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, 2013 Commission file number: 0-12014            

IMPERIAL OIL LIMITED

(Exact name of registrant as specified in its charter)

CANADA	98-0017682
(State or other jurisdiction of incorporation or organization)	(I.R.S. Employer Identification No.)
237 FOURTH AVENUE S.W., CALGARY, AB, CANADA	T2P 3M9
(Address of principal executive offices)	(Postal Code)

Registrant’s telephone number, including area code:

1-800-567-3776

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

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

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 ü     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).

Yesü     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 ü     No……

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

Large accelerated filer ü    Accelerated filer……Non-accelerated filer……Smaller reporting company……

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 ü

As of the last business day of the 2013 second fiscal quarter, the aggregate market value of the voting stock held by non-affiliates of the registrant was Canadian $10,345,478,926 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 13, 2014, was 847,599,011.

1

Table of contents		Page
PART I			3
Item 1.	Business		3
	Upstream		4
	Disclosure of reserves		4
	Proved undeveloped reserves		5
	Oil and gas production, production prices and production costs		6
	Drilling and other exploratory and development activities		7
	Present activities		10
	Delivery commitments		10
	Oil and gas properties, wells, operations, and acreage		11
	Downstream		13
	Supply		13
	Transportation		13
	Refining		13
	Distribution		14
	Marketing		14
	Chemical		14
	Research		15
	Environmental protection		15
	Human resources		15
	Competition		15
	Government regulation		15
	The company online		16
Item 1A.	Risk factors		17
Item 1B.	Unresolved staff comments		20
Item 2.	Properties		20
Item 3.	Legal proceedings		20
Item 4.	Mine safety disclosures		20
PART II			21
Item 5.	Market for registrant’s common equity, related stockholder matters and issuer purchases of equity securities		21
Item 6.	Selected financial data		22
Item 7.	Management’s discussion and analysis of financial condition and results of operations		22
Item 7A.	Quantitative and qualitative disclosures about market risk		23
Item 8.	Financial statements and supplementary data		23
Item 9.	Changes in and disagreements with accountants on accounting and financial disclosure		23
Item 9A.	Controls and procedures		23
Item 9B.	Other information		23
PART III			24
Item 10.	Directors, executive officers and corporate governance		24
Item 11.	Executive compensation		24
Item 12.	Security ownership of certain beneficial owners and management and related stockholder matters		25
Item 13.	Certain relationships and related transactions, and director independence		25
Item 14.	Principal accountant fees and services		25
PART IV			26
Item 15.	Exhibits, financial statement schedules		26
Financial section			31
Proxy information section			87

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	2013		2012		2011		2010		2009
Rate at end of period		0.9348		1.0042		0.9835		0.9991		0.9559
Average rate during period		0.9665		1.0006		1.0144		0.9659		0.8793
High		1.0164		1.0299		1.0584		1.0040		0.9719
Low		0.9348		0.9600		0.9430		0.9280		0.7695

On February 13, 2014, 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 $0.9108 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 results, including demand growth and energy source mix; production growth and mix; project plans, dates, costs and capacities; production rates 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 price, and supply of and demand for crude oil, natural gas, and petroleum and petrochemical products; political or regulatory events; project schedules; commercial negotiations; the receipt, in a timely manner, of regulatory and third-party approvals; unanticipated operational disruptions; unexpected technological developments; 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. Imperial’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.

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 237 Fourth Avenue S.W. Calgary, Alberta, Canada T2P 3M9; telephone 1-800-567-3776. Exxon Mobil Corporation 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 and natural gas and 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”.

On February 26, 2013, ExxonMobil Canada acquired Celtic Exploration Ltd. (Celtic). Immediately following the acquisition, Imperial acquired a 50 percent interest in Celtic’s assets and liabilities from ExxonMobil Canada for $1.6 billion, financed by a combination of related party and third party debt. Concurrently, a general partnership was formed to hold and operate the assets of Celtic. The name of the general partnership was changed to XTO Energy Canada (XTO Canada). XTO Canada is involved in the exploration for, production of, and transportation and sale of natural gas and crude oil, condensate and natural gas liquids. Details of the transaction are contained in the Financial section of this report under note 18 to the consolidated financial statements: “Acquisition”. The company’s share of financial results and operating information, including reserves, volumes, wells and acreage relating to XTO Canada, are included for the first time in 2013.

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, 2013, as detailed in the “Supplemental information on oil and gas exploration and production activities” part of the Financial section, starting on page 31 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, 2013 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		55		368		579		1,417		2,113
Undeveloped		7		310		-		1,450		1,509
Total net proved		62		678		579		2,867		3,622

(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 pressure declines. 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 and significant changes in projections of long-term oil and gas price levels.

Technologies used in establishing proved reserves estimates

Additions to Imperial’s proved reserves in 2013 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 high-quality 2-D and 3-D 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 United States 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.

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Key components of the reserves estimation process include technical evaluations and analysis of well and field performance and a rigorous peer review. The reserves management group maintains a central database containing the official company reserves estimates and production data. 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. 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 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 Operations Technical Engineering Manager is a professional engineer registered in Alberta, Canada and has over 25 years of petroleum industry experience, including 20 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 60 persons with an average of 16 years of relevant technical experience in evaluating reserves, of whom 38 persons are qualified reserves evaluators for purposes of Canadian securities regulatory requirements. The company’s internal reserves evaluation management team is made up of 16 persons with an average of 12 years of relevant experience in evaluating and managing the evaluation of reserves. No independent qualified reserves evaluator or auditor was involved in the preparation of the company’s reserves data.

Proved undeveloped reserves

As at December 31, 2013, approximately 42 percent of the company’s proved reserves were proved undeveloped reserves reflecting volumes of 1,509 million oil-equivalent barrels. Nearly all of those undeveloped reserves are associated with either the Kearl project or Cold Lake field. This compared to approximately 65 percent or 2,318 million oil-equivalent barrels of proved undeveloped reserves reported at the end of 2012. Decreased proved undeveloped bitumen reserves in 2013 were largely due to the start-up of the initial development at Kearl in the second quarter, resulting in a migration of proved undeveloped reserves to proved developed. Increased proved undeveloped liquids and natural gas reserves were primarily associated with the company’s share of reserves from the Celtic acquisition in 2013.

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 significant lead-time in order to be developed. The company made investments of about $4.5 billion during the year to progress the development of reported proved undeveloped reserves. The largest project under development in 2013 was the Kearl project. Production from the initial development commenced in the second quarter of 2013. By 2013 year-end, the Kearl expansion project was 72 percent complete and remains on target for a 2015 start-up.

Proved undeveloped reserves at Cold Lake are associated with the ongoing drilling program and the Nabiye project. Imperial moved 19 million oil-equivalent barrels from proved undeveloped to proved developed reserves at Cold Lake through ongoing drilling programs. By 2013 year-end, the Nabiye project was 65 percent complete. Target start-up, although under pressure, remains year-end 2014.

Proved undeveloped reserves that have remained undeveloped for five years or more are primarily associated with Cold Lake and were not material compared to the company’s proved reserves and proved undeveloped reserves.

