 10 percent to 12 percent.

(b) There were no material net (charges) credits for the effect of changes in tax laws and rates included in the provisions for deferred income taxes in 2016.

(c) Cash outflow from income taxes, plus investment credits earned, was $322 million (2016 - $172 million, 2015 - $202 million).

(d) 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 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	2017			2016			2015
Depreciation and amortization		5,564			5,361			4,677
Successful drilling and land acquisitions		762			891			922
Pension and benefits		(422	)		(457	)		(396	)
Asset retirement obligation		(376	)		(396	)		(406	)
Capitalized interest		118			114			104
LIFO inventory valuation (a)		(318	)		(240	)		-
Tax loss carryforwards		(936	)		(1,056	)		(610	)
Other (a)		(196	)		(212	)		(100	)
Net long-term deferred income tax liabilities		4,196			4,005			4,191
LIFO inventory valuation (a)		-			-			(112	)
Other (a)		-			-			(160	)
Net current deferred income tax assets		-			-			(272	)
Net current deferred income tax liabilities (a)		-			-			41
Net deferred income tax liabilities		4,196			4,005			3,960

(a) Effective 2016, under ASU 2015-17, deferred tax assets and liabilities have been classified as non-current. 2015 was not restated.

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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	2017			2016			2015
Balance as of January 1		106			132			151
Additions for prior years’ tax position		2			2			10
Reductions for prior years’ tax positions		-			(18	)		(4	)
Reductions due to lapse of the statute of limitations		-			(5	)		-
Settlements with tax authorities		(30	)		(5	)		(25	)
Balance as of December 31		78			106			132

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 2017, 2016 and 2015 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 2010 to 2017 are subject to examination by the tax authorities. Tax filings from 1998, 2000 and 2003 to 2009 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 2018. 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.

4. 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.

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The benefit obligations and plan assets associated with the company’s defined benefit plans are measured on December 31.

	Pension benefits						Other post retirement benefits
	2017			2016			2017			2016
Assumptions used to determine benefit obligations at December 31 (percent)
Discount rate		3.40			3.75			3.40			3.75
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		8,356			8,147			706			642
Current service cost		217			203			16			16
Interest cost		313			319			23			27
Actuarial loss (gain)		415			157			(49	)		46
Benefits paid (a)		(516	)		(470	)		(26	)		(25	)
Projected benefit obligation at December 31		8,785			8,356			670			706
Accumulated benefit obligation at December 31		8,043			7,681

The discount rate for the purpose of calculating year-end post retirement benefits plan liabilities is determined by using the Canadian Institute of Actuaries recommended spot curve for high-quality, long-term Canadian corporate bonds with an average maturity (or duration) approximating that of the liabilities. The measurement of the accumulated post retirement benefit obligation assumes a health care cost trend rate of 4.50 percent in 2018 and subsequent years.

	Pension benefits						Other post retirement benefits
millions of Canadian dollars	2017			2016			2017			2016
Change in plan assets
Fair value at January 1		7,359			7,260
Actual return (loss) on plan assets		700			316
Company contributions		212			163
Benefits paid (b)		(401	)		(380	)
Fair value at December 31		7,870			7,359
Plan assets in excess of (less than) projected benefit obligation at December 31
Funded plans		(408	)		(444	)
Unfunded plans		(507	)		(553	)		(670	)		(706	)
Total (c)		(915	)		(997	)		(670	)		(706	)

(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 post retirement benefits plans, the underfunded status of the company’s defined benefit post retirement plans was recorded as a liability in the balance sheet, and the changes in that funded status in the year in which the changes occurred was recognized through other comprehensive income.

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	Pension benefits						Other post retirement benefits
millions of Canadian dollars	2017			2016			2017			2016
Amounts recorded in the consolidated balance sheet consist of:
Current liabilities		(28	)		(29	)		(28	)		(29	)
Other long-term obligations		(887	)		(968	)		(642	)		(677	)
Total recorded		(915	)		(997	)		(670	)		(706	)
Amounts recorded in accumulated other comprehensive income consist of:
Net actuarial loss (gain)		2,408			2,461			140			197
Prior service cost		4			14			-			-
Total recorded in accumulated other     comprehensive income, before tax		2,412			2,475			140			197

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 2017 long-term expected return of 5.5 percent used in the calculations of pension expense compares to an actual rate of return of 6.3 percent and 7.3 percent over the last 10- and 20-year periods respectively, ending December 31, 2017.

	Pension benefits									Other post retirement benefits
millions of Canadian dollars	2017			2016			2015			2017			2016			2015
Assumptions used to determine net periodic benefit cost for years ended December 31 (percent)
Discount rate		3.75			4.00			3.75			3.75			4.00			3.75
Long-term rate of return on funded assets		5.50			5.50			5.75			-			-			-
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		217			203			211			16			16			15
Interest cost		313			319			307			23			27			25
Expected return on plan assets		(408	)		(400	)		(392	)		-			-			-
Amortization of prior service cost		10			9			16			-			-			-
Amortization of actuarial loss (gain)		176			162			198			8			13			14
Net periodic benefit cost		308			293			340			47			56			54
Changes in amounts recorded in accumulated other comprehensive income
Net actuarial loss (gain)		123			241			(86	)		(49	)		46			(2	)
Amortization of net actuarial (loss) gain included in net periodic benefit cost		(176	)		(162	)		(198	)		(8	)		(13	)		(14	)
Amortization of prior service cost included in net periodic benefit cost		(10	)		(9	)		(16	)		-			-			-
Total recorded in other comprehensive income		(63	)		70			(300	)		(57	)		33			(16	)
Total recorded in net periodic benefit cost and other comprehensive income, before tax		245			363			40			(10	)		89			38

Costs for defined contribution plans, primarily the employee savings plan, were $40 million in 2017 (2016 - $44 million, 2015 - $43 million).

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A summary of the change in accumulated other comprehensive income is shown in the table below:

	Total pension and other post retirement benefits
millions of Canadian dollars	2017			2016			2015
(Charge) credit to other comprehensive income, before tax		120			(103	)		316
Deferred income tax (charge) credit (note 17)		(38	)		34			(85	)
(Charge) credit to other comprehensive income, after tax		82			(69	)		231

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 indexed equity and domestic indexed bond funds to diversify risk while minimizing costs. The equity funds hold Imperial Oil Limited stock only to the extent necessary to replicate the relevant equity index. The balance of the plan assets is largely invested in high-quality corporate and government debt securities. Studies are periodically conducted to establish the preferred target asset allocation. The target asset allocation for equity securities is 28 percent. The target allocation for debt securities is 67 percent. Plan assets for the remaining 5 percent are invested in venture capital partnerships that pursue a strategy of investment in U.S. and international early stage ventures.

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 Value
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

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The 2016 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, 2016, using:
millions of Canadian dollars	Total	Level 1	Level 2	Level 3	Net Asset Value (a)
Asset class
Equity securities
Canadian	433				433
Non-Canadian	2,448				2,448
Debt securities - Canadian
Corporate	988				988
Government	3,218				3,218
Asset backed	-				-
Equities – Venture capital	241				241
Cash	31	6			25
Total plan assets at fair value	7,359	6	-	-	7,353

(a) Per ASU 2015-07, certain investments that are measured at fair value using the Net Asset Value (NAV) per share practical expedient have been re-categorized from the fair value hierarchy. The fair value amounts presented in this table are intended to permit reconciliation of the fair value hierarchy to the total value 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	2017		2016
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		507		553
Accumulated benefit obligation		480		525

Estimated 2018 amortization from accumulated other comprehensive income

millions of Canadian dollars	Pension benefits		Other post retirement benefits
Net actuarial loss (gain) (a)		170	9
Prior service cost (b)		4	-

(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.

(b) The company amortizes prior service cost on a straight-line basis.

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Cash flows

Benefit payments expected in:

millions of Canadian dollars	Pension benefits		Other post retirement  benefits
2018		425		29
2019		430		29
2020		435		29
2021		435		30
2022		435		30
2023 - 2027		2,165		155

In 2018, the company expects to make cash contributions of about $240 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		(75)		75
Discount rate:
Effect on net benefit cost, before tax		(90)		120
Effect on benefit obligation		(1,215)		1,570
Rate of pay increases:
Effect on net benefit cost, before tax		55		(45)
Effect on benefit obligation		265		(225)

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		80		(60)

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5. Other long-term obligations

millions of Canadian dollars	2017		2016
Employee retirement benefits (a) (note 4)		1,529		1,645
Asset retirement obligations and other environmental liabilities (b) (d)		1,460		1,544
Share-based incentive compensation liabilities (note 7)		99		139
Other obligations (c)		692		328
Total other long-term obligations		3,780		3,656

(a) Total recorded employee retirement benefits obligations also included $56 million in current liabilities (2016 – $58 million).

(b) Total asset retirement obligations and other environmental liabilities also included $101 million in current liabilities (2016 – $108 million).

(c) Included carbon emission program obligations. Carbon emission program credits are recorded under other assets, including intangibles, net.

(d) For 2017, the asset retirement obligations were discounted at 6 percent (2016 - 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	2017			2016
Balance as at January 1		1,472			1,571
Additions (deductions)		(124	)		(160	)
Accretion		92			97
Settlement		(43	)		(36	)
Balance as at December 31		1,397			1,472

6. Derivatives and financial 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 currency exchange rates and commodity prices. The company makes use of 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 estimated fair value of derivative instruments outstanding and recorded on the balance sheet was a net liability of $4 million at year-end 2017 (2016 - $0 million). Assets and liabilities associated with derivatives are usually recorded either in “Materials, supplies and prepaid expenses” or “Accounts payable and accrued liabilities”.

The company’s fair value measurement of its derivative instruments use either Level 1 or Level 2 inputs.

The company recognized a before-tax loss related to settled and unsettled derivative instruments of $5 million during 2017 (2016 - $0 million). Income statement effects associated with derivatives are recorded in “Purchases of crude oil and products”.

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 values of the company’s financial instruments and the recorded book value. The fair value hierarchy for long-term debt is primarily Level 2.

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7. 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, 2017:

	Restricted stock units			Deferred     share units
Outstanding at January 1, 2017		6,662,126			136,177
Granted		758,990			13,231
Vested / Exercised		(1,545,921	)		-
Forfeited and cancelled		(16,145	)		-
Outstanding at December 31, 2017		5,859,050			149,408

In 2017, the before-tax compensation expense charged against income for these programs was $14 million (2016 - $83 million, 2015 - $48 million). Income tax benefit recognized in income related to compensation expense for the year was $4 million (2016 - $24 million, 2015 - $13 million). Cash payments of $71 million were made for these programs in 2017 (2016 - $79 million, 2015 - $78 million).

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As of December 31, 2017, there was $94 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 3.8 years. All units under the deferred share programs have vested as of December 31, 2017.

8. Investment and other income

Investment and other income includes gains and losses on asset sales as follows:

millions of Canadian dollars	2017		2016		2015
Proceeds from asset sales		232		3,021		142
Book value of asset sales		12		777		45
Gain (loss) on asset sales, before tax (a) (b)		220		2,244		97
Gain (loss) on asset sales, after tax (a) (b)		192		1,908		79

(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.

9. 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. No unconditional purchase obligations existed in 2017 and 2016 (2015 - $125 million).

As a result of the completed sale of Imperial’s remaining company-owned Esso retail sites, the company was contingently liable at December 31, 2017, for guarantees relating to performance under contracts of other third-party obligations totaling $42 million (2016 - $49 million).

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10. Common shares

thousands of shares	As at Dec 31 2017		As at         Dec 31 2016
Authorized		1,100,000		1,100,000
Common shares outstanding		831,242		847,599

The current 12-month normal course issuer bid program was announced on June 22, 2017, under which Imperial continued its share purchase program. The program enables the company to purchase up to a maximum of 25,395,927 common shares (3 percent of the total shares on June 13, 2017), 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 shares			Millions of dollars
Balance as at January 1, 2015		847,599			1,566
Issued under employee share-based awards		1			-
Purchases at stated value		(1	)		-
Balance as at December 31, 2015		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

The following table provides the calculation of basic and diluted earnings per common share:

	2017		2016		2015
Net income (loss) per common share – basic
Net income (loss) (millions of Canadian dollars)		490		2,165		1,122
Weighted average number of common shares outstanding (millions of shares)		842.9		847.6		847.6
Net income (loss) per common share (dollars)		0.58		2.55		1.32
Net income (loss) per common share - diluted
Net income (loss) (millions of Canadian dollars)		490		2,165		1,122
Weighted average number of common shares outstanding (millions of shares)		842.9		847.6		847.6
Effect of employee share-based awards (millions of shares)		2.8		2.9		3.0
Weighted average number of common shares outstanding, assuming dilution (millions of shares)		845.7		850.5		850.6
Net income (loss) per common share (dollars)		0.58		2.55		1.32

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11. Miscellaneous financial information

In 2017, net income included an after-tax gain of $5 million (2016 – $5 million gain, 2015 – $39 million loss) 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, 2017 by about $1.4 billion (2016 – $1 billion). Inventories of crude oil and products at year-end consisted of the following:

millions of Canadian dollars	2017		2016
Crude oil		690		558
Petroleum products		307		300
Chemical products		42		51
Natural gas and other		36		40
Total inventories of crude oil and products		1,075		949

Net research and development costs charged to expenses in 2017 were $111 million (2016 – $152 million, 2015 – $149 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 $437 million at December 31, 2017 (2016 – $396 million).

12. Financing costs and additional notes and loans payable information

millions of Canadian dollars	2017			2016			2015
Debt-related interest		103			121			102
Capitalized interest		(38	)		(49	)		(68	)
Net interest expense		65			72			34
Other interest		13			(7	)		5
Total financing costs (a)		78			65			39

 (a) Cash interest payments in 2017 were $58 million (2016 – $73 million, 2015 – $74 million). The weighted average interest rate on short-term borrowings in 2017 was 0.9 percent (2016 – 0.8 percent, 2015 – 0.8 percent). Average effective rate on the long-term borrowings with ExxonMobil in 2017 was 1.3 percent (2016 - 1.0 percent, 2015 - 1.0 percent).

As at December 31, 2017, the company had borrowed $75 million under an arrangement with an affiliated company of ExxonMobil that provides for a non-interest bearing, revolving demand loan from ExxonMobil to the company of up to $75 million. The loan represents ExxonMobil’s share of a working capital facility required to support purchasing, marketing and transportation arrangements for crude oil and diluent products undertaken by Imperial on behalf of ExxonMobil.

In November 2017, the company extended the maturity date of its existing $250 million committed long-term line of credit to November 2019. The company has not drawn on the facility.

In December 2017, the company extended the maturity date of its existing $250 million committed short-term line of credit to December 2018. The company has not drawn on the facility.

13. Leased facilities

At December 31, 2017, the company held non-cancelable operating leases covering primarily storage tanks, rail cars and marine vessels, with minimum undiscounted lease commitments totaling $199 million as indicated in the following table:

	Payments due by period
millions of Canadian dollars	2018		2019		2020		2021		2022		After 2022		Total
Lease payments under minimum commitments (a)		120		56		19		2		1		1		199

 (a) Net rental cost under cancelable and non-cancelable operating leases incurred in 2017 was $206 million (2016 - $253 million, 2015 - $311 million). Related rental income was not material.

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14. Long-term debt

millions of Canadian dollars	As at Dec 31 2017		As at         Dec 31 2016
Long-term debt (a)		4,447		4,447
Capital leases (b)		558		585
Total long-term debt		5,005		5,032

 (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 7.0 percent in 2017 (2016 – 6.9 percent). Total capitalized lease obligations also include $27 million in current liabilities (2016 - $27 million). Principal payments on capital leases of approximately $21 million on average per year are due in each of the next four years after December 31, 2018.

15. 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	2017			2016			2015
Balance as at January 1		143			167			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			167

Period end capitalized suspended exploratory well costs:

millions of Canadian dollars	2017		2016		2015
Capitalized for a period of one year or less		-		-		-
Capitalized for a period of between one and ten years		-		143		167
Capitalized for a period of greater than one year		-		143		167
Total		-		143		167

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.

	2017		2016		2015
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		1
Total		-		1		1

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16. 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) Whereby ExxonMobil enters 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 2017, with ExxonMobil, were $2,648 million and $4,080 million respectively (2016 - $2,187 million and $2,315 million respectively).

As at December 31, 2017, the company had outstanding long-term loans of $4,447 million (2016 – $4,447 million) and short-term loans of $75 million (2016 – $75 million) from ExxonMobil (see note 14 “Long-term debt”, on page 84 and note 12, “Financing costs and additional notes and loans payable information”, on page 83 for further details).

Imperial has other related party transactions not detailed above in note 16, as they are not significant.

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17. Other comprehensive income (loss) information

Changes in accumulated other comprehensive income (loss):

millions of Canadian dollars	2017			2016			2015
Balance at January 1		(1,897	)		(1,828	)		(2,059	)
Post retirement benefits liability adjustment:
Current period change excluding amounts reclassified from accumulated other comprehensive income		(54	)		(210	)		64
Amounts reclassified from accumulated other comprehensive income		136			141			167
Balance at December 31		(1,815	)		(1,897	)		(1,828	)

Amounts reclassified out of accumulated other comprehensive income (loss) - before-tax income (expense):

millions of Canadian dollars	2017			2016			2015
Amortization of post retirement benefits liability adjustment included in net periodic benefit cost (a)		(194	)		(184	)		(228	)

 (a) This accumulated other comprehensive income component is included in the computation of net periodic benefit cost (note 4).

Income tax expense (credit) for components of other comprehensive income (loss):

millions of Canadian dollars	2017			2016			2015
Post retirement benefits liability adjustments:
Post retirement benefits liability adjustment (excluding amortization)		(20	)		(77	)		24
Amortization of post retirement benefits liability adjustment included in net periodic benefit cost		58			43			61
Total		38			(34	)		85

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Supplemental information on oil and gas exploration and production activities (unaudited)

The information on pages 87 to 88 excludes items not related to oil and natural gas extraction, such as administrative and general expenses, pipeline operations, gas plant processing fees and gains or losses on asset sales. The company’s 25 percent interest in proved synthetic oil reserves in the Syncrude joint-venture is included as part of the company’s total proved oil and gas reserves and in the calculation of the standardized measure of discounted future cash flows, in accordance with U.S. Securities and Exchange Commission and U.S. Financial Accounting Standards Board rules. Results of operations, costs incurred in property acquisitions, exploration and development activities, and capitalized costs include the company’s share of Syncrude, Kearl and other unproved mineable acreages in the following tables.

Results of operations

millions of Canadian dollars	2017			2016			2015
Sales to customers (a)		3,283			2,210			2,483
Intersegment sales (a) (b)		1,750			1,791			1,855
		5,033			4,001			4,338
Production expenses		3,959			3,657			3,727
Exploration expenses		183			94			73
Depreciation and depletion		1,623			1,275			1,102
Income taxes		(217	)		(366	)		174
Results of operations		(515	)		(659	)		(738	)

The amounts reported as costs incurred in property acquisitions, exploration and development activities include both capitalized costs and costs charged to expense during the year. Costs incurred also include new asset retirement obligations established in the current year, as well as increases or decreases to the asset retirement obligation resulting from changes in cost estimates or abandonment date.

Costs incurred in property acquisitions, exploration and development activities

millions of Canadian dollars	2017		2016		2015
Property costs (c)
Proved		-		1		-
Unproved		32		-		-
Exploration costs		40		70		76
Development costs		214		543		3,035
Total costs incurred in property acquisitions, exploration and development activities		286		614		3,111

(a) Sales to customers or intersegment sales do not include the sale of natural gas and natural gas liquids purchased for resale, as well as royalty payments. These items are reported gross in note 2 in “Operating revenues”, “Intersegment sales” and in “Purchases of crude oil and products”.

(b) Sales of crude oil to consolidated affiliates are at market value, using posted field prices. Sales of natural gas liquids to consolidated affiliates are at prices estimated to be obtainable in a competitive, arm’s-length transaction.

(c) “Property costs” are payments for rights to explore for petroleum and natural gas and for purchased reserves (acquired tangible and intangible assets such as gas plants, production facilities and producing-well costs are included under “producing assets”). “Proved” represents areas where successful drilling has delineated a field capable of production. “Unproved” represents all other areas.

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Capitalized costs

millions of Canadian dollars	2017			2016
Property costs (a)
Proved		2,214			2,194
Unproved		2,465			2,466
Producing assets		38,332			36,827
Incomplete construction		673			2,287
Total capitalized cost		43,684			43,774
Accumulated depreciation and depletion		(13,733	)		(12,243	)
Net capitalized costs		29,951			31,531

 (a) “Property costs” are payments for rights to explore for petroleum and natural gas and for purchased reserves (acquired tangible and intangible assets such as gas plants, production facilities and producing-well costs are included under “producing assets”). “Proved” represents areas where successful drilling has delineated a field capable of production. “Unproved” represents all other areas.

Standardized measure of discounted future cash flows

As required by the U.S. Financial Accounting Standards Board, the standardized measure of discounted future net cash flows is computed by applying first-day-of-the-month average prices, year-end costs and legislated tax rates and a discount factor of 10 percent to net proved reserves. The standardized measure includes costs for future dismantlement, abandonment and remediation obligations. The company believes the standardized measure does not provide a reliable estimate of the company’s expected future cash flows to be obtained from the development and production of its oil and gas properties or of the value of its proved oil and gas reserves. The standardized measure is prepared on the basis of certain prescribed assumptions, including first-day-of-the-month average prices, which represent discrete points in time and therefore may cause significant variability in cash flows from year to year as prices change.

Standardized measure of discounted future net cash flows related to proved oil and gas reserves

millions of Canadian dollars	2017			2016			2015
Future cash flows		72,325			53,743			168,482
Future production costs		(44,822	)		(36,100	)		(122,188	)
Future development costs		(14,640	)		(11,917	)		(36,048	)
Future income taxes		(3,916	)		(1,263	)		(3,333	)
Future net cash flows		8,947			4,463			6,913
Annual discount of 10 percent for estimated timing of cash flows		(3,811	)		(1,717	)		(3,683	)
Discounted future cash flows		5,136			2,746			3,230

Changes in standardized measure of discounted future net cash flows related to proved oil and gas reserves

Balance at beginning of year	2,746		3,230		31,057
Changes resulting from:
Sales and transfers of oil and gas produced, net of production costs	(1,516	)	(718	)	(1,134	)
Net changes in prices, development costs and production costs (a)	4,231		(1,468	)	(37,945	)
Extensions, discoveries, additions and improved recovery, less related costs	81		14		29
Development costs incurred during the year	376		651		2,250
Revisions of previous quantity estimates	110		56		972
Accretion of discount	290		417		1,683
Net change in income taxes	(1,182	)	564		6,318
Net change	2,390		(484	)	(27,827	)
Balance at end of year	5,136		2,746		3,230

(a) SEC rules require the company’s reserves to be calculated on the basis of average first-of-month oil and natural gas prices during the reporting year. Future net cash flows are determined based on the net proved reserves as outlined in the Net Proved Reserves table.

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Net proved reserves (a)

	Liquids (b)			Natural gas			Synthetic oil			Bitumen			Total oil-equivalent basis (c)
	millions of barrels			billions of cubic feet			millions of barrels			millions of barrels			millions of barrels
Beginning of year 2015		46			627			534			3,274			3,959
Revisions		(10	)		(28	)		68			331			384
Improved recovery		-			-			-			-			-
(Sale) purchase of reserves in place		1			11			-			-			3
Discoveries and extensions		2			18			-			-			5
Production		(5	)		(45	)		(21	)		(90	)		(124	)
End of year 2015		34			583			581			3,515			4,227
Revisions		3			(58	)		8			(2,720	)		(2,719	)
Improved recovery		-			-			-			-			-
(Sale) purchase of reserves in place		-			-			-			-			-
Discoveries and extensions		2			15			-			-			4
Production		(4	)		(45	)		(25	)		(94	)		(130	)
End of year 2016		35			495			564			701			1,382
Revisions		4			115			(70	)		332			286
Improved recovery		-			1			-			6			6
(Sale) purchase of reserves in place		4			28			-			-			9
Discoveries and extensions		2			43			-			-			9
Production		(1	)		(41	)		(21	)		(93	)		(122	)
End of year 2017		44			641			473			946			1,570
Net proved developed reserves included above, as of
January 1, 2015		36			300			534			1,635			2,255
December 31, 2015		23			283			581			3,063			3,714
December 31, 2016		19			263			564			436			1,063
December 31, 2017		9			282			473			591			1,120
Net proved undeveloped reserves included above, as of
January 1, 2015		10			327			-			1,639			1,704
December 31, 2015		11			300			-			452			513
December 31, 2016		16			232			-			265			319
December 31, 2017		35			359			-			355			450

(a) Net reserves are the company’s share of reserves after deducting the shares of mineral owners or governments or both. All reported reserves are located in Canada. Reserves of natural gas are calculated at a pressure of 14.73 pounds per square inch at 60°F.

(b) Liquids include crude, condensate and natural gas liquids (NGLs). NGL proved reserves are not material and are therefore included under liquids.

(c) Gas converted to oil-equivalent at six million cubic feet per one thousand barrels.

The information above describes changes during the years and balances of proved oil and gas reserves at year-end 2015, 2016 and 2017. The definitions used are in accordance with the U.S. Securities and Exchange Commission’s Rule 4-10 (a) of Regulation S-X.

Proved oil and natural gas reserves are those quantities of oil and gas, which, by analysis of geoscience and engineering data, can be estimated with reasonable certainty to be economically producible – from a given date forward, from known reservoirs, and under existing economic conditions, operating methods and government regulations – prior to the time at which contracts providing the right to operate expire. In some cases, substantial new investments in additional wells and other facilities will be required to recover these proved reserves.

89

In accordance with SEC rules, the year-end reserves volumes, as well as the reserves change categories shown in the proved reserves tables are required to be calculated on the basis of average prices during the 12-month period prior to the ending date of the period covered by the report, determined as an unweighted arithmetic average of the first-day-of-the-month price for each month within such period. These reserves quantities were also used in calculating unit-of-production depreciation rates and in calculating the standardized measure of discounted net cash flow.

Revisions can include upward or downward changes in previously estimated volumes of proved reserves for existing fields due to the evaluation or re-evaluation of already available geologic, reservoir or production data; new geologic, reservoir or production data; or changes in the average of first-of-month oil and natural gas prices and / or costs that are used in the estimation of reserves. Revisions can result from significant changes in either development strategy or production equipment / facility capacity.

At year-end 2015, upward revisions of proved developed bitumen reserves were associated with migration of the Kearl expansion project from proved undeveloped, and improved performance demonstrated at Kearl. As well, upward revision to bitumen and synthetic oil were associated with lower royalty obligations driven by lower pricing.

At year-end 2016, downward revisions of proved developed and undeveloped bitumen reserves were a result of low prices. The entire 2.5 billion barrels of bitumen at Kearl and approximately 0.2 billion barrels of bitumen at Cold Lake no longer qualified as proved reserves under the U.S. Securities and Exchange Commission definition of proved reserves.

As a result of improved prices in 2017, an additional 0.3 billion barrels of bitumen at Kearl and Cold Lake now qualify as proved reserves at year-end 2017. Among the factors that would result in additional amounts being recognized as proved reserves at some point in the future are a further recovery in yearly average price levels, a further decline in costs and additional planned investment in reliability improvements. Under the terms of certain contractual arrangements or government royalty regimes, lower prices can also increase proved reserves attributable to Imperial. The company’s operating decisions and its outlook for future production volumes are not impacted by proved reserves as disclosed under the U.S. Securities and Exchange Commission definition.

At year-end 2017, downward revisions of proved developed synthetic oil reserves were a result of higher royalty obligations driven by higher pricing and mine plan updates.

Net proved reserves are determined by deducting the estimated future share of mineral owners or governments or both. For liquids and natural gas, net proved reserves are based on estimated future royalty rates as of the date the estimate is made incorporating the applicable governments’ oil and gas royalty regimes. For bitumen, net proved reserves are based on the company’s best estimate of average royalty rates over the remaining life of each of the Cold Lake and Kearl fields, and they incorporate the Alberta government’s oil sands royalty regime. For synthetic oil, net proved reserves are based on the company’s best estimate of average royalty rates over the remaining life of the project, and they incorporate the Alberta government’s oil sands royalty regime. In all cases, actual future royalty rates may vary with production, price and costs.

Net proved developed reserves are those volumes that are expected to be recovered through existing wells and facilities with existing equipment and operating methods or in which the cost of the required equipment is relatively minor compared to the cost of a new well or facility. Net proved undeveloped reserves are those volumes that are expected to be recovered as a result of future investments to drill new wells, to recomplete existing wells and/or to install facilities to collect and deliver the production from existing and future wells and facilities.

90

Quarterly financial and stock trading data (a)

	2017												2016
	three months ended												three months ended
	Dec. 31			Sept. 30			June 30			Mar. 31			Dec. 31			Sept. 30			June 30			Mar. 31
Financial data (millions of Canadian dollars)
Total revenues and other income		8,077			7,158			7,033			7,156			8,442			7,442			6,248			5,222
Total expenses		8,286			6,662			7,158			6,736			6,779			6,260			6,500			5,371
Income (loss) before income taxes		(209	)		496			(125	)		420			1,663			1,182			(252	)		(149	)
Income taxes		(72	)		125			(48	)		87			219			179			(71	)		(48	)
Net income (loss)		(137	)		371			(77	)		333			1,444			1,003			(181	)		(101	)
Net income (loss) (millions of Canadian dollars)
Upstream		(481	)		62			(201	)		(86	)		103			(26	)		(290	)		(448	)
Downstream		290			292			78			380			1,361			1,002			71			320
Chemical		74			52			64			45			27			56			55			49
Corporate and other		(20	)		(35	)		(18	)		(6	)		(47	)		(29	)		(17	)		(22	)
Net income (loss)		(137	)		371			(77	)		333			1,444			1,003			(181	)		(101	)
Per share information (Canadian dollars)
Net income (loss) per common share - basic		(0.16	)		0.44			(0.09	)		0.39			1.70			1.18			(0.21	)		(0.12	)
Net income (loss) per common share - diluted		(0.16	)		0.44			(0.09	)		0.39			1.70			1.18			(0.21	)		(0.12	)
Dividends per share - declared		0.16			0.16			0.16			0.15			0.15			0.15			0.15			0.14
Share prices (Canadian dollars) (b)
Toronto Stock Exchange
High		42.26			40.11			41.77			47.60			48.72			42.10			43.21			46.25
Low		37.88			35.15			37.27			40.51			40.76			38.41			38.71			37.25
Close		39.23			39.86			37.80			40.52			46.71			41.04			40.88			43.39
NYSE American LLC (U.S. dollars) (b)
High		32.75			32.15			31.14			35.43			36.85			32.42			34.11			35.48
Low		29.41			27.81			27.59			30.04			31.07			29.26			29.54			25.55
Close		31.19			31.94			29.18			30.50			34.76			31.32			31.56			33.40
Shares traded (thousands) (c)		88,735			88,089			92,636			84,436			70,560			67,098			101,121			112,059

(a) Quarterly data has not been audited by the company’s independent auditors.

(b) Imperial’s shares are listed on the Toronto Stock Exchange. The company’s shares also trade in the United States of America on the NYSE American LLC. Imperial has unlisted privileges on the NYSE American LLC. The symbol on these exchanges for Imperial’s common shares is IMO. Share prices were obtained from stock exchange records. U.S. dollar share price presented is based on consolidated U.S. market data.

(c) The number of shares traded is based on transactions on the above stock exchanges and through other designated exchanges and published markets in Canada.

91

Proxy information section

Table of contents	Page
Nominees for director	93
Director nominee tables	93
Majority voting policy	97
Corporate governance disclosure	98
Corporate governance disclosure at a glance	98
Statement of corporate governance practice	99
Composition of our board nominees	99
Tenure of our board nominees	99
Skills and experience of our board members	100
Independence of our board members	101
Committee membership of our board	102
Number of meetings	102
Attendance of our board members in 2017	103
Other public company directorships of our board members	103
Interlocking directorships of our board members	104
Director qualification and selection process	104
Director orientation, education and development	105
Board performance assessment	105
Board and committee structure	106
Director compensation	111
Share ownership guidelines of independent directors and chairman, president and chief executive officer	118
Ethical business conduct	119
Restrictions on insider trading	120
Diversity	120
Shareholder engagement	121
Largest shareholder	121
Transactions with Exxon Mobil Corporation	121
Company executives and executive compensation	123
Named executive officers of the company	123
Other executive officers of the company	124
Letter to shareholders from the executive resources committee on executive compensation	126
Compensation discussion and analysis	128
Overview	129
Compensation program	132
Compensation decision making process and considerations for named executive officers	138
Executive compensation tables and narratives	143
Appendix	150
Appendix A – Board of Director and Committee Charters	150

92

Nominees for director

The director nominee tables on the following pages provide information on the seven nominees proposed for election to the board of directors of the company. All of the nominees are now directors and have been since the dates indicated. V.L. Young is currently a director and is not standing for re-election in 2018 as he will reach the company’s mandatory retirement age for directors in 2018.

Included in these tables is information relating to the director nominees’ biographies, independence status, expertise, committee memberships, attendance, public board memberships and shareholdings in the company. The information is as of February 7, 2018, the effective date of this circular, unless otherwise indicated.

For more information on our director nominees, please see the Statement of corporate governance practice starting on page 99.

Director nominee tables

David W. Cornhill Calgary, Alberta, Canada Nonemployee director (independent) Age: 64 Director since: November 29, 2017 Skills and experience: Leadership of large organizations, Operations/Technical, Project management, Strategy development, Audit committee financial expert, Financial expertise, Executive compensation David Cornhill is chairman of the board of directors of AltaGas Ltd., a position he has held since AltaGas Services Inc.’s (AltaGas’

predecessor) inception in 1994. Mr. Cornhill is a founding shareholder of AltaGas Services Inc., and was chief executive officer from 1994 to 2016. Prior to forming AltaGas Services Inc., Mr. Cornhill served in the capacities of vice-president, finance and administration and treasurer at Alberta and Southern Gas Co. Ltd, from 1991 to 1993 and as president and chief executive officer until 1994. Mr. Cornhill is an experienced leader in the business community and is a strong supporter of communities and community collaboration, investment and enhancement. He serves on the board of governors at Western University and is a member of the Ivey Advisory Board at Western. Mr. Cornhill holds a Bachelor of Science (Hons.) degree and a Master of Business Administration degree, both from Western, and was awarded an honorary Doctor of Laws degree by the University in 2015.

Imperial Oil Limited Ownership and Value of Equity (a) (b) (c) (d)
	IMO Common     Shares (% of class)	IMO Deferred     Share Units (DSU)	Total Vested     Equity Holdings     (Common + DSU)	Restricted      Stock Units      (RSU)	Total Holdings*      (Common + DSU      + RSU)
Holdings as at February 7, 2018 (#)	12,500 (<0.01%)	354	12,854	2,600	15,454
Total market value as at February 7, 2018 ($)	443,750	12,567	456,317	92,300	548,617
Year over year change (#)	n/a	n/a	n/a	n/a	n/a

                *Meets the necessary share ownership requirements

Board and Committee Membership*	Meeting Attendance 2017	Public Company Directorships in the Past Five Years*
Imperial Oil Limited board Audit committee Executive resources committee Environment, health and safety committee Nominations and corporate governance committee Contributions committee	1 of 1 (100%) 0 of 0 (n/a) 1 of 1 (100%) 1 of 1 (100%) 1 of 1 (100%) 1 of 1 (100%)	- AltaGas Ltd. (2010 – present) - Alterra Power Corp. (2008 – 2018) - Painted Pony Energy Ltd. (2015 – 2017) - Northern Power Systems Corp. (2014 – 2015) *no public board interlocks

Voting Results of 2017 Annual General Meeting:		Other Positions in the Past Five Years: (position, date office held, and status of employer)
n/a	n/a	- AltaGas Ltd., Chairman of the Board (1994 – present) - AltaGas Ltd., Chief Executive Officer (1994 – 2016)

93

Krystyna T. Hoeg Toronto, Ontario, Canada Nonemployee director (independent) Age: 68 Director since: May 1, 2008 Skills and experience: Leadership of large organizations, Project management, Global experience, Strategy development, Audit committee financial expert, Financial expertise, Executive compensation Ms. Hoeg was the president and chief executive officer of Corby Distilleries Limited from 1996 until her retirement in February 2007.

She previously held several positions in the finance and controllers functions of Allied Domecq PLC and Hiram Walker & Sons Limited. Prior to that, she spent five years in public practice as a chartered accountant with the accounting firm of Touche Ross. She is currently a director of New Flyer Industries Inc. and is also a director of Samuel, Son & Co. Limited and Revera Inc., privately owned corporations. Ms. Hoeg is the past chair of the board of the Michael Garron Hospital (formerly known as the Toronto East General Hospital).

Imperial Oil Limited Ownership and Value of Equity (a) (b) (c) (d)
	IMO Common     Shares (% of class)	IMO Deferred     Share Units (DSU)	Total Vested     Equity Holdings     (Common + DSU)	Restricted      Stock Units      (RSU)	Total Holdings*      (Common + DSU      + RSU)
Holdings as at February 7, 2018 (#)	0	31,141	31,141	11,200	42,341
Total market value as at February 7, 2018 ($)	0	1,105,506	1,105,506	397,600	1,503,106
Year over year change (#)	0	3,498	3,498	600	4,098

                *Meets the necessary share ownership requirements

Board and Committee Membership	Meeting Attendance 2017	Public Company Directorships in the Past Five Years*
Imperial Oil Limited board Audit committee Executive resources committee (Chair) Environment, health and safety committee Nominations and corporate governance committee Contributions committee	7 of 7 (100%) 5 of 5 (100%) 7 of 7 (100%) 3 of 3 (100%) 7 of 7 (100%) 2 of 2 (100%)	- New Flyer Industries (2015 – Present) - Sun Life Financial Inc. (2002 – 2016) - Canadian Pacific Railway Limited (2007 – 2015) - Canadian Pacific Railway Company (2007 – 2015) - Shoppers Drug Mart Corporation (2006 – 2014) *no public board interlocks

Voting Results of 2017 Annual General Meeting:		Other Positions in the Past Five Years: (position, date office held, and status of employer)
Votes in Favour: 754,930,036    (99.88%)	Votes Withheld: 882,189    (0.12%)	No other position held in the last five years

Richard M. Kruger Calgary, Alberta, Canada Non-independent director Age: 58 Director since: March 1, 2013 Skills and experience: Leadership of large organizations, Operations/technical, Project management, Global experience, Strategy development, Financial expertise, Government relations, Executive compensation Mr. Kruger was appointed chairman, president and chief executive officer of Imperial Oil Limited effective March 1, 2013. Mr. Kruger has

worked for Exxon Mobil Corporation and its predecessor companies since 1981 in various upstream and downstream assignments with responsibilities in the United States, the former Soviet Union, the Middle East, Africa and Southeast Asia. In his previous position, Mr. Kruger was vice-president of Exxon Mobil Corporation and president of ExxonMobil Production Company, a division of Exxon Mobil Corporation, with responsibility for ExxonMobil’s global oil and gas producing operations.