5

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 35 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, 2013 was as follows. All reported production volumes were from Canada.

thousands of barrels per day		2013		2012		2011
Bitumen (a):	- gross (b)		169		154		160
	- net (c)		142		123		120
Synthetic oil (d):	- gross (b)		67		72		72
	- net (c)		65		69		67
Liquids:	- gross (b)		25		24		23
	- net (c)		20		18		17
Total:	- gross (b)		261		250		255
	- net (c)		227		210		204

(a) The company’s bitumen production volumes included production volumes from the Cold Lake operation for all years presented in the table above and, beginning in 2013, also included production volumes from the Kearl initial development (16,000 barrels per day gross, 15,000 net).

(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.

Average daily production and sales of natural gas

The company’s average daily production and sales of natural gas during the three years ended December 31, 2013 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 35 of this report for a narrative discussion on the material changes.

millions of cubic feet per day	2013		2012		2011
Gross production (a) (b)		201		192		254
Net production (b) (c)		189		195		228
Sales (d)		167		177		237

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

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

(c) Net production is gross production less the mineral owners’ or governments’ share or both. Net natural gas production in 2012 included favourable royalty cost adjustments.

(d) Includes sales of the company’s share of production (before deduction of the mineral owners’ and/or governments’ share) and sales of gas purchased, processed and/or resold. Sales of natural gas exclude amounts used for internal consumption.

Total average daily oil-equivalent basis production

The company’s total average daily production expressed in 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	2013		2012		2011
Total production oil-equivalent basis:
- gross (a)		295		282		297
- net (b)		259		243		242

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

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

6

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, 2013, were as follows.

dollars per barrel	2013		2012		2011
Liquids		75.61		71.52		77.34
Synthetic oil		99.69		92.48		101.43
Bitumen		60.57		59.76		63.95
dollars per thousand cubic feet
Natural gas		3.27		2.33		3.59

Average unit production costs

dollars per barrel	2013		2012		2011
Synthetic oil		53.27		48.41		48.33
Bitumen		32.20		21.98		19.30
Total oil-equivalent basis (a)		35.93		29.10		26.63

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

Synthetic oil production costs increased in 2013 primarily due to higher planned maintenance activities at Syncrude. Increased bitumen production costs in 2013 were primarily driven by Kearl start-up and operating costs.

In 2012, unit production costs increased on a net basis primarily due to pre start-up costs associated with the Kearl initial development.

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, 2013.

wells	2013		2012		2011
Net productive exploratory		1		1		3
Net dry exploratory		1		-		-
Net productive development		157		39		96
Net dry development		-		-		-
Total		159		40		99

In 2013, the following wells were drilled to add productive capacity: 120 development wells at the Cold Lake Nabiye expansion project, 34 net tight oil development wells and three net other wells.

In 2012, the following wells were drilled to add productive capacity: 28 bitumen development wells in undeveloped areas of existing phases at Cold Lake, three development evaluation wells at Cold Lake, four net Horn River pilot wells and four net tight oil development wells.

In 2011, the following wells were drilled to add productive capacity: 34 bitumen development wells in undeveloped areas of existing phases at Cold Lake, 60 gas development wells in the shallow gas area and two net tight oil wells in the company’s existing conventional acreage.

7

Wells drilling

At December 31, 2013, the company was participating in the drilling of the following exploratory and development wells. All wells were located in Canada.

	2013
wells	Gross		Net
Total		85		78

Exploratory and development activities regarding oil and gas resources

Cold Lake

In February 2012, the Nabiye expansion at Cold Lake was sanctioned. The expansion is expected to ultimately bring on additional production of 40,000 barrels per day, before royalties. The expansion was 65 percent complete by 2013 year-end. During the fourth quarter of 2013, plant construction progressed somewhat slower than planned due to lower contractor productivity and harsh winter conditions. Target start-up, although under pressure, remains year-end 2014.

To maintain production at Cold Lake, additional wells were drilled on existing phases in 2013. In 2014, a development drilling program is planned within the approved development area to add productive capacity from undeveloped areas of existing Cold Lake phases.

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

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. The company retains a 100 percent interest in the largest of these fields.

In late 2010, the National Energy Board (NEB) announced its approval of plans to build and operate the project subject to 264 conditions in areas such as engineering, safety and environmental protection. Federal cabinet approved the project in early 2011.

The commercial viability of these natural gas resources, and the pipeline required to transport this natural gas to markets, is dependent on a number of factors. These factors include natural gas markets, continued support from northern parties, fiscal framework and the cost of constructing, operating and abandoning the field production and pipeline facilities.

The company continues to maintain the right of way agreements and permits required to develop its Mackenzie Delta natural gas resource and in December 2013, updated costs were filed as required under one of the conditions of the permits. No final investment decision has been made.

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’s interest in its 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, and continued community consultations. No final investment decision has been made.

The company’s share of the total work commitment for the Beaufort Sea licence is $441 million.

8

Other oil sands activity

In the third quarter of 2013, the company (27.5 percent) and ExxonMobil Canada (72.5 percent) acquired an interest in the Clyden oil sands lease, 150 kilometres south of Fort McMurray, Alberta. The 226,000 gross acre lease is amenable to in-situ recovery techniques.

The company filed a regulatory application for a new in-situ oil sands project at Aspen (south of Kearl) in December 2013. Steam-assisted gravity drainage (SAGD) technology would be used to develop the project in three phases of about 45,000 barrels per day before royalties, per phase. No final investment decision has been made. Work continues on technical evaluations to support potential Cold Lake Grand Rapids and Corner 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.

Liquefied natural gas (LNG) export application

In December 2013, WCC LNG Ltd., jointly owned by the company (50 percent) and ExxonMobil Canada Ltd. (50 percent), received approval from the NEB to export up to 30 million tonnes of LNG per year for a period of 25 years. No final investment decision has been made.

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

Kearl

The company holds a 70.96 percent participating interest in the Kearl oil sands project, a joint venture with ExxonMobil Canada Properties, a subsidiary of Exxon Mobil Corporation. The Kearl project recovers shallow deposits of oil sands using open-pit mining methods. The project is located approximately 75 kilometres north of Fort McMurray, Alberta.

The Kearl project received project development approvals from the Province of Alberta in 2007 and the Government of Canada in 2008. The Province of Alberta issued an operating and construction licence in 2008, which permits the project to mine oil sands and produce bitumen from approved development areas on oil sands leases. Production from the initial development commenced in April 2013, as discussed in the “Present activities” section on page 10.

The Kearl expansion project was 72 percent complete at the end of 2013. The Kearl expansion project remains on schedule for a 2015 start-up and is expected to produce 110,000 barrels of bitumen per day, before royalties, of which the company’s share would be about 78,000 barrels per day.

Potential future debottlenecking of both the initial development and expansion would increase output to reach the regulatory capacity of 345,000 barrels of bitumen per day by about 2020, of which the company’s share would be about 245,000 barrels per day.

Other oil sands activity

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

9

Present activities

Review of principal ongoing activities

Cold Lake

During 2013, average net production at Cold Lake was about 127,000 barrels per day and gross production was about 153,000 barrels per day.

Most of the production from Cold Lake is sold to refineries in the United States. The remainder of Cold Lake production is shipped to certain of the company’s refineries and to third-party Canadian refineries.

The Province of Alberta, in its capacity as lessor of Cold Lake oil sands leases, is entitled to a royalty on production at Cold Lake. Royalty rates are based upon a sliding scale determined by the price of crude oil.