Imperial Oil Limited Ownership and Value of Equity (a) (b) (c) (d)
	IMO Common     Shares (% of class)	IMO Deferred     Share Units (DSU)	Total Vested     Equity Holdings     (Common + DSU)	Restricted      Stock Units      (RSU)	Total Holdings*      (Common + DSU      + RSU)
Holdings as at February 7, 2018 (#)	0	0	0	492,500	492,500
Total market value as at February 7, 2018 ($)	0	0	0	17,483,750	17,483,750
Year over year change (#)	0	0	0	99,000	99,000

                *Meets the necessary share ownership requirements

Board and Committee Membership	Meeting Attendance 2017	Public Company Directorships in the Past Five Years*
Imperial Oil Limited board (Chair) Contributions committee	7 of 7 (100%) 2 of 2 (100%)	No other public company directorships in the past five years *no public board interlocks

Voting Results of 2017 Annual General Meeting:		Other Positions in the Past Five Years: (position, date office held, and status of employer)
Votes in Favour: 750,338,099    (99.28%)	Votes Withheld: 5,474,126    (0.72%)	- Vice-president, Exxon Mobil Corporation and   President, ExxonMobil Production Company   (2008 – 2013) (Affiliate)

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Jack M. Mintz Calgary, Alberta, Canada Nonemployee director (independent) Age: 66 Director since: April 21, 2005 Skills and experience: Global experience, Strategy development, Financial expertise, Government relations, Academic/research, Executive compensation Dr. Mintz is currently the President’s Fellow at the University of Calgary’s School of Public Policy focusing on tax, urban and financial

market regulatory policy programs and also serves as the national policy advisor for EY (formerly Ernst & Young). From 2006 to 2015, Dr. Mintz was the founding Director and Palmer Chair in Public Policy for the University of Calgary, and from 1999 to 2006, he was the president and chief executive officer of The C.D. Howe Institute. He has been a member of the board of Morneau Shepell since 2010. He has also been a professor at Queen’s University Economics Department from 1978 to 1989 and the Joseph L. Rotman School of Management at the University of Toronto from 1989 to 2007. Dr. Mintz also has published widely in the fields of public economics and fiscal federalism, has been an advisor to governments throughout the world on fiscal matters, and has frequently published articles in national newspapers and magazines. Dr. Mintz received the Order of Canada in 2015.

Imperial Oil Limited Ownership and Value of Equity (a) (b) (c) (d)
	IMO Common     Shares (% of class)	IMO Deferred     Share Units (DSU)	Total Vested     Equity Holdings     (Common + DSU)	Restricted      Stock Units      (RSU)	Total Holdings*      (Common + DSU      + RSU)
Holdings as at February 7, 2018 (#)	1,000 (<0.01%)	27,023	28,023	11,200	39,223
Total market value as at February 7, 2018 ($)	35,500	959,317	994,817	397,600	1,392,417
Year over year change (#)	0	3,433	3,433	600	4,033

                *Meets the necessary share ownership requirements

Board and Committee Membership	Meeting Attendance 2017	Public Company Directorships in the Past Five Years*
Imperial Oil Limited board Audit committee Executive resources committee Environment, health and safety committee (Chair) Nominations and corporate governance committee Contributions committee	7 of 7 (100%) 5 of 5 (100%) 7 of 7 (100%) 3 of 3 (100%) 7 of 7 (100%) 2 of 2 (100%)	- Morneau Shepell Inc. (2010 – Present) *no public board interlocks

Voting Results of 2017 Annual General Meeting:		Other Positions in the Past Five Years: (position, date office held, and status of employer)
Votes in Favour: 754,860,462     (99.87%)	Votes Withheld: 951,763    (0.13%)	No other position held in the last five years

David S. Sutherland Waterloo, Ontario, Canada Nonemployee director (independent) Age: 68 Director since: April 29, 2010 Skills and experience: Leadership of large organizations, Operations/technical, Global experience, Strategy development, Audit committee financial expert, Financial expertise, Government relations, Executive compensation In July 2007, Mr. Sutherland retired as president and chief executive officer of the former IPSCO, Inc. after spending 30 years with the

company and more than five years as president and chief executive officer. Mr. Sutherland is the chairman of the board of United States Steel Corporation and director of GATX Corporation. Mr. Sutherland is also chairman of Graham Group Ltd., an employee owned corporation and is a director of Steelcraft Inc., a privately owned corporation. Mr. Sutherland is a former chairman of the American Iron and Steel Institute and served as a member of the board of directors of the Steel Manufacturers Association, the International Iron and Steel Institute, the Canadian Steel Producers Association and the National Association of Manufacturers.

Imperial Oil Limited Ownership and Value of Equity (a) (b) (c) (d)
	IMO Common     Shares (% of class)	IMO Deferred     Share Units (DSU)	Total Vested     Equity Holdings     (Common + DSU)	Restricted      Stock Units      (RSU)	Total Holdings*      (Common + DSU      + RSU)
Holdings as at February 7, 2018 (#)	55,000 (<0.01%)	24,449	79,449	11,200	90,649
Total market value as at February 7, 2018 ($)	1,952,500	867,940	2,820,440	397,600	3,218,040
Year over year change (#)	10,000	3,393	13,393	600	13,993

                *Meets the necessary share ownership requirements

Board and Committee Membership	Meeting Attendance 2017	Public Company Directorships in the Past Five Years*
Imperial Oil Limited board Audit committee Executive resources committee Environment, health and safety committee Nominations and corporate governance committee Contributions committee (Chair)	6 of 7 (86%) 4 of 5 (80%) 6 of 7 (86%) 2 of 3 (67%) 6 of 7 (86%) 2 of 2 (100%)	- GATX Corporation (2007 – Present) - United States Steel Corporation, (2008 – Present) *no public board interlocks

Voting Results of 2017 Annual General Meeting:		Other Positions in the Past Five Years: (position, date office held, and status of employer)
Votes in Favour: 754,853,875    (99.87%)	Votes Withheld: 958,350    (0.13%)	No other position held in the last five years

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Jerry Wascom Spring, Texas, United States of America Non-independent director Age: 61 Director since: July 30, 2014 Skills and experience: Leadership of large organizations, Operations/technical, Project management, Global experience, Strategy development, Financial expertise, Executive compensation Mr. Wascom is vice-president, operational excellence, safety, security, health and environment for Exxon Mobil Corporation. He is

located in Dallas, Texas. Mr. Wascom has worked for ExxonMobil in a range of refining operations and management assignments, overseeing refining operations in North and Central/South America, the USA and Canada, as well as international assignments in Asia Pacific.

Imperial Oil Limited Ownership and Value of Equity (a) (b) (c) (d)
	IMO Common     Shares (% of class)	IMO Deferred     Share Units (DSU)	Total Vested     Equity Holdings     (Common + DSU)	Restricted      Stock Units      (RSU)	Total Holdings*      (Common + DSU      + RSU)
Holdings as at February 7, 2018 (#)	0	0	0	0	0
Total market value as at February 7, 2018 ($)	0	0	0	0	0
Year over year change (#)	0	0	0	0	0

                *No share ownership guidelines apply

Board and Committee Membership	Meeting Attendance 2017	Public Company Directorships in the Past Five Years*
Imperial Oil Limited board Executive resources committee Environment, health and safety committee Nominations and corporate governance committee Contributions committee	6 of 7 (86%) 6 of 7 (86%) 2 of 3 (67%) 6 of 7 (86%) 1 of 2 (50%)	No other public company directorships in the past five years *no public board interlocks

Voting Results of 2017 Annual General Meeting:		Other Positions in the Past Five Years: (position, date office held, and status of employer)
Votes in Favour: 674,075,378    (89.19%)	Votes Withheld: 81,736,847    (10.81%)	- President, Exxon Mobil Refining & Supply Company   (2014 – 2017) (Affiliate) - Director, Refining North America, ExxonMobil Refining & Supply   Company (2013 – 2014) (Affiliate) - Director, Refining Americas, ExxonMobil Refining & Supply   Company (2009 – 2013) (Affiliate)

Sheelagh D. Whittaker London, England Nonemployee director (independent) Age: 70 Director since: April 19, 1996 Skills and experience: Leadership of large organizations, Global experience, Strategy development, Audit committee financial expert, Financial expertise, Government relations, Information technology, Executive compensation Ms. Whittaker spent much of her early business career as director and partner with The Canada Consulting Group, now Boston

Consulting Group. From 1989 she was president and chief executive officer of Canadian Satellite Communications (Cancom). In 1993, Ms. Whittaker joined Electronic Data Systems of Plano, Texas, then one of the world’s foremost providers of information technology services. Initially spending several years as president and chief executive officer of EDS Canada, Ms. Whittaker then undertook other key leadership roles globally, ultimately serving the company as managing director, United Kingdom, Middle East and Africa, until her retirement from EDS in November 2005.

Imperial Oil Limited Ownership and Value of Equity (a) (b) (c) (d)
	IMO Common     Shares (% of class)	IMO Deferred     Share Units (DSU)	Total Vested     Equity Holdings     (Common + DSU)	Restricted      Stock Units      (RSU)	Total Holdings*      (Common + DSU      + RSU)
Holdings as at February 7, 2018 (#)	9,350 (<0.01%)	53,248	62,598	11,200	73,798
Total market value as at February 7, 2018 ($)	331,925	1,890,304	2,222,229	397,600	2,619,829
Year over year change (#)	0	2,344	2,344	600	2,944

                *Meets the necessary share ownership requirements

Board and Committee Membership	Meeting Attendance 2017	Public Company Directorships in the Past Five Years*
Imperial Oil Limited board Audit committee Executive resources committee Environment, health and safety committee Nominations and corporate governance committee (Chair) Contributions committee	7 of 7 (100%) 5 of 5 (100%) 7 of 7 (100%) 3 of 3 (100%) 7 of 7 (100%) 2 of 2 (100%)	- Standard Life Canada (2013 – 2015) - Standard Life plc (2009 – 2013) *no public board interlocks

Voting Results of 2017 Annual General Meeting:		Other Positions in the Past Five Years: (position, date office held, and status of employer)
Votes in Favour: 750,579,322    (99.31%)	Votes Withheld: 5,232,903    (0.69%)	No other position held in the last five years

96

Footnotes to Director nominee tables on pages 93 through 96:

(a) The information includes the beneficial ownership of common shares of Imperial Oil Limited, which information not being within the knowledge of the company has been provided by the nominees individually.

(b) The company’s plan for restricted stock units for nonemployee directors is described on page 114. The company’s plan for deferred share units for nonemployee directors is described on page 113. The company’s plan for restricted stock units for selected employees is described on page 134.

(c) The numbers for the company’s restricted stock units represent the total of the outstanding restricted stock units received in 2011 through 2017 and deferred share units received since directors’ appointment.

(d) The value for Imperial Oil Limited common shares, deferred share units and restricted stock units is based on the closing price for Imperial Oil Limited common shares on the Toronto Stock Exchange of $35.50 on February 7, 2018.

Director holdings in Exxon Mobil Corporation (a)

Director	XOM Common Shares (#)	XOM Restricted Stock (#)(b)	Total Common Shares and Restricted Stock (#)	Total Market Value of Common Shares and Restricted Stock ($)(c)
R.M. Kruger	1,418	118,500	119,918	11,575,556
D.S. Sutherland	5,730	-	5,730	553,111
D.G. Wascom	18,080	207,600	225,680	21,784,648

(a) Holdings as at February 7, 2018. The information includes the beneficial ownership of common shares of Exxon Mobil Corporation, which information not being within the knowledge of the company has been provided by the nominees individually. D.W. Cornhill, K.T. Hoeg, J.M. Mintz, S.D. Whittaker and V.L. Young do not own common shares or hold restricted stock of Exxon Mobil Corporation.

(b) The numbers for Exxon Mobil Corporation restricted stock include outstanding restricted stock and restricted stock units granted under its restricted stock plan which is similar to the company’s restricted stock unit plan.

(c) The value for Exxon Mobil Corporation common shares and restricted stock is based on the closing price for Exxon Mobil Corporation common shares on the New York Stock Exchange of $76.94 U.S., which is converted to Canadian dollars at the daily rate of exchange of $1.2546 provided by the Bank of Canada for February  7, 2018.

Majority voting policy    

In order to better align with the Canadian Coalition for Good Governance’s policy, “Governance Differences of Equity Controlled Corporations” – October, 2011, in 2012, the board of directors of the company passed a resolution adopting a majority voting policy. As of the date of this circular, Exxon Mobil Corporation holds 69.6 percent of the company’s shares. If Exxon Mobil Corporation’s shareholdings were ever to fall below 50 percent, the company’s policy provides that for any non-contested election of directors, any director nominee who receives a greater number of votes “withheld” from his or her election than votes “for” in such election shall tender his or her resignation. Within 90 days after certification of the election results, the board of directors will decide, through a process managed by the nominations and corporate governance committee and excluding the nominee in question, whether to accept the resignation. Absent a compelling reason for the director to remain on the board, the board shall accept the resignation. The board will promptly disclose its decision and, if applicable, the reasons for rejecting the tendered resignation.

97

Corporate governance disclosure

Corporate governance at a glance
Controlled company	Yes
Size of current board	8
Current number of independent directors	6
Women on board	2
Average attendance of director at board and committee meetings	94%
Independent chair of the executive sessions	Yes
In camera sessions of independent directors at every board meeting	Yes
Independent status of audit committee	100%
Audit committee members financially literate	All
Independent status of executive resources committee	85%
Independent status of nominations and corporate governance committee	85%
Majority of independent directors on all committees	Yes
Individual director elections	Yes
Average tenure of director nominees	9 years
Average age of director nominees	65 years
Mandatory retirement age	72 years
Majority voting policy	Yes
Separate board chair and CEO	No
Number of board interlocks	None
No director serves on more than two boards of another reporting issuer	Yes
Share ownership requirements for independent directors	Yes
Share ownership requirements for chairman and chief executive officer	Yes
Board orientation and education program	Yes
Code of business conduct and ethics	Yes
Board and committee charters	Yes
Position descriptions for the chairman and chief executive officer and the chair of each committee	Yes
Skills matrix for directors	Yes
Annual board evaluation process	Yes
Annual advisory vote on executive compensation	No
Dual-class shares	No
Change of control agreements	No

98

Statement of corporate governance practice

This section provides information pertaining to our board, the committees of the board, ethics, diversity and shareholder engagement. The company is committed to high corporate governance standards and best practices. The company’s corporate governance policies and practices comply with and in most cases exceed the requirements of National Instrument 52-110 Audit Committees (NI 52-110), National Policy 58-201 Corporate Governance Guidelines (NP 58-201) and National Instrument 58-101 Disclosure of Corporate Governance Practices (NI 58-101). The company’s common shares trade on the Toronto Stock Exchange and the NYSE American LLC and our corporate governance practices reflect the corporate governance standards of these exchanges.

The company continually reviews its governance practices and monitors regulatory changes.

Composition of our board nominees    

Tenure of our board nominees

The board charter provides that incumbent directors will not be renominated if they have attained the age of 72, except under exceptional circumstances and at the request of the chairman. The company does not have term limits for independent directors because it values the comprehensive knowledge of the company that long serving directors possess and independent directors are expected to remain qualified to serve for a minimum of five years. The following chart shows the current years of service of the nominees for the board of directors and the year they would normally be expected to retire from the board.

Name of director nominee	Years of service on the board	Year of expected retirement from the board for independent directors
D.W. Cornhill	2 months	2025
K.T. Hoeg	10 years	2022
R.M. Kruger	5 years	-
J.M. Mintz	13 years	2023
D.S. Sutherland	8 years	2022
D.G. Wascom	4 years	-
S.D. Whittaker	22 years	2019
Years of combined experience on the board: 62 years Average tenure on the board: 9 years Average age of directors: 65 years

99

Skills and experience of our board members

Our directors provide a wide range of skills, diversity and experience.

The current directors collectively have experience and expertise required to ensure effective stewardship and governance of the company. The key areas of experience and skills for each of the nominees for election as directors can also be found in each of the nominees tables on pages 93 through 97 of this circular.

The table below sets out the diverse skill set required of the board and identifies the particular experience, qualifications, attributes, and skills of each director that led the board to conclude that such person should serve as a director of the company.

	D.W. Cornhill (a)	K.T. Hoeg	R.M. Kruger	J.M. Mintz	D.S. Sutherland	D.G. Wascom	S.D. Whittaker	Y.L. Young (b)
Leadership of large organizations	∎	∎	∎		∎	∎	∎	∎
Operations / Technical	∎		∎		∎	∎
Project management	∎	∎	∎			∎
Global experience		∎	∎	∎	∎	∎	∎
Strategy development	∎	∎	∎	∎	∎	∎	∎	∎
Audit committee financial expert	∎	∎			∎		∎	∎
Financial expertise	∎	∎	∎	∎	∎	∎	∎	∎
Government relations			∎	∎	∎		∎	∎
Academic / Research				∎
Information technology							∎
Executive compensation	∎	∎	∎	∎	∎	∎	∎	∎

(a) D.W. Cornhill was appointed to the board and its committees on November 29, 2017.

(b) V.L. Young is currently a director, but is not standing for re-election at the annual meeting of shareholders.

100

Independence of our board members

Five out of seven of the director nominees are independent.

The board is currently composed of eight directors, seven of whom will be standing for re-election at the annual meeting of shareholders on April 27, 2018. V.L. Young will not stand for re-election as he will reach the company’s mandatory retirement age for directors in 2018. The majority of the board (six out of eight) and nominees (five out of seven) are independent. The independent directors are not employees of the company.

The board determines independence on the basis of the standards specified by National Instrument

52-110 Audit Committees (NI 52-110), the U.S. Securities and Exchange Commission rules and the listing standards of the NYSE American LLC. The board has reviewed relevant relationships between the company and each nonemployee director and director nominee to determine compliance with these standards.

Based on the directors’ responses to an annual questionnaire, the board determined that none of the independent directors has any interest, business or other relationship that could or could reasonably be perceived to constitute a material relationship with the company. R.M. Kruger is a director and chairman, president and chief executive officer of the company and not considered to be independent. The board believes that Mr. Kruger’s extensive knowledge of the business of the company and Exxon Mobil Corporation is beneficial to the other directors and his participation enhances the effectiveness of the board.

D.G. Wascom is also a non-independent director as he is an officer of Exxon Mobil Corporation. The company believes that Mr. Wascom, although deemed non-independent under the relevant standards by virtue of his employment, can be viewed as independent of the company’s management and that his ability to reflect the perspective of the company’s shareholders enhances the effectiveness of the board.

Name of director	Management	Independent	Not independent	Reason for non-independent status
D.W. Cornhill (a)		∎
K.T. Hoeg		∎
R.M. Kruger	∎		∎	R.M. Kruger is a director and chairman, president and chief executive officer of Imperial Oil Limited.
J.M. Mintz		∎
D.S. Sutherland		∎
D.G. Wascom			∎	D.G. Wascom is an officer of Exxon Mobil Corporation.
S.D. Whittaker		∎
V.L. Young (b)		∎

(a) D.W. Cornhill was appointed to the board and its committees on November 29, 2017.

(b) V.L. Young is currently a director, but is not standing for re-election at the annual meeting of shareholders.

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Committee membership of our board

Each committee is chaired by a different independent director and

all of the independent directors are members of each committee.

The chart below shows the company’s committee memberships and the chair of each committee.

Director	Nominations and corporate governance committee	Audit committee (b)	Environment health and safety committee	Executive resources committee	Contributions committee
D.W. Cornhill (c)	∎	∎	∎	∎	∎
K.T. Hoeg (c)	∎	∎	∎	∎ Chair	∎
R.M. Kruger (a)	-	-	-	-	∎
J.M. Mintz	∎	∎	∎ Chair	∎	∎
D.S. Sutherland (c)	∎	∎	∎	∎	∎ Chair
D.G. Wascom (a)	∎	-	∎	∎	∎
S.D. Whittaker (c)	∎ Chair	∎	∎	∎	∎
V.L. Young (c)	∎	∎ Chair	∎	∎	∎

(a) Not independent directors.

(b) All members of the audit committee are independent and financially literate within the meaning of National Instrument 52-110 Audit Committees and the listing standards of the NYSE American LLC. V.L. Young is currently the chair of the audit committee, but is not standing for re-election at the annual meeting of shareholders.

(c) Audit committee financial experts under U.S. regulatory requirements.

Number of meetings

The chart below shows the number of board, committee and annual meetings held in 2017.

Board or committee	Number of meetings held in 2017
Imperial Oil Limited board	7
Audit committee	5
Executive resources committee	7
Environment, health and safety committee	3
Nominations and corporate governance committee	7
Contributions committee	2
Annual meeting of shareholders	1

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Attendance of our board members in 2017

94% board and committee meeting attendance from all members.

The following chart provides a summary of the attendance record of each of the directors in 2017. The attendance record of each director nominee is also set out in his or her biographical information on pages 93 through 96. The attendance chart also provides an overall view of the attendance per committee. Senior management directors and other members of management periodically attend committee meetings at the request of the committee chair.

Director	Board	Audit committee	Executive resources committee	Environment health and safety committee	Nominations and corporate governance committee	Contributions committee	Annual meeting	Total	Percentage by director
D.W. Cornhill (a)	1 of 1	n/a	1 of 1	1 of 1	1 of 1	1 of 1	n/a	5 of 5	100%
K.T. Hoeg	7 of 7	5 of 5	7 of 7 (chair)	3 of 3	7 of 7	2 of 2	1 of 1	32 of 32	100%
R.M. Kruger	7 of 7 (chair)	-	-	-	-	2 of 2	1 of 1	10 of 10	100%
J.M. Mintz	7 of 7	5 of 5	7 of 7	3 of 3 (chair)	7 of 7	2 of 2	1 of 1	32 of 32	100%
D.S. Sutherland	6 of 7	4 of 5	6 of 7	2 of 3	6 of 7	2 of 2 (chair)	1 of 1	27 of 32	84%
D.G. Wascom	6 of 7	-	6 of 7	2 of 3	6 of 7	1 of 2	1 of 1	22 of 27	81%
S.D. Whittaker	7 of 7	5 of 5	7 of 7	3 of 3	7 of 7 (chair)	2 of 2	1 of 1	32 of 32	100%
V.L. Young	6 of 7	5 of 5 (chair)	6 of 7	3 of 3	6 of 7	2 of 2	1 of 1	29 of 32	90%
Percentage by committee	94%	96%	93%	89%	93%	93%	100%	189/202	Overall attendance 94%

(a) D.W. Cornhill was appointed to the board and its committees on November 29, 2017.

Other public company directorships of our board members

No director serves on more than two boards of another reporting issuer.

The following table shows which directors serve on the boards of other reporting issuers and the committee memberships in those companies.

Name of director	Other reporting issuers of which director is also a director	Type of company	Stock symbol: Exchange	Committee appointments
D.W. Cornhill	AltaGas Ltd.	Diversified energy company	ALA:TSX	Chairman of the board
K.T. Hoeg	New Flyer Industries Inc.	Manufacturer of heavy duty transit buses	NFI:TSX	Human resources, compensation, and corporate governance committee and audit committee
R.M. Kruger	-	-	-	-
J.M. Mintz	Morneau Shepell Inc.	Human resources consulting	MSI:TSX	Audit committee (chair) and governance committee
D.S. Sutherland	GATX Corporation	Commercial rail vehicles and aircraft engines – shipping	GMT:NYSE	Compensation committee (chair) and governance committee
	United States Steel Corporation	Iron and steel	X:NYSE	Chairman of the board
D.G. Wascom	-	-	-	-
S.D. Whittaker	-	-	-	-
V.L. Young	-	-	-	-

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Interlocking directorships of our board members

As of the date of this proxy circular, there are no interlocking public company directorships among the directors listed in this circular.

Director qualification and selection process

The nominations and corporate governance committee is responsible for identifying and recommending new candidates for board nomination. The committee identifies candidates from a number of sources, including executive search firms and referrals from existing directors. The process for selection is described in paragraph 10 (a) of the Board of Directors Charter attached as Appendix A. The committee will consider potential future candidates as required. In considering the qualifications of potential nominees for election as directors, the nominations and corporate governance committee considers the work experience and other areas of expertise of the potential nominees with the objective of providing for diversity among the nonemployee directors. The following key criteria are considered to be relevant to the work of the board of directors and its committees:

Work experience

● Experience in leadership of businesses or other large organizations (Leadership of large organizations)

● Operations/technical experience (Operations/technical)

● Project management experience (Project management)

● Experience in working in a global work environment (Global experience)

● Experience in development of business strategy (Strategy development)

Other expertise

● Audit committee financial expert (also see the financial expert section in the audit committee table starting on page 107)

● Expertise in financial matters (Financial expertise)

● Expertise in managing relations with government (Government relations)

● Experience in academia or in research (Academic/research)

● Expertise in information technology (Information technology)

● Expertise in executive compensation policies and practices (Executive compensation)

The nominations and corporate governance committee may consider the following additional factors in assessing potential nominees:

● possessing expertise in any of the following areas: law, science, marketing, administration, social/political environment or community and civic affairs;

● individual competencies in business and other areas of endeavour in contributing to the collective experience of the directors; and

● providing diversity of age, gender and regional association.

The nominations and corporate governance committee assesses the work experience and other expertise each existing director possesses and whether the candidate is able to fill any gaps in such experience, expertise and diversity of age, gender and regional association. Consideration is also given to whether candidates possess the ability to contribute to the broad range of issues with which the board and its committees must deal, are able to devote the necessary amount of time to prepare for and attend board and committee meetings and are free of any potential legal impediment or conflict of interest. Candidates are expected to remain qualified to serve for a minimum of five years and independent directors are expected to achieve ownership of no less than 15,000 common shares, deferred share units and restricted share units within five years of becoming an independent director.

When the committee is recommending candidates for re-nomination, it assesses such candidates against the criteria for re-nomination as set out in paragraph 10 (b) of the Board of Directors Charter found in Appendix A of this circular. Candidates for re-nomination are expected not to change their principal position, the thrust of their involvement or their regional association in a way that would significantly detract from their value as a director of the corporation. They are also expected to continue to be compatible with the criteria that led to their selection as nominees.

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Director orientation, education and development

The company regularly provides in-depth presentations to the directors on relevant

and emerging issues and encourages continuing education opportunities.

The corporate secretary organizes an orientation program for all new directors. In a series of meetings over several days, new directors are briefed by staff and functional managers on all significant areas of the company’s operations, industry specific topics, risk oversight and regulatory issues. New directors are also briefed on significant company policies, organizational structure, security, information technology management and on critical planning and reserves processes. They also receive key governance and disclosure documents and a comprehensive board manual which contains a record of historical information about the company, by-laws, company policies, the charters of the board and its committees, other relevant company business information, information on directors’ duties and additional board related activities and calendars.

Continuing education is provided to board and committee members through regular presentations by management which focus on providing more in-depth information about key aspects of the business. Each year the board has an extended meeting that focuses on a particular area of the company’s operations and includes a visit to one or more of the company’s operating sites or a site of relevance to the company’s operations. In September 2017, the board visited the Calgary research centre for a tour of the facility and presentations specific to the work being performed at the centre. The board and the committees also received a number of presentations in 2017 that focused on performance, strategy and opportunities for the business. Some of these continuing education events included an asset impairment review, an investor relations review, a tax review, a review of environmental performance, a review of upstream and downstream performance and improvement plans, a competition and anti-corruption review, and an information technology and cybersecurity update.

Members of Exxon Mobil Corporation’s management also provide reviews of various aspects of ExxonMobil’s global business. In 2017, the directors received presentations on ExxonMobil’s information technology and cybersecurity processes, an overview of ExxonMobil’s production program, an overview of ExxonMobil’s global business, and a presentation on ExxonMobil’s audit program and processes.

Members of the board also receive an extensive package of materials prior to each board meeting that provides a comprehensive summary on each agenda item to be discussed. Similarly, the committee members also receive a comprehensive summary on each agenda item to be discussed by that particular committee. Informational communications and other written publications or reports of interest to the directors are also forwarded routinely.

The board members are canvassed as to whether there are any additional topics relevant to the board or to a specific committee that they would like to see addressed and management schedules presentations covering these areas. In addition, at every meeting the board receives an extensive update from the chairman, president and chief executive officer on business environment trends, relevant geopolitical activities, federal government priorities, key provincial issues and competitor activities, as appropriate.    

Directors are encouraged to participate in continuing education programs and events to ensure their skills and knowledge remain current.

Board performance assessment

The board and its committees, as well as the performance of the directors, are assessed on an annual basis. In 2017, the directors engaged in a performance assessment with the chairman, president and chief executive officer during which the directors evaluated the board and each committee’s effectiveness in various areas. The chairman, president and chief executive officer also meets regularly with directors individually to discuss any outstanding issues. The nominations and corporate governance committee discussed a summary of these assessment outcomes at its January 2018 meeting.

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Board and committee structure

Leadership structure

The company has chosen to combine the positions of chairman, president and chief executive officer. The board believes the interests of all shareholders are best served at the present time through a leadership model with a combined chairman and chief executive officer position. The company does not have a lead director. While the chairman of the board is not an independent director, S.D. Whittaker, chair of the executive sessions, provides leadership for the independent directors. The duties of the chair of the executive sessions include presiding at executive sessions of the board, and reviewing and modifying, if necessary, the agenda of the meetings of the board in advance to ensure that the board may successfully carry out its duties. The position description of the chair of the executive sessions is described in paragraph 9 (c) of the Board of Directors Charter attached as Appendix A.

Independent director executive sessions

The executive sessions of the board are in camera meetings of the independent directors and are held in conjunction with every board meeting. These meetings are held in the absence of management. The independent directors held seven executive sessions in 2017. The purposes of the executive sessions of the board include the following:

● raising substantive issues that are more appropriately discussed in the absence of management;

● discussing the need to communicate to the chairman of the board any matter of concern raised by any committee or director;

● addressing issues raised but not resolved at meetings of the board and assessing any follow-up needs with the chairman of the board;

● discussing the quality, quantity, and timeliness of the flow of information from management that is necessary for the independent directors to effectively and responsibly perform their duties, and advising the chairman of the board of any changes required; and

● seeking feedback about board processes.

In camera sessions of the board committees

Various committees also regularly hold in camera sessions without management present. The audit committee regularly holds private sessions of the committee members as well as private meetings of the committee with each of the external auditor, the internal auditor and senior management as part of every regularly scheduled committee meeting.

Committee structure

The board has created five committees to help carry out its duties. Each committee is chaired by a different independent director and all of the independent directors are members of each committee. D.G. Wascom is also a member of each committee, with the exception of the audit committee, which is composed entirely of independent directors. R.M. Kruger is also a member of the contributions committee. Board committees work on key issues in greater detail than would be possible at full board meetings, allowing directors to more effectively discharge their stewardship responsibilities. The independent chairs of the five committees are able to take a leadership role in executing the board’s responsibility with respect to a specific area of the company’s operations falling within the responsibility of the committee he or she chairs. The board and each committee have a written charter that can be found in Appendix A of this circular. The charters are reviewed and approved by the board annually, and were revised in 2017. The charters set out the purpose, structure, position description for the chair, and the responsibility and authority of that committee.

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The following table provides additional information about the board and its five committees:

Board of Directors

The board of directors is responsible for the stewardship of the corporation. The stewardship process is carried out by the board directly or through one or more of the committees of the board. The formal mandate of the board can be found within the Board of Directors Charter in Appendix A of this circular.

Directors	●   R.M. Kruger (chair) ●   D.W. Cornhill ●   K.T. Hoeg ●   J.M. Mintz	●   D.S. Sutherland ●   D.G. Wascom ●   S.D. Whittaker ●   V.L. Young
Number of meetings	Seven meetings of the board of directors were held in 2017. There were no special meetings held this year. The independent directors hold executive sessions of the board in conjunction with every board meeting. These meetings are held in the absence of management. The independent directors held seven executive sessions in 2017.
Board highlights in 2017	●   Provided oversight in support of safety and environmental performance. ●   Regularly discussed industry activity and provided operational updates. ●   Regularly discussed risk management and business controls environment. ●   Reviewed cyber security and information technology strategies. ●   Extensively discussed business trends and market factors relevant to the company. ●   Regularly assessed performance of the Kearl oil sands operations and approved funding for reliability improvements. ●   Discussed priorities and plans associated with market access strategy. ●   Reinstituted significant share buyback program to return capital to shareholders. ●   Conducted a site visit of the Calgary research centre. ●   Appointed new independent director. ●   Discussed comprehensive company strategy for all business lines.
Role in risk oversight	The chairman, president and chief executive officer is charged with identifying, for review with the board of directors, the principal risks of the corporation’s business, and ensuring appropriate systems are in place to manage such risks. The company’s financial, execution and operational risk rests with management and the company is governed by well-established risk management systems. The board of directors carefully considers these risks in evaluating the company’s strategic plans and specific proposals for capital expenditures and budget additions.
Disclosure policy	The company is committed to full, true and plain public disclosure of all material information in a timely manner, in order to keep security holders and the investing public informed about the company’s operations. The full details of the corporate disclosure policy can be found on the company’s internet site at www.imperialoil.ca.
Independence	The current board of directors is composed of eight directors, the majority of whom (six out of eight) are independent. The six independent directors are not employees of the company.

Audit Committee

The role of the audit committee includes selecting and overseeing the independent auditor, reviewing the scope and results of the audit conducted by the independent auditor, assisting the board in overseeing the integrity of the company’s financial statements, the company’s compliance with legal and regulatory requirements and the quality and effectiveness of internal controls, approving any changes in accounting principles and practices, and reviewing the results of monitoring activity under the company’s business ethics compliance program. The formal mandate of the audit committee can be found within the Audit Committee Charter in Appendix A of this circular.

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Committee members	●   V.L. Young (chair) ●   S.D. Whittaker (vice-chair) ●   D.W. Cornhill	●   K.T. Hoeg ●   J.M. Mintz ●   D.S. Sutherland
Number of meetings	Five meetings of the audit committee were held in 2017. The committee members met in camera without management present at every regularly scheduled meeting and also separately with the internal auditor and the external auditor at all regularly scheduled meetings. A pre-audit meeting also occurs prior to every regularly scheduled audit committee meeting with the chair of the audit committee and the chief financial officer and both the internal and external auditors.
Committee highlights in 2017	●   Reviewed the interim and full year financial and operating results. ●   Reviewed and assessed the results of the internal auditor’s audit program. ●   Reviewed and assessed the external auditor plan, performance and fees. ●   Reviewed the committee’s mandate and completed the committee self-assessment. ●   Reviewed evolving regulations and reporting obligations. ●   Reviewed asset impairment. ●   Reviewed finance plan. ●   Reviewed overall tax process management and tax litigation update. ●   Performed external auditor performance evaluation.
Financial expertise	The company’s board of directors has determined that D.W. Cornhill, K.T. Hoeg, D.S. Sutherland, S.D. Whittaker and V.L. Young meet the definition of “audit committee financial expert”. The U.S. Securities and Exchange Commission has indicated that the designation of an audit committee financial expert does not make that person an expert for any purpose, or impose any duties, obligations or liability on that person that are greater than those imposed on members of the audit committee and board of directors in the absence of such designation or identification. All members of the audit committee are financially literate within the meaning of Multilateral Instrument 52-110 Audit Committees and the listing standards of the NYSE American LLC.
Role in risk oversight	The audit committee also has an important role in risk oversight. It regularly receives updates from management on the company’s risk management systems. The audit committee reviewed the scope of PricewaterhouseCoopers’ audit in light of risks associated with the energy industry, the regulatory environment and company-specific financial audit risks. The committee reviews financial statements and internal and external audit results. It oversees risks associated with financial and accounting matters, including compliance with legal and regulatory requirements, and the company’s financial reporting and internal controls systems.
Independence	The audit committee is composed entirely of independent directors. All members met board approved independence standards, as that term is defined in Multilateral Instrument 52-110 Audit Committees, the U.S. Securities and Exchange Commission rules and the listing standards of the NYSE American LLC.
Executive Resources Committee The executive resources committee is responsible for corporate policy on compensation and for specific decisions on the compensation of the chief executive officer and key senior executives and officers reporting directly to that position. In addition to compensation matters, the committee is also responsible for succession plans and appointments to senior executive and officer positions, including the chief executive officer. The formal mandate of the executive resources committee can be found within the Executive Resources Committee Charter in Appendix A of this circular.
Committee members	●   K.T. Hoeg (chair) ●   V.L. Young (vice-chair) ●   D.W. Cornhill ●   J.M. Mintz	●   D.S. Sutherland ●   D.G. Wascom ●   S.D. Whittaker
	None of the members of the executive resources committee currently serves as a chief executive officer of another company.
Number of meetings	Seven meetings of the executive resources committee were held in 2017.

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Committee highlights in 2017	●   Reviewed executive compensation program and principles. ●   Reviewed current and planned activities to address recent and upcoming legislative changes impacting the workforce. ●   Continued focus on succession planning for senior management positions. ●   Appointment of general auditor. ●   Appointment of vice president and general counsel. ●   Appointment of senior vice president, commercial and corporate development. ●   Appointment of senior vice president, upstream. ●   Appointment of three officer positions.
Committee members relevant skills and experience	D.W. Cornhill, K.T. Hoeg, D.S. Sutherland, D.G. Wascom, S.D. Whittaker and V.L. Young had extensive and lengthy experience in managing and implementing their respective companies’ compensation policies and practices in their past role as chief executive officers or members of senior management. Mr. Cornhill, Ms. Hoeg, Dr. Mintz, Mr. Sutherland and Ms. Whittaker sit or have sat on compensation committees of one or more public companies. Accordingly, committee members are able to use this experience and knowledge derived from their roles with other companies in judging the suitability of the company’s compensation policies and practices.
Role in risk oversight	The executive resources committee oversees the compensation programs and practices that are designed to encourage appropriate risk assessment and risk management.
Independence	The members of the executive resources committee are independent, with the exception of D.G. Wascom, who is not considered to be independent under the rules of the U.S. Securities and Exchange Commission, Canadian securities rules and the rules of the NYSE American LLC due to his employment with Exxon Mobil Corporation. However, the Canadian Coalition for Good Governance’s policy, “Governance Differences of Equity Controlled Corporations” – October, 2011, would view Mr. Wascom as a related director and independent of management and who may participate as a member of the company’s executive resources committee. Mr. Wascom’s participation helps to ensure an objective process for determining compensation of the company’s officers and directors and assists the deliberations of this committee by bringing the views and perspectives of the majority shareholder.
Environment, Health and Safety Committee The role of the environment, health and safety committee is to review and monitor the company’s policies and practices in matters of the environment, health and safety and to monitor the company’s compliance with legislative, regulatory and corporate standards in these areas. The committee monitors trends and reviews current and emerging public policy. The formal mandate of the environment, health and safety committee can be found within the Environment, Health and Safety Committee Charter in Appendix A of this circular.
Committee members	●   J.M. Mintz (chair) ●   D.S. Sutherland (vice-chair) ●   D.W. Cornhill ●   K.T. Hoeg	●   D.G. Wascom ●   S.D. Whittaker ●   V.L. Young
Number of meetings	Three meetings of the environment, health and safety committee were held in 2017.
Committee highlights in 2017	●   Personnel and process safety review. ●   Emissions and environmental incident review. ●   Operations integrity management system review. ●   Key issue reviews on climate change, biodiversity, NAFTA, market access and Indigenous relations.
Role in risk oversight	The environment, health and safety committee reviews and monitors the company’s policies and practices in matters of environment, health and safety, which policies and practices are intended to mitigate and manage risk in these areas. The committee receives regular reports from management on these matters.
Independence	The members of the environment, health and safety committee are independent, with the exception of D.G. Wascom.

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Nominations and Corporate Governance Committee The role of the nominations and corporate governance committee is to oversee issues of corporate governance as they apply to the company, including the overall performance of the board, review potential nominees for directorship and review the charters of the board and any of its committees. The formal mandate of the nominations and corporate governance committee can be found within the Nominations and Corporate Governance Committee Charter in Appendix A of this circular.
Committee members	●   S.D. Whittaker (chair) ●   J.M. Mintz (vice-chair) ●   D.W. Cornhill ●   K.T. Hoeg	●   D.S. Sutherland ●   D.G. Wascom ●   V.L. Young
Number of meetings	Seven meetings of the nominations and corporate governance committee were held in 2017.
Committee highlights in 2017	●   Board succession planning. ●   Board and committee charter revisions. ●   Approval of the statement of corporate governance practices. ●   Completion of the board and committee self-assessment. ●   Review of director compensation principles.
Role in risk oversight	The nominations and corporate governance committee oversees risk by implementing an effective program for corporate governance, including board composition and succession planning.
Independence	The members of the nominations and corporate governance committee are independent, with the exception of D.G. Wascom, who is not considered to be independent under the rules of the U.S. Securities and Exchange Commission, Canadian securities rules and the rules of the NYSE American LLC due to his employment with Exxon Mobil Corporation. However, the Canadian Coalition for Good Governance’s policy, “Governance Differences of Equity Controlled Corporations” – October, 2011, would view Mr. Wascom as a related director and independent of management and who may participate as a member of the company’s nominations and corporate governance committee. Mr. Wascom’s participation helps to ensure an objective nominations process and assists the deliberations of this committee by bringing the views and perspectives of the majority shareholder.
Contributions Committee The role of the contributions committee is to oversee all of the company’s community investment activities, including charitable donations. The formal mandate of the contributions committee can be found within the Contributions Committee Charter in Appendix A of this circular.
Committee members	●   D.S. Sutherland (chair) ●   K.T. Hoeg (vice-chair) ●   D.W. Cornhill ●   R.M. Kruger	●   J.M. Mintz ●   D.G. Wascom ●   S.D. Whittaker ●   V.L. Young
Number of meetings	Two meetings of the contributions committee were held in 2017.
Committee highlights in 2017	●   Reviewed London Benchmarking Group (LBG) assessment of Imperial’s overall value to the community at $21.2 million, which was invested and leveraged with lower than industry average program management costs. ●   Celebrated Canada’s sesquicentennial through the donation of 43 iconic Canadian artworks to 15 galleries at an estimated value of over $6M. ●   Realigned community investment focus areas to reflect current business needs in the areas of Innovation, Indigenous capacity building and our operating communities. ●   Supported wildfire recovery efforts in British Columbia with a $50,000 donation to the BC Cattlemen’s Association to provide fire safety training to BC livestock producers. ●   Contributed $3.5 million in 2017 to support Imperial’s United Way partners across Canada.
Independence	The majority of the members of the contributions committee are independent (six out of eight) with the exception of R.M. Kruger and D.G. Wascom.

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Director compensation

Director compensation discussion and analysis

Directors’ compensation is intended to align the long-term

financial interests of the directors with those of the shareholders.

Nonemployee director (‘NED’) compensation levels are reviewed by the nominations and corporate governance committee each year, and resulting recommendations are presented to the full board for approval. The nominations and corporate governance committee decided not to use an external research firm to assemble the comparator data to determine compensation for the July 1, 2017 - June 30, 2018 period. The committee relied instead on an internally-led assessment to provide competitive compensation and market data for directors’ compensation, which assisted the committee in making a compensation recommendation for the company’s directors. The internal assessment maintained the compensation design philosophy, objectives and principles and was consistent with previous methodology used in this analysis.

Employees of the company or Exxon Mobil Corporation receive no extra pay for serving as directors. Nonemployee directors receive compensation consisting of cash and restricted stock units. Since 1999, the nonemployee directors have been able to receive all or part of their cash directors’ fees in the form of deferred share units. The purpose of the deferred share unit plan for nonemployee directors is to provide them with additional motivation to promote sustained improvement in the company’s business performance and shareholder value by allowing them to have all or part of their directors’ fees tied to the future growth in value of the company’s common shares. The deferred share unit plan is described in more detail on page 113.

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Compensation decision making process and considerations

The nominations and corporate governance committee relies on market comparisons with a group of 19 major Canadian companies with national and international scope and complexity. The company draws its nonemployee directors from a wide variety of industrial sectors and, as such, a broad sample is appropriate for this purpose. The nominations and corporate governance committee does not target any specific percentile among comparator companies at which to align compensation for this group.

The 19 comparator companies included in the benchmark sample are as follows:

Energy	Non-Energy
Canadian Natural Resources Limited	Air Canada
Cenovus Energy Inc.	Bank of Nova Scotia
Encana Corporation	BCE Inc.
Enbridge Inc.	Canadian National Railway Company
Husky Energy Inc.	Potash Corporation of Saskatchewan Inc.
Parkland Fuel Corporation	Royal Bank of Canada
Suncor Energy Inc.	Sun Life Financial Inc.
TransCanada Corporation	Teck Resources Limited
	TELUS Corporation
	Thomson Reuters Corporation
	The Toronto-Dominion Bank

Hedging policy

Company policy prohibits all employees, including executives, and directors, from purchasing or selling puts, calls, other options or futures contracts on the company or Exxon Mobil Corporation stock.

For a discussion on the process by which the compensation of the company’s executive officers is determined, see the Compensation discussion and analysis section starting on page 128.

Compensation details

Board and Committee Chair Retainer

The compensation of the nonemployee directors is assessed annually. In July 2016, the board approved a change in the compensation paid to the nonemployee directors to better align the long-term financial interests of the directors with those of the shareholders. Effective July 1, 2016, the nonemployee directors received an annual retainer for board membership of $110,000 per year, and also received a retainer of $10,000 for each committee chaired. The committee membership retainer and the fee for meetings that occur outside of the regularly-scheduled meeting dates were eliminated and the grant of restricted stock units was increased from 2,000 to 2,600.

Effective July 1, 2017, the nominations and corporate governance committee recommended, and the board subsequently approved, no change to the compensation paid to the nonemployee directors.

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The following table summarizes the compensation terms for the nonemployee directors in 2017:

Director compensation
Annual retainer terms:
Cash retainer: (a)
Board membership	$110,000 annually
Committee membership	None
Committee chair	$ 10,000 annually
Unscheduled meeting fee	None
Equity based compensation:
Restricted stock units	2,600 units (which vest on the 5th and 10th anniversary of date of grant)

(a) The nonemployee directors may elect to take all or a portion of the cash retainer in the form of deferred share units.

Equity based compensation

Deferred share units

In 1999, an additional form of long-term incentive compensation (“deferred share units”) was made available to nonemployee directors. Nonemployee directors may elect to receive all or a portion of their cash compensation in the form of deferred share units.

The following table shows the portion of the retainer each nonemployee director elected to receive in cash and deferred share units in 2017.

Director	Election for 2017 director’s fees in cash (%)	Election for 2017 director’s fees in deferred share units (%)
D.W. Cornhill	0	100
K.T. Hoeg	0	100
J.M. Mintz	0	100
D.S. Sutherland	0	100
S.D. Whittaker	50	50
V.L. Young	100	0

The number of deferred share units granted to a nonemployee director is determined at the end of each calendar quarter for that year by dividing (i) the dollar amount of the nonemployee director’s fees for that calendar quarter that the director elected to receive as deferred share units by (ii) the average of the closing price of the company’s shares on the Toronto Stock Exchange for the five consecutive trading days (“average closing price”) immediately prior to the last day of that calendar quarter. Those deferred share units are granted effective the last day of that calendar quarter.

A nonemployee director is granted additional deferred share units in respect of the unexercised deferred share units on the dividend payment dates for the common shares of the company. The number of such additional deferred share units is determined for each cash dividend payment date by (i) dividing the cash dividend payable for a common share of the company by the average closing price immediately prior to the payment date for that dividend and then (ii) multiplying that resultant number by the number of unexercised deferred share units held by the nonemployee directors on the record date for the determination of shareholders entitled to receive payment of such cash dividend.

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A nonemployee director may only exercise these deferred share units by the end of the calendar year following the year of termination of service as a director of the company, including termination of service due to death. No deferred share units granted to a nonemployee director may be exercised unless all of the deferred share units are exercised on the same date.

Restricted stock units

In addition to the cash fees described above, the company pays a significant portion of director compensation in restricted stock units to align director compensation with the long-term interests of shareholders. The restricted stock unit plan is described in more detail beginning on page 134.

An award of 2,000 restricted stock units was awarded annually up until 2015 with 50 percent vesting in cash three years from the date of grant and the remaining 50 percent vesting on the seventh anniversary of the grant date. Directors could elect to receive one common share for each unit or a cash payment for the units to be vested on the seventh anniversary of the date of grant of the restricted stock units.

In 2016, in order to better align the long-term financial interests of the directors with those of the shareholders, the vesting period of the restricted stock units was increased such that 50 percent vests on the fifth anniversary of the date of grant and the remaining 50 percent vests on the tenth anniversary of the date of grant. In addition, the number of units awarded was changed to a grant of 2,600 restricted stock units. Directors may receive one common share or elect to receive a cash payment for all units to be vested. The vesting periods are not accelerated upon separation or retirement from the board, except in the event of death.

In contrast to the forfeiture provisions for restricted stock units held by employees of the company, the restricted stock units awarded to nonemployee directors are not subject to risk of forfeiture at the time a director leaves the company’s board. This provision is designed to reinforce the independence of these board members. However, while on the board and for a 24-month period after leaving the company’s board, restricted stock units may be forfeited if the nonemployee director engages in direct competition with the company or otherwise engages in any activity detrimental to the company. The board agreed that the word “detrimental” shall not include any actions taken by a nonemployee director or former nonemployee director who acted in good faith and in the best interest of the company.

Prior to vesting of the restricted stock units, the nonemployee directors receive amounts equivalent to the cash dividends paid to holders of regular common stock. The amount is determined for each cash dividend payment date by (i) dividing the cash dividend payable for a common share of the company by the average closing price immediately prior to the payment date for that dividend, and then (ii) multiplying that resultant number by the number of unvested restricted stock units held by the nonemployee directors on the record date of the determination of shareholders entitled to receive payment of such cash dividend.

Other reimbursement

Nonemployee directors are also reimbursed for travel and other expenses incurred for attendance at board and committee meetings.

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Components of director compensation

The following table sets out the details of compensation paid to the nonemployee directors in 2017.

Director	Annual retainer for board membership ($) (a)	Annual retainer for committee chair ($) (a)	Restricted stock units (RSU) (#)	Total fees paid in cash ($) (b)	Total value of deferred share units (DSU) ($) (c)	Total value of restricted stock units (RSU) ($) (d)	All other compen- sation ($) (e)	Total compen- sation ($)
D.W. Cornhill	13,750	0	2,600	0	13,750	102,648	0	116,398
K.T. Hoeg	110,000	10,000 (ERC)	2,600	0	120,000	102,648	24,721	247,369
J.M. Mintz	110,000	10,000 (EH&S)	2,600	0	120,000	102,648	22,887	245,535
D.S. Sutherland	110,000	10,000 (CC)	2,600	0	120,000	102,648	20,397	243,045
S.D. Whittaker	110,000	10,000 (N&CG)	2,600	60,000	60,000	102,648	39,102	261,750
V.L. Young	110,000	10,000 (AC)	2,600	120,000	0	102,648	14,709	237,357

(a) D.W. Cornhill was appointed to the board on November 29, 2017, and his “Annual retainer for board membership” has been pro-rated accordingly. Mr. Cornhill was not the chair of any committee.

(b) “Total fees paid in cash” is the portion of the “Annual retainer for board membership” and “Annual retainer for committee chair” which the director elected to receive as cash. This amount is reported as “Fees earned” in the Director compensation table on page 116.

(c) “Total value of deferred share units” is the portion of the “Annual retainer for board membership” and “Annual retainer for committee chair”, which the director elected to receive as deferred share units, as set out in the previous table on page 113. This amount plus the “Total value of restricted stock units” amount is shown as “Share-based awards” in the Director compensation table on page 116.

(d) The values of the restricted stock units shown are the number of units multiplied by the closing price of the company’s shares on the date of grant, which was $39.48.

(e) Amounts under “All other compensation” consist of dividend equivalent payments on unvested restricted stock units, the value of additional deferred share units granted in lieu of dividends on unvested deferred share units and security provided for certain directors. In 2017, K.T. Hoeg received $6,482 in dividend equivalent payments on restricted stock units and additional deferred share units valued at $18,239 in lieu of dividends on deferred share units. J.M. Mintz received $6,482 in dividend equivalent payments on restricted stock units and additional deferred share units valued at $15,670 in lieu of dividends on deferred share units. D.S. Sutherland received $6,332 in dividend equivalent payments on restricted stock units and additional deferred share units valued at $14,065 in lieu of dividends on deferred share units. S.D. Whittaker received $6,482 in dividend equivalent payments on restricted stock units and additional deferred share units valued at $32,620 in lieu of dividends on deferred share units. V.L. Young received $6,482 in dividend equivalent payments on restricted stock units and additional deferred share units valued at $8,227 in lieu of dividends on deferred share units.

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Director compensation table

The following table summarizes the compensation paid, payable, awarded or granted for 2017 to each of the nonemployee directors of the company.

Name (a)	Fees earned ($)(b)	Share- based awards ($) (c)	Option- based awards ($)	Non-equity incentive plan compensation ($)	Pension value ($)	All other compensation ($) (d)	Total     ($)
D.W. Cornhill	0	116,398	-	-	-	0	116,398
K.T. Hoeg	0	222,648	-	-	-	24,721	247,369
J.M. Mintz	0	222,648	-	-	-	22,887	245,535
D.S. Sutherland	0	222,648	-	-	-	20,397	243,045
S.D. Whittaker	60,000	162,648	-	-	-	39,102	261,750
V.L. Young	120,000	102,648	-	-	-	14,709	237,357

(a) As directors employed by the company or Exxon Mobil Corporation in 2017, R.M. Kruger and D.G. Wascom did not receive compensation for acting as directors. D.W. Cornhill was appointed to the board on November 29, 2017, and his annual retainer for board membership has been pro-rated accordingly.

(b) Represents all fees awarded, earned, paid or payable in cash for services as a director, including retainer fees and committee chair fees. The nonemployee directors are able to receive all or part of their directors’ fees in the form of deferred share units.

(c) Represents the value of the restricted stock units (calculated by multiplying the number of units by the closing price of the company’s shares on the date of grant), plus the value of deferred share units (calculated by the portion of the “Annual retainer for board membership” and “Annual retainer for committee chair” which the director elected to receive as deferred share units as noted on page 113).

(d) Amounts under “All other compensation” consist of dividend equivalent payments on unvested restricted stock units, the value of additional deferred share units granted in lieu of dividends on unexercised deferred share units and security provided for certain directors. In 2017, K.T. Hoeg received $6,482 in dividend equivalent payments on restricted stock units and additional deferred share units valued at $18,239 in lieu of dividends on deferred share units. J.M. Mintz received $6,482 in dividend equivalent payments on restricted stock units and additional deferred share units valued at $15,670 in lieu of dividends on deferred share units. D.S. Sutherland received $6,332 in dividend equivalent payments on restricted stock units and additional deferred share units valued at $14,065 in lieu of dividends on deferred share units. S.D. Whittaker received $6,482 in dividend equivalent payments on restricted stock units and additional deferred share units valued at $32,620 in lieu of dividends on deferred share units. V.L. Young received $6,482 in dividend equivalent payments on restricted stock units and additional deferred share units valued at $8,227 in lieu of dividends on deferred share units.

Five-year look back at total compensation paid to nonemployee directors
Year	Amount
2013	$1,245,529
2014	$1,326,687
2015	$1,206,084
2016	$1,342,664
2017	$1,351,454

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Outstanding share-based awards and option-based awards for directors

The following table sets forth all outstanding awards held by nonemployee directors of the company as at December 31, 2017 and does not include common shares owned by the director.

	Option-based awards				Share-based awards
Name (a)	Number of securities underlying unexercised options (#)	Option exercise price ($)	Option expiration date	Value of unexercised in-the-money options ($)	Number of shares or units of shares that have not vested (#) (b)	Market or payout value of share-based awards that   have not vested   ($) (c)
D.W. Cornhill	-	-	-	-	2,954	115,885
K.T. Hoeg	-	-	-	-	42,341	1,661,037
J.M. Mintz	-	-	-	-	38,223	1,499,488
D.S. Sutherland	-	-	-	-	35,649	1,398,510
S.D. Whittaker	-	-	-	-	64,448	2,528,295
V.L. Young	-	-	-	-	24,390	956,820

(a)  As directors employed by the company or Exxon Mobil Corporation in 2017, R.M. Kruger and D.G. Wascom did not receive compensation for acting as directors. D.W. Cornhill was appointed to the board on November 29, 2017.

(b)  Represents restricted stock units and deferred share units held as of December 31, 2017.

(c)  Value is based on the closing price of the company’s shares on December 31, 2017, which was $39.23.

Incentive plan awards for directors – Value vested or earned during the year

The following table sets forth the value of the awards that vested or were earned by each nonemployee director of the company in 2017.

Name (a)	Option-based awards – Value vested during the year ($)	Share-based awards –Value vested during the year ($) (b)	Non-equity incentive plan   compensation – Value earned during the year ($)
D.W. Cornhill	-	-	-
K.T. Hoeg	-	79,290	-
J.M. Mintz	-	79,290	-
D.S. Sutherland	-	79,290	-
S.D. Whittaker	-	79,290	-
V.L. Young	-	79,290	-

(a)  As directors employed by the company or Exxon Mobil Corporation in 2017, R.M. Kruger and D.G. Wascom did not receive compensation for acting as directors. D.W. Cornhill was appointed to the board on November 29, 2017.

(b)  Represents restricted stock units granted in 2010 and 2014, which vested in 2017. Value is based on the average of the weighted average price (as determined by the Toronto Stock Exchange) of common shares of the company on the vesting date and the four consecutive trading days immediately prior to the vesting date.

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Share ownership guidelines of independent directors and chairman, president and chief executive officer

Independent directors are required to hold the equivalent of at least 15,000 shares of Imperial Oil Limited, including common shares, deferred share units and restricted stock units. Independent directors are expected to reach this level within five years from the date of appointment to the board. The chairman, president and chief executive officer has separate share ownership requirements and must, within three years of his appointment, acquire shares of the company, including common shares and restricted stock units, of a value of no less than five times his base salary. The board of directors believes that these share ownership guidelines will result in an alignment of the interests of board members with the interests of all other shareholders. As of the date of this circular, the independent directors currently have holdings in excess of 308,355 shares which is more than three times the required guideline.

	Minimum share ownership requirement	Time to fulfill
Chairman, president and chief executive officer	5 x base salary	Within 3 years of appointment
Independent directors	15,000 shares	Within 5 years of initial appointment

The chart below shows the shareholdings of the independent directors and the chairman, president and chief executive officer of the company as of February 7, 2018, the record date of the management proxy circular.

Director	Director since	Amount acquired since last report (February 9, 2017 to February 7, 2018) (#)	Total holdings (includes common shares, deferred share units and restricted stock units) (#)	Market value of total holdings (a) ($)	Minimum shareholding requirement	Minimum   requirement   met
D.W. Cornhill	November 29, 2017	15,454	15,454	548,617	15,000	Yes
K.T. Hoeg	May 1, 2008	4,098	42,341	1,503,106	15,000	Yes
R.M. Kruger	March 1, 2013	99,000	492,500	17,483,750	Five times base salary	Yes
J.M. Mintz	April 21, 2005	4,033	39,223	1,392,417	15,000	Yes
D.S. Sutherland	April 29, 2010	13,993	90,649	3,218,040	15,000	Yes
S.D. Whittaker	April 19, 1996	2,944	73,798	2,619,829	15,000	Yes
V.L. Young (b)	April 23, 2002	808	46,890	1,664,595	15,000	Yes
Total accumulated holdings (#) and value of directors’ holdings ($)			800,855	28,430,353

(a)  The amount shown in the column “Value of total holdings” is equal to the “Total holdings” multiplied by the closing price of the company’s shares on the proxy circular record date February 7, 2018 ($35.50).

(b)  V.L. Young is currently a director, but is not standing for re-election at the annual meeting of shareholders. Mr. Young’s total holdings consist of 22,500 common shares (<0.01%), 13,190 deferred share units and 11,200 restricted stock units.

For information relating to compensation of the company’s named executive officers, see the Compensation discussion and analysis section starting on page 128.

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Ethical business conduct

The company is committed to high ethical standards through its policies and practices.

The board has adopted a written code of ethics and business conduct (“Code”) which can be found on the company’s website at www.imperialoil.ca.

The Code is applicable to each of the company’s directors, officers and employees, and consists of the ethics policy, the conflicts of interest policy, the corporate assets policy, the directorships policy and the procedures and open door communication. There have been no material change reports filed in the past 12 months pertaining to conduct of a director or executive officer that constitute a departure from the Code. Under the company’s procedures and open door communication, employees are encouraged and expected to refer suspected violations of the law, company policy or internal controls procedures to their supervisors. Suspected violations involving a director or executive officer, as well as any concern regarding questionable accounting or auditing matters are to be referred directly to the internal auditor. The audit committee initially reviews all issues involving directors or executive officers, and then refers all issues to the board of directors. In the alternative, employees may also address concerns to individual nonemployee directors or to nonemployee directors as a group. In addition, the directors of the company must comply with the conflict of interest provisions of the Canada Business Corporations Act, as well as the relevant securities regulatory instruments, in order to ensure that the directors exercise independent judgment in considering transactions and agreements in respect of which such director has a material interest.

Management provides the board of directors with a review of corporate ethics and conflicts of interest on an annual basis. Directors, officers and employees review the company’s standards of business conduct (which includes the Code) on an annual basis, with independent directors and employees in positions where there is a higher risk of exposure to ethical or conflict of interest situations being required to sign a declaration card confirming that they have read and are familiar with the standards of business conduct. In addition, every four years a business practices review is conducted in which managers review the standards of business conduct with employees in their respective work units.

The board, through its audit committee, examines the effectiveness of the company’s internal control processes and management information systems. The board consults with the external auditor, the internal auditor and the management of the company to ensure the integrity of the systems.

There are a number of structures and processes in place to facilitate the functioning of the board independently of management. The board has a majority of independent directors. Each committee is chaired by a different independent director and all of the independent directors are members of each committee. The audit committee is composed entirely of independent directors. Each other committee (except the contributions committee) is composed entirely of the independent directors and D.G. Wascom, who is an officer of Exxon Mobil Corporation, and is, therefore, independent of the company’s management. The agendas of each of the board and its committees are not set by management alone, but by the board as a whole and by each committee. A significant number of agenda items are mandatory and recurring. Board meetings are scheduled at least one full year in advance. Any director may call a meeting of the board or a meeting of a committee of which the director is a member. There is a board-prescribed flow of financial, operating and other corporate information to all directors.

The independent directors conduct executive sessions in the absence of members of management. These meetings are chaired by S.D. Whittaker, the independent director designated by the independent directors to chair and lead these discussions. Seven executive sessions were held in 2017.

The company’s delegation of authority guide provides that certain matters of the company are reviewed by functional contacts within ExxonMobil. The company’s employees are regularly reminded that they are expected to act in the best interests of the company, and are reminded of their obligation to identify any instances where the company’s general interest may not be consistent with ExxonMobil’s priorities. If such situations ever occurred, employees are expected to escalate such issues with successive levels of the company’s management. Final resolution of any such issues is made by the company’s chairman, president and chief executive officer.

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Restrictions on insider trading

Commitment to stringent safeguards with trading restrictions and reporting for company insiders.

Structures and processes are in place to caution, track and monitor reporting insiders, nonemployee directors and key employees with access to sensitive information with respect to personal trading in the company’s shares. Nonemployee directors are required to pre-clear any trades in the company’s shares. Reporting insiders are required to give advance notice to the company of any sale of the company shares and advise the company within five days of any purchase of the company’s shares. Reporting insiders are required, under securities regulations, to publically disclose all transactions in the company’s shares on the System for Electronic Disclosure by Insiders (SEDI).

From time to time, the company advises its directors and officers, and those of Exxon Mobil Corporation, and employees in certain positions not to trade in the company’s shares. Trading bans occur in connection with the directors’ pending consideration of the financial statements of the company, including the unaudited financial statements for each quarter, and in connection with undisclosed pending events that constitute material information about the business affairs of the company.

Diversity

The company has a long history of diversity on the board.

Board diversity

The company has a longstanding commitment to diversity amongst its directors. The board nominee composition charts on page 99 show the diversity of our board nominees with respect to gender, experience and regional association. The company has had a woman on its board continuously since 1977. Today, two of the eight directors are women, representing 25 percent of the board and 33 percent of its independent directors. Two of the seven nominees for director are women, representing 29 percent of the nominees. The company has not adopted a target regarding women on its board. With the objective of fostering a diversity of expertise, viewpoint and competencies, the board charter provides that the nominations and corporate governance committee may consider a number of factors, including gender, in assessing potential nominees. The nominations and corporate governance committee assesses the work experience, other expertise, individual competencies and diversity of age, gender and regional association each existing director possesses and whether each nominee is able to fill any gaps amongst the existing directors. The company does not believe that any one of these dimensions should be considered, without due regard to all of these other factors, in determining the ability of potential directors to contribute to the work of the board of directors.

Executive officer diversity

In considering potential nominees for executive officer appointments, the executive resources committee considers diversity of gender, work experience, other expertise, individual competencies and other dimensions of diversity in addition to the other factors described on page 131. The company has not adopted a target regarding women in executive officer positions. The company does not believe that any one of these dimensions should be considered, without due regard to all of these other factors, in determining the ability of potential nominees to fill executive officers positions. Seven out of the 19 executive officers of the company and its major subsidiary are women, representing 37 percent of the group.

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Shareholder engagement

Shareholder engagement strategy focuses on wide-ranging dialogue between shareholders and management.

The company’s senior management regularly meet with institutional investors and shareholders through industry conferences, roadshows and company hosted investor events. Materials from these conferences and hosted events are available on our website. For shareholders that are not able to attend our annual meeting in person, the company offers a webcast of the event. The webcast is available on the company website along with speeches and presentations from the annual general meeting and the outcome of the voting on each resolution. The company annually solicits questions and comments from registered shareholders on the proxy form. The comments received are reviewed by senior management providing them with an indication of areas of interest to our shareholders and those requiring a response are answered individually.

Largest shareholder

Exxon Mobil Corporation is the majority shareholder of the company, holding 69.6% of the company’s shares.

To the knowledge of the directors and executive officers of the company, the only shareholder who, as of February 7, 2018, owned beneficially, or exercised control or direction over, directly or indirectly, more than 10 percent of the outstanding common shares of the company is Exxon Mobil Corporation, 5959 Las Colinas Boulevard, Irving, Texas 75039-2298, which owns beneficially 578,544,049 common shares, representing approximately 69.6 percent of the outstanding voting shares of the company. As a consequence, the company is a “controlled company” for purposes of the listing standards of the NYSE American LLC and a “majority controlled company” for purposes of the TSX Company Manual.

Transactions with Exxon Mobil Corporation

The company has written procedures that provide that any transactions between the company and Exxon Mobil Corporation and its subsidiaries are subject to review by the chairman, president, and chief executive officer. The board of directors receive an annual review of related party transactions with Exxon Mobil Corporation and its subsidiaries.

On June 27, 2016, the company implemented a 12-month “normal course” share purchase program. Between June 27, 2016 and June 26, 2017, the company purchased the maximum 1,000,000 common shares on the open market and a corresponding 2,287,062 common shares from Exxon Mobil Corporation concurrent with, but outside of the program to maintain its shareholding at approximately 69.6 percent. On June 27, 2017, a further 12-month normal course share purchase program was implemented. Under the current program, the company may purchase up to 25,395,927 common shares (three percent of its outstanding common shares as of June 13, 2017) from the open market, less the amount purchased from Exxon Mobil Corporation concurrent with, but outside of the program to maintain its ownership percentage at approximately 69.6 percent. As of February 7, 2018, under the current program, the company purchased 3,975,250 common shares on the open market and 9,097,192 common shares from Exxon Mobil Corporation.

The amounts of purchases and sales by the company and its subsidiaries for other transactions in 2017 with Exxon Mobil Corporation and affiliates of ExxonMobil were $2,648 million and $4,080 million, respectively. These transactions were conducted on terms as favourable as they would have been 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 services. 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 affiliates of ExxonMobil to provide computer and customer support services to the company and to share common business and operational support services to allow the companies to consolidate duplicate work and systems. The company has a contractual agreement with an affiliate of ExxonMobil in Canada to operate certain Western Canada production properties owned by ExxonMobil. There are no asset ownership changes. The company and that

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affiliate also have a contractual agreement to provide for equal participation in new upstream opportunities. During 2007, the company entered into agreements with ExxonMobil and one of its affiliated companies that provide for the delivery of management, business and technical services to Syncrude Canada Ltd. by ExxonMobil. In 2017, the company entered into an agreement whereby ExxonMobil enters into derivate agreements on the company’s behalf.

As at December 31, 2017, the company had an outstanding loan of $4,447 million under an existing agreement with an affiliated company of ExxonMobil that provides for a long term, variable rate loan from ExxonMobil to the company of up to $7.75 billion (Canadian) at market interest rates. The agreement is effective until July 31, 2020, cancellable if ExxonMobil provides at least 370 days advance written notice. Additionally, the company had outstanding short-term loans of $75 million from an affiliated company of ExxonMobil. This loan is borrowed under an arrangement with ExxonMobil that provides for a non-interest bearing, revolving demand loan from ExxonMobil to the company of up to $75 million and represents ExxonMobil’s share of a working capital facility required to support purchasing, marketing and transportation arrangements for crude oil and diluent products undertaken by the company on behalf of ExxonMobil.

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Company executives and executive compensation

Named executive officers of the company

The named executive officers of the company at year end 2017 were:

Richard M. Kruger, 58 Calgary, Alberta, Canada	Position held at the end of 2017 (date office held): Chairman, president and chief executive officer (2013 - Present) Other positions in the past five years (position, date office held and status of employer): Vice-president, Exxon Mobil Corporation (2008 - 2013) (Affiliate) President, ExxonMobil Production Company (2008 - 2013) (Affiliate)
Beverley A. Babcock, 56 Calgary, Alberta, Canada	Position held at the end of 2017 (date office held): Senior vice-president, finance and administration, and controller (2015 – Present) Other positions in the past five years (position, date office held and status of employer): Vice-president, corporate financial services, Exxon Mobil Corporation (2013 - 2015) (Affiliate) Assistant controller, corporate accounting services, Exxon Mobil Corporation (2011 - 2013) (Affiliate)
John R. Whelan, 52 Calgary, Alberta, Canada	Position held at the end of 2017 (date office held): Senior vice-president, upstream (2017 – Present) Other positions in the past five years (position, date office held and status of employer): Vice-president production, upstream (2016 – 2017) Production manager, mining, upstream (2013 – 2015)
Theresa B. Redburn, 56 Calgary, Alberta, Canada	Position held at the end of 2017 (date office held): Senior vice-president, commercial and corporate development (2017 – Present) Other positions in the past five years (position, date office held and status of employer): Vice-president, upstream commercial (2014 – 2016) Commercial manager, upstream ventures, Exxon Mobil Corporation (2011-2014), (Affiliate)
Peter M. Dinnick, 53 Calgary, Alberta, Canada	Position held at the end of 2017 (date office held): Vice-president and general counsel (2017 – Present) Other positions in the past five years (position, date office held and status of employer): Assistant general counsel, upstream (2012 - 2016)

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Other executive officers of the company

Jonathan R. Wetmore, 45 Calgary, Alberta, Canada	Current position (date office held): Vice-president, Imperial Oil Downstream and Manager, western Canada fuels (2018 - Present) Position held at the end of 2017 (date office held): Manager, supply and manufacturing (June 2017 – December 2017) Other positions in the past five years (position, date office held and status of employer): Refinery manager, Fawley UK, UK Esso Petroleum Company Ltd (2013 - 2017) (Affiliate) Refinery manager, Port Jerome, France, France Esso Raffinage S.A.S. (2012 - 2013) (Affiliate)
Glenn R. Peterson, 57 Calgary, Alberta, Canada	Position held at the end of 2017 (date office held): Treasurer (2017 – Present) Other positions in the past five years (position, date office held and status of employer): Senior business advisor, Treasurer’s (2000 - 2017)
Jim E. Burgess, 43 Calgary, Alberta, Canada	Position held at the end of 2017 (date office held): Assistant controller (2016 – Present) Other positions in the past five years (position, date office held and status of employer): Lead controller and financial accounting process manager, Thailand business support centre, ExxonMobil Limited (2014 – 2016), (Affiliate) Senior financial advisor, Exxon Mobil Corporation (2012 - 2014), (Affiliate)
Barry J. Murphy, 49 Calgary, Alberta, Canada	Current position (date office held): Director, fuel sales (2018 - Present) Position held at the end of 2017 (date office held): Manager, Americas industrial & commercial sales (2016 – 2017) Other positions in the past five years (position, date office held and status of employer): Manager, fuels national account sales (2015 – 2016) Manager, project office, retail support (February 2015 – August 2015) Manager, customer service Americas (2013 – 2015)

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Other executive officers of the company

Denise H. Hughes, 50 Calgary, Alberta, Canada	Position held at the end of 2017 (date office held): Vice-president, human resources (2013 - Present) Other positions in the past five years (position, date office held and status of employer): Manager, executive development, education compensation and benefits (2010 - 2013)
Marvin E. Lamb, 62 Calgary, Alberta, Canada	Position held at the end of 2017 (date office held): Director, corporate tax (2001 – 2018) Other positions in the past five years (position, date office held and status of employer): No other positions held in the last five years
Lara H. Pella, 48 Calgary, Alberta, Canada	Position held at the end of 2017 (date office held): Assistant general counsel, downstream and corporate departments, and Corporate secretary (2013 – Present) Other positions in the past five years (position, date office held and status of employer): Assistant general counsel, corporate departments, and Corporate secretary (2013 – 2016) Assistant general counsel, upstream (2010 - 2013)

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Letter to shareholders from the executive resources committee on executive compensation

Dear fellow shareholders:

The executive resources committee (“committee”) would like to outline for you the role of the committee in ensuring good governance in the management of executive compensation within the company.

Compensation governance

The committee is responsible for corporate policy on compensation and for specific decisions on the compensation of the chief executive officer, key senior executives and officers of the company. In exercising this responsibility, the committee views long-term orientation and the management of risk as integral elements of the compensation policies and practices of the company. These policies and practices are designed to keep management, including named executive officers, focused on the strategic objectives of the company over the long term and to effectively assess and mitigate risk in the execution of these objectives. The committee exercises oversight of a compensation program that supports the company’s objective to attract, develop and retain key talent needed to achieve its strategic objectives.

The compensation discussion and analysis (“CD&A”) section that follows describes the compensation program for the company’s named executive officers and how the program supports the business goals of the company. The company’s compensation program is designed to:

● align the interests of its executives with long-term shareholder interests;

● encourage executives to manage risk and take a long-term view when making investments and managing the assets of the business;

● reinforce the company’s philosophy that the experience, skill and motivation of the company’s executives are significant determinants of future business success; and

● promote career orientation and strong individual performance.

The compensation program design is aligned with the core elements of the majority shareholder’s compensation program, including linkage to short and mid-term aspects of incentive pay, long vesting periods, risk of forfeiture and alignment with the shareholder experience.

We execute our oversight responsibilities in this regard by ensuring the company’s program is built on sound principles of compensation design, including an annual assessment of comparator companies, appropriate risk assessment and risk management practices, sound governance principles, and support of the company’s business model. In exercising our oversight and decision making roles, the committee balances many factors each year in terms of impact on compensation decisions relative to the company’s performance.

2017 business performance results

The committee considers both business results and individual performance in its decisions. In 2017, financial performance continued to be affected by low global crude prices. Notwithstanding the difficult business environment, the committee evaluated the company’s performance relative to its proven business model and strategies to deliver long-term shareholder value. Key 2017 business results include:

● Strong safety, operational integrity and risk management performance

● $490 million net income; $1,056 million excluding upstream non-cash impairment charges

● $2,763 million cash flow from operations, the highest since 2014

● $1,151 million returned to shareholders through share purchases and dividends

● 23rd consecutive year of dividend growth

● Reinstituted share buyback program

● Strong performance across all business lines

● Record annual production at Cold Lake and Kearl

● Best-ever refining results in energy efficiency and reliability

● Highest petroleum product sales in more than 25 years

● Expanded branded fuels business with Husky conversion and introduction of Mobil brand

● Second highest annual chemical earnings

● $190 million reduction in above-field costs; nearly $400 million since 2015

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● Progressed opportunities to add value to high-quality asset portfolio

● Completed Kearl enhancements to improve reliability and reduce unit costs

● Approved investment to increase Kearl production beyond initial scope

● Approved Strathcona refinery cogeneration project to improve energy efficiency

● Continued commitment to industry leadership in technology and innovation

● More than $150 million invested in research

Collectively these factors had an impact on 2017 compensation decisions for the named executive officers. The individual committee members, through their experience in stewarding compensation programs and their participation on board committees, are able to understand the company’s overall objectives, operating risks and financial risks. This understanding of the company’s objectives and range of business risks allows an appropriate calibration of the company’s compensation policies and practices to the business model.

The committee’s assessment is that the company’s compensation program is working as intended and has been effectively integrated over the long term with the company’s business model. The committee has recommended to the board that the CD&A be included in the company’s management proxy circular for the 2018 annual meeting of shareholders. We encourage you to read the comprehensive disclosure in the CD&A that follows. The committee is committed to overseeing all aspects of the executive compensation program in the best interests of the company and all shareholders.

Submitted on behalf of the executive resources committee,

Original signed by

K.T. Hoeg,

Chair, executive resources committee

V.L. Young, Vice-chair

D.W. Cornhill

J.M. Mintz

D.S. Sutherland

S.D. Whittaker

D.G. Wascom

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Compensation discussion and analysis

Table of contents

Overview	129
Canadian business environment	129
Business model	129
Key business strategies	129
Key elements of the compensation program	129
Management of risk	129
Other supporting compensation and staffing practices	131
Hedging policy	131
Business performance and basis for compensation	131
Succession planning	131
Compensation program	132
Career orientation	132
Base salary	133
Annual bonus	133
Restricted stock units	134
Vesting of restricted stock units	135
Amendments to the restricted stock unit plan	136
Forfeiture and claw-back risk	136
Retirement benefits	137
Pension plan benefits	137
Savings plan benefits	138
Compensation considerations	138
Benchmarking	138
Comparator companies	138
Analytical tools – Compensation summary sheets	139
2017 named executive officer compensation assessment	139
2017 chief executive officer compensation assessment	140
Pay awarded to other named executive officers	141
Independent consultant	141
Performance graph	142
Executive compensation tables and narratives	143
Summary compensation table	143
Outstanding share-based awards and option-based awards for named executive officers	145
Incentive plan awards for named executive officers – Value vested during the year	146
Equity compensation plan information	147
Restricted stock units as a percentage of outstanding shares	147
Annual burn rate	148
Status of prior long-term incentive compensation plans	148
Pension plan benefits	148

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Overview

The company takes a long-term view to managing its business.