Kearl

Bitumen from the Kearl project is extracted from oil sands produced from open-pit mining operations and is processed through bitumen extraction facilities and froth treatment trains. The product, a blend of bitumen and diluent, is shipped to certain of the company’s refineries, ExxonMobil refineries and to other unrelated third parties.

Production of mined diluted bitumen began in April 2013 and continued to ramp-up throughout the remainder of the year. Since start-up, improvements have been made to equipment reliability. Although gross production rates of 100,000 barrels per day (71,000 Imperial’s share) were reached in the fourth quarter, ongoing activities to stabilize performance at these higher levels are progressing. Also in the fourth quarter, sales to unrelated third parties commenced as planned. During 2013, average gross production at Kearl was about 23,000 barrels per day (16,000 barrels per day Imperial’s share).

The Province of Alberta, in its capacity as lessor of Kearl oil sands leases, is entitled to a royalty on production at Kearl. Royalty rates are based upon a sliding scale determined by the price of crude oil.

Syncrude

The company holds a 25 percent participating interest in Syncrude, a joint venture established to recover shallow deposits of oil sands using open-pit mining methods to extract the crude bitumen, and to produce a high-quality, light (32 degree API), sweet, synthetic crude oil. The Syncrude operation, located near Fort McMurray, Alberta, mines a portion of the Athabasca oil sands deposit. The produced synthetic crude oil is shipped from the Syncrude site to Edmonton, Alberta by Alberta Oil Sands Pipeline Ltd.

In 2013, the company’s share of Syncrude’s net production of synthetic crude oil was about 65,000 barrels per day and gross production was about 67,000 barrels per day.

Effective January 1, 2009, the Syncrude Crown Royalty Agreement was amended. Under the amended agreement, starting in 2010 and through 2015, Syncrude will pay the existing Crown royalty rates plus an incremental royalty, the amount of which will be subject to minimum production thresholds, before transitioning to the new generic royalty framework in 2016. Also, beginning January 1, 2009, Syncrude’s royalty is based on bitumen value with upgrading costs and revenues excluded from the calculation.

Conventional oil and gas

The Norman Wells oil field in the Northwest Territories is the company’s largest conventional oil producing asset and currently accounts for about 50 percent of the company’s gross production of conventional crude oil. In 2013, gross production of conventional crude oil from Norman Wells was about 11,000 barrels per day.

In 2013, the company commenced marketing of three mature conventional properties; Boundary Lake, Pembina and Rocky Mountain House. Combined production from these properties totalled about 15,000 oil-equivalent barrels per day in 2013, split about evenly between oil and gas.

Delivery commitments

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

10

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, 2013 and December 31, 2012, 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, 2013

Year-ended December 31, 2012

Crude oil

Natural gas

Crude oil

Natural gas

wells

Gross (a)

Net (b)

Gross (a)

Net (b)

Gross (a)

Net (b)

Gross (a) (c)

Net (b) (c)

Total (d)

5,207

4,847

3,615

1,235

5,036

4,736

3,328

1,140

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

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

(c) Natural gas wells in 2012 reflect revised numbers from properties operated by others.

(d) Multiple completion wells are permanently equipped to produce separately from two or more distinctly different geological formations. At year-end 2013, the company had an interest in four gross wells with multiple completions (2012 - four gross wells).

The total number of wells increased in 2013 primarily due to the acquisition of a 50 percent interest in Celtic’s assets and liabilities.

Land holdings

At December 31, 2013 and 2012, the company held the following oil and gas rights, 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		2013		2012		2013		2012		2013		2012
Western provinces:
Liquids and gas (a)	- gross (b)		2,337		2,127		1,312		658		3,649		2,785
	- net (c)		764		687		662		359		1,426		1,046
Bitumen (a)	- gross (b)		156		103		737		606		893		709
	- net (c)		130		103		370		345		500		448
Synthetic oil	- gross (b)		118		118		135		135		253		253
	- net (c)		29		29		34		34		63		63
Canada lands (d):
Liquids and gas	- gross (b)		4		4		2,272		2,314		2,276		2,318
	- net (c)		2		2		718		722		720		724
Atlantic offshore:
Liquids and gas	- gross (b)		65		65		288		1,780		353		1,845
	- net (c)		6		6		46		270		52		276
Total (e):	- gross (b)		2,680		2,417		4,744		5,493		7,424		7,910
	- net (c)		931		827		1,830		1,730		2,761		2,557

(a) Land holdings associated with the acquisition of the Celtic assets in February 2013 are primarily included within western provinces liquids and gas acreage and at 2013 year-end totalled about 191,000 gross developed acres (about 67,000 net developed) and about 694,000 gross undeveloped acres (about 315,000 net undeveloped). Land holdings associated with the acquisition of Celtic assets included in bitumen are de minimis.

(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 193,000 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, acquired by the company in 2013. These 193,000 net acres are amenable to 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 fifteen years and are continued beyond that point by meeting the minimum level of evaluation, payment of 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 1,426,000 net acres of developed and undeveloped land in western Canada related to crude oil and natural gas. Included in this number is a total acreage position of about 170,000 net acres at Horn River, British Columbia. Crude oil and natural gas acreage increased in 2013, largely due to the acquisition of the Celtic assets in February 2013.

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

Canada lands

Land holdings in Canada lands primarily include acreage in the Beaufort Sea of about 252,000 net acres, the Summit Creek area of central Mackenzie Valley totalling about 222,000 net acres and the Mackenzie Delta of about 181,000 net acres.

Exploration licences on Canada lands and Atlantic offshore have a finite term. If a significant discovery is made, a significant discovery licence (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 exploration licences and SDLs.

Atlantic offshore

In 2013, the company assigned its land holdings in the Orphan Basin area totalling about 224,000 net acres to an unrelated third party.

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

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Downstream

Supply

To supply the requirements of its own refineries and condensate requirements for blending with crude bitumen, the company supplements its own production with substantial purchases from others.

The company purchases domestic crude oil at freely negotiated prices from a number of sources. Domestic purchases of crude oil are generally made under renewable contracts with 30 to 60 day cancellation terms.

When required, crude oil from foreign sources is purchased by the company at market prices mainly through Exxon Mobil Corporation (which has beneficial access to major market sources of crude oil throughout the world). Following the conversion of the Dartmouth refinery to a fuels terminal, crude oil from foreign sources is anticipated to decline significantly.

Transportation

Imperial currently transports about 400,000 barrels per day by pipeline and has secured an additional 390,000 barrels per day capacity on pipeline projects set to be in service over the next several years. To mitigate uncertainty associated with the timing of pipeline projects, the company is developing rail infrastructure with potential incremental capacity up to 200,000 barrels per day over the next several years. These transportation capacities are primarily to ship crude oil.

Refining

The company owns and operates three refineries. The Strathcona and Sarnia refineries process Canadian crude oil and the Nanticoke refinery processes a combination of Canadian and foreign crude oil. The Strathcona refinery operates lubricating oil production facilities. In addition to crude oil, the company purchases finished products to supplement its refinery production.

In the second quarter of 2013, the company announced its decision to convert the Dartmouth refinery to a fuels terminal. In the third quarter, refinery operations at the Dartmouth refinery were discontinued. The company continues to supply east coast Canadian markets with petroleum products.

In 2013, capital expenditures of about $82 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, 2013, and the daily rated capacities of the refineries as at December 31, 2013 were as follows.