Providing energy to help meet the demands of both Canada and the rest of North America is a complex business. The company meets this challenge by taking a long-term view to managing its business rather than reacting to short-term business cycles. As such, the compensation program of the company aligns with this long-term business outlook and supports key business strategies as outlined below:

Canadian business environment

● Large, accessible upstream resources

● Mature, competitive downstream markets

● Evolving environmental and fiscal policies impacting global competitiveness

● Market access limitations, uncertainties

Business model

● Long-life, competitively advantaged assets

● Disciplined investment and cost management

● Value-chain integration and synergies

● High-impact technologies and innovation

● Operational excellence and responsible growth

Key business strategies

● Personnel safety and operational excellence

● Grow profitable production and sales volumes

● Disciplined and long-term focus on improving the productivity of the company’s asset mix

● Best-in-class cost structure to support industry-leading returns on capital and superior cash flow

These key business strategies are the primary focus and support long-term growth in shareholder value.

Key elements of the compensation program

The key elements of the company’s compensation program that align with the business model and support key business strategies are:

● long-term career orientation with high individual performance standards (see page 132);

● base salary that rewards individual performance and experience (see page 133);

● annual bonus grants to eligible executives based on company performance, as well as individual performance and experience (see page 133);

● payment of a large portion of executive compensation in the form of restricted stock units with long vesting periods and risk of forfeiture (see pages 134 through 137); and

● retirement benefits (pension and savings plans) that provide for financial security after employment (see pages 137 through 138).

Management of risk

The company operates in an industry environment in which effective risk management is critical. For this reason, the company places a high premium on managing risks, including safety, security, health, environmental, financial, operational and reputational risks. The company’s success in managing risk over time has been achieved through emphasis on execution of a disciplined management framework, which has been in place since the early 1990’s. This framework establishes common expectations for addressing risks inherent in our business and takes priority over other business and financial objectives. The company also has strong controls and compliance programs to manage other types of risk, including fraud, regulatory compliance and litigation risks.

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The company’s long-term orientation and compensation program design encourage the highest performance standards and discourage inappropriate risk taking. The compensation program design features described below work together to ensure executives have a clear and strong financial incentive to:

● protect the safety and security of our employees, the communities and the environment in which we operate;

● manage risk and operate the business with effective business controls;

● create value for company shareholders by increasing shareholder return, net income, return on capital employed; and

● advance the long-term strategic direction of the company.

Compensation components

A substantial portion of total compensation (excluding compensatory pension value) to senior executives is in the form of an annual bonus and restricted stock units. In the judgment of the committee, the mix of short, medium and long-term incentives strikes an appropriate balance in aligning the interests of the senior executives with the business priorities of the company and sustainable growth in long-term shareholder value. Ongoing reviews of our compensation program, including incentives, ensure continued relevance of this mix and applicability for the company.

Annual bonus

● Delayed payout – Payout of 50 percent of the annual bonus is delayed. The timing of the delayed payout is determined by earnings performance. This is a unique feature of the company’s program relative to many comparator companies.

● Recoupment (“claw-back”) and forfeiture – The entire annual bonus is subject to recoupment (“claw-back”) and the delayed portion of the annual bonus is subject to forfeiture in the event of material negative restatement of the company’s reported financial or operating results. This reinforces the importance of the company’s financial controls and compliance programs. Claw-back and forfeiture provisions also apply if an executive resigns or engages in detrimental activity.

● The company’s annual bonus program is described in more detail on pages 133 and 136.

Restricted stock units

● Long holding periods – To further reinforce the importance of risk management and a long-term investment orientation, senior executives are required to hold a substantial portion of their equity incentive award for periods that far exceed the typical holding periods of comparator stock programs. The lengthy holding periods are tailored to the company’s business model.

● Risk of forfeiture – During these long holding periods, the restricted stock units are at risk of forfeiture for resignation or detrimental activity. The long vesting periods on restricted stock units and the risk of forfeiture together support an appropriate risk/reward profile that reinforces the long-term orientation expected of senior executives.

● The company’s restricted stock unit program is described in more detail on pages 134 through 137.

Common programs

● All executives of the company, including the named executive officers, participate in common programs (the same salary, incentive and retirement programs). Similar compensation design features and allocation of awards within the programs discourage inappropriate risk taking. The compensation of executives is differentiated based on individual performance assessment, level of responsibility and individual experience.

● All executives on assignment from an affiliate of the company, including the named executive officers on assignment from Exxon Mobil Corporation, Esso Australia Pty Ltd. and ExxonMobil Canada Ltd., also participate in common programs, which are administered by Exxon Mobil Corporation or such affiliates. The named executive officers on assignment receive the company’s restricted stock units.

● The executive resources committee reviews and approves compensation recommendations for each named executive officer prior to implementation.

Pension

● The company’s defined benefit pension plan and supplemental pension arrangements are highly dependent on executives remaining with the company for a career and performing at the highest levels until retirement. This dimension of total compensation encourages executives to take a long-term view when making business decisions and to focus on achieving sustainable growth for shareholders.

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Other supporting compensation and staffing practices

● A long established program of management development and succession planning is in place to reinforce a career orientation and ensure continuity of leadership.

● The use of perquisites at the company is very limited, and mainly composed of financial planning for senior executives and the selective use of club memberships which are largely tied to building business relationships.

● Tax assistance is provided for employees on expatriate assignment. This assistance consists primarily of a tax equalization component designed to maintain the employees’ overall income tax burden at approximately the same level it would have otherwise been, had they remained in their home country. The expatriate relocation program is broad-based and applies to all executive, management, professional and technical transferred employees.

Hedging policy

Company policy prohibits all employees, including executives, and directors, from purchasing or selling puts, calls, other options or futures contracts on the company or Exxon Mobil Corporation stock.

Business performance and basis for compensation

The assessment of individual performance is conducted through the company’s employee appraisal program. Conducted annually, the appraisal process assesses performance against relevant business performance measures and objectives, including the means by which performance is achieved. These business performance measures may include:

● safety, health and environmental performance;

● risk management;

● total shareholder return;

● net income;

● return on capital employed;

● cash flow from operations and asset sales;

● operating performance of the upstream, downstream and chemical segments; and

● progress on advancing government relations and long-term strategic interests.

The appraisal process includes a comparative assessment of employee performance using a standard approach throughout the organization and at all levels. It is integrated with the compensation program, which results in significant pay differentiation between higher and lower performers. The appraisal process is also integrated with the executive development process. Both have been in place for many years and are the basis for planning individual development and succession for management positions. Decision-making with respect to compensation requires judgment, taking into account business and individual performance and responsibility. Quantitative targets or formulae are not used to assess individual performance or determine the amount of compensation.

Succession planning

The succession planning process fosters the company’s approach to a career orientation and promotion from within. This approach strengthens continuity of leadership and supports ongoing alignment with our long-term business model. This process helps to assess the competence and readiness of individuals for senior executive positions. The executive resources committee is responsible for approving specific succession plans for the position of chairman, president and chief executive officer and key senior executive positions reporting to him, including all officers of the company.

The executive resources committee regularly reviews the company’s succession plans for key senior executive positions. It considers candidates for these positions from within the company and certain candidates from Exxon Mobil Corporation and its affiliates. This is an in-depth review of succession plans, which includes the consideration of various aspects of diversity as well as plans to address gaps, if any, for key executives. For example, the company has a long-standing practice to regularly review with senior management the progress of women, which includes topics such as recruitment, attrition, relocation, training and development. The representation of female company executives is approximately one third. The chairman, president and chief executive officer also discusses the strengths, progress and development needs of key succession candidates each year. This provides the board an opportunity to confirm a pipeline of key and diverse talent exists to enable achievement of long-term strategic objectives. The executive resources committee makes recommendations to the board of directors for selection of all officers of the company, as well as other key senior executive positions reporting to the chairman, president and chief executive officer.

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Compensation program

The company’s compensation program is designed to reward performance,

promote retention, and encourage long-term business decisions.

Career orientation

The company’s objective is to attract, develop and retain over a career the best talent available. It takes a long period of time and significant investment to develop the experienced executive talent necessary to succeed in the company’s business; senior executives must have experience with all phases of the business cycle to be effective leaders. The company’s compensation program elements are designed to encourage a career orientation among employees at all levels of the company. Career orientation among a dedicated and highly skilled workforce, combined with the highest performance standards, contributes to the company’s leadership in the industry and serves the interests of shareholders in the long term. The company service of the named executive officers ranges from approximately 31 to 33 years and reflects this on-going career orientation strategy.

The compensation program emphasizes individual experience and sustained performance; executives holding similar positions may receive substantially different levels of compensation. Consistent with the company’s long-term career orientation, high-performing executives typically earn substantially higher levels of compensation in the later years of their careers. This pay practice reinforces the importance of a long-term focus on making decisions that are key to business success.

The company’s executive compensation program is composed of base salaries, cash bonuses and medium and long-term incentive compensation. The company does not have written employment contracts or any other agreement with its named executive officers providing for payments on change of control or termination of employment. The following chart provides an overview of the combined elements of the compensation program for executives, including the ‘pay at risk’ horizon for the executives.

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Base salary

Salaries provide executives with a base level of income. The level of annual salary is based on the executive’s responsibility, performance assessment and career experience. Individual salary increases vary depending on each executive’s performance assessment and other factors such as time in position and potential for advancement. Salary decisions also directly affect the level of retirement benefits since salary is included in the retirement benefits calculation. Thus, the level of retirement benefits is also performance-based, like other elements of compensation. The salary program in 2017 maintained the company’s desired competitive orientation in the marketplace.

Annual bonus

The bonus program is established annually by the executive resources committee based on earnings, and can be highly variable depending on these results.

In establishing the annual bonus program, the executive resources committee:

● considers input from the chairman, president and chief executive officer on performance of the company and from the company’s internal compensation advisors regarding compensation trends as obtained from external consultants;

● considers its linkage to majority shareholder bonus program given the company’s working interest is included in Exxon Mobil Corporation earnings;

● considers annual net income of the company; and

● uses judgment to manage the overall size of the annual bonus program taking into consideration the cyclical nature and long-term orientation of the business.

The annual bonus program incorporates unique elements to further reinforce retention and recognize performance. Awards under this program are generally delivered as:

= +

● The annual bonus includes the combined value of the cash bonus and delayed earnings bonus unit portion, and is intended to be competitive with the annual bonus awards of other major comparator companies.

● The cash component is intended to be a short-term incentive, while the earnings bonus unit is intended to be a medium-term incentive. Earnings bonus units are generally equal to and granted in tandem with cash bonuses. Individual bonus awards vary depending on each executive’s performance assessment.

● Earnings bonus units are cash awards that are tied to future cumulative earnings per share. Earnings bonus units pay out when a specified level of cumulative earnings per share (or trigger) is achieved or in three years at a reduced level. The trigger is intentionally set at a level that is expected to be achieved within the three-year period and reinforces the company’s principle of sustained improvement in the company’s business performance and aligns the interests of executives with those of long-term shareholders.

● If cumulative earnings per share do not reach the trigger within three years, the payment with respect to the earnings bonus units will be reduced to an amount equal to the number of units times the actual cumulative earnings per share over the three-year period. The amount of the award, once vested, will never exceed the original grant value. The delayed portion for the earnings bonus unit portion of the annual bonus puts part of the annual bonus at risk of forfeiture and thus reinforces the performance basis of the annual bonus grant.

In 2017, an annual bonus was granted to approximately 50 executives to reward their contributions to the business during the past year. The cost of the 2017 annual bonus program was $3.4 million versus $3.0 million in 2016. For earnings bonus units granted in 2017, the maximum settlement value (trigger) or cumulative earnings per share required for payout remained at $3.50.

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Restricted stock units

The vesting periods of the company’s long-term incentive program are greater

than those in use by comparator companies.

The company’s only long-term incentive compensation plan is a restricted stock unit plan, in place since December 2002. Restricted stock units are granted to selected employees of the company, selected employees of a designated affiliate and nonemployee directors of the company. The current plan’s vesting periods for employees are as follows:

●  for the chairman, president and chief executive officer:

●  for all other employees:

Granting compensation in the form of restricted stock units with long vesting periods as described above is aligned with the long-term nature of the company’s business. This stock program design helps keep executives focused on the key premise that decisions made today affect the performance of the organization and company stock for many years to come. This practice supports a risk/reward model that reinforces a long-term view, which is critical to the company’s business success, and discourages inappropriate risk taking.

The basis for the grant includes an annual assessment of individual performance including a review of business performance results as noted on page 139. The amount granted is intended to provide an incentive to promote individual contribution to the company’s performance and to remain with the company. Grant level guidelines for the restricted stock unit program award the same number of shares for the same level of individual performance and classification or level of responsibility, and may be adjusted periodically based on an assessment of the program’s competitive orientation. An individual’s grant amount may be reduced at time of grant, if recent performance is deemed to have changed significantly at that time. As a matter of principle, the company does not offset losses on prior grants with higher share awards in subsequent grants, nor does the company re-price restricted stock units. Restricted stock units are not included in pension calculations.

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The vesting periods, which are typically greater than those in use by other companies, reinforce the company’s focus on growing shareholder value over the long term by linking a large percentage of executive compensation and the shareholding net worth of executives to the value of the company’s stock. The long vesting periods ensure that a substantial portion of the compensation received by the chairman, president and chief executive officer, as well as other key senior executives, will be received after retirement. The value of this compensation is at risk in the event that their decisions prior to retirement negatively impact share market value after retirement. The objective of these aforementioned vesting periods is to hold senior executives accountable for many years into the future, and even into retirement, for investment and operating decisions made today. This type of compensation design removes employee discretion in the timing of exercising restricted stock units, reinforces retention objectives, and supports alignment with the long-term interests of shareholders.

In 2017, after a review of the competitive orientation of the company’s restricted stock unit program, it was determined that current levels of restricted stock units were appropriate and that the program continues to align with the design of the majority shareholder’s program. In 2017, 415 recipients, including 55 executives, were granted 758,990 restricted stock units.

Vesting of restricted stock units

Restricted stock units vest pursuant to the vesting provisions described in the previous section. Restricted stock units cannot be assigned. The vesting period for restricted stock unit awards is not subject to acceleration, except in the case of death.

Upon vesting, each restricted stock unit entitles the recipient to the right to receive an amount equal to the value of one common share of the company, based on the five day average closing price of the company’s shares on the vesting date and the four preceding trading days. For units granted to senior executives other than the chairman, president and chief executive officer, 50 percent of the units vest as a cash payment on the third and seventh anniversary of the grant date, with the following exception: for units granted to Canadian residents, the recipient may receive one common share of the company per unit or elect to receive a cash payment for the units that vest on the seventh anniversary. For all units granted to the chairman, president and chief executive officer, upon vesting, the recipient may receive one common share of the company per unit or elect to receive a cash payment for the units. During the restricted period, the recipient will also receive cash payments equivalent to the cash dividends paid to holders of regular common stock.

The company’s directors, officers and vice-presidents as a group hold approximately 21 percent of the unvested restricted stock units that give the recipient the right to receive common shares that represent about 0.08 percent of the company’s outstanding common shares. Currently, the maximum number of common shares that any one person may receive from the vesting of restricted stock units is 492,500 common shares, which is about 0.06 percent of the outstanding common shares. In the case of any subdivision, consolidation, or reclassification of the shares of the company or other relevant change in the capitalization of the company, the company, in its discretion, may make appropriate adjustments in the number of common shares to be issued and the calculation of the cash amount payable per restricted stock unit.

Exxon Mobil Corporation has a plan similar to the company’s restricted stock unit plan, under which grantees may receive restricted stock or restricted stock units, both of which are referred to herein as Exxon Mobil Corporation restricted stock. R.M. Kruger holds Exxon Mobil Corporation restricted stock granted in 2012 and previous years, as well as the company’s restricted stock units granted since 2013. J.R. Whelan and P.M. Dinnick also hold Exxon Mobil Corporation restricted stock granted in 2016 and previous years, as well as the company’s restricted stock units granted in 2017.

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Amendments to the restricted stock unit plan

In 2008, the company’s restricted stock unit plan was amended to provide that the number of common shares of the company issuable under the plan to any insiders (as defined by the Toronto Stock Exchange) cannot exceed 10 percent of the issued and outstanding common shares, whether at any time or as issued in any one year. The Toronto Stock Exchange advised that this amendment did not require shareholder approval. Additionally, shareholders approved the following changes to the restricted stock unit plan:

● In addition to the existing three and seven year vesting provisions, include an additional vesting period option for 50 percent of restricted stock units to vest on the fifth anniversary of the date of grant, with the remaining 50 percent of the grant to vest on the later of the tenth anniversary of the date of grant or the date of retirement of the grantee. The recipient of such restricted stock units may receive one common share of the company per unit or elect to receive the cash payment for all units to be vested. The choice of which vesting period provision to use will be at the discretion of the company.

● Set a vesting price based on the weighted average price of the company’s shares on the vesting date and the four consecutive trading days immediately prior to the vesting date.

● Set out which amendments in the future will require shareholder approval, and which amendments will only require board of directors approval. The board of directors may amend the plan without shareholder approval for RSUs previously issued or to be issued in the future, unless the amendment is with respect to:

● increasing the shares served for issuance;

● increasing the vesting price;

● extending eligibility to participate in the plan to persons not included in the plan;

● extending the right of a grantee to transfer or assign RSUs; or

● adjusting the vesting date for any RSUs previously granted.

In 2011, the restricted stock unit plan was amended to include language confirming the long-standing practice of not forfeiting any restricted stock units in the event that grantee’s continued employment terminates on or after the date grantee reaches the age of 65 in circumstances where grantee becomes entitled to an annuity under the company’s retirement plan.

In 2016, the restricted stock unit plan was amended to update provisions regarding forfeiture of restricted stock units in the event of detrimental activity and to provide a new vesting option in addition to the existing vesting options previously described, such that the second 50 percent of the restricted stock units may vest on the tenth anniversary following the grant date.

Forfeiture and claw-back risk

The company’s incentive plans include forfeiture and claw-back provisions that discourage

employees from taking inappropriate risks and engaging in detrimental activities.

The annual bonus is subject to forfeiture and claw-back if:

● An executive retires or employment with the company terminates (for any reason, whether at initiative of employee, the company or otherwise).

● The company has indicated its intention not to forfeit outstanding awards of employees who retire at age 65. In other circumstances, where a recipient retires or terminates employment, the company may determine that awards shall not be forfeited.

● Risk of forfeiture and claw-back continues to exist for detrimental activity.

● An executive, without the consent of the company, engages in any activity, during employment or after retirement or the termination of employment, which is detrimental to the company, including working for a competitor.

● In 2016, the plan was amended to extend the forfeiture period for detrimental activity from two years to the life of the award.

● There is a material negative restatement of the company’s reported financial or operating results. For executive officers of the company, some or all of any unvested earnings bonus units granted in the three years prior to the restatement are subject to forfeiture. In addition, any cash amounts received from bonus or earnings bonus units that were paid out up to five years prior to the restatement are subject to claw-back.

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Restricted stock units are subject to forfeiture and claw-back if:

● A recipient retires or employment with the company terminates (for any reason, whether at initiative of employee, the company or otherwise).

● The company has indicated its intention not to forfeit restricted stock units of employees who retire at age 65. In other circumstances, where a recipient retires or terminates employment, the company may determine that restricted stock units shall not be forfeited.

● Risk of forfeiture and claw-back continues to exist for detrimental activity.

● A recipient, without the consent of the company, engages in any activity, during employment or after retirement or termination of employment, which is detrimental to the company, including working for a competitor.

● With respect to executives, at any time prior to vesting of the outstanding awards.

● With respect to all other employees, for a period of up to three years after retirement or the termination of employment.

● In 2016, the plan was amended to extend the forfeiture period for detrimental activity from two years to the periods noted above.

Retirement benefits

Named executive officers participate in the same pension plan, including supplemental pension arrangements outside the registered plan, as other employees, except for R.M. Kruger, J.R. Whelan and P.M. Dinnick who participate in Exxon Mobil Corporation or respective affiliates’ pension plans.

Pension plan benefits

The company has provided defined benefit pension plans to its employees since 1919. The current plan provides a 1.5 percent accrual formula to all employees hired on and after September 1, 2015. All plan participants employed prior to the date of the change will continue to accrue pension benefits based on accrual formulae in place prior to September 1, 2015.

All named executive officers, except those who are a participant in the Exxon Mobil Corporation or affiliate pension plans (R.M. Kruger, J.R. Whelan and P.M. Dinnick), are participants in a historic 1.6 percent provision of the company’s plan that was closed to new participants at the end of 1997. Key features of this historic plan include:

● An annual benefit equal to 1.6 percent x final average earnings x years of service, with a partial offset for applicable government pension benefits. Final average earnings consists of base salary over the highest 36 consecutive months in the 10 years of service prior to retirement.

● An option to forego a portion of the company’s matching contributions to the savings plan to receive an additional 0.4 percent of final average earnings.

The company’s supplemental pension arrangements address any portions of the defined benefit that cannot be paid from the registered plan due to tax regulations. Any amounts paid to an eligible employee, in this regard, are subject to the employee meeting the terms of the registered pension plan and the criteria of the supplemental pension arrangements, as applicable.

For executive officers who receive an annual bonus, the company’s supplemental pension arrangements can also provide an annual benefit of 1.6 percent of final average bonus earnings times years of service. Final average bonus earnings include the average annual bonus for the three highest grants of the last five awarded prior to retirement for eligible executives, but do not include restricted stock units. Limiting the timeframe to the five years prior to retirement provides a strong incentive for executives to continue to perform at a high level. Annual bonus includes the cash amounts that are paid at grant and the maximum settlement value of any earnings bonus units received, as described on page 133. The value of the earnings bonus units are expected to pay out, subject to forfeiture provisions, and are therefore included for supplemental pension arrangement purposes in the year of grant rather than the year of payment.

The estimated benefits that would be payable upon retirement to each named executive officer under the company’s pension plan and the supplemental pension arrangements can be found in the pension plan benefits table beginning on page 148. The company does not grant additional pension service credit.

R.M. Kruger, J.R. Whelan and P.M. Dinnick are not participants in the company’s pension plan, but are participants in the Exxon Mobil Corporation or respective affiliates’ pension plans. R.M. Kruger participates in the Exxon Mobil Corporation defined benefit plan. Under this plan, the pension is payable in U.S. dollars and

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is calculated based on final average base salary over the highest 36 consecutive months in the 10 years of service prior to retirement, and the average annual bonus for the three highest grants of the last five awarded prior to retirement. J.R. Whelan participates in the ExxonMobil Canada Ltd. defined contribution plan. Under this plan, the pension is payable in Canadian dollars and the contribution to the plan is calculated based on average base salary. P.M. Dinnick participates in the Esso Australia Pty Ltd. defined benefit plan. Under this plan, the pension is payable in Australian dollars and is calculated based on final average base salary over the highest 12 consecutive months in the 10 years of service prior to retirement.

Savings plan benefits

The company maintains a savings plan into which career employees with more than one year of service may contribute between one and 30 percent of normal earnings. The company provides contributions which vary depending on the amount of employee contributions and in which defined-benefit pension arrangement the employee participates. All named executive officers are eligible to receive a company matching contribution of up to six percent, except for R.M. Kruger, J.R. Whelan and P.M. Dinnick, who participate in their respective affiliates’ savings plan, where applicable.

Employee and company contributions can be allocated in any combination to a non-registered (tax-paid) account, or a registered (tax-deferred) group retirement savings plan (RRSP). Employee contributions can be redirected from the tax-paid account to a tax-free savings account (TFSA). Both the RRSP and TFSA accounts are subject to contribution limits under the Income Tax Act.

Available investment options include cash savings, a money market mutual fund, a suite of four index-based equity or bond mutual funds and company shares. Assets in the RRSP account and company contributions to the tax-paid account may only be withdrawn upon retirement or termination of employment, reinforcing the company’s long-term approach to total compensation. Income tax regulations require RRSPs to be converted into an eligible form of retirement income by the end of the calendar year in which the individual reaches age 71.

Compensation decision making process and considerations for named executive officers

Benchmarking

In addition to the assessment of business performance, individual performance and level of responsibility, the executive resources committee relies on market comparisons to a group of 22 major Canadian companies whose revenues (or the revenues of their parent companies) exceed $1 billion a year.

Comparator companies

The following criteria are used to select comparator companies:

● Canadian companies or Canadian affiliates;

● large operating scope and complexity;

● capital intensive; and

● proven sustainability.

The 22 companies benchmarked are as follows:

Energy	Non-Energy
Agrium Inc.	BCE Inc.
BP Canada Energy Group ULC	Canadian Pacific Railway Limited
Cenovus Energy Inc.	Canadian Tire Corporation Limited
Chevron Canada Limited	General Electric Canada
ConocoPhillips Canada	IBM Canada Ltd.
Devon Canada Corporation	Proctor & Gamble Inc.
Enbridge Inc.	Royal Bank of Canada
Encana Corporation
Husky Energy Inc.
Nexen Energy ULC
NOVA Chemicals Corporation
Repsol
Shell Canada Limited
Suncor Energy Inc.
TransCanada Corporation

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The company is a national employer drawing from a wide range of disciplines. It is important to understand its competitive orientation relative to a variety of energy and non-energy employers. Compensation trends across industries, based on survey data, are prepared annually by an independent external consultant with additional analysis and recommendation provided by the company’s internal compensation advisors. Consistent with the executive resources committee’s practice of using well-informed judgment rather than formulae to determine executive compensation, the committee does not target any specific percentile among comparator companies to align compensation. The focus is on a broader and more flexible orientation, generally a range around the median of the comparator energy companies’ compensation. This approach applies to salaries and the annual incentive program that includes bonus and restricted stock units.

As a secondary source of data, the executive resources committee also considers a comparison with the majority shareholder when it determines the annual bonus program. For the restricted stock unit program, the executive resources committee also reviews a summary of data of the comparator companies provided by the same external consultant in order to assist in assessing total value of long-term compensation grants. As a result, grant level guidelines may be adjusted periodically to maintain the program’s competitive orientation. As a matter of principle, the company does not offset losses on prior grants with higher share awards in subsequent grants, nor does the company re-price restricted stock units.

This overall approach provides the company with the ability to:

● better respond to changing business conditions;

● manage salaries based on a career orientation;

● minimize potential for automatic increasing of salaries, which could occur with an inflexible and narrow target among benchmarked companies; and

● differentiate salaries based on performance and experience levels among executives.

Details of the compensation assessment for the named executive officers are outlined below and on page 140.

Analytical tools – Compensation summary sheets

The compensation summary sheet is a matrix used by the executive resources committee that shows the individual elements and total compensation for each senior executive. The summary sheet is used to understand how decisions on each individual element of compensation affect total compensation for each senior executive. The committee considers both current compensation recommendations and prior compensation results in its final determination.

The elements of the Exxon Mobil Corporation and respective affiliates’ compensation programs for R.M. Kruger, J.R. Whelan and P.M. Dinnick, including salary and annual bonus and equity (long-term) compensation considerations, are generally similar to those of the company. The data used for long-term compensation determination for R.M. Kruger, J.R. Whelan and P.M. Dinnick is as described above, as they received company restricted stock units in 2017. The executive resources committee reviews and approves recommendations for each named executive officer prior to implementation. R.M. Kruger’s compensation determination is described in more detail beginning on page 140.

2017 named executive officer compensation assessment

When determining the annual compensation for the named executive officers, the executive resources committee has reflected on the following business performance result indicators in its determination of 2017 salary and incentive compensation.

Business performance results for consideration

The operating and financial performance results listed below and the company’s continued maintenance of sound business controls and a strong corporate governance environment formed the basis for the salary and incentive award decisions made by the executive resources committee in 2017. The executive resources committee considered the results over multiple years, relative to the company’s proven business model and strategies, to deliver long-term shareholder value.

● Strong safety, operational integrity and risk management performance

● $490 million net income; $1,056 million excluding upstream non-cash impairment charges

● $2,763 million cash flow from operations, the highest since 2014

● $1,151 million returned to shareholders through share purchases and dividends

● 23rd consecutive year of dividend growth

● Reinstituted share buyback program

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● Strong performance across all business lines

● Record annual production at Cold Lake and Kearl

● Best-ever refining results in energy efficiency and reliability

● Highest petroleum product sales in more than 25 years

● Expanded branded fuels business with Husky conversion and introduction of Mobil brand

● Second highest annual chemical earnings

● $190 million reduction in above-field costs; nearly $400 million since 2015

● Progressed opportunities to add value to high-quality asset portfolio

● Completed Kearl enhancements to improve reliability and reduce unit costs

● Approved investment to increase Kearl production beyond initial scope

● Approved Strathcona refinery cogeneration project to improve energy efficiency

● Continued commitment to industry leadership in technology and innovation

● More than $150 million invested in research

Performance assessment considerations

The preceding results form the context in which the committee assesses the individual performance of each senior executive, taking into account experience and level of responsibility.

Annually, the chairman, president and chief executive officer reviews the performance of the senior executives in achieving business results and individual development needs.

The same long-term key business strategies noted on page 129 and results noted on page 139 are key elements in the assessment of the chairman, president and chief executive officer’s performance by the executive resources committee.

The performance of all named executive officers is also assessed by the board of directors throughout the year during specific business reviews and board committee meetings that provide information on strategy development, operating and financial results, safety, health, and environmental results, business controls, and other areas pertinent to the general performance of the company.

The executive resources committee does not use quantitative targets or formulae to assess individual executive performance or determine compensation. The executive resources committee does not assign weights to the factors considered. Formula-based performance assessments and compensation typically require emphasis on two or three business metrics. For the company to be an industry leader and effectively manage the technical complexity and integrated scope of its operations, most senior executives must advance multiple strategies and objectives in parallel, versus emphasizing one or two at the expense of others that require equal attention.

Senior executives and officers are expected to perform at the highest level or they are replaced. If it is determined that another executive is ready and would make a stronger contribution than one of the current incumbents, a replacement plan is implemented.

2017 chief executive officer compensation assessment

R.M. Kruger was appointed chairman, president and chief executive officer of the company on March 1, 2013. Mr. Kruger has worked for Exxon Mobil Corporation and its predecessor companies since 1981. His level of salary was determined by the executive resources committee based on his individual performance and to align with that of his peers in ExxonMobil. It was also the objective of the executive resources committee to ensure appropriate internal alignment with senior management in the company. The committee approved a salary increase of $29,000 U.S. to $899,000 U.S., effective January 1, 2018.

Mr. Kruger’s 2017 annual bonus was based on his performance as assessed by the executive resources committee since his appointment to the position of chairman, president and chief executive officer. His long-term incentive award was granted in the form of company restricted stock units, not Exxon Mobil Corporation restricted stock, to reinforce alignment of his interests with that of the company’s shareholders. His company restricted stock units are subject to vesting periods longer than those applied by most companies conducting business in Canada. Fifty percent of the restricted stock units awarded vest in five years and the other 50 percent vest on the later of 10 years from the date of grant or the date of retirement. The purpose of these long vesting periods is to reinforce the long investment lead times in the business and to link a substantial portion of Mr. Kruger’s shareholding net worth to the performance of the company. As such, the payout value of the long-term incentive grants may differ from the amounts shown in the summary compensation table, depending on how the company actually performs at time of future vesting. During these vesting periods, the awards are subject to risk of forfeiture based on detrimental activity or leaving the company before normal retirement.

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The executive resources committee has determined that the total compensation of Mr. Kruger is appropriate based on the company’s financial and operating performance, and its assessment of his effectiveness in leading the organization relative to the business performance measures outlined on page 131. Taking all factors into consideration, the committee’s decisions on compensation of the chief executive officer reflect judgment, rather than the application of formulae or targets.

Pay awarded to other named executive officers

Within the context of the compensation program structure and performance assessment processes previously described, the value of 2017 incentive awards and salary adjustments align with:

● performance of the company;

● individual performance;

● long-term strategic plan of the business; and

● annual compensation of comparator companies.

Taking all factors into consideration, the executive resources committee’s decisions on pay awarded to other named executive officers reflect judgment, rather than the application of formulae or targets. The executive resources committee approved the individual elements of compensation and the total compensation as shown in the summary compensation table on page 143.

Independent consultant

In fulfilling its responsibilities during 2017, the executive resources committee did not retain an independent consultant or advisor in determining compensation for any of the company’s officers or any other senior executives. The company’s management retained an independent consultant to provide an assessment of competitive compensation and market data for all salaried levels of employees of the company. While providing this data, they did not provide individual compensation recommendations or advice for the compensation of the chairman, president and chief executive officer or other senior executives.

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Performance graph

The following graph shows changes over the past 10 years in the value of $100 invested in (i) Imperial Oil Limited common shares, (ii) the S&P/TSX Composite Index, and (iii) the S&P/TSX Composite Energy Index. The S&P/TSX Composite Energy Index is currently made up of share performance data for 50 oil and gas companies including integrated oil companies, oil and gas producers and oil and gas service companies.

The year-end values in the graph represent appreciation in share price and the value of dividends paid and reinvested. The calculations exclude trading commissions and taxes. Total shareholder returns from each investment, whether measured in dollars or percent, can be calculated from the year-end investment values shown beneath the graph.

During the past 10 years, the company’s cumulative total shareholder return was negative 20 percent, for an average annual return of negative 2 percent. Over the past five years, the cumulative total shareholder return was negative 2 percent. Total direct compensation for named executive officers generally reflects the trend in total shareholder returns as the largest single component of executive compensation is awarded in the form of restricted stock units with long holding periods. This design reinforces the long-term linkage between executive compensation and the shareholding net worth of executives to the return on the company’s stock realized by shareholders. Total direct compensation includes salary, the annual bonus (cash and earnings bonus unit awards), and the grant date fair value of the restricted stock unit award which is equal to the price for the company’s stock on the date of grant.

(a) Effective December 21, 2012, S&P discontinued the S&P/TSX Equity Energy Index. This was replaced with the S&P/TSX Composite Energy Index (STENRSR).

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Executive compensation tables and narratives

Summary compensation table

The following table shows the compensation for the chairman, president and chief executive officer; the senior vice-president, finance and administration, and controller; and the three other most highly compensated executive officers of the company who were serving as at the end of 2017. This information includes the Canadian dollar value of base salaries, cash bonus awards and earnings bonus unit payments, long-term incentive compensation and certain other compensation. Amounts in the Summary compensation table pertain to the named executive officers’ respective periods of assignment with the company.

Name and principal         position at the end                  of 2017	Year	Salary ($) (b)	Share- based awards ($) (c)	Option- based awards ($) (d)	Non-equity incentive plan compensation ($)		Pension value ($) (g)	All other compensation ($) (h)	Total   compensation   ($) (i)
					Annual incentive plans (e)	Long- term incentive plans (f)
R.M. Kruger (a) Chairman, president and chief executive officer	2017	1,129,782	3,908,520	-	488,923	620,727	(1,159,234)	1,850,506	6,839,224
	2016	1,139,328	4,979,700	-	356,371	0	(379,289)	1,481,708	7,577,818
	2015	1,062,600	4,224,365	-	444,348	611,219	(353,857)	3,022,231	9,010,906
B.A. Babcock Senior vice-president, finance and administration, and controller (since September 1, 2015)	2017	502,250	868,560	-	89,400	166,597	204,300	116,802	1,947,909
	2016	495,750	995,940	-	74,700	0	(12,700)	113,294	1,666,984
	2015	163,333	922,900	-	106,900	0	(656,200)	80,770	617,703
J.R. Whelan (a) Senior vice-president, upstream	2017	476,583	868,560	-	103,758	153,810	72,751	178,832	1,854,294
	2016	458,250	936,806	-	58,159	0	79,929	169,591	1,702,735
	2015	438,667	848,070	-	79,535	139,434	29,849	150,055	1,685,610
T.B. Redburn Senior vice-president, commercial and corporate development	2017	458,000	868,560	-	99,000	128,566	549,400	55,817	2,159,343
	2016	444,167	733,374	-	57,600	0	(136,000)	60,241	1,159,382
	2015	427,167	679,590	-	82,500	0	(589,100)	55,689	655,846
P.M. Dinnick (a) Vice-president and general counsel	2017	437,167	410,592	-	39,997	29,163	182,213	546,595	1,645,727
	2016	397,757	439,489	-	21,594	0	105,426	437,998	1,402,264
	2015	367,276	355,980	-	20,459	27,292	95,361	351,073	1,217,441

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Footnotes to the Summary compensation table for named executive officers

(a) R.M. Kruger has been on expatriate assignment from Exxon Mobil Corporation, an affiliate in the U.S., since 2013. P.M. Dinnick has been on expatriate assignment from Esso Australia Pty Ltd., an affiliate in Australia, since 2012. J.R. Whelan has been on domestic loan assignment from ExxonMobil Canada Ltd., an affiliate in Canada, since 2013. Their compensation is paid directly by Exxon Mobil Corporation and respective affiliates, with the exception of the compensation related to the vesting of the company’s restricted stock units and dividend equivalents on outstanding restricted stock units. They also receive employee benefits under their respective affiliates’ employee benefit plans, and not under the company’s employee benefit plans. The company reimburses the respective affiliates for applicable compensation paid and employee benefits provided to them. The company does not reimburse Exxon Mobil Corporation for the cost of incentive awards granted by Exxon Mobil Corporation.

(b) The amounts listed in the “Salary” column for each named executive officer on expatriate assignment (R.M. Kruger and P.M. Dinnick) are paid in their local currency, but disclosed in Canadian dollars. R.M. Kruger’s salary is paid in U.S. dollars and was converted to Canadian dollars at the average 2017 exchange rate of 1.2986. In 2016 and 2015 the average exchange rate was 1.3248 and 1.2787 respectively. P.M. Dinnick’s salary is paid in Australian dollars and was converted to Canadian dollars at the average 2017 exchange rate of 0.9951. In 2016 and 2015 the average exchange rate was 0.9852 and 0.9604, respectively.

(c) The grant date fair value equals the number of restricted stock units multiplied by the closing price of the company’s shares on the date of grant. The closing price of the company’s shares on the grant date in 2017 was $39.48, which is the same as the accounting fair value for the restricted stock units on the date of grant. The closing price of the company’s shares on the grant date in 2016 was $45.27 and in 2015 was $41.95, which is the same as the accounting fair value for the restricted stock units on the date of grant. The company chose this method of valuation as it believes it results in the most accurate representation of fair value. In 2016 and 2015, J.R. Whelan and P.M. Dinnick participated in Exxon Mobil Corporation’s restricted stock plan, which is similar to the company’s restricted stock unit plan. The closing price of Exxon Mobil Corporation stock on the grant date in 2016 was $87.30 U.S. and in 2015 was $81.88 U.S. and is converted to Canadian dollars at the annual average exchange rate of 1.3248 and 1.2787 respectively.

(d) The company has not granted stock options since 2002. The stock option plan expired in 2012.

(e) The amounts listed in the “Annual incentive plans” column for each named executive officer represent their 2017 cash bonus. R.M. Kruger, J.R. Whelan and P.M. Dinnick participate in Exxon Mobil Corporation’s annual cash bonus program, which is similar to the company’s plan, and is paid in U.S. dollars, but disclosed in Canadian dollars. Amounts paid in U.S. dollars were converted to Canadian dollars at the average 2017 exchange rate of 1.2986. In 2016 and 2015 the average exchange rate was 1.3248 and 1.2787 respectively.

(f) The amounts listed in the “Long-term incentive plans” column represent earnings bonus unit payouts related to prior year grants. These are paid when the maximum settlement value (trigger) or cumulative earnings per share is achieved or after three years if such value is not achieved. The earnings bonus unit program is described on page 133. R.M. Kruger, J.R. Whelan and P.M. Dinnick participate in Exxon Mobil Corporation’s earnings bonus unit program, which is similar to the company’s plan, and is paid in U.S. dollars, but disclosed in Canadian dollars. Amounts paid in U.S. dollars were converted to Canadian dollars at the average 2017 exchange rate of 1.2986. In 2016 and 2015 the average exchange rate was 1.3248 and 1.2787 respectively. Their payouts are also subject to a maximum settlement value (trigger) or cumulative earnings per share.

(g) “Pension value” is the “Compensatory change” in pensions as of December 31, 2017 as set out in the “Pension plan benefits” table on page 148.

(h) The amounts listed in the “All other compensation” column include dividend equivalent payments on restricted stock units granted, savings plans contributions, expatriate assignment costs, parking and the cost of perquisites including financial planning and business club memberships, as well as security costs and costs associated with participation in Exxon Mobil Corporation’s executive life insurance benefit plan, as applicable.

● For each named executive officer, the aggregate value of perquisites received in 2017 was not greater than $50,000 or 10 percent of the named executive officer’s base salary.

● It is noted that in 2017, the actual dividend equivalent payments on the company restricted stock units were $227,470 for R.M. Kruger, $69,205 for B.A. Babcock and $47,432 for T.B. Redburn. The dividend equivalent payments on Exxon Mobil Corporation restricted stock granted in previous years were $561,685 for R.M. Kruger, $146,431 for J.R. Whelan and $64,374 for P.M. Dinnick; these amounts were converted to Canadian dollars at the average 2017 exchange rate of 1.2986.

● For the named executive officers on expatriate assignment (R.M. Kruger and P.M. Dinnick), “All other compensation” also includes expatriate assignment costs which consist of expatriate allowances and the net effect of tax equalization costs in the year. Tax equalization costs include the net effect of taxes paid by the companies to local taxing authorities on behalf of the named executive officer offset by a withholding from their income that approximates the amount of tax they would pay if they had not gone on expatriate assignment. Tax equalization is an integral part of the expatriate relocation program and is designed to maintain an individual’s overall tax burden at approximately the same level it would have otherwise been, had they remained in their home country. Tax equalization amounts vary from one year to the next and the net impact may be positive or negative in the year.

(i) “Total compensation” consists of the total dollar value of “Salary”, “Share-based awards”, “Option-based awards”, “Non-equity incentive plan compensation”, “Pension value” and “All other compensation”.

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Outstanding share-based awards and option-based awards for named executive officers

The following table sets forth all share-based and option-based awards outstanding for each named executive officer of the company as at December 31, 2017.

	Option-based awards				Share-based awards
Name	Number of securities underlying unexercised options (#)	Option exercise price ($)	Option expiration date	Value of unexercised in-the- money options ($)	Number of shares or units of shares that have not vested (#) (d)	Market or payout value of share- based awards that have not vested ($) (d)	Market or payout value of vested share- based awards not paid out or distributed ($)
R.M. Kruger (a)	-	-	-	-	492,500	19,320,775	-
B.A. Babcock	-	-	-	-	111,000	4,354,530	-
J.R. Whelan (b)	-	-	-	-	22,000	863,060	-
T.B. Redburn	-	-	-	-	83,850	3,289,436	-
P.M. Dinnick (c)	-	-	-	-	10,400	407,992	-

(a) R.M. Kruger was granted restricted stock units from 2013 to 2017 under the company’s plan. With respect to previous years, R.M. Kruger participated in Exxon Mobil Corporation’s restricted stock plan, which is similar to the company’s restricted stock unit plan. Under that plan, R.M. Kruger held 118,500 Exxon Mobil Corporation restricted stock whose value on December 31, 2017 was $12,433,776 based on a closing price for Exxon Mobil Corporation shares on December 31, 2017 of $83.64 U.S., which was converted to Canadian dollars at the December 31, 2017 close rate of 1.2545 provided by the Bank of Canada.

(b) J.R. Whelan was granted restricted stock units in 2017 under the company’s plan. With respect to previous years, J.R. Whelan participated in Exxon Mobil Corporation’s restricted stock plan, which is similar to the company’s restricted stock unit plan. Under that plan, J.R. Whelan held 30,200 Exxon Mobil Corporation restricted stock whose value on December 31, 2017 was $3,168,777 based on a closing price for Exxon Mobil Corporation shares on December 31, 2017 of $83.64 U.S., which was converted to Canadian dollars at the December 31, 2017 close rate of 1.2545 provided by the Bank of Canada.

(c) P.M. Dinnick was granted restricted stock units in 2017 under the company’s plan. With respect to previous years, P.M. Dinnick participated in Exxon Mobil Corporation’s restricted stock plan, which is similar to the company’s restricted stock unit plan. Under that plan, P.M. Dinnick held 13,200 Exxon Mobil Corporation restricted stock whose value on December 31, 2017 was $1,385,028 based on a closing price for Exxon Mobil Corporation shares on December 31, 2017 of $83.64 U.S., which was converted to Canadian dollars at the December 31, 2017 close rate of 1.2545 provided by the Bank of Canada.

(d) Represents the total of the outstanding restricted stock units received from the company plan in 2011 through 2017. The value is based on the closing price of the company’s shares on December 31, 2017 of $39.23.

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Incentive plan awards for named executive officers – Value vested or earned during the year

The following table sets forth the value of the incentive plan awards that vested in the year for each named executive officer of the company.

Name	Option-based awards – Value vested during the year ($)	Share-based awards – Value vested during the year ($) (d)	Non-equity incentive plan compensation – Value earned during the year ($) (e)
R.M. Kruger (a)	-	-	-
B.A. Babcock	-	892,013	255,997
J.R. Whelan (b)	-	-	-
T.B. Redburn	-	598,617	227,566
P.M. Dinnick (c)	-	-	-

(a) Although R.M. Kruger received restricted stock units under the company’s plan from 2013 to 2017, these restricted stock units have not vested. In previous years, R.M. Kruger participated in Exxon Mobil Corporation’s restricted stock plan, which is similar to the company’s restricted stock unit plan. In 2017, restrictions were removed on 22,850 Exxon Mobil Corporation restricted stock having a value as at December 31, 2017 of $2,397,568 based on the closing price of Exxon Mobil Corporation common shares of $83.64 U.S., which was converted to Canadian dollars at the December 31, 2017 close rate of 1.2545 provided by the Bank of Canada. R.M. Kruger received an annual bonus from Exxon Mobil Corporation in 2017 and participates in Exxon Mobil Corporation’s earnings bonus unit plan, which is similar to the company’s earnings bonus unit plan. R.M. Kruger $1,109,650 with respect to the annual cash bonus received in 2017 and earnings bonus units granted in 2014 and paid out in 2017, which amount was paid in U.S. dollars and is converted to Canadian dollars at the average 2017 exchange rate of 1.2986.

(b) Although J.R. Whelan received restricted stock units under the company’s plan in 2017, these restricted stock units have not vested. In previous years, J.R. Whelan participated in Exxon Mobil Corporation’s restricted stock plan, which is similar to the company’s restricted stock unit plan. In 2017, restrictions were removed on 6,650 Exxon Mobil Corporation restricted stock having a value as at December 31, 2017 of $697,760 based on the closing price of Exxon Mobil Corporation common shares of $83.64 U.S., which was converted to Canadian dollars at the December 31, 2017 close rate of 1.2545 provided by the Bank of Canada. J.R. Whelan received an annual bonus from Exxon Mobil Corporation in 2017 and participates in Exxon Mobil Corporation’s earnings bonus unit plan, which is similar to the company’s earnings bonus unit plan. J.R. Whelan received $257,568 with respect to the annual cash bonus in 2017 and earnings bonus units granted in 2014 and paid out in 2017, which amount was paid in U.S. dollars and is converted to Canadian dollars at the average 2017 exchange rate of 1.2986.

(c) Although P.M. Dinnick received restricted stock units under the company’s plan in 2017, these restricted stock units have not vested. In previous years, P.M. Dinnick participated in Exxon Mobil Corporation’s restricted stock plan, which is similar to the company’s restricted stock unit plan. In 2017, restrictions were removed on 3,000 Exxon Mobil Corporation restricted stock having a value as at December 31, 2017 of $314,779 based on the closing price of Exxon Mobil Corporation common shares of $83.64 U.S., which was converted to Canadian dollars at the December 31, 2017 close rate of 1.2545 provided by the Bank of Canada. P.M. Dinnick received an annual bonus from Exxon Mobil Corporation in 2017 and participates in Exxon Mobil Corporation’s earnings bonus unit plan, which is similar to the company’s earnings bonus unit plan. P.M. Dinnick received $69,160 with respect to the annual cash bonus in 2017 and earnings bonus units granted in 2014 and paid out in 2017, which amount was paid in U.S. dollars and is converted to Canadian dollars at the average 2017 exchange rate of 1.2986.

(d) These values show restricted stock units granted by the company that vested in 2017. The value is based on the five day average closing price of the company’s shares, which includes the vesting date and the four preceding trading days. For B.A. Babcock and T.B. Redburn the value represents restricted stock units granted in 2010 and 2014, which vested in 2017.

(e) These values include amounts paid by the company with respect to the 2017 annual cash bonus and earnings bonus unit granted in 2014 which paid out in 2017.

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Equity compensation plan information

The following table provides information on the common shares of the company that may be issued as of the end of 2017 pursuant to compensation plans of the company.

Plan category	Number of securities to be issued upon exercise of outstanding options, warrants and rights (#) (c)	Weighted average exercise price of outstanding options, warrants and rights ($)	Number of securities remaining available for future issuance under equity compensation plans (excluding securities reflected in the first column) (#) (c)
Equity compensation plans approved by security holders (a)	-	-	-
Equity compensation plans not approved by security holders (b)	3,213,880	-	7,270,632
Total	3,213,880		7,270,632

(a) The company’s stock option plan expired in 2012.

(b) This is a restricted stock unit plan, which is described starting on page 134.

(c) The number of securities to be issued represents the total number of restricted stock units issued since 2008 and still outstanding (5,859,050) minus the outstanding restricted stock units that are only eligible for cash (and not common shares) upon vesting (2,645,170). The number of securities remaining available for future issuance represents the restricted stock units not yet granted (4,625,462) plus the number of outstanding restricted stock units that are only eligible for cash (and not common shares) upon vesting (2,645,170).

Restricted stock units as a percentage of outstanding shares

The following table provides information on the restricted stock unit plan, expressed as a number and as a percentage of the common shares of the company as of the end of 2017.

	Maximum number of restricted stock units issuable under the plan (#) (b)	Total number of restricted stock units awarded and outstanding (#)	Total number of restricted stock units available for grant (#)
Number	10,484,512	5,859,050	4,625,462
Percent of outstanding common shares (a)	1.26%	0.70%	0.56%

(a) As of December 31, 2017, the number of common shares outstanding was 831,242,307.

(b) The maximum number of restricted stock units issuable under the company plan is the number as of December 31, 2016 (10,486,262) minus the common shares issued in 2017 pursuant to the vesting of restricted stock units under the plan (1,750 common shares).

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Annual burn rate

The following table provides the annual burn rate associated with the restricted stock unit plan for each of the company’s three most recent fiscal years.

	Number of restricted stock units granted under the plan (#) (a)	Weighted average number of securities outstanding (#) (b)	Annual burn rate (%) (c)
2017	758,990	842,943,735	0.09%
2016	815,870	847,599,011	0.10%
2015	884,080	847,599,011	0.10%

(a) The Number of restricted stock units granted under the plan in the applicable fiscal year.

(b) The Weighted average number of securities outstanding during the period is the number of securities outstanding at the beginning of the period, adjusted by the number of securities bought back or issued during the period multiplied by a time-weighting factor.

(c) The Annual burn rate percent is the Number of restricted stock units granted under the plan divided by the Weighted average number of securities outstanding.

Status of prior long-term incentive compensation plans

The company’s only long-term incentive compensation plan is the restricted stock unit plan described on pages 134 through 137. There are no units outstanding for any historical plan.

Pension plan benefits

The following table provides information for each named executive officer of the company participating in a defined benefit pension plan. Information for named executive officers on assignment from affiliates of the company who participate in a plan provided by such affiliates is disclosed in the footnotes.

Name	Number of years credited service (as of December 31, 2017) (#) (a)	Annual benefits payable ($)		Opening present value of defined benefit obligation ($) (d)	Compensatory change ($) (e)	Non- compensatory change ($) (f)	Closing present value of defined benefit   obligation   ($) (d)
		At year- end (b)	At age 65 (c)
R.M. Kruger	-	-	-	-	-	-	-
B.A. Babcock	30.7	380,200	480,100	6,372,900	204,300	497,600	7,074,800
J.R. Whelan (g)	-	-	-	-	-	-	-
T.B. Redburn	32.6	363,400	475,600	5,921,300	549,400	401,100	6,871,800
P.M. Dinnick (g)	-	-	-	-	-	-	-

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(a) R.M. Kruger participates in the Exxon Mobil Corporation defined benefit pension plan including tax-qualified and non-qualified plans. Benefits under this plan are payable in U.S. dollars and have been converted to Canadian dollars at the average 2017 exchange rate of 1.2986. Under this plan, R.M. Kruger had 36.5 years of credited service. J.R. Whelan participates in the ExxonMobil Canada Ltd. defined contribution plan. Benefits under this plan are payable in Canadian dollars. Under this plan, J.R. Whelan had 21.4 years of credited service. P.M. Dinnick participates in the Esso Australia Pty Ltd. defined benefit and defined contribution pension plans. Benefits under these plans are payable in Australian dollars and have been converted to Canadian dollars at the average 2017 exchange rate of 0.9951. Under these plans, P.M. Dinnick had 23.4 years of credited service.

(b) For members of the company’s pension plan, the annual benefits include the amount of the accrued annual lifetime pension from the company’s registered pension plan and supplemental pension arrangement. For members of the Exxon Mobil Corporation pension plan, the annual benefits include the accrued annual lifetime pension from the tax-qualified and the annual amount calculated under the non-qualified plans. For R.M. Kruger this value was $1,304,583. Non-qualified plan benefits are payable only as a lump sum equivalent upon retirement. For members of the Esso Australia Pty Ltd. pension plan, benefits are payable only as a lump sum equivalent upon retirement. For P.M. Dinnick this lump-sum value was $2,184,309.

(c) For members of the company’s pension plan, the annual benefits include the amount of the accrued annual lifetime pension from the company’s registered pension plan and supplemental pension arrangement that would be earned to age 65 assuming final average earnings as at December 31, 2017. For members of the the Exxon Mobil Corporation pension plan, the annual benefits include the annual lifetime pension from the tax-qualified and the annual amount calculated under the non-qualified plans that would be earned to age 65 assuming final average earnings as at December 31, 2017. For R.M. Kruger this value was $1,527,785. Non-qualified plan benefits are payable only as a lump sum equivalent upon retirement. For members of the Esso Australia Pty Ltd. pension plan, benefits are payable only as a lump sum equivalent upon retirement. For P.M. Dinnick the lump-sum value that would be earned to age 65 assuming final average earnings as of December 31, 2017 was $3,738,396.

(d) For members of the company’s pension plan, the opening and closing defined benefit obligation is defined under U.S. generally accepted accounting principles (GAAP) and values are calculated on a basis that is consistent with the valuation that was performed for accounting purposes for the company’s plans. The value is calculated based on estimated earnings eligible for pension as described previously and Yearly Maximum Pensionable Earnings (YMPE) as defined by the Canada Revenue Agency, projected to retirement and pro-rated on service to the date of valuation. The calculations assume that the Canada Pension Plan offset is based on the annual maximum benefit at retirement and the Old Age Security (OAS) offset is based on the OAS benefit at the date of valuation, projected to retirement. For members of the Exxon Mobil Corporation and the Esso Australia Pty Ltd. pension plan respectively, the opening and closing defined benefit obligation is defined under GAAP and values are consistent with the valuation performed for accounting purposes for the applicable affiliate plan. The values are calculated based on estimated earnings eligible for pension as described previously. For R.M. Kruger the opening value was $18,534,731 and the closing value was $18,554,823. For P.M. Dinnick the opening value was $2,100,946 and the closing value was $2,331,550.

(e) The value for “Compensatory change” includes service cost for 2017 and the impact of change in earnings on the projected benefit obligation. For members of the company’s plan, these values are calculated using the individual’s additional pensionable service in 2017 and the actual salary and bonus received in 2017. For members of the Exxon Mobil Corporation and Esso Australia Pty Ltd. pension plans, these values are calculated using the individual’s additional pensionable service in 2017 and earnings as described previously. For R.M. Kruger this value was ($1,159,234). For P.M. Dinnick this value was $178,099.

(f) The value for “Non-compensatory change” includes the impact of experience not related to earnings, benefit payments and change in measurement assumptions. With respect to the company pension plan, the discount rate used to determine the closing present value of defined benefit obligation at the end of 2017 decreased to 3.40 percent, from 3.75 percent at the end of 2016, which had a positive impact on the non-compensatory change element. For members of the Exxon Mobil Corporation and Esso Australia Pty Ltd. pension plans, the value for “Non-compensatory change” includes the impact of experience not related to earnings or service. This includes the effect of interest based on a discount rate of 3.80 percent at the end of 2017, down from 4.25 percent at the end of 2016. For R.M. Kruger this value was $1,179,326. For P.M. Dinnick this value was $52,505.

(g) J.R. Whelan participates in the ExxonMobil Canada Ltd. defined contribution plan. Under this plan, the affiliate contributes a percent of base pay to the fund monthly, subject to regulatory limits. The “Accumulated value at start of year” was $516,811, the “Compensatory value” was $72,751 reflecting affiliate contribution and investment earnings, and the “Accumulated value at year-end” was $589,562. P.M. Dinnick is a member of the Esso Australia Pty Ltd. defined contribution plan. Contribution limits under this plan have been reached. The “Accumulated value at start of year” was $51,022, the “Compensatory value” was $4,114 reflecting investment earnings, and the “Accumulated value at year-end” was $55,136.

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Appendix A – Board of director and committee charters

Board of Directors Charter

The structure, process and responsibilities of the board of directors of the corporation shall include the following items and matters:

1. Responsibility

The directors shall be responsible for the stewardship of the corporation.

2. Duty of care

The directors, in exercising their powers and discharging their duties, shall:

(a) act honestly and in good faith with a view to the best interests of the corporation; and

(b) exercise the care, diligence and skill that a reasonably prudent person would exercise in comparable circumstances.

3. Stewardship process

In order to carry out their responsibility for stewardship within their duty of care, the directors shall, directly or through one or more committees of directors,

(a) contribute to the formulation of and approve strategic plans on at least an annual basis;

(b) identify the principal risks of the corporation’s business where identifiable and oversee the implementation of appropriate systems to manage such risks;

(c) oversee succession planning for senior management, including the appointing, training and monitoring thereof;

(d) approve the corporate disclosure guidelines and monitor the external communications of the corporation;

(e) monitor the integrity of the corporation’s internal control and management information systems;

(f) consider management’s recommendations regarding major corporation decisions and actions, which have significant societal implications;

(g) monitor compliance with major corporate policies;

(h) charge the chief executive officer of the corporation with the general management and direction of the business and affairs of the corporation;

(i) monitor the performance of the chief executive officer;

(j) satisfy itself as to the integrity of the chief executive officer and other executive officers and ensure that the chief executive officer and the other executive officers create a culture of integrity throughout the company;

(k) annually review and approve the corporation’s code of ethics and business conduct;

(l) monitor compliance with the code of ethics and business conduct, provided that any waivers from the code that are granted for the benefit of the issuer’s directors or executive officers should be granted by the board only;

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(m) determine appropriate measures are in place for receiving feedback from stakeholders;

(n) by appropriate charter resolutions, establish the audit, executive resources, nominations and corporate governance, environment, health and safety, and contributions committees of the board with specific duties defined and the corporation provide each board committee with sufficient funds to discharge its responsibilities in accordance with its charter;

(o) determine membership of each committee, including its chair and vice-chair, after receiving the recommendation of the nominations and corporate governance committee;

(p) direct the distribution to the board by management of information that will enhance their familiarity with the corporation’s activities and the environment in which it operates, as set out in section 5;

(q) review the corporation’s process in respect of employee conflicts of interest and directorships in non-affiliated commercial, financial and industrial organizations and the disclosures thereof;

(r) review the mandates of the board and of the committees and their effectiveness at least annually; and

(s) undertake such additional activities within the scope of its responsibilities as it may deem appropriate.

4. Range of items to be considered by the board

The following categories and specific items shall be referred to the board for information or decision on a regularly scheduled basis, to the extent appropriate:

Organization/legal

● fixing of the number of directors

● director appointments to fill interim vacancies

● director slate for election by the shareholders

● officer appointments

● board governance processes

● by-laws and administrative resolutions

● changes in fundamental structure of the corporation

● shareholder meeting notice and materials

● nonemployee director compensation

● policies adopted by the board

● investigations and litigation of a material nature

Financial

● equity or debt financing

● dividend declarations

● financial statements and the related management discussion and analysis, annual and quarterly

● status of the corporation’s retirement plan and employee savings plan

Strategic/investment/operating plans/performance

● near-term and long-range outlooks

● capital, lease, loan and contributions budgets annually

● budget additions over $250 million individually

● quarterly updates of actual and projected capital expenditures

● capital expenditures or dispositions in excess of $250 million individually

● entering into any venture that is outside of the corporation’s existing businesses

● financial and operating results quarterly

● Canadian and world economic outlooks

● regional socio-economic reviews

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In addition to the items which are specific to the categories identified above, the chief executive officer shall refer to the board for information or decision all other items of corporate significance; and any member of the board may request a review of any such item. Items to be referred to the committees of the board are specified in their respective charters.

5. Information to be received by the board

Material shall be distributed to directors through the office of the corporate secretary. Corporate policies, board calendars, contact information and other company processes, are updated on the board portal site and accessible to all directors.

Material under the following general headings, including the specific items listed below and only other similar items, shall be distributed to directors on a regular basis:

Organization/legal

● articles of incorporation, by-laws and administrative resolutions

● corporate policies

● corporate data

● board and management processes

● financial and operating report

● organization outline

Social/political/economic environment

● public issues updates

● economic outlook

● external communications packages

Major announcements

● press releases

● speeches by management

● organization changes

Communications to shareholders

Other significant submissions, studies and reports

6. Meetings of the board

(a) The board normally holds seven (7) regular meetings per year. Additional meetings may be scheduled as required to consider the range of items charged for consideration by the board.

(b) An agenda for each board meeting and briefing materials will, to the extent practicable in light of the timing of matters that require board attention, be distributed to each director approximately five to seven days prior to each meeting. The chairman, in consultation with the chair of the executive sessions will normally set the agenda for board meetings. Any director may request the inclusion of specific items.

(c) It is expected that each director will make every effort to attend each board meeting and each meeting of any committee on which he or she sits. Attendance in person is preferred but attendance by teleconference is permitted if necessary.

(d) Each director should be familiar with the agenda for each meeting, have carefully reviewed all other materials distributed in advance of the meeting, and be prepared to participate meaningfully in the meeting, and to discuss all scheduled items of business.

(e) The proceedings and deliberations of the board and its committees are confidential. Each director will maintain the confidentiality of information received in connection with his or her service as a director, and the chief executive officer, or those whom he or she has designated, will speak for the corporation.

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7. Independent directors

(a) The board shall be composed of a majority of independent directors. The board may also include one or more directors who are not independent, but who, as officers of the majority shareholder, may be viewed as independent of the company’s management.

(b) In respect of each director to be appointed to fill a vacancy and each director to be nominated for election or re-election by the shareholders, the board shall make an express determination as to whether he or she is an independent director and, for a director who may become a member of the audit committee, whether he or she is an audit committee financial expert or financially literate.

(c) The term “independent”, shall have the meaning as set out in applicable law, including on the basis of the standards specified by Multilateral Instrument 52-110 Audit Committees, the US. Securities and Exchange Commission rules and the listing standards of the NYSE MKT LLC.

(d) Independent directors will have full access to senior management of the corporation and other employees on request to discuss the business and affairs of the corporation. The board expects that there will be regular opportunities for directors to meet with the chief executive officer, and other members of management in board and committee meetings and in other formal or informal settings.

(e) Compensation for independent directors will be determined by the board on the recommendation of the nominations and corporate governance committee and will be reviewed annually. Non-employee director compensation will be set at a level that is consistent with market practice, taking into account the size and scope of the corporation’s business and the responsibilities of its directors. A substantial portion of the compensation paid to independent directors for service on the board will be paid in restricted stock units of the corporation.

8. Independent legal or other advice

It is normally expected that information regarding the corporation’s business and affairs will be provided to the board by the corporation’s management and staff and by its independent auditors. However, the board and, with the approval of the board, any director, may engage independent counsel and other advisors at the expense of the corporation. The fees and expenses of any such advisor will be paid by the corporation.

9. Meetings of the independent directors in the absence of members of management

(a) Meetings of the independent directors (“executive sessions of the board”) shall be held in conjunction with all board meetings including unscheduled telephonic board meetings. Additional executive sessions may be convened by the chair of the executive sessions at his or her discretion and will be convened if requested by any other director. Any independent director may raise issues for discussion at an executive session.

(b) The chair of the executive sessions of the board shall be chosen by the independent directors.

(c) The chair of the executive sessions of the board, or in the chair’s absence an independent director chosen by the independent directors, shall

(i) preside at executive sessions of the board;

(ii) ensure that meetings of the independent directors are held in accordance with this charter;

(iii) review, and modify if necessary the agenda of the meetings of the board in advance to ensure that the board may successfully carry out its duties; and

(iv) act as a liaison with the chairman, including providing feedback from the executive sessions to the chairman, provided that each director will also be afforded direct and complete access to the chairman at any time as such director deems necessary or appropriate.

(d) The purposes of the executive sessions of the board shall include the following:

(i) to raise substantive issues that are more appropriately discussed in the absence of management;

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(ii) to discuss the need to communicate to the chairman of the board any matter of concern raised by any committee or any director;

(iii) to address issues raised but not resolved at meetings of the board and assess any follow-up needs with the chairman of the board;

(iv) to discuss the quality, quantity, and timeliness of the flow of information from management that is necessary for the independent directors to effectively and responsibly perform their duties, and advise the chairman of the board of any changes required; and

(v) to seek feedback about board processes.

10. Selection and tenure of directors

The nominations and corporate governance committee shall recommend to the board a slate of director candidates for election at each annual meeting of shareholders and shall recommend to the board directors to fill vacancies, including vacancies created as a result of any increase of the size of the board.

The guidelines for selection and tenure of directors shall be as follows:

(a)    Selection

In considering the qualifications of potential nominees for election as directors, the nominations and corporate governance committee considers the work experience and other areas of expertise of the potential nominees with the objective of providing for diversity among non-employee directors. The following key criteria are considered to be relevant to the work of the board of directors and its committees:

Work Experience

● Experience in leadership of businesses or other large organizations (Leadership of large organizations)

● Operations/technical experience (Operations/technical)

● Project management experience (Project management)

● Experience in working in a global work environment (Global experience)

● Experience in development of business strategy (Strategy development)

Other Expertise

● Audit committee financial expert

● Expertise in financial matters (Financial expertise)

● Expertise in managing relations with government (Government relations)

● Experience in academia or in research (Academic/research)

● Expertise in information technology (Information technology)

● Expertise in executive compensation policies and practices (Executive compensation)

In addition, the nominations and corporate governance committee may consider the following additional factors:

● possessing expertise in any of the following areas: law, science, marketing, administration, social/political environment or community and civic affairs;

● individual competencies in business and other areas of endeavour in contributing to the collective experience of the directors; and

● providing diversity in age, gender or regional association.

The nominations and corporate governance committee shall then assess what work experience and other expertise each existing director possesses. The nominations and corporate governance committee shall identify individuals qualified to become new board members and recommend to the board the new director nominees. In making its recommendations, the nominations and corporate governance committee shall consider the work experience and other expertise that the board considers each existing director to possess and which each new nominee will bring. The nominations and corporate governance committee may also consider the additional factors noted above and any other factors which it believes to be relevant.

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A candidate may be nominated for directorship after consideration has been given as to his or her degree of compatibility with the following criteria, i.e., as to whether he or she:

● will not adversely affect the requirements with respect to citizenship and residency for the directors imposed by the Canada Business Corporations Act;

● will not adversely affect the corporation’s status as a foreign private issuer under U.S. securities legislation;

● possesses the ability to contribute to the broad range of issues with which the directors and any one or all of the committees of directors must deal;

● will serve on the boards of other public companies only to the extent that such services do not detract from the director’s ability to devote the necessary time and attention as a director;

● is able to devote the necessary amount of time to prepare for and attend all meetings of the directors and committees of directors, and to keep abreast of significant corporate developments;

● is free of any present or apparent potential legal impediment or conflict of interest, such as:

o serving as an employee or principal of any organization presently providing a significant level of service to the corporation or which might so provide to the corporation, for example, institutions engaged in commercial banking, underwriting, law, management consulting, insurance, or trust companies; or of any substantial customer or supplier of the corporation;

o serving as an employee or director of a competitor of the corporation, such as petroleum or chemical businesses, or of a significant competitor of corporations represented by a director of this corporation;

o serving as the chief executive officer or a top administrator of an organization that has the chief executive officer or a top administrator of this corporation serving as director;

● is expected to remain qualified to serve for a minimum of five years;

● will not, at the time that he or she stands for election or appointment, have attained the age of 72;

● if an independent director, is, or will become within a period of five years of becoming a director, the beneficial owner, directly or indirectly, of not less than 15,000 common shares, deferred share units or restricted stock units of the corporation.

(b)  Tenure

(i) Re-nomination

An incumbent director shall be supported for re-nomination as long as he or she:

● does not suffer from any disability that would prevent the effective discharge of his or her responsibilities as a director;

● makes a positive contribution to the effective performance of the directors;

● regularly attends directors’ and committee meetings;

● has not made a change with respect to principal position or thrust of involvement or regional association that would significantly detract from his or her value as a director of the corporation;

● is not otherwise, to a significant degree, incompatible with the criteria established for use in the selection process;

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● in a situation where it is known that a director will become incompatible with the criteria established for use in the selection process within a three-month period of election, such as retirement from principal position at age 65, this information would be included in the management proxy circular, and where possible, information regarding the proposed replacement would also be included;

● will not, at the time that he or she stands for re-election, have attained the age of 72; however, under exceptional circumstances, at the request of the chairman, the nominations and corporate governance committee may continue to support the nomination.

(ii) Resignation

An incumbent director will resign in the event that he or she:

● experiences a change in circumstances such as a change in his or her principal occupation, including an officer of the corporation ceasing to hold that position, but not merely a change in geographic location;

● displays a change in the exercise of his or her powers and in the discharge of duties that, in the opinion of at least 75 percent of the directors, is incompatible with the duty of care of a director as defined in the Canada Business Corporations Act;

● has made a change in citizenship or residency that will adversely affect the requirements for directors with respect to those areas imposed by the Canada Business Corporations Act;

● has made a change in citizenship or residency that adversely affects the corporation’s status as a foreign private issuer under U.S. securities legislation;

● develops a conflict of interest, such as

o assuming a position as an employee or principal with any organization providing a significant level of service to the corporation, for example, institutions engaged in commercial banking, underwriting, law, management consulting, insurance, or trust companies; or with any substantial customer or supplier of the corporation;

o assuming a position as an employee or director of any competitor of the corporation, such as petroleum or chemical businesses, or of a competitor of corporations represented by a director of this corporation;

o assuming the position of chief executive officer or a top administrator of an organization that has the chief executive officer or a top administrator of this corporation serving as a director;

o becomes unable to devote the necessary amount of time to prepare for and regularly attend meetings of the directors and committees of directors, and to keep abreast of significant corporate developments,

and the nominations and corporate governance committee will make a recommendation to the board as to whether to accept or reject such resignation.

11. Election of Directors

All directors will stand for election at the annual meeting of shareholders. If the majority shareholder’s holdings were ever to fall below 50% for any non-contested elections of directors, any director nominee who receives a greater number of votes “withheld” from his or her election than votes “for” in such election shall tender his or her resignation. Within 90 days after certification of the election results, the board will decide, through a process managed by the nominations and corporate governance committee and excluding the nominee in question, whether to accept the resignation. Absent a compelling reason for the director to remain on the board, the board shall accept the resignation. The board will promptly disclose and, if applicable, the reasons for rejecting the tendered resignation.

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12.  Director Orientation and Continuing Education

(a)  Orientation

New non-employee directors will receive a comprehensive orientation from appropriate executives regarding the corporation’s business and affairs.

(b)  Continuing Education

Reviews of aspects of the corporation’s operations will be presented by appropriate employees from time to time as part of the agenda of regular board meetings. The board will also normally conduct an on-site visit to a location other than the corporation’s headquarters in conjunction with one or more regular board meetings every year.

13.  Chairman and chief executive officer

The board currently believes that it is appropriate and efficient for the corporation’s chief executive officer to also act as chairman of the board. However, the board retains the authority to separate those functions if it deems such action appropriate in the future.

(a)  Position description

The chairman and chief executive officer shall:

● plan and organize all activities of the board of directors;

● ensure that the board receives sufficient, timely information on all material aspects of the corporation’s operations and financial affairs;

● chair annual and special meetings of the shareholders;

● conduct the general management and direction of the business and affairs of the corporation;

● recommend to the board of directors a strategic plan for the corporation’s business and, when approved by the board of directors, implement this strategic plan and report to the board of directors on the implementation of this strategic plan;

● develop and implement operational policies to guide the corporation within the limits prescribed by the corporation’s by-laws and the directions adopted by the board of directors;

● identify, for review with the board of directors, the principal risks of the corporation’s business, where identifiable, and develop appropriate systems to manage such risks;

● under the oversight of the board of directors, develop plans for succession planning for senior management, including the appointing, training and monitoring thereof, and implement those plans;

● ensure compliance with the corporation’s code of ethics and business conduct so as to foster a culture of integrity throughout the company; and

● ensure effective internal controls and management information systems are in place.

(b)  Minimum shareholding requirements

The chairman and chief executive officer shall hold, or shall, within three years after his appointment as chairman and chief executive officer, acquire shares of the corporation, including common shares and restricted stock units, of a value no less than five times his base salary.

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Audit Committee Charter

1. Purpose of the Committee

The primary purpose of the audit committee (the “committee”) is oversight. The committee shall assist the board of directors (the “board”) in fulfilling its responsibility to oversee:

● management’s conduct of the corporation’s financial reporting process,

● the integrity of the financial statements and other financial information provided by the corporation to Canadian securities regulators, the United States Securities and Exchange Commission (the “SEC”) and the public,

● the corporation’s system of internal accounting and financial controls,

● the corporation’s compliance with legal and regulatory requirements,

● the performance of the corporation’s internal audit function,

● the independent auditors’ qualifications, performance, and independence, and

● the annual independent audit of the corporation’s financial statements.

The corporation’s management is responsible for preparing the corporation’s financial statements. The independent auditors are responsible for auditing those financial statements. Management, including the internal audit function, and the independent auditors, have more time, knowledge, and detailed information about the corporation than do committee members. Consequently, in carrying out its oversight responsibilities, the committee is not providing any expert or special assurance as to the corporation’s financial statements, or any professional certification as to the independent auditors’ work, including with respect to auditor independence. Each member of the committee shall be entitled to rely on the integrity of people and organizations from whom the committee receives information and the accuracy of such information, including representations by management and the independent auditors regarding non-audit services provided by the independent auditors.

2. Committee Membership

The committee shall consist of no fewer than three members. Committee members shall be appointed by the board from among its independent members who shall serve at the pleasure of the board, but only so long as he or she continues to be a directors of the corporation and is independent. Each member of the committee must satisfy such criteria of independence as the board may establish and such additional regulatory or listing requirements as the board may determine to be applicable or appropriate. Each member of the committee shall serve only so long as he or she continues to be a director of the corporation and is independent. The actual number of members shall be determined from time to time by resolution of the board.

Accordingly, each member of the committee shall be financially literate within a reasonable period of time after appointment to the committee; must be “independent” as defined in the board charter; and may not serve on more than two other public company audit committees unless the board determines that such simultaneous service would not impair the ability of the member to serve effectively on the committee. In addition, at least one member of the committee shall be an “audit committee financial expert” as defined by applicable laws.

3. Committee Structure and Operation

The chair and vice-chair of the committee shall be designated by the board from among the members of the committee. The committee shall fix its own rules of procedure and shall meet where and as provided by such rules or by resolution of the committee. In addition to the regular meeting schedule established by the committee, the chair of the committee may call a special meeting at any time.

The chair, or in that person’s absence, the vice-chair or in the vice-chair’s absence, an alternate designated by the committee, shall:

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(a) preside at committee meetings;

(b) ensure that meetings of the committee are held in accordance with this charter; and

(c) review, and modify if necessary the agenda of the meetings of this committee in advance to ensure that the committee may effectively carry out its duties.

A majority of the members of the committee shall constitute a quorum thereof. Every question shall be decided by a majority of the votes cast on the question and in the case of an equality of votes, the chair of the meeting shall be entitled to a second or casting vote.

The committee shall designate its secretary.

Meetings of the committee may be called by any member or by the external auditors of the corporation, and notice of every meeting shall be given to the external auditors.

The external auditors and the internal auditor of the corporation shall report directly to the audit committee.

The committee shall act only on the affirmative vote of a majority of the members at a meeting or by unanimous written consent.

The committee may establish sub-committees to carry out such duties as the committee may assign.

4. Committee Activities

The following shall be the common recurring activities of the committee in carrying out its purposes. These activities are set forth as a guide with the understanding that the committee may diverge from this guide as appropriate given the circumstances.

The committee shall:

(a) recommend the external auditors to be appointed by the shareholders, review and recommend their remuneration to the board, approve advances on such remuneration, which shall be paid by the corporation, and oversee their work, including the resolution of disagreements between management and the external auditor regarding financial reporting.

(b) approve the proposed current year audit program of the external auditors and assess the results of the program after the end of the program period.

(c) approve in advance any non-audit services that are permitted by applicable law to be performed by the external auditors after considering the effect of such services on their independence.

(d) receive from the external auditors a formal written statement delineating all relationships between the external auditor and the corporation consistent with Independence Standards Board Standard 1, and shall actively engage in a dialogue with the external auditor with respect to any disclosed relationships or services that may impact the objectivity and independence of the external auditor and shall recommend that the board take any appropriate action to oversee the independence of the external auditor.

(e) maintain hiring policies for employees and former employees of the independent auditors.

(f) establish procedures for the receipt, retention and treatment of complaints received by the corporation regarding accounting, internal accounting controls, or auditing matters and the confidential, anonymous submission by employees of the corporation of concerns regarding questionable accounting or auditing matters.

(g) approve the proposed current year audit program of the internal auditors and assess the results of the program after the end of each quarter.