	Refinery throughput (a)						Rated capacities (b) at
	Year-ended December 31						December 31
thousands of barrels per day	2013		2012		2011		2013
Strathcona, Alberta		172		163		169		189
Sarnia, Ontario		105		103		102		119
Nanticoke, Ontario		99		99		93		113
Dartmouth, Nova Scotia (c) (d)		50		70		66		n/a
Total		426		435		430		421

(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.

(c) Refinery operations at the Dartmouth refinery were discontinued on September 16, 2013.

(d) Dartmouth refinery rated capacity as at December 31, 2012 was 85,000 barrels per day.

In 2013, refinery throughput was 88 percent of capacity, two percent higher than the previous year. The higher rate was primarily a result of increased product sales and reduced maintenance activities. Capacity utilization in 2013 is calculated based on the number of days the refineries were operated as a refinery.

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Distribution

The company maintains a nationwide distribution system, including 22 primary terminals, 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.

Marketing

The company markets more than 550 petroleum products throughout Canada under well-known brand names, most notably Esso and Mobil, to all types of customers.

The company sells to the motoring public through Esso retail service stations. On average during the year, there were more than 1,700 retail service stations, of which about 470 were company owned or leased, but none of which were company operated. The company continues to improve its Esso retail service station network, providing more customer services such as car washes and convenience stores, primarily at high volume sites in urban centres.

The Canadian agriculture, residential heating and small commercial markets are served by about 28 branded resellers. The company also sells petroleum products to large industrial and commercial accounts as well as to other refiners and marketers.

The approximate daily volumes of net petroleum products (excluding purchases/sales contracts with the same counterparty) sold during the three years ended December 31, 2013, are set out in the following table.

thousands of barrels per day	2013		2012		2011
Gasolines		223		221		220
Heating, diesel and jet fuels		160		151		157
Heavy fuel oils		29		30		29
Lube oils and other products		42		43		41
Net petroleum product sales		454		445		447

Total Downstream capital expenditures were $187 million in 2013.

Chemical

The company’s Chemical operations manufacture and market ethylene, benzene, aromatic and aliphatic solvents, plasticizer intermediates and polyethylene resin. Its major petrochemical and polyethylene manufacturing operations are located in Sarnia, Ontario, adjacent to the company’s petroleum refinery. As part of the decision to convert the Dartmouth refinery to a fuels terminal, the heptene and octene plant located at Dartmouth was shut down.

Progress continued on the infrastructure required to implement a long-term supply agreement for ethane from the nearby Marcellus shale gas development. First deliveries of this feedstock to the Sarnia chemical plant are expected in the first quarter of 2014.

The company’s total sales volumes of petrochemicals during the three years ended December 31, 2013, were as follows.

thousands of tonnes	2013		2012		2011
Total sales of petrochemicals		940		1,044		1,016

Lower sales volumes in 2013 were primarily due to lower manufacturing as a result of the plant shutdown at Dartmouth noted above and lower ethylene feed availability.

Capital expenditures in 2013 were $9 million.

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Research

In 2013, the company’s total gross research expenditures, before credits, were about $199 million, as compared with $201 million in 2012, and $163 million in 2011. Research expenditures are mainly for developing technologies to reduce the environmental impact and improve bitumen recovery in the Upstream and for supporting environmental and process improvements in the refineries, as well as accessing ExxonMobil’s data worldwide.

The company has scientific research agreements with affiliates of Exxon Mobil Corporation, 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 is concerned with and active in protecting the environment in connection with its various operations. The company works in cooperation with government agencies, industry associations and communities to deal with existing, and to anticipate potential, environmental protection issues. In the past five years, the company has made capital and operating expenditures of about $4.7 billion on environmental protection and facilities. In 2013, the company’s environmental capital and operating expenditures totalled approximately $1.5 billion, which was spent primarily on air emissions reductions, water and tailings treatment at both company owned facilities and Syncrude and remediation of idled facilities and operations. Capital and operating expenditures relating to environmental protection are expected to be about $1.7 billion in 2014.

Human resources

Career employees (a)	2013		2012		2011
Total		5,300		5,100		4,900

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

The increase in career employees in 2013 is primarily associated with start-up of the Kearl oil sands project. About eight 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 other needs of consumers.

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.

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Crude oil

Production

The maximum allowable gross production of crude oil from wells in Canada is subject to limitation 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 crude bitumen) require the prior approval of the 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 2013 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.

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 Exxon Mobil Corporation, the company is considered to be an entity which is not controlled by Canadians.

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

Volatility of oil and natural gas prices

The company’s results of operations and financial condition are dependent on the prices it receives for its oil and natural gas production. Crude oil and natural gas prices are determined by global and North American markets and are subject to changing supply and demand conditions. These can be influenced by a wide range of factors including economic conditions, international political developments and weather. Disruptions to pipelines linking production to markets may reduce the price for that production or lead to curtailment of production. In the past, crude oil and natural gas prices have been volatile, and the company expects that volatility to continue. Any material decline in oil or natural gas prices could have a material adverse effect on the company’s operations, financial condition, proved reserves and the amount spent to develop oil and natural gas reserves.

A significant portion of the company’s production is bitumen. The market prices for bitumen differ from the established market indices for light and medium grades of oil principally due to the higher transportation and refining costs associated with bitumen and limited refining capacity capable of processing bitumen. Bitumen may also be subject to limits on transportation capacity to markets to a larger extent than light crude oil. As a result, the price received for bitumen is generally lower than the price for medium and light oil. Future differentials are uncertain and increases in the bitumen differentials could have a material adverse effect on the company’s business.

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.

The company does not use derivative instruments to offset exposures associated with hydrocarbon prices, currency exchange rates and interest rates that arise from existing assets, liabilities and transactions. The company does not engage in speculative derivative activities nor does it use derivatives with leveraged features.

Competitive factors

The oil and gas industry is highly competitive, particularly in the following areas: searching for and developing new sources of supply; constructing and operating crude oil, natural gas and refined products pipelines and facilities; and the refining, distribution and marketing of petroleum products and chemicals. The company’s competitors include major integrated oil and gas companies and numerous other independent oil and gas companies. The petroleum industry also competes with other industries in supplying energy, fuel and related products to customers.

Competitive forces may result in shortages of prospects to drill, services to carry out exploration, development or operating activities and infrastructure to produce and transport production. It may also result in an oversupply of crude oil, natural gas, petroleum products and chemicals. Each of these factors could have a negative impact on costs and prices and, therefore, the company’s financial results.

Environmental risks

All phases of the Upstream, Downstream and Chemical businesses are subject to environmental regulation pursuant to a variety of Canadian federal, provincial 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 to 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, 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 imposition of fines and penalties and liability for clean-up costs and damages. The costs of complying with environmental legislation

17

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 to the air from its operations and result in increased capital expenditures. Changes in environmental regulations or other laws (including changes in laws related to hydraulic fracturing) may increase our 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

The Government of Canada has confirmed its intent to introduce a set of regulations to limit emissions of greenhouse gas and air pollutants from major industrial facilities in Canada and to align Canadian policy in this area with that of the U.S. As these policies and potential regulations remain under development, attempts to assess the impact on the company are premature.