(h) review the adequacy of the corporation’s system of internal controls and auditing procedures.

(i) review the accounting and financial reporting processes of the corporation.

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(j) approve changes proposed by management in accounting principles and practices, and review changes proposed by the accounting profession or other regulatory bodies which impact directly on such principles and practices.

(k) review the quarterly news release of financial and operating results, the annual and quarterly financial statements of the corporation, any accounting items affecting the statements and the overall format and content of the statements, and the related management discussion and analysis, prior to approval of such news release and financial statements by the board of directors.

(l) review the results of the corporation’s business ethics compliance program.

(m) review annually a summary of senior management expense accounts.

(n) evaluate, along with the other members of the board, management, the controller, and the general auditor, the qualifications, performance and independence of the independent auditors, including the performance of the lead audit partner.

(o) require attendances at its meetings by members of management, as the committee may direct.

(p) undertake such additional activities within the scope of its responsibilities as it may deem appropriate.

5. Committee Evaluation

The committee will annually complete a self-evaluation of the committee’s own performance and effectiveness and will consider whether any changes to the committee’s charter are appropriate.

6. Resources and Authority of the Committee

The committee has exclusive authority with respect to the retention of the independent auditors described in section 4 of this charter. In discharging its oversight role, the committee is empowered to investigate any matter brought to its attention with full access to all books, records, facilities, and personnel of the corporation. The committee also has the authority to retain outside advisors, including legal counsel, auditors, or other experts, as it deems appropriate; to approve the fees and expenses of such advisors; and to incur such other ordinary administrative expenses as are necessary or appropriate in carrying out its duties.

Environment, Health and Safety Committee Charter

1. Purpose of the Committee

The primary purpose of the safety, health and environment committee (the ‘committee’) is to review and provide advice, as the committee deems appropriate, regarding the corporation’s policies, programs and practices on public issues of significance including their effects on safety, health and the environment.

2. Committee Membership

The committee shall consist of no fewer than three members, to be appointed by the board of directors from among (a) the independent directors; and (b) the non-independent directors who are not members of the corporation’s management, who shall serve at the pleasure of the board, but only so long as he or she continues to be a director of the corporation. The actual number of members shall be determined from time to time by resolution of the board. Members of the committee should be suitably knowledgeable in matters pertaining to public issues.

3. Committee Structure and Operation

The chair and vice-chair of the committee shall be designated by the board from among the members of the committee. The committee shall fix its own rules of procedure and shall meet where and as provided by such rules or by resolution of the committee.

The chair, or in that person’s absence, the vice-chair or in the vice-chair’s absence, an alternate designated by the committee, shall:

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(a) preside at committee meetings;

(b) ensure that meetings of the committee are held in accordance with this charter; and

(c) review, and modify if necessary the agenda of the meetings of this committee in advance to ensure that the committee may effectively carry out its duties.

A majority of the members of the committee shall constitute a quorum thereof. Every question shall be decided by a majority of the votes cast on the question and in the case of an equality of votes, the chair of the meeting shall be entitled to a second or casting vote.

The committee shall designate its secretary.

Meetings of the committee may be called by any member.

The committee shall act only on the affirmative vote of a majority of the members at a meeting or by unanimous written consent.

The committee may establish subcommittees consisting of one or more members to carry out such duties as the committee may delegate.

4. Committee Activities

The following shall be the common recurring activities of the committee in carrying out its purpose. These activities are set forth as a guide with the understanding that the committee may diverge from this guide as appropriate given the circumstances.

The committee shall:

(a) review and monitor the effectiveness of the corporation’s policies, programs and practices on safety, health and environment, and make such recommendations to the board with respect thereto as it may deem advisable.

(b) monitor the corporation’s compliance with legislative, regulatory and corporation standards for environmental, health and safety practices and matters, and advise the directors on the results and adequacy thereof.

(c) monitor trends and review current and emerging public policy issues in matters of the environment, health and safety as they may impact the corporation’s operations.

(d) review the impact of proposed legislation in matters of the environment, health and safety on the operations of the corporation and advise the directors and management as to the appropriate response of the corporation thereto.

(e) recommend to the directors and management desirable policies and actions arising from its review and monitoring activity.

(f) require attendances at its meetings by members of management, as the committee may direct.

(g) undertake such additional activities within the scope of its responsibilities as it may deem appropriate.

5. Committee Evaluation

The committee will annually complete a self-evaluation of the committee’s own performance and effectiveness and will consider whether any changes to the committee’s charter are appropriate.

6. Resources and Authority of the Committee

The committee has the authority to retain such outside advisors, including legal counsel or other experts, as it deems appropriate, and to approve the fees and expenses of such advisors.

161

Executive Resources Committee Charter

1. Purpose of the Committee

The primary purpose of the executive resources committee (the “committee”) is to discharge the board of directors’ (the “board”) responsibilities relating to the evaluation and compensation of the corporation’s chief executive officer (the “CEO”) and certain other key senior executive management positions reporting directly to the CEO, including all officers of the corporation, and to discharge the responsibilities of the committee under applicable rules and regulations. The committee also makes recommendations to the board regarding succession planning and development for senior executives and positions as needed.

2. Committee Membership

The committee shall consist of no fewer than three members, to be appointed by the board of directors from among (a) the independent directors; and (b) the non-independent directors who are not members of the corporation’s management, who shall serve at the pleasure of the board, but only so long as he or she continues to be a director of the corporation. The actual number of members shall be determined from time to time by resolution of the board. Members of the committee should be suitably knowledgeable in matters pertaining to executive compensation.

3. Committee Structure and Operation

The chair and vice-chair of the committee shall be designated by the board from among the members of the committee. The committee shall fix its own rules of procedure and shall meet where and as provided by such rules or by resolution of the committee.

The chair, or in that person’s absence, the vice-chair or in the vice-chair’s absence, an alternate designated by the committee, shall:

(a) preside at committee meetings;

(b) ensure that meetings of the committee are held in accordance with this charter; and

(c) review, and modify if necessary the agenda of the meetings of this committee in advance to ensure that the committee may effectively carry out its duties.

A majority of the members of the committee shall constitute a quorum thereof. Every question shall be decided by a majority of the votes cast on the question and in the case of an equality of votes, the chair of the meeting shall be entitled to a second or casting vote.

The committee shall designate its secretary.

Meetings of the committee may be called by any member.

The committee shall act only on the affirmative vote of a majority of the members at a meeting or by unanimous written consent.

The committee may establish subcommittees consisting of one or more members to carry out such duties as the committee may delegate.

4. Committee Activities

The following shall be the common recurring activities of the committee in carrying out its purposes. These activities are set forth as a guide with the understanding that the committee may diverge from this guide as appropriate given the circumstances.

The committee shall:

(a) review and approve the corporate goals and objectives relevant to the compensation of the CEO.

(b) review data on competitive compensation practices and review and evaluate policies and programs through which the corporation compensates its employees.

162

(c) at least annually evaluate the CEO’s performance as measured against the goals and objectives outlined above.

(d) approve salaries and other compensation (including supplemental compensation such as cash bonuses and incentive bonus units, long-term incentive compensation such as restricted stock units, and any other payments for service), for the CEO and other key senior executive management positions reporting directly to the CEO, including all officers of the corporation.

(e) at least annually review succession planning and development strategies for the CEO and key senior executive management positions reporting directly to the CEO, including all officers of the corporation.

(f) review the executive development system to ensure that it foresees the corporation’s senior management requirements and provides for early identification and development of key resources.

(g) review and approve an annual report on compensation for inclusion in the corporation’s management proxy circular in accordance with applicable legal requirements.

(h) make recommendations to the board with respect to incentive compensation plans and equity-based plans.

(i) review proposed terms of any new incentive program and any major amendment of an existing program, and make such recommendations to the board with respect thereto as it may deem advisable.

(j) review and report on risks arising from the corporation’s compensation policies and practices for employees as required by Canadian securities regulators and stock exchanges on which the corporation’s stock trades.

(k) consider factors that could affect the independence or represent a conflict of interest on the part of any compensation consultant, independent legal counsel, or other adviser the committee may retain and report thereon as required by Canadian securities regulators and stock exchanges on which the corporation’s stock trades.

(l) require attendances at its meetings by members of management, as the committee may direct.

(m) undertake such additional activities within the scope of its responsibilities as it may deem appropriate.

5. Committee Evaluation

The committee will annually complete a self-evaluation of the committee’s own performance and effectiveness and will consider whether any changes to the committee’s charter are appropriate.

6. Resources and Authority of the Committee

The committee and, with the approval of the committee, any member, may engage independent counsel, compensation consultants or other advisors at the expense of the corporation. The committee shall be directly responsible for the appointment, compensation and oversight of the work of any independent legal counsel, compensation consultant or other advisor retained by the committee. The committee may select outside legal counsel, a compensation consultant or other advisor (an “Advisor”) to the committee only after taking into consideration all factors relevant to the Advisor’s independence from management, including the following:

● the provision of other services to the corporation by the person that employs the Advisor;

● the amount of fees received from the corporation by the person that employs the Advisor as a percentage of such that person’s total revenue;

● the policies and procedures of the person that employs the Advisor that are designed to prevent conflicts of interest;

● any business or personal relationship of the Advisor with a member of the committee;

● any stock of the corporation owned by the Advisor; and

● any business or personal relationship of the Advisor or the person employing the Advisor with an executive officer of the corporation.

163

Nominations and Corporate Governance Committee Charter

1. Purpose of the Committee

The primary purpose of the nominations and corporate governance committee (the ‘committee’) is to monitor compliance with good corporate governance standards; to identify individuals qualified to become board members; to recommend to the board director nominees for election at the annual meeting of shareholders or for election by the board to fill open seats between annual meetings; to recommend to the board committee appointments for directors, including appointments as chair and vice chair of such committees; to review and make recommendations to the board regarding non-employee director compensation; and to develop and recommend to the board corporate governance guidelines applicable to the corporation.

2. Committee Membership

The committee shall consist of no fewer than three members, to be appointed by the board of directors from among (a) the independent directors; and (b) the non-independent directors who are not members of the corporation’s management, who shall serve at the pleasure of the board, but only so long as he or she continues to be a director of the corporation. The actual number of members shall be determined from time to time by resolution of the board. Members of the committee should be suitably knowledgeable in matters pertaining to corporate governance.

3. Committee Structure and Operation

The chair and vice-chair of the committee shall be designated by the board from among the members of the committee. The committee shall fix its own rules of procedure and shall meet where and as provided by such rules or by resolution of the committee.

The chair, or in that person’s absence, the vice-chair or in the vice-chair’s absence, an alternate designated by the committee, shall:

(a) preside at committee meetings;

(b) ensure that meetings of the committee are held in accordance with this charter; and

(c) review, and modify if necessary the agenda of the meetings of this committee in advance to ensure that the committee may effectively carry out its duties.

A majority of the members of the committee shall constitute a quorum thereof. Every question shall be decided by a majority of the votes cast on the question and in the case of an equality of votes, the chair of the meeting shall be entitled to a second or casting vote.

The committee shall designate its secretary.

Meetings of the committee may be called by any member.

The committee shall act only on the affirmative vote of a majority of the members at a meeting or by unanimous written consent.

The committee may establish subcommittees consisting of one or more members to carry out such duties as the committee may delegate.

4. Committee Activities

The following shall be the common recurring activities of the committee in carrying out its purpose. These activities are set forth as a guide with the understanding that the committee may diverge from this guide as appropriate given the circumstances.

The committee shall:

(a) oversee issues of corporate governance as they apply to the corporation, including the effectiveness of the system of corporate governance, and the board’s relationship with management, and report to the board on such matters.

164

(b) oversee the annual assessment of the effectiveness and contribution of the board, its committees and each individual director.

(c) make recommendations to the board as to the appropriate size of the board with a view to facilitating effective decision-making.

(d) review and recommend to the board of directors any modifications to the charters of the board or any of its committees.

(e) review qualifications of existing directors and individuals suggested as potential candidates for director of the corporation, including candidates suggested by shareholders, and consider for nomination any of such individuals who are deemed qualified pursuant to the provisions of the board charter.

(f) recommend to the board the nominees to be proposed by the board for election as directors of the corporation at the annual meeting of shareholders.

(g) recommend to the board candidates for election as directors of the corporation to fill open seats on the board between annual meetings, including vacancies created by an increase in the authorized number of directors.

(h) consider resignations tendered by directors in the event of:

(i) the majority shareholder’s holdings falling below 50%, for any non-contested election of directors in the event a nominee standing for election by shareholders in a non-contested election receives a greater number of votes withheld from his or her election than votes for such election and, in any such case, refer the matter to the board with the committee’s recommendation whether such resignation should be accepted, or

(ii) a change of circumstance as described in section 10(b)(ii) of the board charter.

(i) review the remuneration of independent directors and make such recommendations to the board with respect thereto as it may deem advisable.

(j) review present plans, programs or arrangements, and any proposed terms of any new plans, programs or arrangements, for the benefit of independent directors, and make such recommendations to the board with respect thereto as it may deem advisable.

(k) review and recommend to the board guidelines to be adopted relating to tenure of independent directors.

(l) provide recommendations to the board concerning committee structure of the board, committee operations, committee member qualifications, and committee member appointment.

(m) review any allegation that an executive officer or director may have violated the corporation’s Standards of Business Conduct and report its findings to the board and the general auditor.

(n) require attendances at its meetings by members of management, as the committee may direct.

(o) undertake such additional activities within the scope of its responsibilities as it may deem appropriate.

5. Committee Evaluation

The committee will annually complete a self-evaluation of the committee’s own performance and effectiveness and will consider whether any changes to the committee’s charter are appropriate.

6. Resources and Authority of the Committee

The committee has the authority to retain such outside advisors, including legal counsel or other experts, as it deems appropriate, and to approve the fees and expenses of such advisors. Without limiting the foregoing, the committee will have sole authority to retain and terminate any search firm to be used by the committee to identify director candidates and any consultant used by the committee to evaluate non-employee director compensation.

165

Contributions Committee Charter

1. Purpose of the Committee

The primary purpose of the contributions committee (the ‘committee’) is to review and provide advice on the corporation’s overall contributions objectives, policies and programs.

2. Committee Membership

The committee shall consist of no fewer than three members to be appointed by the board from among its members who shall serve at the pleasure of the board, but only so long as he or she continues to be a director of the corporation. The actual number of members shall be determined from time to time by resolution of the board. Members of the committee should be suitably knowledgeable in matters pertaining to issues relating to corporate contributions and community investment.

3. Committee Structure and Operation

The chair and vice-chair of the committee shall be designated by the board from among the members of the committee. The committee shall fix its own rules of procedure and shall meet where and as provided by such rules or by resolution of the committee. In addition to the regular meeting schedule established by the committee, the chair of the committee may call a special meeting at any time.

The chair, or in that person’s absence, the vice-chair or in the vice-chair’s absence, an alternate designated by the committee, shall:

(a) preside at committee meetings;

(b) ensure that meetings of the committee are held in accordance with this charter; and

(c) review, and modify if necessary the agenda of the meetings of this committee in advance to ensure that the committee may effectively carry out its duties.

A majority of the members of the committee shall constitute a quorum thereof. Every question shall be decided by a majority of the votes cast on the question and in the case of an equality of votes, the chair of the meeting shall be entitled to a second or casting vote.

The committee shall designate its secretary.

Meetings of the committee may be called by any member.

The committee shall act only on the affirmative vote of a majority of the members at a meeting or by unanimous written consent.

The committee may establish subcommittees consisting of one or more members to carry out such duties as the committee may delegate.

4. Committee Activities

The following shall be the common recurring activities of the committee in carrying out its purpose. These activities are set forth as a guide with the understanding that the committee may diverge from this guide as appropriate given the circumstances.

The committee shall:

(a) review and monitor the corporation’s policies and practices in matters relating to “Community Investment”, which Community Investment shall consist of:

(i) charitable contributions,

(ii) local community contributions by business units on community-serving projects that also benefit the corporation, which are charitable in nature;

(iii) the corporation’s share of community-serving projects described in section 4(a)(ii) above by joint ventures operated by other companies;

166

(iv) funding for public policy groups;

(v) university research awards;

(vi) sponsorships whose primary purpose is to promote brand recognition, product sales or business development; and

(vii) expenditures required under socio-economic agreements to gain access to resources.

(b) review each year, prior to the development of the following year’s budget for Community Investment, proposed overall contributions objectives, policies and programs, including, as appropriate, goals and criteria, the level of corporate contributions, the subject areas to which contributions are to be made and the relative weighting thereof, and the need to make such contributions to gain access to resources or otherwise advance the business objectives of the company.

(c) approve the proposed budget for charitable contributions and local community contributions, as described in sections 4(a)(i) and (ii) above, of the corporation and its consolidated affiliates, and to review such budgets for charitable contributions and local community contributions as to the consistency of such budgets with the contributions objectives, policies and programs established in respect of each year.

(d) review the proposed budget for Community Investment of the corporation and its consolidated affiliates as to the consistency of such budgets with the contributions objectives, policies and programs established in respect of each year, and possible contributions of an unusual amount.

(e) approve all grants or contributions for charitable contributions and local community contributions, as described in sections 4(a)(i) and (ii) above, in excess of $300,000.

(f) require attendances at its meetings by members of management, as the committee may direct.

(g) undertake such additional activities within the scope of its responsibilities as it may deem appropriate.

5. Committee Evaluation

The committee will annually complete a self-evaluation of the committee’s own performance and effectiveness and will consider whether any changes to the committee’s charter are appropriate.

6. Resources and Authority of the Committee

The committee has the authority to retain such outside advisors, including legal counsel or other experts, as it deems appropriate, and to approve the fees and expenses of such advisors.

167

EX-31.1

Exhibit (31.1)

Certifications

I, Richard M. Kruger, certify that:

1. I have reviewed this annual report on Form 10-K of Imperial Oil Limited;

2. Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;

3. Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;

4. The registrant’s other certifying officer(s) and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:

(a) Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;

(b) Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;

(c) Evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and

(d) Disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal quarter (the registrant’s fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting; and

5. The registrant’s other certifying officer(s) and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant’s auditors and the audit committee of the registrant’s board of directors (or persons performing the equivalent functions):

(a) All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and

(b) Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting.

Date:   February 28, 2018

/s/ Richard M. Kruger

Richard M. Kruger

Chairman, president and

chief executive officer

(Principal executive officer)

EX-31.2

Exhibit (31.2)

Certifications

I, Beverley A. Babcock, certify that:

1. I have reviewed this annual report on Form 10-K of Imperial Oil Limited;

2. Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;

3. Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;

4. The registrant’s other certifying officer(s) and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:

(a) Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;

(b) Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;

(c) Evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and

(d) Disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal quarter (the registrant’s fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting; and

5. The registrant’s other certifying officer(s) and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant’s auditors and the audit committee of the registrant’s board of directors (or persons performing the equivalent functions):

(a) All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and

(b) Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting.

Date:  February 28, 2018

/s/ Beverley A. Babcock

Beverley A. Babcock

Senior vice-president, finance and

administration, and controller

(Principal financial officer)

EX-32.1

Exhibit (32.1)

Certification of Periodic Financial Report

Pursuant to 18 U.S.C. Section 1350

For purposes of 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002, the undersigned, Richard M. Kruger, the chief executive officer of Imperial Oil Limited (the “company”), hereby certifies that, to his knowledge:

(i) the Annual Report on Form 10-K of the company for the year ended December 31, 2017 as filed with the Securities and Exchange Commission (the “Report”), fully complies with the requirements of section 13(a) or 15(d) of the Securities Exchange Act of 1934; and

(ii) the information contained in the Report fairly presents, in all material respects, the financial condition and results of operations of the company.

Date:     February 28, 2018

/s/ Richard M. Kruger

Richard M. Kruger

Chairman, president and

chief executive officer

(Principal executive officer)

EX-32.2

Exhibit (32.2)

Certification of Periodic Financial Report

Pursuant to 18 U.S.C. Section 1350

For purposes of 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002, the undersigned, Beverley A. Babcock, the chief financial officer of Imperial Oil Limited (the “company”), hereby certifies that, to her knowledge:

(i) the Annual Report on Form 10-K of the company for the year ended December 31, 2017 as filed with the Securities and Exchange Commission (the “Report”), fully complies with the requirements of section 13(a) or 15(d) of the Securities Exchange Act of 1934; and

(ii) the information contained in the Report fairly presents, in all material respects, the financial condition and results of operations of the company.

Date:    February 28, 2018

/s/ Beverley A. Babcock

Beverley A. Babcock

Senior vice-president, finance and

administration, and controller

(Chief financial officer)

XML

Document and Entity Information - CAD	12 Months Ended
	Dec. 31, 2017	Feb. 07, 2018	Jun. 30, 2017
Document Information [Line Items]
Document Type	10-K
Amendment Flag	false
Document Period End Date	Dec. 31, 2017
Document Fiscal Year Focus	2017
Document Fiscal Period Focus	FY
Trading Symbol	IMO
Entity Registrant Name	IMPERIAL OIL LTD
Entity Central Index Key	0000049938
Current Fiscal Year End Date	--12-31
Entity Well-known Seasoned Issuer	Yes
Entity Current Reporting Status	Yes
Entity Voluntary Filers	No
Entity Filer Category	Large Accelerated Filer
Entity Common Stock, Shares Outstanding		831,242,307
Entity Public Float			CAD 9,702,192,452

XML

Consolidated statement of income - CAD CAD in Millions		12 Months Ended
		Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Revenues and other income
Operating revenues	[1],[2]	CAD 29,125	CAD 25,049	CAD 26,756
Investment and other income (note 8)		299	2,305	132
Total revenues and other income		29,424	27,354	26,888
Expenses
Exploration (note 15)	[3]	183	94	73
Purchases of crude oil and products	[4]	18,145	15,120	15,284
Production and manufacturing	[5]	5,698	5,224	5,434
Selling and general	[5]	893	1,129	1,117
Federal excise tax		1,673	1,650	1,568
Depreciation and depletion	[3]	2,172	1,628	1,450
Financing costs (note 12)	[6]	78	65	39
Total expenses		28,842	24,910	24,965
Income (loss) before income taxes		582	2,444	1,923
Income taxes (note 3)	[7],[8]	92	279	801
Net income (loss)		CAD 490	CAD 2,165	CAD 1,122
Per share information (Canadian dollars)
Net income (loss) per common share - basic (note 10)		CAD 0.58	CAD 2.55	CAD 1.32
Net income (loss) per common share - diluted (note 10)		0.58	2.55	1.32
Dividends per common share		CAD 0.63	CAD 0.59	CAD 0.54

[1] Amounts from related parties included in operating revenues (note 16). 4,110 2,342 3,058

[2] Includes export sales to the United States of $4,392 million (2016 - $3,612 million, 2015 - $4,157 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 16). 2,687 2,224 2,684

[5] Amounts to related parties included in production and manufacturing, and selling and general expenses (note 16). 544 533 442

[6] Cash interest payments in 2017 were $58 million (2016 - $73 million, 2015 - $74 million). The weighted average interest rate on short-term borrowings in 2017 was 0.9 percent (2016 - 0.8 percent, 2015 - 0.8 percent). Average effective rate on the long-term borrowings with ExxonMobil in 2017 was 1.3 percent (2016 - 1.0 percent, 2015 - 1.0 percent).

[7] Cash outflow from income taxes, plus investment credits earned, was $322 million (2016 - $172 million, 2015 - $202 million).

[8] On November 2, 2017 the British Columbia government enacted a 1 percent increase in the provincial tax rate from 11 percent to 12 percent. On June 30, 2015 the Alberta government enacted a 2 percent increase in the provincial tax rate, from 10 percent to 12 percent.

XML

Consolidated statement of income (Parenthetical) - CAD CAD in Millions	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Amounts from related parties included in operating revenues (note 16)	CAD 4,110	CAD 2,342	CAD 3,058
Amounts to related parties included in purchases of crude oil and products (note 16)	2,687	2,224	2,684
Amounts to related parties included in production and manufacturing, and selling and general expenses (note 16)	CAD 544	CAD 533	CAD 442

XML

Consolidated statement of comprehensive income - CAD CAD in Millions	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Net income (loss)	CAD 490	CAD 2,165	CAD 1,122
Other comprehensive income (loss), net of income taxes
Post retirement benefits liability adjustment (excluding amortization)	(54)	(210)	64
Amortization of post retirement benefits liability adjustment included in net periodic benefit costs	136	141	167
Total other comprehensive income (loss)	82	(69)	231
Comprehensive income (loss)	CAD 572	CAD 2,096	CAD 1,353

XML

Consolidated balance sheet - CAD CAD in Millions		Dec. 31, 2017	Dec. 31, 2016
Current assets
Cash	[1]	CAD 1,195	CAD 391
Accounts receivable, less estimated doubtful accounts	[2]	2,712	2,023
Inventories of crude oil and products (note 11)		1,075	949
Materials, supplies and prepaid expenses		425	468
Total current assets		5,407	3,831
Investments and long-term receivables	[3]	865	1,030
Property, plant and equipment, less accumulated depreciation and depletion	[4],[5]	34,473	36,333
Goodwill		186	186
Other assets, including intangibles, net (note 5)		670	274
Total assets		41,601	41,654
Current liabilities
Notes and loans payable (note 12)	[6]	202	202
Accounts payable and accrued liabilities (note 11)	[2]	3,877	3,193
Income taxes payable		57	488
Total current liabilities		4,136	3,883
Long-term debt (note 14)	[7]	5,005	5,032
Other long-term obligations (note 5)	[8]	3,780	3,656
Deferred income tax liabilities (note 3)		4,245	4,062
Total liabilities		17,166	16,633
Commitments and contingent liabilities (note 9)
Shareholders' equity
Common shares at stated value (note 10)	[9]	1,536	1,566
Earnings reinvested		24,714	25,352
Accumulated other comprehensive income (loss) (note 17)		(1,815)	(1,897)
Total shareholders' equity		24,435	25,021
Total liabilities and shareholders' equity		CAD 41,601	CAD 41,654

[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 $509 million (2016 - $172 million), (note 16).

[3] Investments and long-term receivables included amounts from related parties of $19 million (2016 - $0 million), (note 16).

[4] Includes property, plant and equipment under construction of $1,047 million (2016 - $2,705 million, 2015 - $3,719 million).

[5] 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.

[6] Notes and loans payable included amounts to related parties of $75 million (2016 - $75 million), (note 16).

[7] Long-term debt included amounts to related parties of $4,447 million (2016 - $4,447 million), (note 16).

[8] Other long-term obligations included amounts to related parties of $60 million (2016 - $104 million), (note 16).

[9] Number of common shares authorized and outstanding were 1,100 million and 831 million, respectively (2016 - 1,100 million and 848 million, respectively), (note 10).

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Consolidated balance sheet (Parenthetical) - CAD CAD in Millions	Dec. 31, 2017	Dec. 31, 2016
Amounts receivable (payable) from (to) related parties	CAD 509	CAD 172
Due to related parties, current	CAD 75	CAD 75
Common shares authorized	1,100,000,000	1,100,000,000
Common shares outstanding	831,242,000	847,599,000
Investments and Long Term Receivables
Investments and long-term receivables	CAD 19	CAD 0
Long-term debt
Due to related parties	4,447	4,447
Other long-term obligations
Due to related parties	CAD 60	CAD 104

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Consolidated statement of shareholders' equity - CAD CAD in Millions	Total	Common shares at stated value (note 10)	Earnings reinvested	Accumulated other comprehensive income (loss) (note 17)
At beginning of year at Dec. 31, 2014		CAD 1,566	CAD 23,023	CAD (2,059)
Net income (loss) for the year	CAD 1,122		1,122
Issued under the stock option plan		0
Other comprehensive income (loss)	231			231
Dividends declared			(458)
At end of year at Dec. 31, 2015	23,425	1,566	23,687	(1,828)
Net income (loss) for the year	2,165		2,165
Issued under the stock option plan		0
Other comprehensive income (loss)	(69)			(69)
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		0
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	CAD 24,435	CAD 1,536	CAD 24,714	CAD (1,815)

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Consolidated statement of cash flows - CAD CAD in Millions		12 Months Ended
		Dec. 31, 2017		Dec. 31, 2016		Dec. 31, 2015
Operating activities
Net income (loss)		CAD 490		CAD 2,165		CAD 1,122
Adjustments for non-cash items:
Depreciation and depletion	[1]	2,172		1,628		1,450
(Gain) loss on asset sales (note 8)	[2],[3]	(220)		(2,244)		(97)
Inventory write-down to current market value						59
Deferred income taxes and other		321		114		367
Changes in operating assets and liabilities:
Accounts receivable		(689)		(442)		(42)
Inventories, materials, supplies and prepaid expenses		(83)		197		(172)
Income taxes payable		(431)		36		418
Accounts payable and accrued liabilities		678		237		(1,030)
All other items - net	[4],[5]	525		324		92
Cash flows from (used in) operating activities		2,763		2,015		2,167
Investing activities
Additions to property, plant and equipment	[5]	(993)		(1,073)		(2,994)
Proceeds from asset sales (note 8)		232		3,021		142
Additional investments		(1)		(1)		(32)
Loans to equity company		(19)
Cash flows from (used in) investing activities		(781)		1,947		(2,884)
Financing activities
Short-term debt - net				(1,749)		(32)
Long-term debt - additions (note 14)				495		1,206
Long-term debt - reductions (note 14)				(2,000)
Reduction in capitalized lease obligations (note 14)		(27)		(28)		(20)
Dividends paid		(524)		(492)		(449)
Common shares purchased (note 10)		(627)
Cash flows from (used in) financing activities		(1,178)		(3,774)		705
Increase (decrease) in cash		804		188		(12)
Cash at beginning of year		391	[6]	203	[6]	215
Cash at end of year	[6]	CAD 1,195		CAD 391		CAD 203

[1] 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.

[2] 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.

[3] 2017 included a gain of $174 million ($151 million after tax) from the sale of surplus property in Ontario.

[4] Included contribution to registered pension plans. 212 163 225

[5] The impact of carbon emission programs are included in additions to property, plant and equipment, and all other items - net.

[6] 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.

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Consolidated statement of cash flows (Parenthetical) - CAD CAD in Millions	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Included contribution to registered pension plans	CAD 212	CAD 163	CAD 225
Long-term capital lease obligation			CAD 480

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Summary of significant accounting policies

12 Months Ended

Dec. 31, 2017

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

Revenues associated with sales of crude oil, natural gas, petroleum and chemical products and other items are recorded when the products are delivered. Delivery occurs when the customer has taken title and has assumed the risks and rewards of ownership, prices are fixed or determinable and collectability is reasonably assured. 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.

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.

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.

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 has the ability to use 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 “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. Other investments are recorded at cost. Dividends from these other 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. The effect of this approach on the company’s 2018 depreciation expense compared to 2017 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 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 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 technology 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 and 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 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 7 to the consolidated financial statements on page 80 for further details.

Recently issued accounting standards

Effective January 1, 2018, Imperial adopted the Financial Accounting Standards Board (FASB) standard, Revenue from Contracts with Customers, as amended. The standard establishes a single revenue recognition model for all contracts with customers, eliminates industry and transaction specific requirements, and expands disclosure requirements. The standard was adopted using the modified retrospective method, under which prior years’ results are not restated, but supplemental information on the impact of the new standard will be included in the 2018 results if material. The standard is not expected to have a material impact on the company’s financial statements. The cumulative effect of adoption of the new standard is de minimis.

Effective January 1, 2018, Imperial adopted the FASB standard update, Compensation – Retirement Benefits (Topic 715): Improving the Presentation of Net Periodic Pension Cost and Net Periodic Postretirement Benefit Cost. The update requires the service cost component of net benefit costs to be reported in the same line in the income statement as other compensation costs and the other components of net benefit costs (non-service costs) be presented separately from the service cost component. Additionally, only the service cost component of net benefit costs is eligible for capitalization. The company expects to add a new line “Non-service pension and other postretirement benefit” expense to its consolidated statement of income, and expects to include all of these costs in the “Corporate and other” expenses. This line would reflect the non-service costs that were previously included in “Production and manufacturing” expenses, and “Selling and general” expenses. The update is not expected to have a material impact on Imperial’s financial statements.

Effective January 1, 2019, Imperial will adopt the FASB standard, Leases. The standard requires that all leases with an initial term greater than one year be recorded on the balance sheet as an asset and a lease liability. Imperial is gathering and evaluating data, and recently acquired a system to facilitate implementation. The company continues to progress an assessment of the magnitude of the effect on the company’s financial statements.

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Business segments

12 Months Ended

Dec. 31, 2017

Business segments

2. 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 post retirement benefits liability adjustment. Net earnings effects under Corporate and other activities primarily include debt-related financing, corporate governance 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	2017			2016			2015			2017			2016			2015			2017			2016			2015
Revenues and other income
Operating revenues (a)		7,302			5,492			5,776			20,714			18,511			19,796			1,109			1,046			1,184
Intersegment sales		2,264			2,215			2,486			1,155			1,007			1,019			262			212			234
Investment and other income (note 8)		16			13			22			269			2,278			104			-			-			-
		9,582			7,720			8,284			22,138			21,796			20,919			1,371			1,258			1,418
Expenses
Exploration (b) (note 15)		183			94			73			-			-			-			-			-			-
Purchases of crude oil and products		4,526			3,666			3,768			16,543			14,178			14,526			751			705			725
Production and manufacturing		3,913			3,591			3,766			1,576			1,428			1,461			209			205			207
Selling and general		-			(5	)		(2	)		772			972			986			78			83			87
Federal excise tax		-			-			-			1,673			1,650			1,568			-			-			-
Depreciation and depletion (b)		1,939			1,396			1,193			202			206			233			12			10			11
Financing costs (note 12)		13			(7	)		5			-			-			-			-			-			-
Total expenses		10,574			8,735			8,803			20,766			18,434			18,774			1,050			1,003			1,030
Income (loss) before income taxes		(992	)		(1,015	)		(519	)		1,372			3,362			2,145			321			255			388
Income taxes (note 3)
Current		484			(491	)		(77	)		(504	)		674			476			(32	)		68			97
Deferred		(770	)		137			262			836			(66	)		83			118			-			4
Total income tax expense (benefit)		(286	)		(354	)		185			332			608			559			86			68			101
Net income (loss)		(706	)		(661	)		(704	)		1,040			2,754			1,586			235			187			287
Cash flows from (used in) operating activities		1,257			402			224			1,396			1,574			1,686			235			203			383
Capital and exploration expenditures (c)		416			896			3,135			200			190			340			17			26			52
Property, plant and equipment
Cost		45,542			45,850			45,171			5,683			6,166			7,596			888			872			857
Accumulated depreciation and depletion		(13,844	)		(12,312	)		(11,016	)		(3,594	)		(4,037	)		(4,584	)		(644	)		(629	)		(616	)
Net property, plant and equipment (b) (d)		31,698			33,538			34,155			2,089			2,129			3,012			244			243			241
Total assets		35,044			36,840			36,971			4,890			3,958			5,574			399			346			394
	Corporate and other									Eliminations									Consolidated
millions of Canadian dollars	2017			2016			2015			2017			2016			2015			2017			2016			2015
Revenues and other income
Operating revenues (a)		-			-			-			-			-			-			29,125			25,049			26,756
Intersegment sales		-			-			-			(3,681	)		(3,434	)		(3,739	)		-			-			-
Investment and other income (note 8)		14			14			6			-			-			-			299			2,305			132
		14			14			6			(3,681	)		(3,434	)		(3,739	)		29,424			27,354			26,888
Expenses
Exploration (b) (note 15)		-			-			-			-			-			-			183			94			73
Purchases of crude oil and products		-			-			-			(3,675	)		(3,429	)		(3,735	)		18,145			15,120			15,284
Production and manufacturing		-			-			-			-			-			-			5,698			5,224			5,434
Selling and general		49			84			50			(6	)		(5	)		(4	)		893			1,129			1,117
Federal excise tax		-			-			-			-			-			-			1,673			1,650			1,568
Depreciation and depletion (b)		19			16			13			-			-			-			2,172			1,628			1,450
Financing costs (note 12)		65			72			34			-			-			-			78			65			39
Total expenses		133			172			97			(3,681	)		(3,434	)		(3,739	)		28,842			24,910			24,965
Income (loss) before income taxes		(119	)		(158	)		(91	)		-			-			-			582			2,444			1,923
Income taxes (note 3)
Current		(6	)		(51	)		(45	)		-			-			-			(58	)		200			451
Deferred		(34	)		8			1			-			-			-			150			79			350
Total income tax expense (benefit)		(40	)		(43	)		(44	)		-			-			-			92			279			801
Net income (loss)		(79	)		(115	)		(47	)		-			-			-			490			2,165			1,122
Cash flows from (used in) operating activities		(125	)		(143	)		(124	)		-			(21	)		(2	)		2,763			2,015			2,167
Capital and exploration expenditures (c)		38			49			68			-			-			-			671			1,161			3,595
Property, plant and equipment
Cost		665			627			579			-			-			-			52,778			53,515			54,203
Accumulated depreciation and depletion		(223	)		(204	)		(188	)		-			-			-			(18,305	)		(17,182	)		(16,404	)
Net property, plant and equipment (b) (d)		442			423			391			-			-			-			34,473			36,333			37,799
Total assets		1,703			894			579			(435	)		(384	)		(348	)		41,601			41,654			43,170

(a) Includes export sales to the United States of $4,392 million (2016 - $3,612 million, 2015 - $4,157 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) 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.

(d) Includes property, plant and equipment under construction of $1,047 million (2016 - $2,705 million, 2015 - $3,719 million).

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Income taxes

12 Months Ended

Dec. 31, 2017

Income taxes

3. Income taxes

millions of Canadian dollars	2017			2016			2015
Current income tax expense (a)		(58	)		200			451
Deferred income tax expense (a) (b)		150			79			350
Total income tax expense (a) (c)		92			279			801
Statutory corporate tax rate (percent)		26.9			26.8			27.2
Increase (decrease) resulting from:
Disposals (d)		(5.3	)		(11.6	)		(0.4	)
Enacted tax rate change (a)		0.9			-			16.1
Other		(6.6	)		(3.8	)		(1.2	)
Effective income tax rate		15.9			11.4			41.7

(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. On June 30, 2015 the Alberta government enacted a 2 percent increase in the provincial tax rate, from 10 percent to 12 percent.

(b) There were no material net (charges) credits for the effect of changes in tax laws and rates included in the provisions for deferred income taxes in 2016.

(c) Cash outflow from income taxes, plus investment credits earned, was $322 million (2016 - $172 million, 2015 - $202 million).

(d) 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 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	2017			2016			2015
Depreciation and amortization		5,564			5,361			4,677
Successful drilling and land acquisitions		762			891			922
Pension and benefits		(422	)		(457	)		(396	)
Asset retirement obligation		(376	)		(396	)		(406	)
Capitalized interest		118			114			104
LIFO inventory valuation (a)		(318	)		(240	)		-
Tax loss carryforwards		(936	)		(1,056	)		(610	)
Other (a)		(196	)		(212	)		(100	)
Net long-term deferred income tax liabilities		4,196			4,005			4,191
LIFO inventory valuation (a)		-			-			(112	)
Other (a)		-			-			(160	)
Net current deferred income tax assets		-			-			(272	)
Net current deferred income tax liabilities (a)		-			-			41
Net deferred income tax liabilities		4,196			4,005			3,960

(a) Effective 2016, under ASU 2015-17, deferred tax assets and liabilities have been classified as non-current. 2015 was not restated.