In the Province of Alberta, regulations governing greenhouse gas emissions from large industrial facilities came into effect in 2007. The regulation requires a reduction by 12 percent in the greenhouse gas emissions per unit of production from each facility’s average annual intensity. Allowed compliance measures include participation in an Alberta emission-trading system or payment to Alberta’s Climate Change and Emissions Management Fund. The impact on the company has not been material.

The Province of British Columbia has established a carbon tax, applicable to purchases of hydrocarbon fuels and emissions of greenhouse gases. The impact on the company has not been material.

The Province of Quebec has implemented a cap-and-trade system which will regulate greenhouse gas emissions from transportation and heating sources in 2015. The impact on the company is not anticipated to be material.

The Province of Ontario has passed legislation authorizing the issuing of regulations for the creation of a provincial cap-and-trade system controlling greenhouse gas emissions. Details on such possible regulations have not been issued so an assessment of impacts is premature.

The Province of British Columbia’s Renewable and Low Carbon Fuel Requirement Regulation requires suppliers of transportation fuels to reduce the carbon intensity of fuels sold in the province by an increasing amount over time. To date, there has not been a significant impact to the company’s operations.

Further federal, provincial or international legislation or regulation controlling greenhouse gas emissions could occur. Such requirements could make our products more expensive; lengthen project implementation times; reduce demand for hydrocarbons and shift hydrocarbon demand toward relatively lower-carbon sources, such as natural gas; and may result in increased capital expenditures and operating costs. Such requirements may have a material adverse effect on the company’s financial condition or results of operations, but this cannot be estimated at this time.

Other regulatory risk

The company is subject to a wide range of legislation and regulation governing its operations and industry transportation infrastructure, over which it has no control. Changes may affect every aspect of the company’s operations and financial performance. In addition, the company’s longer-term development plans may be adversely affected if, for regulatory or other reasons, necessary additional transportation infrastructure is not added in a timely fashion.

Need to replace reserves

The company’s future liquids, bitumen, synthetic oil and natural gas reserves and production, and therefore cash flows, are highly dependent upon the company’s success in exploiting its current reserve base and acquiring or discovering additional reserves. Without additions to the company’s reserves through exploration,

18

acquisition or development activities, reserves and production will decline over time as reserves are depleted. The business of exploring for, developing or acquiring reserves is capital intensive. 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 impaired. 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.

Research and development

To maintain our competitive position, especially in light of the technological nature of our business and the need for continuous efficiency improvement, the research and development organizations of the company and ExxonMobil, with whom the company conducts shared research, must be successful and able to adapt to a changing market and policy environment.

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, crude oil spills, severe weather, and geological events. Our operations are also subject to the additional hazards of pollution, releases of toxic gas and other environmental hazards and risks. Our results depend on management’s ability to minimize these inherent risks, to control effectively our business activities and to minimize the potential for human error. We apply rigorous management systems and continuous focus to workplace safety and to avoiding spills or other adverse environmental events. For example, we work to minimize spills through a combined program of effective operations integrity management, ongoing upgrades, key equipment replacements, and comprehensive inspection and surveillance. We also maintain a disciplined framework of internal controls and apply a controls management system for monitoring compliance with this framework. Substantial liabilities and other adverse impacts could result if our management systems and controls do not function as intended. The company’s insurance may not provide adequate coverage in certain unforeseen circumstances.

Operational efficiency

An important component of the company’s competitive performance, especially given the commodity-based nature of many of our business segments, is our ability to operate efficiently, including our ability to manage expenses and improve production yields on an ongoing basis. This requires continuous management focus, including technology improvements, cost control, productivity enhancements, regular reappraisal of our asset portfolio, and the recruitment, development and retention of high caliber employees.

Preparedness

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

Other business risks

The marketability of the company’s production is subject in part to the risks associated with transporting, processing and storing crude oil, natural gas and other related products. The availability, proximity, and capacity of pipeline facilities and railcars could negatively impact our ability to produce at capacity levels. Transportation disruptions could adversely affect commodity prices, the company’s price realizations, refining operations and sales volumes, or limit our ability to deliver production to market.

Other factors that may affect the demand for oil, gas and petrochemicals, and therefore impact the company’s results, include 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; and changes in technology or consumer preferences that alter fuels choices, such as toward alternative fueled vehicles.

Business risks also include the risk of cyber security breaches. If management’s systems for protecting against cyber security risk prove not to be sufficient, the company could be adversely affected such as by having its business systems compromised, its proprietary information altered, lost or stolen, or its business operations disrupted.

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Uncertainty of reserve estimates

There are numerous uncertainties inherent in estimating quantities of reserves, including many factors beyond the company’s control. In general, estimates of economically recoverable oil and natural gas reserves and the future net cash flow are based upon a number of factors and assumptions made as of the date on which the reserve estimates were determined, such as geological and engineering estimates which have inherent uncertainties, the assumed effects of regulation by governmental agencies and future commodity prices and operating costs, all of which may vary considerably from actual results. All such estimates are, to some degree, uncertain and classifications of reserves are only attempts to define the degree of uncertainty involved. For these reasons, estimates of the economically recoverable oil and natural gas reserves, the classification of such reserves based on risk of recovery and estimates of future net revenues expected therefrom, prepared by different reserves evaluators or by the same evaluators at different times, may vary substantially. Actual production, revenues, taxes, and development, abandonment and operating expenditures with respect to reserves will likely vary from such estimates, and such variances could be material.

Estimates with respect to reserves that may be developed and produced in the future are often based upon volumetric calculations and upon analogy to similar types of reserves, rather than upon actual production history. Estimates based on these methods generally are less reliable than those based on actual production history. Subsequent evaluation of the same reserves based upon production history will result in variations, which may be material, in the estimated reserves.

Project factors

The company’s results depend on its ability to develop and operate major 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 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.

Item 1B. Unresolved staff comments

None.

Item 2. Properties

Reference is made to Item 1 above.

Item 3. Legal proceedings

Not applicable.

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 MKT LLC, a subsidiary of NYSE Euronext. Reference is made to the “Quarterly financial and stock trading data” portion of the Financial section on page 86 of this report. The closing price for Imperial Oil Limited common shares on the Toronto Stock Exchange was $47.27 as at February 13, 2014.

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.

	2013								2012
dollars	Q4		Q3		Q2		Q1		Q4		Q3		Q2		Q1
Declared dividend per share:		0.13		0.12		0.12		0.12		0.12		0.12		0.12		0.12

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 five percent on dividends paid to a corporation resident in the U.S. that owns at least ten 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 13, 2014 there were 12,215 holders of record of common shares of the company.

During the period October 1, 2013 to December 31, 2013, there were no shares issued by the company to employees or former employees outside the U.S. under its restricted stock unit plan.

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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 87. The company’s management proxy circular is prepared in accordance with Canadian securities regulations.

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

— entitled “Performance graph” within the “Compensation discussion and analysis section” on page 133 of this report; and

— entitled “Equity compensation plan information”, within the “Compensation discussion and analysis section”, on page 139 of this report.

Issuer purchases of equity securities

	Total number of shares purchased		Average price paid per share (dollars)		Total number of shares purchased as part of publicly announced plans or programs		Maximum number (or approximate dollar value) of shares that may yet be purchased under the plans or programs (a)
October 2013 (October 1 – October 31)		-		-		-		1,000,000
November 2013 (November 1 - November 30)		-		-		-		1,000,000
December 2013 (December 1 - December 31)		-		-		-		1,000,000

(a) On June 21, 2013, 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 share repurchase program. The new program enables the company to repurchase up to a maximum of 1,000,000 common shares during the period June 25, 2013 to June 24, 2014. Unlike prior programs, this maximum amount is not reduced by common shares purchased for the company’s employee savings plan, the company’s employee retirement plan and from Exxon Mobil Corporation. If not previously terminated, the program will end on June 24, 2014.

Item 6. Selected financial data

millions of dollars	2013		2012		2011		2010		2009
Operating revenues		32,722		31,053		30,474		24,946		21,292
Net income		2,828		3,766		3,371		2,210		1,579
Total assets at year-end		37,218		29,364		25,429		20,580		17,473
Long-term debt at year-end		4,444		1,175		843		527		31
Total debt at year-end		6,287		1,647		1,207		756		140
Other long-term obligations at year-end		3,091		3,983		3,876		2,753		2,839
dollars
Net income per share – basic		3.34		4.44		3.98		2.61		1.86
Net income per share – diluted		3.32		4.42		3.95		2.59		1.84
Dividends declared		0.49		0.48		0.44		0.43		0.40

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 35 of this report.

22

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 48 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.

Item 8. Financial statements and supplementary data

Reference is made to the table of contents in the Financial section on page 31 of this report:

— Consolidated financial statements, together with the report thereon of PricewaterhouseCoopers LLP (PwC) dated February 25, 2014 beginning with the section entitled “Report of independent registered public accounting firm” on page 54 and continuing through note 18, “Acquisition” on page 81;

— “Supplemental information on oil and gas exploration and production activities” (unaudited) starting on page 82; and

— “Quarterly financial and stock trading data” (unaudited) on page 86.

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, 2013. 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 53 of this report for “Management’s report on internal control over financial reporting” and page 54 for the “Report of independent registered public accounting firm” on the company’s internal control over financial reporting as of December 31, 2013.

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.

23

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 87. The company’s management proxy circular is prepared in accordance with Canadian securities regulations.

The company currently has seven 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 “Director information” on pages 88 to 96 of this report have been nominated for election at the annual meeting of shareholders to be held April 24, 2014. All of the nominees are directors and have been since the dates indicated. Bruce H. March announced his resignation as a director and as chairman, president and chief executive officer effective March 1, 2013. Richard M. Kruger was elected as a director and as chairman, president and chief executive officer effective March 1, 2013.

Reference is made to the sections under “III. Board of directors”:

— “Director information”, on pages 88 to 96 of this report;

— The table entitled “Audit committee” under “Board and committee structure”, on page 102 of this report; and

— “Other public company directorships”, on page 110 of this report.

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

— “Named executive officers of the company” and “Other executive officers of the company”, on page 116 and page 117 of this report.

Reference is made to the sections under “V. Other important information”:

— “Largest shareholder”, on page 141 of this report; and

— “Ethical business conduct”, starting on page 143 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 87. The company’s management proxy circular is prepared in accordance with Canadian securities regulations.

Reference is made to the sections under “III. Board of directors”:

— “Share ownership guidelines”, on page 109 of this report; and

— “Directors’ compensation program”, on pages 111 to 115 of this report.

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

— “Report of executive resources committee on executive compensation”, starting on page 118 of this report; and

— “Compensation discussion and analysis”, on pages 120 to 140 of this report.

24

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 87. The company’s management proxy circular is prepared in accordance with Canadian securities regulations.

Reference is made to the section under “IV. Company executives and executive compensation” entitled “Equity compensation plan information”, within the “Compensation discussion and analysis section”, on page 139 of this report.

Reference is made to the section under “V. Other important information” entitled “Largest shareholder”, on page 141 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. As of February 13, 2014, P.J. Masschelin was the owner of 1,000 common shares of the company and held 77,800 restricted stock units of the company. T.G. Scott was the owner of 10,000 common shares of the company and held 77,275 restricted stock units of the company. B.W. Livingston was the owner of 30,091 common shares of the company and held 112,250 restricted stock units of the company. B.G. Merkel was the owner of 4,866 common shares of the company and held 72,100 restricted stock units of the company.

The directors and the executive officers of the company, whose compensation for the year-ended December 31, 2013 is described in the sections under “III. Board of directors” starting on page 88 and “IV. Company executives and executive compensation” starting on page 116, consist of 15 persons, who, as a group, own beneficially 123,442 common shares of the company, being approximately 0.01 percent of the total number of outstanding shares of the company, and 544,460 shares of Exxon Mobil Corporation (including 453,100 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 344,450 common shares of the company, as of February 13, 2014.

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 87. The company’s management proxy circular is prepared in accordance with Canadian securities regulations.

Reference is made to the section under “V. Other important information” entitled “Transactions with Exxon Mobil Corporation”, on page 141 of this report.

Reference is made to the section under “III. Board of directors” entitled “Independence of the directors”, on page 99 of this report.

D.W. Woods is deemed a non-independent member of 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 ExxonMobil Refining and Supply Company, D.W. Woods is independent of the company’s management and is able to assist these committees by reflecting the perspective of the company’s shareholders.

Item 14. Principal accountant fees and services

Sections of the company’s management proxy circular are contained in the Proxy information section, starting on page 87. The company’s management proxy circular is prepared in accordance with Canadian securities regulations.

Reference is made to the section under “V. Other important information” entitled “Auditor information”, on page 142 of this report.

25

PART IV

Item 15. Exhibits, financial statement schedules

Reference is made to the table of contents in the Financial section on page 31 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-Q 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)).
(4)		The company’s long-term debt authorized under any instrument does not exceed 10 percent of the company’s consolidated assets. The company agrees to furnish to the Commission upon request a copy of any such instrument.
(10)	(ii)	(1)	Alberta Crown Agreement, dated February 4, 1975, relating to the participation of the Province of Alberta in Syncrude (Incorporated herein by reference to Exhibit 13(a) 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)	Amendment to Alberta Crown Agreement, dated January 1, 1983 (Incorporated herein by reference to Exhibit (10)(ii)(2) of the company’s Annual Report on Form 10-K for the year ended December 31, 1983 (File No. 2-9259)).
		(3)	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)).
		(4)	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)).
		(5)	Norman Wells Pipeline Agreement, dated January 1, 1980, relating to the operation, tolls and financing of the pipeline system from the Norman Wells field (Incorporated herein by reference to Exhibit 10(a)(3) of the company’s Annual Report on Form 10-K for the year ended December 31, 1981 (File No. 2-9259)).
		(6)	Norman Wells Pipeline Amending Agreement, dated April 1, 1982 (Incorporated herein by reference to Exhibit (10)(ii)(5) of the company’s Annual Report on Form 10-K for the year ended December 31, 1982 (File No. 2-9259)).
		(7)	Letter Agreement clarifying certain provisions to the Norman Wells Pipeline Agreement, dated August 29, 1983 (Incorporated herein by reference to Exhibit (10)(ii)(7) of the company’s Annual Report on Form 10-K for the year ended December 31, 1983 (File No. 2-9259)).
		(8)	Norman Wells Pipeline Amending Agreement, made as of February 1, 1985, relating to certain amendments ordered by the National Energy Board (Incorporated herein by reference to Exhibit (10)(ii)(8) of the company’s Annual Report on Form 10-K for the year ended December 31, 1986 (File No. 0-12014)).
		(9)	Norman Wells Pipeline Amending Agreement, made as of April 1, 1985, relating to the definition of “Operating Year” (Incorporated herein by reference to Exhibit (10)(ii)(9) of the company’s Annual Report on Form 10-K for the year ended December 31, 1986 (File No. 0-12014)).
		(10)	Norman Wells Expansion Agreement, dated October 6, 1983, relating to the prices and royalties payable for crude oil production at Norman Wells (Incorporated herein by reference to Exhibit (10)(ii)(8) of the company’s Annual Report on Form 10-K for the year ended December 31, 1983 (File No. 2-9259)).
		(11)	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)).
		(12)	Amendment to Alberta Crown Agreement, dated January 1, 1986 (Incorporated herein by reference to Exhibit (10)(ii)(12) of the company’s Annual Report on Form 10-K for the year ended December 31, 1987 (File No. 0-12014)).
		(13)	Amendment to Alberta Crown Agreement, dated November 25, 1987 (Incorporated herein by reference to Exhibit (10)(ii)(13) of the company’s Annual Report on Form 10-K for the year ended December 31, 1987 (File No. 0-12014)).