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	2017			2016			2015
Balance as of January 1		106			132			151
Additions for prior years’ tax position		2			2			10
Reductions for prior years’ tax positions		-			(18	)		(4	)
Reductions due to lapse of the statute of limitations		-			(5	)		-
Settlements with tax authorities		(30	)		(5	)		(25	)
Balance as of December 31		78			106			132

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 2017, 2016 and 2015 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 2010 to 2017 are subject to examination by the tax authorities. Tax filings from 1998, 2000 and 2003 to 2009 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 2018. 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.

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Employee retirement benefits

12 Months Ended

Dec. 31, 2017

Employee retirement benefits

4. 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 post retirement benefits
	2017			2016			2017			2016
Assumptions used to determine benefit obligations at December 31 (percent)
Discount rate		3.40			3.75			3.40			3.75
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		8,356			8,147			706			642
Current service cost		217			203			16			16
Interest cost		313			319			23			27
Actuarial loss (gain)		415			157			(49	)		46
Benefits paid (a)		(516	)		(470	)		(26	)		(25	)
Projected benefit obligation at December 31		8,785			8,356			670			706
Accumulated benefit obligation at December 31		8,043			7,681

The discount rate for the purpose of calculating year-end post retirement benefits plan liabilities is determined by using the Canadian Institute of Actuaries recommended spot curve for high-quality, long-term Canadian corporate bonds with an average maturity (or duration) approximating that of the liabilities. The measurement of the accumulated post retirement benefit obligation assumes a health care cost trend rate of 4.50 percent in 2018 and subsequent years.

	Pension benefits						Other post retirement benefits
millions of Canadian dollars	2017			2016			2017			2016
Change in plan assets
Fair value at January 1		7,359			7,260
Actual return (loss) on plan assets		700			316
Company contributions		212			163
Benefits paid (b)		(401	)		(380	)
Fair value at December 31		7,870			7,359
Plan assets in excess of (less than) projected benefit obligation at December 31
Funded plans		(408	)		(444	)
Unfunded plans		(507	)		(553	)		(670	)		(706	)
Total (c)		(915	)		(997	)		(670	)		(706	)

(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 post retirement benefits plans, the underfunded status of the company’s defined benefit post retirement plans was recorded as a liability in the 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 post retirement benefits
millions of Canadian dollars	2017			2016			2017			2016
Amounts recorded in the consolidated balance sheet consist of:
Current liabilities		(28	)		(29	)		(28	)		(29	)
Other long-term obligations		(887	)		(968	)		(642	)		(677	)
Total recorded		(915	)		(997	)		(670	)		(706	)
Amounts recorded in accumulated other comprehensive income consist of:
Net actuarial loss (gain)		2,408			2,461			140			197
Prior service cost		4			14			-			-
Total recorded in accumulated other     comprehensive income, before tax		2,412			2,475			140			197

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 2017 long-term expected return of 5.5 percent used in the calculations of pension expense compares to an actual rate of return of 6.3 percent and 7.3 percent over the last 10- and 20-year periods respectively, ending December 31, 2017.

	Pension benefits									Other post retirement benefits
millions of Canadian dollars	2017			2016			2015			2017			2016			2015
Assumptions used to determine net periodic benefit cost for years ended December 31 (percent)
Discount rate		3.75			4.00			3.75			3.75			4.00			3.75
Long-term rate of return on funded assets		5.50			5.50			5.75			-			-			-
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		217			203			211			16			16			15
Interest cost		313			319			307			23			27			25
Expected return on plan assets		(408	)		(400	)		(392	)		-			-			-
Amortization of prior service cost		10			9			16			-			-			-
Amortization of actuarial loss (gain)		176			162			198			8			13			14
Net periodic benefit cost		308			293			340			47			56			54
Changes in amounts recorded in accumulated other comprehensive income
Net actuarial loss (gain)		123			241			(86	)		(49	)		46			(2	)
Amortization of net actuarial (loss) gain included in net periodic benefit cost		(176	)		(162	)		(198	)		(8	)		(13	)		(14	)
Amortization of prior service cost included in net periodic benefit cost		(10	)		(9	)		(16	)		-			-			-
Total recorded in other comprehensive income		(63	)		70			(300	)		(57	)		33			(16	)
Total recorded in net periodic benefit cost and other comprehensive income, before tax		245			363			40			(10	)		89			38

Costs for defined contribution plans, primarily the employee savings plan, were $40 million in 2017 (2016 - $44 million, 2015 - $43 million).

A summary of the change in accumulated other comprehensive income is shown in the table below:

	Total pension and other post retirement benefits
millions of Canadian dollars	2017			2016			2015
(Charge) credit to other comprehensive income, before tax		120			(103	)		316
Deferred income tax (charge) credit (note 17)		(38	)		34			(85	)
(Charge) credit to other comprehensive income, after tax		82			(69	)		231

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 indexed equity and domestic indexed bond funds to diversify risk while minimizing costs. The equity funds hold Imperial Oil Limited stock only to the extent necessary to replicate the relevant equity index. The balance of the plan assets is largely invested in high-quality corporate and government debt securities. Studies are periodically conducted to establish the preferred target asset allocation. The target asset allocation for equity securities is 28 percent. The target allocation for debt securities is 67 percent. Plan assets for the remaining 5 percent are invested in venture capital partnerships that pursue a strategy of investment in U.S. and international early stage ventures.

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 Value
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

The 2016 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, 2016, using:
millions of Canadian dollars	Total	Level 1	Level 2	Level 3	Net Asset Value (a)
Asset class
Equity securities
Canadian	433				433
Non-Canadian	2,448				2,448
Debt securities - Canadian
Corporate	988				988
Government	3,218				3,218
Asset backed	-				-
Equities – Venture capital	241				241
Cash	31	6			25
Total plan assets at fair value	7,359	6	-	-	7,353

(a) Per ASU 2015-07, certain investments that are measured at fair value using the Net Asset Value (NAV) per share practical expedient have been re-categorized from the fair value hierarchy. The fair value amounts presented in this table are intended to permit reconciliation of the fair value hierarchy to the total value 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	2017		2016
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		507		553
Accumulated benefit obligation		480		525

Estimated 2018 amortization from accumulated other comprehensive income

millions of Canadian dollars	Pension benefits		Other post retirement benefits
Net actuarial loss (gain) (a)		170	9
Prior service cost (b)		4	-

(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.

(b) The company amortizes prior service cost on a straight-line basis.

Cash flows

Benefit payments expected in:

millions of Canadian dollars	Pension benefits		Other post retirement  benefits
2018		425		29
2019		430		29
2020		435		29
2021		435		30
2022		435		30
2023 - 2027		2,165		155

In 2018, the company expects to make cash contributions of about $240 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		(75)		75
Discount rate:
Effect on net benefit cost, before tax		(90)		120
Effect on benefit obligation		(1,215)		1,570
Rate of pay increases:
Effect on net benefit cost, before tax		55		(45)
Effect on benefit obligation		265		(225)

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		80		(60)

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Other long-term obligations

12 Months Ended

Dec. 31, 2017

Other long-term obligations

5. Other long-term obligations

millions of Canadian dollars	2017		2016
Employee retirement benefits (a) (note 4)		1,529		1,645
Asset retirement obligations and other environmental liabilities (b) (d)		1,460		1,544
Share-based incentive compensation liabilities (note 7)		99		139
Other obligations (c)		692		328
Total other long-term obligations		3,780		3,656

(a) Total recorded employee retirement benefits obligations also included $56 million in current liabilities (2016 – $58 million).

(b) Total asset retirement obligations and other environmental liabilities also included $101 million in current liabilities (2016 – $108 million).

(c) Included carbon emission program obligations. Carbon emission program credits are recorded under other assets, including intangibles, net.

(d) For 2017, the asset retirement obligations were discounted at 6 percent (2016 - 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	2017			2016
Balance as at January 1		1,472			1,571
Additions (deductions)		(124	)		(160	)
Accretion		92			97
Settlement		(43	)		(36	)
Balance as at December 31		1,397			1,472

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Derivatives and financial instruments

12 Months Ended

Dec. 31, 2017

Derivatives and financial instruments

6. Derivatives and financial 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 currency exchange rates and commodity prices. The company makes use of 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 estimated fair value of derivative instruments outstanding and recorded on the balance sheet was a net liability of $4 million at year-end 2017 (2016 - $0 million). Assets and liabilities associated with derivatives are usually recorded either in “Materials, supplies and prepaid expenses” or “Accounts payable and accrued liabilities”.

The company’s fair value measurement of its derivative instruments use either Level 1 or Level 2 inputs.

The company recognized a before-tax loss related to settled and unsettled derivative instruments of $5 million during 2017 (2016 - $0 million). Income statement effects associated with derivatives are recorded in “Purchases of crude oil and products”.

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 values of the company’s financial instruments and the recorded book value. The fair value hierarchy for long-term debt is primarily Level 2.

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Share-based incentive compensation programs

12 Months Ended

Dec. 31, 2017

Share-based incentive compensation programs

7. 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, 2017:

	Restricted stock units			Deferred     share units
Outstanding at January 1, 2017		6,662,126			136,177
Granted		758,990			13,231
Vested / Exercised		(1,545,921	)		-
Forfeited and cancelled		(16,145	)		-
Outstanding at December 31, 2017		5,859,050			149,408

In 2017, the before-tax compensation expense charged against income for these programs was $14 million (2016 - $83 million, 2015 - $48 million). Income tax benefit recognized in income related to compensation expense for the year was $4 million (2016 - $24 million, 2015 - $13 million). Cash payments of $71 million were made for these programs in 2017 (2016 - $79 million, 2015 - $78 million).

As of December 31, 2017, there was $94 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 3.8 years. All units under the deferred share programs have vested as of December 31, 2017.

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Investment and other income

12 Months Ended

Dec. 31, 2017

Investment and other income

8. Investment and other income

Investment and other income includes gains and losses on asset sales as follows:

millions of Canadian dollars	2017		2016		2015
Proceeds from asset sales		232		3,021		142
Book value of asset sales		12		777		45
Gain (loss) on asset sales, before tax (a) (b)		220		2,244		97
Gain (loss) on asset sales, after tax (a) (b)		192		1,908		79

(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.

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Litigation and other contingencies

12 Months Ended

Dec. 31, 2017

Litigation and other contingencies

9. 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. No unconditional purchase obligations existed in 2017 and 2016 (2015 - $125 million).

As a result of the completed sale of Imperial’s remaining company-owned Esso retail sites, the company was contingently liable at December 31, 2017, for guarantees relating to performance under contracts of other third-party obligations totaling $42 million (2016 - $49 million).

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Common shares

12 Months Ended

Dec. 31, 2017

Common shares

10. Common shares

thousands of shares	As at Dec 31 2017		As at         Dec 31 2016
Authorized		1,100,000		1,100,000
Common shares outstanding		831,242		847,599

The current 12-month normal course issuer bid program was announced on June 22, 2017, under which Imperial continued its share purchase program. The program enables the company to purchase up to a maximum of 25,395,927 common shares (3 percent of the total shares on June 13, 2017), 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 shares			Millions of dollars
Balance as at January 1, 2015		847,599			1,566
Issued under employee share-based awards		1			-
Purchases at stated value		(1	)		-
Balance as at December 31, 2015		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

The following table provides the calculation of basic and diluted earnings per common share:

	2017		2016		2015
Net income (loss) per common share – basic
Net income (loss) (millions of Canadian dollars)		490		2,165		1,122
Weighted average number of common shares outstanding (millions of shares)		842.9		847.6		847.6
Net income (loss) per common share (dollars)		0.58		2.55		1.32
Net income (loss) per common share - diluted
Net income (loss) (millions of Canadian dollars)		490		2,165		1,122
Weighted average number of common shares outstanding (millions of shares)		842.9		847.6		847.6
Effect of employee share-based awards (millions of shares)		2.8		2.9		3.0
Weighted average number of common shares outstanding, assuming dilution (millions of shares)		845.7		850.5		850.6
Net income (loss) per common share (dollars)		0.58		2.55		1.32

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Miscellaneous financial information

12 Months Ended

Dec. 31, 2017

Miscellaneous financial information

11. Miscellaneous financial information

In 2017, net income included an after-tax gain of $5 million (2016 – $5 million gain, 2015 – $39 million loss) 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, 2017 by about $1.4 billion (2016 – $1 billion). Inventories of crude oil and products at year-end consisted of the following:

millions of Canadian dollars	2017		2016
Crude oil		690		558
Petroleum products		307		300
Chemical products		42		51
Natural gas and other		36		40
Total inventories of crude oil and products		1,075		949

Net research and development costs charged to expenses in 2017 were $111 million (2016 – $152 million, 2015 – $149 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 $437 million at December 31, 2017 (2016 – $396 million).

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Financing costs and additional notes and loans payable information

12 Months Ended

Dec. 31, 2017

Financing costs and additional notes and loans payable information

12. Financing costs and additional notes and loans payable information

millions of Canadian dollars	2017			2016			2015
Debt-related interest		103			121			102
Capitalized interest		(38	)		(49	)		(68	)
Net interest expense		65			72			34
Other interest		13			(7	)		5
Total financing costs (a)		78			65			39

 (a) Cash interest payments in 2017 were $58 million (2016 – $73 million, 2015 – $74 million). The weighted average interest rate on short-term borrowings in 2017 was 0.9 percent (2016 – 0.8 percent, 2015 – 0.8 percent). Average effective rate on the long-term borrowings with ExxonMobil in 2017 was 1.3 percent (2016 - 1.0 percent, 2015 - 1.0 percent).

As at December 31, 2017, the company had borrowed $75 million under an arrangement with an affiliated company of ExxonMobil that provides for a non-interest bearing, revolving demand loan from ExxonMobil to the company of up to $75 million. The loan represents ExxonMobil’s share of a working capital facility required to support purchasing, marketing and transportation arrangements for crude oil and diluent products undertaken by Imperial on behalf of ExxonMobil.

In November 2017, the company extended the maturity date of its existing $250 million committed long-term line of credit to November 2019. The company has not drawn on the facility.

In December 2017, the company extended the maturity date of its existing $250 million committed short-term line of credit to December 2018. The company has not drawn on the facility.

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Leased facilities

12 Months Ended

Dec. 31, 2017

Leased facilities

13. Leased facilities

At December 31, 2017, the company held non-cancelable operating leases covering primarily storage tanks, rail cars and marine vessels, with minimum undiscounted lease commitments totaling $199 million as indicated in the following table:

	Payments due by period
millions of Canadian dollars	2018		2019		2020		2021		2022		After 2022		Total
Lease payments under minimum commitments (a)		120		56		19		2		1		1		199

 (a) Net rental cost under cancelable and non-cancelable operating leases incurred in 2017 was $206 million (2016 - $253 million, 2015 - $311 million). Related rental income was not material.

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Long-term debt

12 Months Ended

Dec. 31, 2017

Long-term debt

14. Long-term debt

millions of Canadian dollars	As at Dec 31 2017		As at         Dec 31 2016
Long-term debt (a)		4,447		4,447
Capital leases (b)		558		585
Total long-term debt		5,005		5,032

 (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 7.0 percent in 2017 (2016 – 6.9 percent). Total capitalized lease obligations also include $27 million in current liabilities (2016 - $27 million). Principal payments on capital leases of approximately $21 million on average per year are due in each of the next four years after December 31, 2018.

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Accounting for suspended exploratory well costs

12 Months Ended

Dec. 31, 2017

Accounting for suspended exploratory well costs

15. 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	2017			2016			2015
Balance as at January 1		143			167			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			167

Period end capitalized suspended exploratory well costs:

millions of Canadian dollars	2017		2016		2015
Capitalized for a period of one year or less		-		-		-
Capitalized for a period of between one and ten years		-		143		167
Capitalized for a period of greater than one year		-		143		167
Total		-		143		167

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.

	2017		2016		2015
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		1
Total		-		1		1

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Transactions with related parties

12 Months Ended

Dec. 31, 2017

Transactions with related parties

16. 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) Whereby ExxonMobil enters 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 2017, with ExxonMobil, were $2,648 million and $4,080 million respectively (2016 - $2,187 million and $2,315 million respectively).

As at December 31, 2017, the company had outstanding long-term loans of $4,447 million (2016 – $4,447 million) and short-term loans of $75 million (2016 – $75 million) from ExxonMobil (see note 14 “Long-term debt”, on page 84 and note 12, “Financing costs and additional notes and loans payable information”, on page 83 for further details).

Imperial has other related party transactions not detailed above in note 16, as they are not significant.

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Other comprehensive income (loss) information

12 Months Ended

Dec. 31, 2017

Other comprehensive income (loss) information

17. Other comprehensive income (loss) information

Changes in accumulated other comprehensive income (loss):

millions of Canadian dollars	2017			2016			2015
Balance at January 1		(1,897	)		(1,828	)		(2,059	)
Post retirement benefits liability adjustment:
Current period change excluding amounts reclassified from accumulated other comprehensive income		(54	)		(210	)		64
Amounts reclassified from accumulated other comprehensive income		136			141			167
Balance at December 31		(1,815	)		(1,897	)		(1,828	)

Amounts reclassified out of accumulated other comprehensive income (loss) - before-tax income (expense):

millions of Canadian dollars	2017			2016			2015
Amortization of post retirement benefits liability adjustment included in net periodic benefit cost (a)		(194	)		(184	)		(228	)

 (a) This accumulated other comprehensive income component is included in the computation of net periodic benefit cost (note 4).

Income tax expense (credit) for components of other comprehensive income (loss):

millions of Canadian dollars	2017			2016			2015
Post retirement benefits liability adjustments:
Post retirement benefits liability adjustment (excluding amortization)		(20	)		(77	)		24
Amortization of post retirement benefits liability adjustment included in net periodic benefit cost		58			43			61
Total		38			(34	)		85

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Summary of significant accounting policies (Policies)

12 Months Ended

Dec. 31, 2017

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

Revenues associated with sales of crude oil, natural gas, petroleum and chemical products and other items are recorded when the products are delivered. Delivery occurs when the customer has taken title and has assumed the risks and rewards of ownership, prices are fixed or determinable and collectability is reasonably assured. 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.

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.

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.

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 has the ability to use 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 “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. Other investments are recorded at cost. Dividends from these other 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. The effect of this approach on the company’s 2018 depreciation expense compared to 2017 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 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 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 technology 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 and 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 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 7 to the consolidated financial statements on page 80 for further details.

Recently issued accounting standards

Recently issued accounting standards

Effective January 1, 2018, Imperial adopted the Financial Accounting Standards Board (FASB) standard, Revenue from Contracts with Customers, as amended. The standard establishes a single revenue recognition model for all contracts with customers, eliminates industry and transaction specific requirements, and expands disclosure requirements. The standard was adopted using the modified retrospective method, under which prior years’ results are not restated, but supplemental information on the impact of the new standard will be included in the 2018 results if material. The standard is not expected to have a material impact on the company’s financial statements. The cumulative effect of adoption of the new standard is de minimis.

Effective January 1, 2018, Imperial adopted the FASB standard update, Compensation – Retirement Benefits (Topic 715): Improving the Presentation of Net Periodic Pension Cost and Net Periodic Postretirement Benefit Cost. The update requires the service cost component of net benefit costs to be reported in the same line in the income statement as other compensation costs and the other components of net benefit costs (non-service costs) be presented separately from the service cost component. Additionally, only the service cost component of net benefit costs is eligible for capitalization. The company expects to add a new line “Non-service pension and other postretirement benefit” expense to its consolidated statement of income, and expects to include all of these costs in the “Corporate and other” expenses. This line would reflect the non-service costs that were previously included in “Production and manufacturing” expenses, and “Selling and general” expenses. The update is not expected to have a material impact on Imperial’s financial statements.

Effective January 1, 2019, Imperial will adopt the FASB standard, Leases. The standard requires that all leases with an initial term greater than one year be recorded on the balance sheet as an asset and a lease liability. Imperial is gathering and evaluating data, and recently acquired a system to facilitate implementation. The company continues to progress an assessment of the magnitude of the effect on the company’s financial statements.

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Business segments (Tables)

12 Months Ended

Dec. 31, 2017

Business Segments

	Upstream									Downstream									Chemical
millions of Canadian dollars	2017			2016			2015			2017			2016			2015			2017			2016			2015
Revenues and other income
Operating revenues (a)		7,302			5,492			5,776			20,714			18,511			19,796			1,109			1,046			1,184
Intersegment sales		2,264			2,215			2,486			1,155			1,007			1,019			262			212			234
Investment and other income (note 8)		16			13			22			269			2,278			104			-			-			-
		9,582			7,720			8,284			22,138			21,796			20,919			1,371			1,258			1,418
Expenses
Exploration (b) (note 15)		183			94			73			-			-			-			-			-			-
Purchases of crude oil and products		4,526			3,666			3,768			16,543			14,178			14,526			751			705			725
Production and manufacturing		3,913			3,591			3,766			1,576			1,428			1,461			209			205			207
Selling and general		-			(5	)		(2	)		772			972			986			78			83			87
Federal excise tax		-			-			-			1,673			1,650			1,568			-			-			-
Depreciation and depletion (b)		1,939			1,396			1,193			202			206			233			12			10			11
Financing costs (note 12)		13			(7	)		5			-			-			-			-			-			-
Total expenses		10,574			8,735			8,803			20,766			18,434			18,774			1,050			1,003			1,030
Income (loss) before income taxes		(992	)		(1,015	)		(519	)		1,372			3,362			2,145			321			255			388
Income taxes (note 3)
Current		484			(491	)		(77	)		(504	)		674			476			(32	)		68			97
Deferred		(770	)		137			262			836			(66	)		83			118			-			4
Total income tax expense (benefit)		(286	)		(354	)		185			332			608			559			86			68			101
Net income (loss)		(706	)		(661	)		(704	)		1,040			2,754			1,586			235			187			287
Cash flows from (used in) operating activities		1,257			402			224			1,396			1,574			1,686			235			203			383
Capital and exploration expenditures (c)		416			896			3,135			200			190			340			17			26			52
Property, plant and equipment
Cost		45,542			45,850			45,171			5,683			6,166			7,596			888			872			857
Accumulated depreciation and depletion		(13,844	)		(12,312	)		(11,016	)		(3,594	)		(4,037	)		(4,584	)		(644	)		(629	)		(616	)
Net property, plant and equipment (b) (d)		31,698			33,538			34,155			2,089			2,129			3,012			244			243			241
Total assets		35,044			36,840			36,971			4,890			3,958			5,574			399			346			394
	Corporate and other									Eliminations									Consolidated
millions of Canadian dollars	2017			2016			2015			2017			2016			2015			2017			2016			2015
Revenues and other income
Operating revenues (a)		-			-			-			-			-			-			29,125			25,049			26,756
Intersegment sales		-			-			-			(3,681	)		(3,434	)		(3,739	)		-			-			-
Investment and other income (note 8)		14			14			6			-			-			-			299			2,305			132
		14			14			6			(3,681	)		(3,434	)		(3,739	)		29,424			27,354			26,888
Expenses
Exploration (b) (note 15)		-			-			-			-			-			-			183			94			73
Purchases of crude oil and products		-			-			-			(3,675	)		(3,429	)		(3,735	)		18,145			15,120			15,284
Production and manufacturing		-			-			-			-			-			-			5,698			5,224			5,434
Selling and general		49			84			50			(6	)		(5	)		(4	)		893			1,129			1,117
Federal excise tax		-			-			-			-			-			-			1,673			1,650			1,568
Depreciation and depletion (b)		19			16			13			-			-			-			2,172			1,628			1,450
Financing costs (note 12)		65			72			34			-			-			-			78			65			39
Total expenses		133			172			97			(3,681	)		(3,434	)		(3,739	)		28,842			24,910			24,965
Income (loss) before income taxes		(119	)		(158	)		(91	)		-			-			-			582			2,444			1,923
Income taxes (note 3)
Current		(6	)		(51	)		(45	)		-			-			-			(58	)		200			451
Deferred		(34	)		8			1			-			-			-			150			79			350
Total income tax expense (benefit)		(40	)		(43	)		(44	)		-			-			-			92			279			801
Net income (loss)		(79	)		(115	)		(47	)		-			-			-			490			2,165			1,122
Cash flows from (used in) operating activities		(125	)		(143	)		(124	)		-			(21	)		(2	)		2,763			2,015			2,167
Capital and exploration expenditures (c)		38			49			68			-			-			-			671			1,161			3,595
Property, plant and equipment
Cost		665			627			579			-			-			-			52,778			53,515			54,203
Accumulated depreciation and depletion		(223	)		(204	)		(188	)		-			-			-			(18,305	)		(17,182	)		(16,404	)
Net property, plant and equipment (b) (d)		442			423			391			-			-			-			34,473			36,333			37,799
Total assets		1,703			894			579			(435	)		(384	)		(348	)		41,601			41,654			43,170

(a) Includes export sales to the United States of $4,392 million (2016 - $3,612 million, 2015 - $4,157 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) 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.

(d) Includes property, plant and equipment under construction of $1,047 million (2016 - $2,705 million, 2015 - $3,719 million).

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Income taxes (Tables)

12 Months Ended

Dec. 31, 2017

Summary of Income Tax Expense (Benefit)

millions of Canadian dollars	2017			2016			2015
Current income tax expense (a)		(58	)		200			451
Deferred income tax expense (a) (b)		150			79			350
Total income tax expense (a) (c)		92			279			801
Statutory corporate tax rate (percent)		26.9			26.8			27.2
Increase (decrease) resulting from:
Disposals (d)		(5.3	)		(11.6	)		(0.4	)
Enacted tax rate change (a)		0.9			-			16.1
Other		(6.6	)		(3.8	)		(1.2	)
Effective income tax rate		15.9			11.4			41.7

(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. On June 30, 2015 the Alberta government enacted a 2 percent increase in the provincial tax rate, from 10 percent to 12 percent.

(b) There were no material net (charges) credits for the effect of changes in tax laws and rates included in the provisions for deferred income taxes in 2016.

(c) Cash outflow from income taxes, plus investment credits earned, was $322 million (2016 - $172 million, 2015 - $202 million).

(d) 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	2017			2016			2015
Depreciation and amortization		5,564			5,361			4,677
Successful drilling and land acquisitions		762			891			922
Pension and benefits		(422	)		(457	)		(396	)
Asset retirement obligation		(376	)		(396	)		(406	)
Capitalized interest		118			114			104
LIFO inventory valuation (a)		(318	)		(240	)		-
Tax loss carryforwards		(936	)		(1,056	)		(610	)
Other (a)		(196	)		(212	)		(100	)
Net long-term deferred income tax liabilities		4,196			4,005			4,191
LIFO inventory valuation (a)		-			-			(112	)
Other (a)		-			-			(160	)
Net current deferred income tax assets		-			-			(272	)
Net current deferred income tax liabilities (a)		-			-			41
Net deferred income tax liabilities		4,196			4,005			3,960

(a) Effective 2016, under ASU 2015-17, deferred tax assets and liabilities have been classified as non-current. 2015 was not restated.

Unrecognized Tax Benefits

The following table summarizes the movement in unrecognized tax benefits:

millions of Canadian dollars	2017			2016			2015
Balance as of January 1		106			132			151
Additions for prior years’ tax position		2			2			10
Reductions for prior years’ tax positions		-			(18	)		(4	)
Reductions due to lapse of the statute of limitations		-			(5	)		-
Settlements with tax authorities		(30	)		(5	)		(25	)
Balance as of December 31		78			106			132

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Employee retirement benefits (Tables)

12 Months Ended

Dec. 31, 2017

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 post retirement benefits
	2017			2016			2017			2016
Assumptions used to determine benefit obligations at December 31 (percent)
Discount rate		3.40			3.75			3.40			3.75
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		8,356			8,147			706			642
Current service cost		217			203			16			16
Interest cost		313			319			23			27
Actuarial loss (gain)		415			157			(49	)		46
Benefits paid (a)		(516	)		(470	)		(26	)		(25	)
Projected benefit obligation at December 31		8,785			8,356			670			706
Accumulated benefit obligation at December 31		8,043			7,681

Change in Plan Assets of Pension and Other Postretirement Benefits

	Pension benefits							Other post retirement benefits
millions of Canadian dollars		2017			2016				2017			2016
Change in plan assets
Fair value at January 1			7,359			7,260
Actual return (loss) on plan assets			700			316
Company contributions			212			163
Benefits paid (b)			(401	)		(380	)
Fair value at December 31			7,870			7,359
Plan assets in excess of (less than) projected benefit obligation at December 31
Funded plans			(408	)		(444	)
Unfunded plans			(507	)		(553	)			(670	)		(706	)
Total (c)			(915	)		(997	)			(670	)		(706	)

(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 post retirement benefits
millions of Canadian dollars	2017			2016			2017			2016
Amounts recorded in the consolidated balance sheet consist of:
Current liabilities		(28	)		(29	)		(28	)		(29	)
Other long-term obligations		(887	)		(968	)		(642	)		(677	)
Total recorded		(915	)		(997	)		(670	)		(706	)
Amounts recorded in accumulated other comprehensive income consist of:
Net actuarial loss (gain)		2,408			2,461			140			197
Prior service cost		4			14			-			-
Total recorded in accumulated other     comprehensive income, before tax		2,412			2,475			140			197

Assumptions Used to Determine Periodic Benefit Cost

	Pension benefits									Other post retirement benefits
millions of Canadian dollars	2017			2016			2015			2017			2016			2015
Assumptions used to determine net periodic benefit cost for years ended December 31 (percent)
Discount rate		3.75			4.00			3.75			3.75			4.00			3.75
Long-term rate of return on funded assets		5.50			5.50			5.75			-			-			-
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		217			203			211			16			16			15
Interest cost		313			319			307			23			27			25
Expected return on plan assets		(408	)		(400	)		(392	)		-			-			-
Amortization of prior service cost		10			9			16			-			-			-
Amortization of actuarial loss (gain)		176			162			198			8			13			14
Net periodic benefit cost		308			293			340			47			56			54
Changes in amounts recorded in accumulated other comprehensive income
Net actuarial loss (gain)		123			241			(86	)		(49	)		46			(2	)
Amortization of net actuarial (loss) gain included in net periodic benefit cost		(176	)		(162	)		(198	)		(8	)		(13	)		(14	)
Amortization of prior service cost included in net periodic benefit cost		(10	)		(9	)		(16	)		-			-			-
Total recorded in other comprehensive income		(63	)		70			(300	)		(57	)		33			(16	)
Total recorded in net periodic benefit cost and other comprehensive income, before tax		245			363			40			(10	)		89			38

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 post retirement benefits
millions of Canadian dollars	2017			2016			2015
(Charge) credit to other comprehensive income, before tax		120			(103	)		316
Deferred income tax (charge) credit (note 17)		(38	)		34			(85	)
(Charge) credit to other comprehensive income, after tax		82			(69	)		231

Fair Value of Pension Plan Assets Including Level within Fair Value Hierarchy

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 Value
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

The 2016 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, 2016, using:
millions of Canadian dollars	Total	Level 1	Level 2	Level 3	Net Asset Value (a)
Asset class
Equity securities
Canadian	433				433
Non-Canadian	2,448				2,448
Debt securities - Canadian
Corporate	988				988
Government	3,218				3,218
Asset backed	-				-
Equities – Venture capital	241				241
Cash	31	6			25
Total plan assets at fair value	7,359	6	-	-	7,353

(a) Per ASU 2015-07, certain investments that are measured at fair value using the Net Asset Value (NAV) per share practical expedient have been re-categorized from the fair value hierarchy. The fair value amounts presented in this table are intended to permit reconciliation of the fair value hierarchy to the total value of plan assets.

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	2017		2016
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		507		553
Accumulated benefit obligation		480		525

Estimated 2018 Amortization from Accumulated Other Comprehensive Income

Estimated 2018 amortization from accumulated other comprehensive income

millions of Canadian dollars	Pension benefits		Other post retirement benefits
Net actuarial loss (gain) (a)		170	9
Prior service cost (b)		4	-

(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.

(b) The company amortizes prior service cost on a straight-line basis.

Benefit Payments Expected

Benefit payments expected in:

millions of Canadian dollars	Pension benefits		Other post retirement  benefits
2018		425		29
2019		430		29
2020		435		29
2021		435		30
2022		435		30
2023 - 2027		2,165		155

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		(75)		75
Discount rate:
Effect on net benefit cost, before tax		(90)		120
Effect on benefit obligation		(1,215)		1,570
Rate of pay increases:
Effect on net benefit cost, before tax		55		(45)
Effect on benefit obligation		265		(225)

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		80		(60)

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Other long-term obligations (Tables)

12 Months Ended

Dec. 31, 2017

Other Long-Term Obligations

millions of Canadian dollars	2017		2016
Employee retirement benefits (a) (note 4)		1,529		1,645
Asset retirement obligations and other environmental liabilities (b) (d)		1,460		1,544
Share-based incentive compensation liabilities (note 7)		99		139
Other obligations (c)		692		328
Total other long-term obligations		3,780		3,656

(a) Total recorded employee retirement benefits obligations also included $56 million in current liabilities (2016 – $58 million).

(b) Total asset retirement obligations and other environmental liabilities also included $101 million in current liabilities (2016 – $108 million).

(c) Included carbon emission program obligations. Carbon emission program credits are recorded under other assets, including intangibles, net.

(d) For 2017, the asset retirement obligations were discounted at 6 percent (2016 - 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	2017			2016
Balance as at January 1		1,472			1,571
Additions (deductions)		(124	)		(160	)
Accretion		92			97
Settlement		(43	)		(36	)
Balance as at December 31		1,397			1,472

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Share-based incentive compensation programs (Tables)

12 Months Ended

Dec. 31, 2017

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, 2017:

	Restricted stock units			Deferred     share units
Outstanding at January 1, 2017		6,662,126			136,177
Granted		758,990			13,231
Vested / Exercised		(1,545,921	)		-
Forfeited and cancelled		(16,145	)		-
Outstanding at December 31, 2017		5,859,050			149,408

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Investment and other income (Tables)

12 Months Ended

Dec. 31, 2017

Gains and Losses on Asset Sales

Investment and other income includes gains and losses on asset sales as follows:

millions of Canadian dollars	2017		2016		2015
Proceeds from asset sales		232		3,021		142
Book value of asset sales		12		777		45
Gain (loss) on asset sales, before tax (a) (b)		220		2,244		97
Gain (loss) on asset sales, after tax (a) (b)		192		1,908		79

(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.

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Common shares (Tables)

12 Months Ended

Dec. 31, 2017

Summary of Common Shares

thousands of shares	As at Dec 31 2017		As at         Dec 31 2016
Authorized		1,100,000		1,100,000
Common shares outstanding		831,242		847,599

Common Share Activities

The company’s common share activities are summarized below:

	Thousands of shares			Millions of dollars
Balance as at January 1, 2015		847,599			1,566
Issued under employee share-based awards		1			-
Purchases at stated value		(1	)		-
Balance as at December 31, 2015		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

Calculation of Basic and Diluted Earnings Per Share

The following table provides the calculation of basic and diluted earnings per common share:

	2017		2016		2015
Net income (loss) per common share – basic
Net income (loss) (millions of Canadian dollars)		490		2,165		1,122
Weighted average number of common shares outstanding (millions of shares)		842.9		847.6		847.6
Net income (loss) per common share (dollars)		0.58		2.55		1.32
Net income (loss) per common share - diluted
Net income (loss) (millions of Canadian dollars)		490		2,165		1,122
Weighted average number of common shares outstanding (millions of shares)		842.9		847.6		847.6
Effect of employee share-based awards (millions of shares)		2.8		2.9		3.0
Weighted average number of common shares outstanding, assuming dilution (millions of shares)		845.7		850.5		850.6
Net income (loss) per common share (dollars)		0.58		2.55		1.32

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Miscellaneous financial information (Tables)

12 Months Ended

Dec. 31, 2017

Inventories of Crude Oil and Products

Inventories of crude oil and products at year-end consisted of the following:

millions of Canadian dollars	2017		2016
Crude oil		690		558
Petroleum products		307		300
Chemical products		42		51
Natural gas and other		36		40
Total inventories of crude oil and products		1,075		949

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Financing costs and additional notes and loans payable information (Tables)

12 Months Ended

Dec. 31, 2017

Financing Costs and Additional Notes and Loans Payable Information

millions of Canadian dollars	2017			2016			2015
Debt-related interest		103			121			102
Capitalized interest		(38	)		(49	)		(68	)
Net interest expense		65			72			34
Other interest		13			(7	)		5
Total financing costs (a)		78			65			39

 (a) Cash interest payments in 2017 were $58 million (2016 – $73 million, 2015 – $74 million). The weighted average interest rate on short-term borrowings in 2017 was 0.9 percent (2016 – 0.8 percent, 2015 – 0.8 percent). Average effective rate on the long-term borrowings with ExxonMobil in 2017 was 1.3 percent (2016 - 1.0 percent, 2015 - 1.0 percent).

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Leased facilities (Tables)

12 Months Ended

Dec. 31, 2017

Schedule of Operating Leases

At December 31, 2017, the company held non-cancelable operating leases covering primarily storage tanks, rail cars and marine vessels, with minimum undiscounted lease commitments totaling $199 million as indicated in the following table:

	Payments due by period
millions of Canadian dollars	2018		2019		2020		2021		2022		After 2022		Total
Lease payments under minimum commitments (a)		120		56		19		2		1		1		199

 (a) Net rental cost under cancelable and non-cancelable operating leases incurred in 2017 was $206 million (2016 - $253 million, 2015 - $311 million). Related rental income was not material.

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Long-term debt (Tables)

12 Months Ended

Dec. 31, 2017

Long-Term Debt

millions of Canadian dollars	As at Dec 31 2017		As at         Dec 31 2016
Long-term debt (a)		4,447		4,447
Capital leases (b)		558		585
Total long-term debt		5,005		5,032

 (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 7.0 percent in 2017 (2016 – 6.9 percent). Total capitalized lease obligations also include $27 million in current liabilities (2016 - $27 million). Principal payments on capital leases of approximately $21 million on average per year are due in each of the next four years after December 31, 2018.

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Accounting for suspended exploratory well costs (Tables)

12 Months Ended

Dec. 31, 2017

Change in Capitalized Suspended Exploratory Well Costs

Change in capitalized suspended exploratory well costs:

millions of Canadian dollars	2017			2016			2015
Balance as at January 1		143			167			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			167

Schedule of Aging of Capitalized Exploratory Well Costs

Period end capitalized suspended exploratory well costs:

millions of Canadian dollars	2017		2016		2015
Capitalized for a period of one year or less		-		-		-
Capitalized for a period of between one and ten years		-		143		167
Capitalized for a period of greater than one year		-		143		167
Total		-		143		167

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.

	2017		2016		2015
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		1
Total		-		1		1

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Other comprehensive income (loss) information (Tables)

12 Months Ended

Dec. 31, 2017

Changes in Accumulated Other Comprehensive Income (Loss)

Changes in accumulated other comprehensive income (loss):

millions of Canadian dollars	2017			2016			2015
Balance at January 1		(1,897	)		(1,828	)		(2,059	)
Post retirement benefits liability adjustment:
Current period change excluding amounts reclassified from accumulated other comprehensive income		(54	)		(210	)		64
Amounts reclassified from accumulated other comprehensive income		136			141			167
Balance at December 31		(1,815	)		(1,897	)		(1,828	)

Amounts Reclassified Out of Accumulated Other Comprehensive Income (Loss) - Before-Tax Income (Expense)

Amounts reclassified out of accumulated other comprehensive income (loss) - before-tax income (expense):

millions of Canadian dollars	2017			2016			2015
Amortization of post retirement benefits liability adjustment included in net periodic benefit cost (a)		(194	)		(184	)		(228	)

 (a) This accumulated other comprehensive income component is included in the computation of net periodic benefit cost (note 4).