26

	(14)	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)).
	(15)	Amendment to Alberta Crown Agreement, dated August 1, 1991 (Incorporated herein by reference to Exhibit (10)(ii)(15) of the company’s Annual Report on Form 10-K for the year ended December 31, 1991 (File No. 0-12014)).
	(16)	Norman Wells Settlement Agreement, dated July 31, 1996. (Incorporated herein by reference to Exhibit (10)(ii)(16) of the company’s Annual Report on Form 10-K for the year ended December 31, 1996 (File No. 0-12014)).
	(17)	Amendment to Alberta Crown Agreement, dated January 1, 1997. (Incorporated herein by reference to Exhibit (10)(ii)(17) of the company’s Annual Report on Form 10-K for the year ended December 31, 1996 (File No. 0-12014)).
	(18)	Norman Wells Pipeline Amending Agreement, dated December 12, 1997. (Incorporated herein by reference to Exhibit (10)(ii)(18) of the company’s Annual Report on Form 10-K for the year ended December 31, 1998 (File No. 0-12014)).
	(19)	Norman Wells Pipeline 1999 Amending Agreement, dated May 1, 1999. (Incorporated herein by reference to Exhibit (10)(ii)(19) of the company’s Annual Report on Form 10-K for the year ended December 31, 1999 (File No. 0-12014)).
	(20)	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)).
	(21)	Amendment to Alberta Crown Agreement effective January 1, 2001 (Incorporated herein by reference to Exhibit (10)(ii)(21) of the company’s Quarterly Report on Form 10-Q for the quarter ended June 30, 2002 (File No. 0-12014)).
	(22)	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)).
	(23)	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)).
	(24)	Amendment to Alberta Crown Agreement dated November 29, 1995 (Incorporated herein by reference to Exhibit (10)(ii)(24) of the company’s Quarterly Report on Form 10-Q for the quarter ended June 30, 2002 (File No. 0-12014)).
	(25)	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)).
	(26)	Project Approval Order No. OSR045 made under the Alberta Mines and Minerals Act and Oil Sands Royalty Regulation, 1997 in respect of the Syncrude Project (Incorporated herein by reference to Exhibit 1.01(10)(ii)(3) 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)	Incentive Share Unit Plan and Incentive Share Units granted in 2001 are incorporated herein by reference to Exhibit (10)(iii)(A)(2) of the company’s Annual Report on Form 10-K for the year -ended December 31, 2001. Units granted in 2000 are incorporated herein by reference to Exhibit (10)(iii)(A)(2) of the company’s Annual Report on Form 10-K for the year ended December 31, 2000 (File No. 0-12014); units granted in 1999 are incorporated herein by reference to Exhibit (10)(iii)(A)(3) of the company’s Annual Report on Form 10-K for the year ended December 31, 1999 (File No. 0-12014); units granted in 1998 are incorporated herein by reference to Exhibit (10)(iii)(A)(3) of the company’s Annual Report on Form 10-K for the year ended December 31, 1998 (File No. 0-12014).
	(3)	Deferred Share Unit Plan. (Incorporated herein by reference to Exhibit(10)(iii)(A)(5) of the company’s Annual Report on Form 10-K for the year ended December 31, 1998 (File No. 0-12014)).

27

(4)	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)).
(5)	Form of Earnings Bonus Units (Incorporated herein by reference to Exhibit (10)(iii)(A)(5) of the company’s Annual Report on Form 10-K for the year ended December 31, 2003 (File No. 0-12014)) and Earnings Bonus Unit Plan (Incorporated herein by reference to Exhibit (10)(iii)(A)(5) of the company’s Annual Report on Form 10-K for the year ended December 31, 2002 (File No. 0-12014)).
(6)	Incentive Stock Option Plan and Incentive Stock Options granted in 2002 (Incorporated herein by reference to Exhibit (10)(iii)(A)(6) of the company’s Quarterly Report on Form 10-Q for the quarter ended June 30, 2002 (File No. 0-12014)).
(7)	Restricted Stock Unit Plan and Restricted Stock Units granted in 2002 (Incorporated herein by reference to Exhibit (10)(iii)(A)(7) of the company’s Annual Report on Form 10-K for the year ended December 31, 2002 (File No. 0-12014)).
(8)	Restricted Stock Unit Plan and Restricted Stock Units granted in 2003 (Incorporated herein by reference to Exhibit (10)(iii)(A)(8) of the company’s Annual Report on Form 10-K for the year ended December 31, 2003 (File No. 0-12014)).
(9)	Restricted Stock Unit Plan and general form for Restricted Stock Units, as amended effective December 31, 2004 (Incorporated herein by reference to Exhibit 99.1 of the company’s Form 8-K dated December 31, 2004 (File No. 0-12014)).
(10)	Amended Restricted Stock Unit Plan with respect to Restricted Stock Units granted in 2002, as amended effective August 4, 2006 (Incorporated herein by reference to Exhibit 99.10(III)(A)(1) of the company’s Quarterly Report on Form 10-Q for the quarter ended September 30, 2006 (File No. 0-12014)).
(11)	Amended Restricted Stock Unit Plan with respect to Restricted Stock Units granted in 2003, as amended effective August 4, 2006 (Incorporated herein by reference to Exhibit 99.10(III)(A)(2) of the company’s Quarterly Report on Form 10-Q for the quarter ended September 30, 2006 (File No. 0-12014)).
(12)	Amended Restricted Stock Unit Plan with respect to Restricted Stock Units granted in 2004 and 2005, as amended effective August 4, 2006 (Incorporated herein by reference to Exhibit 99.10(III)(A)(3) of the company’s Quarterly Report on Form 10-Q for the quarter ended September 30, 2006 (File No. 0-12014)).
(13)	Amended Restricted Stock Unit Plan with respect to Restricted Stock Units granted in 2006 and subsequent years, as amended effective August 4, 2006 (Incorporated herein by reference to Exhibit 99.10(III)(A)(4) of the company’s Quarterly Report on Form 10-Q for the quarter ended September 30, 2006 (File No. 0-12014)).
(14)	Amended Restricted Stock Unit Plan with respect to Restricted Stock Units granted in 2002, as amended effective February 1, 2007 (Incorporated herein by reference to Exhibit 99.1 of the company’s Form 8-K filed on February 2, 2007 (File No. 0-12014)).
(15)	Amended Restricted Stock Unit Plan with respect to Restricted Stock Units granted in 2002, as amended effective February 26, 2008 and May 1, 2008 (Incorporated herein by reference to Exhibit 6 [10(iii)(A)(15)] of the company’s Quarterly Report on Form 10-Q for the quarter ended March 31, 2008 (File No. 0-12014)).
(16)	Amended Restricted Stock Unit Plan with respect to Restricted Stock Units granted in 2003, as amended effective February 26, 2008 and May 1, 2008 (Incorporated herein by reference to Exhibit 6 [10(iii)(A)(16)] of the company’s Quarterly Report on Form 10-Q for the quarter ended March 31, 2008 (File No. 0-12014)).
(17)	Amended Restricted Stock Unit Plan with respect to Restricted Stock Units granted in 2004 and 2005, as amended effective February 26, 2008 and May 1, 2008 (Incorporated herein by reference to Exhibit 6 [10(iii)(A)(17)] of the company’s Quarterly Report on Form 10-Q for the quarter ended March 31, 2008 (File No. 0-12014)).
(18)	Amended Restricted Stock Unit Plan with respect to Restricted Stock Units granted in 2006 and 2007, as amended effective February 26, 2008 and May 1, 2008 (Incorporated herein by reference to Exhibit 6 [10(iii)(A)(18)] of the company’s Quarterly Report on Form 10-Q for the quarter ended March 31, 2008 (File No. 0-12014)).
(19)	Amended Restricted Stock Unit Plan with respect to Restricted Stock Units granted in 2008 and subsequent years, as amended effective February 26, 2008 and May 1, 2008 (Incorporated herein by reference to Exhibit 6 [10(iii)(A)(19)] of the company’s Quarterly Report on Form 10-Q for the quarter ended March 31, 2008 (File No. 0-12014)).
(20)	Amended Restricted Stock Unit Plan with respect to Restricted Stock Units granted in 2002, as amended effective November 20, 2008 (Incorporated herein by reference to Exhibit 9.01(c)[10(iii)(A)(1)] of the company’s Form 8-K filed on November 25, 2008 (File No. 0-12014)).