Income Tax Expense (Credit) for Components of Other Comprehensive Income (Loss)

Income tax expense (credit) for components of other comprehensive income (loss):

millions of Canadian dollars	2017			2016			2015
Post retirement benefits liability adjustments:
Post retirement benefits liability adjustment (excluding amortization)		(20	)		(77	)		24
Amortization of post retirement benefits liability adjustment included in net periodic benefit cost		58			43			61
Total		38			(34	)		85

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Summary of Significant Accounting Policies - Additional Information (Detail)	12 Months Ended
	Dec. 31, 2017
Significant Accounting Policies [Line Items]
Amortization of computer software development costs, in years	15 years
Amortization of customer lists, in years	10 years
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%

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Business Segments (Detail) - CAD CAD in Millions		12 Months Ended
		Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Revenues and other income
Operating revenues	[1],[2]	CAD 29,125	CAD 25,049	CAD 26,756
Investment and other income (note 8)		299	2,305	132
Total revenues and other income		29,424	27,354	26,888
Expenses
Exploration (note 15)	[3]	183	94	73
Purchases of crude oil and products	[4]	18,145	15,120	15,284
Production and manufacturing	[5]	5,698	5,224	5,434
Selling and general	[5]	893	1,129	1,117
Federal excise tax		1,673	1,650	1,568
Depreciation and depletion	[3]	2,172	1,628	1,450
Financing costs (note 12)	[6]	78	65	39
Total expenses		28,842	24,910	24,965
Income (loss) before income taxes		582	2,444	1,923
Income taxes (note 3)
Current	[7]	(58)	200	451
Deferred	[7],[8]	150	79	350
Total income tax expense (benefit)	[7],[9]	92	279	801
Net income (loss)		490	2,165	1,122
Cash flows from (used in) operating activities		2,763	2,015	2,167
Capital and exploration expenditures	[10]	671	1,161	3,595
Property, plant and equipment Cost		52,778	53,515	54,203
Accumulated depreciation and depletion		(18,305)	(17,182)	(16,404)
Net property, plant and equipment	[3],[11]	34,473	36,333	37,799
Total assets		41,601	41,654	43,170
Consolidation, Eliminations
Revenues and other income
Intersegment sales		(3,681)	(3,434)	(3,739)
TOTAL OPERATING REVENUES, INTERSEGMENT SALES, INVESTMENT AND OTHER INCOME		(3,681)	(3,434)	(3,739)
Expenses
Purchases of crude oil and products		(3,675)	(3,429)	(3,735)
Selling and general		(6)	(5)	(4)
Total expenses		(3,681)	(3,434)	(3,739)
Income taxes (note 3)
Cash flows from (used in) operating activities			(21)	(2)
Total assets		(435)	(384)	(348)
Upstream
Revenues and other income
Operating revenues	[2]	7,302	5,492	5,776
Intersegment sales		2,264	2,215	2,486
Investment and other income (note 8)		16	13	22
TOTAL OPERATING REVENUES, INTERSEGMENT SALES, INVESTMENT AND OTHER INCOME		9,582	7,720	8,284
Expenses
Exploration (note 15)	[3]	183	94	73
Purchases of crude oil and products		4,526	3,666	3,768
Production and manufacturing		3,913	3,591	3,766
Selling and general			(5)	(2)
Depreciation and depletion	[3]	1,939	1,396	1,193
Financing costs (note 12)		13	(7)	5
Total expenses		10,574	8,735	8,803
Income (loss) before income taxes		(992)	(1,015)	(519)
Income taxes (note 3)
Current		484	(491)	(77)
Deferred		(770)	137	262
Total income tax expense (benefit)		(286)	(354)	185
Net income (loss)		(706)	(661)	(704)
Cash flows from (used in) operating activities		1,257	402	224
Capital and exploration expenditures	[10]	416	896	3,135
Property, plant and equipment Cost		45,542	45,850	45,171
Accumulated depreciation and depletion		(13,844)	(12,312)	(11,016)
Net property, plant and equipment	[3],[11]	31,698	33,538	34,155
Total assets		35,044	36,840	36,971
Downstream
Revenues and other income
Operating revenues	[2]	20,714	18,511	19,796
Intersegment sales		1,155	1,007	1,019
Investment and other income (note 8)		269	2,278	104
TOTAL OPERATING REVENUES, INTERSEGMENT SALES, INVESTMENT AND OTHER INCOME		22,138	21,796	20,919
Expenses
Purchases of crude oil and products		16,543	14,178	14,526
Production and manufacturing		1,576	1,428	1,461
Selling and general		772	972	986
Federal excise tax		1,673	1,650	1,568
Depreciation and depletion	[3]	202	206	233
Total expenses		20,766	18,434	18,774
Income (loss) before income taxes		1,372	3,362	2,145
Income taxes (note 3)
Current		(504)	674	476
Deferred		836	(66)	83
Total income tax expense (benefit)		332	608	559
Net income (loss)		1,040	2,754	1,586
Cash flows from (used in) operating activities		1,396	1,574	1,686
Capital and exploration expenditures	[10]	200	190	340
Property, plant and equipment Cost		5,683	6,166	7,596
Accumulated depreciation and depletion		(3,594)	(4,037)	(4,584)
Net property, plant and equipment	[3],[11]	2,089	2,129	3,012
Total assets		4,890	3,958	5,574
Chemical
Revenues and other income
Operating revenues	[2]	1,109	1,046	1,184
Intersegment sales		262	212	234
TOTAL OPERATING REVENUES, INTERSEGMENT SALES, INVESTMENT AND OTHER INCOME		1,371	1,258	1,418
Expenses
Purchases of crude oil and products		751	705	725
Production and manufacturing		209	205	207
Selling and general		78	83	87
Depreciation and depletion	[3]	12	10	11
Total expenses		1,050	1,003	1,030
Income (loss) before income taxes		321	255	388
Income taxes (note 3)
Current		(32)	68	97
Deferred		118		4
Total income tax expense (benefit)		86	68	101
Net income (loss)		235	187	287
Cash flows from (used in) operating activities		235	203	383
Capital and exploration expenditures	[10]	17	26	52
Property, plant and equipment Cost		888	872	857
Accumulated depreciation and depletion		(644)	(629)	(616)
Net property, plant and equipment	[3],[11]	244	243	241
Total assets		399	346	394
Corporate and Other
Revenues and other income
Investment and other income (note 8)		14	14	6
TOTAL OPERATING REVENUES, INTERSEGMENT SALES, INVESTMENT AND OTHER INCOME		14	14	6
Expenses
Selling and general		49	84	50
Depreciation and depletion	[3]	19	16	13
Financing costs (note 12)		65	72	34
Total expenses		133	172	97
Income (loss) before income taxes		(119)	(158)	(91)
Income taxes (note 3)
Current		(6)	(51)	(45)
Deferred		(34)	8	1
Total income tax expense (benefit)		(40)	(43)	(44)
Net income (loss)		(79)	(115)	(47)
Cash flows from (used in) operating activities		(125)	(143)	(124)
Capital and exploration expenditures	[10]	38	49	68
Property, plant and equipment Cost		665	627	579
Accumulated depreciation and depletion		(223)	(204)	(188)
Net property, plant and equipment	[3],[11]	442	423	391
Total assets		CAD 1,703	CAD 894	CAD 579

[1] Amounts from related parties included in operating revenues (note 16). 4,110 2,342 3,058

[2] Includes export sales to the United States of $4,392 million (2016 - $3,612 million, 2015 - $4,157 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 16). 2,687 2,224 2,684

[5] Amounts to related parties included in production and manufacturing, and selling and general expenses (note 16). 544 533 442

[6] Cash interest payments in 2017 were $58 million (2016 - $73 million, 2015 - $74 million). The weighted average interest rate on short-term borrowings in 2017 was 0.9 percent (2016 - 0.8 percent, 2015 - 0.8 percent). Average effective rate on the long-term borrowings with ExxonMobil in 2017 was 1.3 percent (2016 - 1.0 percent, 2015 - 1.0 percent).

[7] On November 2, 2017 the British Columbia government enacted a 1 percent increase in the provincial tax rate from 11 percent to 12 percent. On June 30, 2015 the Alberta government enacted a 2 percent increase in the provincial tax rate, from 10 percent to 12 percent.

[8] There were no material net (charges) credits for the effect of changes in tax laws and rates included in the provisions for deferred income taxes in 2016.

[9] Cash outflow from income taxes, plus investment credits earned, was $322 million (2016 - $172 million, 2015 - $202 million).

[10] 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.

[11] Includes property, plant and equipment under construction of $1,047 million (2016 - $2,705 million, 2015 - $3,719 million).

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Business Segments (Parenthetical) (Detail) - CAD CAD in Millions		12 Months Ended
		Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Segment Reporting Information [Line Items]
Operating revenues	[1],[2]	CAD 29,125	CAD 25,049	CAD 26,756
Plant and equipment under construction		1,047	2,705	3,719
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
United States Exports
Segment Reporting Information [Line Items]
Operating revenues		CAD 4,392	CAD 3,612	CAD 4,157

[1] Amounts from related parties included in operating revenues (note 16). 4,110 2,342 3,058

[2] Includes export sales to the United States of $4,392 million (2016 - $3,612 million, 2015 - $4,157 million). Export sales to the United States were recorded in all operating segments, with the largest effects in the Upstream segment.

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Income Taxes (Detail) - CAD CAD in Millions				12 Months Ended
		Nov. 02, 2017	Jun. 30, 2015	Dec. 31, 2017		Dec. 31, 2016	Dec. 31, 2015
Schedule Of Income Tax [Line Items]
Current income tax expense	[1]			CAD (58)		CAD 200	CAD 451
Deferred income tax expense	[1],[2]			150		79	350
Total income tax expense	[1],[3]			CAD 92		CAD 279	CAD 801
Statutory corporate tax rate (percent)				26.90%		26.80%	27.20%
Disposals	[4]			(5.30%)		(11.60%)	(0.40%)
Enacted tax rate change		1.00%	2.00%	0.90%	[1]		16.10%	[1]
Other				(6.60%)		(3.80%)	(1.20%)
Effective income tax rate				15.90%		11.40%	41.70%

[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. On June 30, 2015 the Alberta government enacted a 2 percent increase in the provincial tax rate, from 10 percent to 12 percent.

[2] There were no material net (charges) credits for the effect of changes in tax laws and rates included in the provisions for deferred income taxes in 2016.

[3] Cash outflow from income taxes, plus investment credits earned, was $322 million (2016 - $172 million, 2015 - $202 million).

[4] 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.

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Income Taxes (Parenthetical) (Detail) - CAD CAD in Millions			12 Months Ended
	Nov. 02, 2017	Jun. 30, 2015	Dec. 31, 2017		Dec. 31, 2016	Dec. 31, 2015
Schedule Of Income Tax [Line Items]
Increase in the provincial tax rate	1.00%	2.00%	0.90%	[1]		16.10%	[1]
Cash outflow from income taxes, plus investment credits earned			CAD 322		CAD 172	CAD 202
Minimum
Schedule Of Income Tax [Line Items]
Provincial tax rate	11.00%	10.00%
Maximum
Schedule Of Income Tax [Line Items]
Provincial tax rate	12.00%	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. On June 30, 2015 the Alberta government enacted a 2 percent increase in the provincial tax rate, from 10 percent to 12 percent.

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Components of Deferred Income Tax Liabilities and Assets (Detail) - CAD CAD in Millions		Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Components Of Deferred Tax Assets And Liabilities [Line Items]
Depreciation and amortization		CAD 5,564	CAD 5,361	CAD 4,677
Successful drilling and land acquisitions		762	891	922
Pension and benefits		(422)	(457)	(396)
Asset retirement obligation		(376)	(396)	(406)
Capitalized interest		118	114	104
LIFO inventory valuation	[1]	(318)	(240)
Tax loss carryforwards		(936)	(1,056)	(610)
Other	[1]	(196)	(212)	(100)
Net long-term deferred income tax liabilities		4,196	4,005	4,191
LIFO inventory valuation	[1]			(112)
Other	[1]			(160)
Net current deferred income tax assets				(272)
Net current deferred income tax liabilities	[1]			41
Net deferred income tax liabilities		CAD 4,196	CAD 4,005	CAD 3,960

[1] Effective 2016, under ASU 2015-17, deferred tax assets and liabilities have been classified as non-current. 2015 was not restated.

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Unrecognized Tax Benefits (Detail) - CAD CAD in Millions	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Schedule of Unrecognized Tax Benefits [Line Items]
Balance as of January 1	CAD 106	CAD 132	CAD 151
Additions for prior years' tax position	2	2	10
Reductions for prior years' tax positions		(18)	(4)
Reductions due to lapse of the statute of limitations		(5)
Settlements with tax authorities	(30)	(5)	(25)
Balance as of December 31	CAD 78	CAD 106	CAD 132

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Assumptions Used to Determine Benefit Obligations (Detail)	Dec. 31, 2017	Dec. 31, 2016
Pension benefits
Defined Benefit Plan Disclosure [Line Items]
Discount rate	3.40%	3.75%
Long-term rate of compensation increase	4.50%	4.50%
Other post-retirement benefits
Defined Benefit Plan Disclosure [Line Items]
Discount rate	3.40%	3.75%
Long-term rate of compensation increase	4.50%	4.50%

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Change in Projected Benefit Obligation (Detail) - CAD CAD in Millions		12 Months Ended
		Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Pension benefits
Schedule Of Defined Benefit Plans Disclosures [Line Items]
Projected benefit obligation at January 1		CAD 8,356	CAD 8,147
Current service cost		217	203	CAD 211
Interest cost		313	319	307
Actuarial loss (gain)		415	157
Benefits paid	[1]	(516)	(470)
Projected benefit obligation at December 31		8,785	8,356	8,147
Accumulated benefit obligation at December 31		8,043	7,681
Other post-retirement benefits
Schedule Of Defined Benefit Plans Disclosures [Line Items]
Projected benefit obligation at January 1		706	642
Current service cost		16	16	15
Interest cost		23	27	25
Actuarial loss (gain)		(49)	46
Benefits paid	[1]	(26)	(25)
Projected benefit obligation at December 31		CAD 670	CAD 706	CAD 642

[1] Benefit payments for funded and unfunded plans.

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Employee Retirement Benefits - Additional Information (Detail) - CAD CAD in Millions	12 Months Ended			120 Months Ended	240 Months Ended
	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2017	Dec. 31, 2017
Defined Benefit Plan Disclosure [Line Items]
Health care cost trend rate assumed for 2018 and subsequent years	4.50%			4.50%	4.50%
Long-term expected return	5.50%
Actual rate of return				6.30%	7.30%
Cost for defined contributions plans	CAD 40	CAD 44	CAD 43
Plan assets invested in venture capital partnerships	5.00%
Cash contributions to pension plans in 2018	CAD 240			CAD 240	CAD 240
Equity Securities
Defined Benefit Plan Disclosure [Line Items]
Target allocation securities	28.00%			28.00%	28.00%
Debt Securities
Defined Benefit Plan Disclosure [Line Items]
Target allocation securities	67.00%			67.00%	67.00%

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Change in Plan Assets and Plan Assets in Excess of Less Than Projected Benefit Obligation (Detail) - CAD CAD in Millions		12 Months Ended
		Dec. 31, 2017	Dec. 31, 2016
Schedule Of Defined Benefit Plans Disclosures [Line Items]
Fair value at January 1		CAD 7,359
Fair value at December 31		7,870	CAD 7,359
Pension benefits
Schedule Of Defined Benefit Plans Disclosures [Line Items]
Fair value at January 1		7,359	7,260
Actual return (loss) on plan assets		700	316
Company contributions		212	163
Benefits paid	[1]	(401)	(380)
Fair value at December 31		7,870	7,359
Funded plans		(408)	(444)
Unfunded plans		(507)	(553)
Total	[2]	(915)	(997)
Other post-retirement benefits
Schedule Of Defined Benefit Plans Disclosures [Line Items]
Unfunded plans		(670)	(706)
Total	[2]	CAD (670)	CAD (706)

[1] Benefit payments for funded plans only.

[2] Fair value of assets less projected benefit obligation shown above.

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Amounts Recorded in Consolidated Balance Sheet and Accumulated Other Comprehensive Income (Detail) - CAD CAD in Millions		Dec. 31, 2017	Dec. 31, 2016
Schedule Of Defined Benefit Plans Disclosures [Line Items]
Current liabilities		CAD (56)	CAD (58)
Other long-term obligations	[1]	(1,529)	(1,645)
Pension benefits
Schedule Of Defined Benefit Plans Disclosures [Line Items]
Current liabilities		(28)	(29)
Other long-term obligations		(887)	(968)
Total recorded		(915)	(997)
Net actuarial loss (gain)		2,408	2,461
Prior service cost		4	14
Total recorded in accumulated other comprehensive income, before tax		2,412	2,475
Other post-retirement benefits
Schedule Of Defined Benefit Plans Disclosures [Line Items]
Current liabilities		(28)	(29)
Other long-term obligations		(642)	(677)
Total recorded		(670)	(706)
Net actuarial loss (gain)		140	197
Total recorded in accumulated other comprehensive income, before tax		CAD 140	CAD 197

[1] Total recorded employee retirement benefits obligations also included $56 million in current liabilities (2016 - $58 million).

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Assumptions Used to Determine Periodic Benefit Cost (Detail)	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Schedule Of Defined Benefit Plans Disclosures [Line Items]
Long-term rate of return on funded assets	5.50%
Pension benefits
Schedule Of Defined Benefit Plans Disclosures [Line Items]
Discount rate	3.75%	4.00%	3.75%
Long-term rate of return on funded assets	5.50%	5.50%	5.75%
Long-term rate of compensation increase	4.50%	4.50%	4.50%
Other post-retirement benefits
Schedule Of Defined Benefit Plans Disclosures [Line Items]
Discount rate	3.75%	4.00%	3.75%
Long-term rate of compensation increase	4.50%	4.50%	4.50%

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Components of Net Periodic Benefit Cost and Changes in Amounts Recorded in Accumulated Other Comprehensive Income (Detail) - CAD CAD in Millions	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Defined Benefit Plan Disclosure [Line Items]
Total recorded in other comprehensive income	CAD (120)	CAD 103	CAD (316)
Pension benefits
Defined Benefit Plan Disclosure [Line Items]
Current service cost	217	203	211
Interest cost	313	319	307
Expected return on plan assets	(408)	(400)	(392)
Amortization of prior service cost	10	9	16
Amortization of actuarial loss (gain)	176	162	198
Net periodic benefit cost	308	293	340
Net actuarial loss (gain)	123	241	(86)
Amortization of net actuarial (loss) gain included in net periodic benefit cost	(176)	(162)	(198)
Amortization of prior service cost included in net periodic benefit cost	(10)	(9)	(16)
Total recorded in other comprehensive income	(63)	70	(300)
Total recorded in net periodic benefit cost and other comprehensive income, before tax	245	363	40
Other post-retirement benefits
Defined Benefit Plan Disclosure [Line Items]
Current service cost	16	16	15
Interest cost	23	27	25
Amortization of actuarial loss (gain)	8	13	14
Net periodic benefit cost	47	56	54
Net actuarial loss (gain)	(49)	46	(2)
Amortization of net actuarial (loss) gain included in net periodic benefit cost	(8)	(13)	(14)
Total recorded in other comprehensive income	(57)	33	(16)
Total recorded in net periodic benefit cost and other comprehensive income, before tax	CAD (10)	CAD 89	CAD 38

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Summary of Change in Accumulated Other Comprehensive Income (Detail) - CAD CAD in Millions	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Defined Benefit Plan Disclosure [Line Items]
(Charge) credit to other comprehensive income, before tax	CAD 120	CAD (103)	CAD 316
Deferred income tax (charge) credit (note 17)	(38)	34	(85)
(Charge) credit to other comprehensive income, after tax	CAD 82	CAD (69)	CAD 231

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Fair Value of Pension Plan Assets Including Level Within Fair Value Hierarchy (Detail) - CAD CAD in Millions	Dec. 31, 2017	Dec. 31, 2016
Defined Benefit Plan Disclosure [Line Items]
Total plan assets at fair value	CAD 7,870	CAD 7,359
Investments that are measured at fair value using net asset value	7,836	7,353	[1]
Canadian Equity Securities
Defined Benefit Plan Disclosure [Line Items]
Total plan assets at fair value	182	433
Investments that are measured at fair value using net asset value	182	433	[1]
Non-Canadian Equity Securities
Defined Benefit Plan Disclosure [Line Items]
Total plan assets at fair value	2,138	2,448
Investments that are measured at fair value using net asset value	2,138	2,448	[1]
Corporate Debt Securities
Defined Benefit Plan Disclosure [Line Items]
Total plan assets at fair value	1,248	988
Investments that are measured at fair value using net asset value	1,248	988	[1]
Government Debt Securities
Defined Benefit Plan Disclosure [Line Items]
Total plan assets at fair value	4,016	3,218
Investments that are measured at fair value using net asset value	4,016	3,218	[1]
Equities - Venture Capital
Defined Benefit Plan Disclosure [Line Items]
Total plan assets at fair value	215	241
Investments that are measured at fair value using net asset value	215	241	[1]
Cash
Defined Benefit Plan Disclosure [Line Items]
Total plan assets at fair value	71	31
Investments that are measured at fair value using net asset value	37	25	[1]
Level 1
Defined Benefit Plan Disclosure [Line Items]
Total plan assets at fair value	34	6
Level 1 | Cash
Defined Benefit Plan Disclosure [Line Items]
Total plan assets at fair value	CAD 34	CAD 6

[1] Per ASU 2015-07, certain investments that are measured at fair value using the Net Asset Value (NAV) per share practical expedient have been re-categorized from the fair value hierarchy. The fair value amounts presented in this table are intended to permit reconciliation of the fair value hierarchy to the total value of plan assets.

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Pension Plan with Accumulated Benefit Obligation in Excess of Plan Assets (Detail) - CAD CAD in Millions	Dec. 31, 2017	Dec. 31, 2016
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	CAD 7,870	CAD 7,359
Funded Pension Plans [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	0	0
Accumulated benefit obligation less fair value of plan assets	0	0
Unfunded Pension Plans [Member]
Defined Benefit Plan Disclosure [Line Items]
Projected benefit obligation	507	553
Accumulated benefit obligation	CAD 480	CAD 525

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Estimated 2018 Amortization from Accumulated Other Comprehensive Income (Detail) CAD in Millions	Dec. 31, 2017 CAD
Pension benefits
Defined Benefit Plan Disclosure [Line Items]
Net actuarial loss (gain)	CAD 170	[1]
Prior service cost	4	[2]
Other post-retirement benefits
Defined Benefit Plan Disclosure [Line Items]
Net actuarial loss (gain)	CAD 9	[1]

[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.

[2] The company amortizes prior service cost on a straight-line basis.

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Expected Benefit Payments (Detail) CAD in Millions	Dec. 31, 2017 CAD
Pension benefits
Defined Benefit Plan Disclosure [Line Items]
2018	CAD 425
2019	430
2020	435
2021	435
2022	435
2023 - 2027	2,165
Other post-retirement benefits
Defined Benefit Plan Disclosure [Line Items]
2018	29
2019	29
2020	29
2021	30
2022	30
2023 - 2027	CAD 155

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Effect of One Percent Change in Assumptions at Which Retirement Liabilities Could be Effectively Settled (Detail) CAD in Millions	12 Months Ended
	Dec. 31, 2017 CAD
Defined Benefit Plan Disclosure [Line Items]
Effect on net benefit cost, before tax, One percent increase - Rate of return on plan assets	CAD (75)
Effect on net benefit cost, before tax, One percent increase - Discount rate	(90)
Effect on benefit obligation, One percent increase - Discount rate	(1,215)
Effect on net benefit cost, before tax, One percent increase- Rate of pay increases	55
Effect on benefit obligation, One percent increase - Rate of pay increases	265
Effect on net benefit cost, before tax, One percent decrease - Rate of return on plan assets	75
Effect on net benefit cost, before tax, One percent decrease - Discount rate	120
Effect on benefit obligation, One percent decrease - Discount rate	1,570
Effect on net benefit cost, before tax, One percent decrease- Rate of pay increases	(45)
Effect on benefit obligation, One percent decrease - Rate of pay increases	CAD (225)

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Effect of One Percent Change in Assumed Health-Care Cost Trend Rate (Detail) CAD in Millions	12 Months Ended
	Dec. 31, 2017 CAD
Defined Benefit Plan Disclosure [Line Items]
Effect on service and interest cost components, One percent increase	CAD 6
Effect on service and interest cost components, One percent decrease	(5)
Effect on benefit obligation, One percent increase	80
Effect on benefit obligation, One percent decrease	CAD (60)

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Other Long-Term Obligations (Detail) - CAD CAD in Millions		Dec. 31, 2017	Dec. 31, 2016
Schedule of Other Liabilities [Line Items]
Employee retirement benefits	[1]	CAD 1,529	CAD 1,645
Asset retirement obligations and other environmental liabilities	[2],[3]	1,460	1,544
Share-based incentive compensation liabilities		99	139
Other obligations	[4]	692	328
Total other long-term obligations	[5]	CAD 3,780	CAD 3,656

[1] Total recorded employee retirement benefits obligations also included $56 million in current liabilities (2016 - $58 million).

[2] For 2017, the asset retirement obligations were discounted at 6 percent (2016 - 6 percent).

[3] Total asset retirement obligations and other environmental liabilities also included $101 million in current liabilities (2016 - $108 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 $60 million (2016 - $104 million), (note 16).

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Other Long-Term Obligations (Parenthetical) (Detail) - CAD CAD in Millions	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016
Schedule of Other Liabilities [Line Items]
Employee retirement benefit obligations in current liabilities	CAD 56	CAD 58
Asset retirement obligations and other environmental liabilities in current liabilities	CAD 101	CAD 108
Asset retirement obligations discount rate	6.00%	6.00%

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Schedule of Asset Retirement Obligations (Detail) - CAD CAD in Millions	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016
Reconciliation of Changes in Asset Retirement Obligations [Line Items]
Balance as at January 1	CAD 1,472	CAD 1,571
Additions (deductions)	(124)	(160)
Accretion	92	97
Settlement	(43)	(36)
Balance as at December 31	CAD 1,397	CAD 1,472

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Derivative and Financial Instruments (Detail) - CAD CAD in Millions	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016
Derivative Instruments [Line Items]
Derivative, Fair Value, Net	CAD 4	CAD 0
Loss recognized related to settled and unsettled derivative, before tax	CAD (5)	CAD 0

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Share-Based Incentive Compensation Programs - Additional Information (Detail) - CAD CAD in Millions	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Compensation expense charged against income	CAD 14	CAD 83	CAD 48
Income tax benefit recognized in income related to compensation expense	4	24	13
Cash payment for compensation expense	CAD 71	CAD 79	CAD 78
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	CAD 94
Weighted average vesting period of nonvested restricted stock	3 years 9 months 18 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%

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Summarized Information About Incentive Share, Deferred Share and Restricted Stock Units (Detail)	12 Months Ended
	Dec. 31, 2017 shares
Restricted Stock Units
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Outstanding at January 1, 2017	6,662,126
Granted	758,990
Vested / Exercised	(1,545,921)
Forfeited and cancelled	(16,145)
Outstanding at December 31, 2017	5,859,050
Deferred Share Units
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Outstanding at January 1, 2017	136,177
Granted	13,231
Outstanding at December 31, 2017	149,408

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Gains and Losses on Asset Sales (Detail) - CAD CAD in Millions		12 Months Ended
		Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Investment And Other Income [Line Items]
Proceeds from asset sales		CAD 232	CAD 3,021	CAD 142
Book value of asset sales		12	777	45
Gain (loss) on asset sales, before tax	[1],[2]	220	2,244	97
Gain (loss) on asset sales, after tax	[1],[2]	CAD 192	CAD 1,908	CAD 79

[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.

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Gains and Losses on Asset Sales (Parenthetical) (Detail) - CAD CAD in Millions		12 Months Ended
		Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Investment And Other Income [Line Items]
Gain (loss) on asset sales, before tax	[1],[2]	CAD 220	CAD 2,244	CAD 97
Gain (loss) on asset sales, after tax	[1],[2]	192	1,908	CAD 79
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			CAD 134
Surplus Property
Investment And Other Income [Line Items]
Gain (loss) on asset sales, before tax		174
Gain (loss) on asset sales, after tax		CAD 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.

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Litigation and Other Contingencies - Additional Information (Detail) - CAD CAD in Millions	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Litigation And Other Contingencies [Line Items]
Total payment on unconditional purchase obligation	CAD 0	CAD 0	CAD 125
Total other third party obligations payable	CAD 42	CAD 49

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Summary of Common Shares (Detail) - shares	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
Class of Stock [Line Items]
Authorized	1,100,000,000	1,100,000,000
Common shares outstanding	831,242,000	847,599,000	847,599,000	847,599,000

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Common Shares - Additional Information (Detail) - shares	12 Months Ended
	Dec. 31, 2017	Jun. 13, 2017
Class of Stock [Line Items]
Exxon Mobil Corporation's ownership interest in Imperial	69.60%
Normal course issuer bid share repurchase shares authorized	25,395,927
Percent of total shares		3.00%
Normal course issuer bid share repurchase term, months	12 months

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Common Share Activities (Detail) - CAD shares in Thousands, CAD in Millions	12 Months Ended
	Dec. 31, 2017		Dec. 31, 2016		Dec. 31, 2015
Class of Stock [Line Items]
Common stock beginning balance, shares	847,599		847,599		847,599
Issued under employee share-based awards	2		1		1
Purchases at stated value, shares	(16,359)		(1)		(1)
Common stock, ending balance, shares	831,242		847,599		847,599
Common stock beginning balance, value	CAD 1,566	[1]	CAD 1,566		CAD 1,566
Issued under employee share-based awards, value	0		0		0
Common stock, ending balance, value	1,536	[1]	CAD 1,566	[1]	CAD 1,566
Common Stock
Class of Stock [Line Items]
Purchases at stated value, value	CAD (30)

[1] Number of common shares authorized and outstanding were 1,100 million and 831 million, respectively (2016 - 1,100 million and 848 million, respectively), (note 10).

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Net Income (Loss) Per Share (Detail) - CAD CAD / shares in Units, shares in Millions, CAD in Millions	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Net income (loss) per common share - basic
Net income (loss)	CAD 490	CAD 2,165	CAD 1,122
Weighted average number of common shares outstanding (millions of shares)	842.9	847.6	847.6
Net income (loss) per common share (dollars)	CAD 0.58	CAD 2.55	CAD 1.32
Net income (loss) per common share - diluted
Net income (loss)	CAD 490	CAD 2,165	CAD 1,122
Weighted average number of common shares outstanding (millions of shares)	842.9	847.6	847.6
Effect of employee share-based awards (millions of shares)	2.8	2.9	3.0
Weighted average number of common shares outstanding, assuming dilution (millions of shares)	845.7	850.5	850.6
Net income (loss) per common share (dollars)	CAD 0.58	CAD 2.55	CAD 1.32

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Miscellaneous Financial Information - Additional Information (Detail) - CAD CAD in Millions	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Additional Financial Information [Line Items]
Effect of LIFO inventory liquidation on income	CAD 5	CAD 5	CAD (39)
Difference between LIFO carrying values and replacement cost of inventories	1,400	1,000
Research and development costs charged to expenses	111	152	CAD 149
Accounts payable and accrued liabilities included accrued taxes other than income taxes	CAD 437	CAD 396

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Inventories of Crude Oil and Products (Detail) - CAD CAD in Millions	Dec. 31, 2017	Dec. 31, 2016
Product Information [Line Items]
Crude oil	CAD 690	CAD 558
Petroleum products	307	300
Chemical products	42	51
Natural gas and other	36	40
Total inventories of crude oil and products	CAD 1,075	CAD 949

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Financing Costs and Additional Notes and Loans Payable Information (Detail) - CAD CAD in Millions		12 Months Ended
		Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Debt-related interest		CAD 103	CAD 121	CAD 102
Capitalized interest		(38)	(49)	(68)
Net interest expense		65	72	34
Other interest		13	(7)	5
Total financing costs	[1]	CAD 78	CAD 65	CAD 39

[1] Cash interest payments in 2017 were $58 million (2016 - $73 million, 2015 - $74 million). The weighted average interest rate on short-term borrowings in 2017 was 0.9 percent (2016 - 0.8 percent, 2015 - 0.8 percent). Average effective rate on the long-term borrowings with ExxonMobil in 2017 was 1.3 percent (2016 - 1.0 percent, 2015 - 1.0 percent).

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Financing Costs and Additional Notes and Loans Payable Information (Parenthetical) (Detail) - CAD CAD in Millions	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Cash interest payments	CAD 58	CAD 73	CAD 74
Weighted average interest rate on short-term borrowings	0.90%	0.80%	0.80%
Average effective rate for affiliate long-term borrowing	1.30%	1.00%	1.00%

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Financing Costs and Additional Notes and Loans Payable Information - Additional Information (Detail) - CAD	1 Months Ended
	Dec. 31, 2017	Nov. 30, 2017
Long Term Line Of Credit
Financing Activities [Line Items]
Non-interest bearing, revolving demand loan, outstanding amount		CAD 0
Debt instrument, maturity date		Nov. 30, 2019
Non-interest bearing, revolving demand loan, remaining borrowing capacity		CAD 250,000,000
Short Term Line of Credit
Financing Activities [Line Items]
Non-interest bearing, revolving demand loan, outstanding amount	CAD 0
Debt instrument, maturity date	Dec. 31, 2018
Non-interest bearing, revolving demand loan, remaining borrowing capacity	CAD 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	CAD 75,000,000

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Leased Facilities - Additional Information (Detail) CAD in Millions	Dec. 31, 2017 CAD
Operating Leased Assets [Line Items]
Minimum undiscounted lease commitments	CAD 199	[1]

[1] Net rental cost under cancelable and non-cancelable operating leases incurred in 2017 was $206 million (2016 - $253 million, 2015 - $311 million). Related rental income was not material.

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Schedule of Non Cancelable Operating Leases (Detail) CAD in Millions	Dec. 31, 2017 CAD	[1]
Operating Leased Assets [Line Items]
Lease payments under minimum commitments, 2018	CAD 120
Lease payments under minimum commitments, 2019	56
Lease payments under minimum commitments, 2020	19
Lease payments under minimum commitments, 2021	2
Lease payments under minimum commitments, 2022	1
Lease payments under minimum commitments, After 2022	1
Total lease payments under minimum commitments	CAD 199

[1] Net rental cost under cancelable and non-cancelable operating leases incurred in 2017 was $206 million (2016 - $253 million, 2015 - $311 million). Related rental income was not material.

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Schedule of Non Cancelable Operating Leases (Parenthetical) (Detail) - CAD CAD in Millions	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Operating Leased Assets [Line Items]
Net rental cost incurred for operating leases	CAD 206	CAD 253	CAD 311

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Long-Term Debt (Detail) - CAD CAD in Millions		Dec. 31, 2017	Dec. 31, 2016
Debt Instrument [Line Items]
Long-term debt	[1]	CAD 4,447	CAD 4,447
Capital leases	[2]	558	585
Total long-term debt	[3]	CAD 5,005	CAD 5,032

[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 7.0 percent in 2017 (2016 - 6.9 percent). Total capitalized lease obligations also include $27 million in current liabilities (2016 - $27 million). Principal payments on capital leases of approximately $21 million on average per year are due in each of the next four years after December 31, 2018.

[3] Long-term debt included amounts to related parties of $4,447 million (2016 - $4,447 million), (note 16).

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Long-Term Debt (Parenthetical) (Detail) - CAD	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016
Debt Instrument [Line Items]
Maximum long-term borrowing from affiliate	CAD 7,750,000,000
Cancellation period long-term borrowing from affiliate, days	370 days
Capitalized lease obligations for marine services, average imputed rate	7.00%	6.90%
Total capitalized lease obligations in current liabilities	CAD 27,000,000	CAD 27,000,000
Principal payments on capital leases, in two years	21,000,000
Principal payments on capital leases, in three years	21,000,000
Principal payments on capital leases, in four years	21,000,000
Principal payments on capital leases, in five years	CAD 21,000,000

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Period End Capitalized Suspended Exploratory Well Costs (Detail) - CAD CAD in Millions	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2016	Dec. 31, 2015
Projects with Exploratory Well Costs Capitalized for More than One Year [Line Items]
Capitalized suspended exploratory well costs, total	CAD 143	CAD 167	CAD 167	CAD 143	CAD 167
Beginning Balance	143	167	167
Additions pending the determination of proved reserves	0	0	0
Charged to expense	(143)	(24)
Reclassification to wells, facilities and equipment based on the determination of proved reserves	0	0	0
Ending Balance		CAD 143	CAD 167
Capitalized for a period of one year or less	CAD 0			0	0
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	167
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				CAD 143	CAD 167

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Number of Projects with Exploratory Well Costs (Detail) - Project	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Exploratory Wells Drilled [Line Items]
Number of projects with first capitalized well drilled in the preceding 12 months	0	0	0
Number of projects that have exploratory well costs capitalized for a period of greater than 12 months		1	1
Total projects		1	1

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Transactions with Related Parties - Additional Information (Detail) - CAD CAD in Millions	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Related Party Transaction [Line Items]
Amounts of sales by Imperial	CAD 4,110	CAD 2,342	CAD 3,058
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	2,648	2,187
Amounts of sales by Imperial	CAD 4,080	CAD 2,315

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Changes in Accumulated Other Comprehensive Income (Loss) (Detail) - CAD CAD in Millions	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Accumulated Other Comprehensive Income (Loss) [Line Items]
Balance at January 1	CAD (1,897)	CAD (1,828)	CAD (2,059)
Current period change excluding amounts reclassified from accumulated other comprehensive income	(54)	(210)	64
Amounts reclassified from accumulated other comprehensive income	136	141	167
Balance at December 31	CAD (1,815)	CAD (1,897)	CAD (1,828)

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Amounts Reclassified Out of Accumulated Other Comprehensive Income (Loss) (Detail) - CAD CAD in Millions		12 Months Ended
		Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Reclassification Adjustment out of Accumulated Other Comprehensive Income
Reclassification Adjustment out of Accumulated Other Comprehensive Income [Line Items]
Amortization of post retirement benefits liability adjustment included in net periodic benefit cost	[1]	CAD (194)	CAD (184)	CAD (228)

[1] This accumulated other comprehensive income component is included in the computation of net periodic benefit cost (note 4).

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Income Tax Expense (Credit) for Components of Other Comprehensive Income (Loss) (Detail) - CAD CAD in Millions	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Accumulated Other Comprehensive Income (Loss) [Line Items]
Post retirement benefits liability adjustment (excluding amortization)	CAD (20)	CAD (77)	CAD 24
Amortization of post retirement benefits liability adjustment included in net periodic benefit cost	58	43	61
Total	CAD 38	CAD (34)	CAD 85