28

	(21)	Amended Restricted Stock Unit Plan with respect to Restricted Stock Units granted in 2003, as amended effective November 20, 2008 (Incorporated herein by reference to Exhibit 9.01(c)[10(iii)(A)(2)] of the company’s Form 8-K filed on November 25, 2008 (File No. 0-12014)).
	(22)	Amended Restricted Stock Unit Plan with respect to Restricted Stock Units granted in 2004 and 2005, as amended effective November 20, 2008 (Incorporated herein by reference to Exhibit 9.01(c)[10(iii)(A)(3)] of the company’s Form 8-K filed on November 25, 2008 (File No. 0-12014)).
	(23)	Amended Restricted Stock Unit Plan with respect to Restricted Stock Units granted in 2006 and 2007, as amended effective November 20, 2008 (Incorporated herein by reference to Exhibit 9.01(c)[10(iii)(A)(4)] of the company’s Form 8-K filed on November 25, 2008 (File No. 0-12014)).
	(24)	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)).
	(25)	Amended Deferred Share Unit Plan for selected executives effective November 20, 2008 (Incorporated herein by reference to Exhibit 15(10)(iii)(A)(25) of the company’s Form 10-K filed on February 27, 2009) (File No. 0-12014)).
	(26)	Termination of Deferred Share Unit Plan for selected executives effective February 2, 2010 (Reference is made to the company’s Form 8-K filed on February 3, 2010 (File No. 0-12014)).
	(27)	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)).
	(28)	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)).
(21)		Imperial Oil Resources Limited, McColl-Frontenac Petroleum Inc., Imperial Oil Resources N.W.T. Limited and Imperial Oil Resources Ventures Limited, all incorporated in Canada, are wholly-owned subsidiaries 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, 2013.
(23) (ii)	(A)	Consent of Independent Registered Public Accounting Firm (PricewaterhouseCoopers LLP).
(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, 237 Fourth Avenue S.W., Calgary, Alberta, Canada T2P 3M9, and payment of processing and mailing costs.

29

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 25, 2014 by the undersigned, thereunto duly authorized.

       Imperial Oil Limited

       By             /s/ Richard M. Kruger

      (Richard M. Kruger, Chairman of the Board,

        President and Chief Executive Officer)

Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below on February 25, 2014 by the following persons on behalf of the registrant and in the capacities indicated.

Signature	Title
/s/ Richard M. Kruger (Richard M. Kruger)	Chairman of the Board, President and Chief Executive Officer and Director (Principal Executive Officer)
/s/ Paul J. Masschelin (Paul J. Masschelin)	Senior Vice-President, Finance and Administration, and Controller (Principal Financial Officer and Principal Accounting Officer)
/s/ Krystyna T. Hoeg (Krystyna T. Hoeg)	Director
/s/ Jack M. Mintz (Jack M. Mintz)	Director
/s/ David S. Sutherland (David S. Sutherland)	Director
/s/ Sheelagh D. Whittaker (Sheelagh D. Whittaker)	Director
/s/ Darren W. Woods (Darren W. Woods)	Director
/s/ Victor L. Young (Victor L. Young)	Director

30

Financial section

Table of contents	Page
Financial summary (U.S. GAAP)		32
Frequently used terms		33
Management’s discussion and analysis of financial condition and results of operations		35
Overview		35
Business environment and risk assessment		35
Results of operations		39
Liquidity and capital resources		44
Capital and exploration expenditures		47
Market risks and other uncertainties		48
Critical accounting estimates		50
Management’s report on internal control over financial reporting		53
Report of independent registered public accounting firm		54
Consolidated statement of income (U.S. GAAP)		55
Consolidated statement of comprehensive income (U.S. GAAP)		56
Consolidated balance sheet (U.S. GAAP)		57
Consolidated statement of shareholders’ equity (U.S. GAAP)		58
Consolidated statement of cash flows (U.S. GAAP)		59
Notes to consolidated financial statements		60
1. Summary of significant accounting policies		60
2. Business segments		63
3. Income taxes		65
4. Employee retirement benefits		66
5. Other long-term obligations		72
6. Derivatives and financial instruments		72
7. Share-based incentive compensation programs		72
8. Investment and other income		74
9. Litigation and other contingencies		74
10. Common shares		75
11. Miscellaneous financial information		76
12. Financing costs and additional notes and loans payable information		76
13. Leased facilities		77
14. Long-term debt		77
15. Accounting for suspended exploratory well costs		78
16. Transactions with related parties		79
17. Other comprehensive income information		80
18. Acquisition		81
Supplemental information on oil and gas exploration and production activities (unaudited)		82
Quarterly financial and stock trading data		86

31

Financial summary (U.S. GAAP)

millions of dollars	2013			2012			2011			2010			2009
Operating revenues		32,722			31,053			30,474			24,946			21,292
Net income by segment:
Upstream		1,712			1,888			2,457			1,764			1,324
Downstream		1,052			1,772			884			442			278
Chemical		162			165			122			69			46
Corporate and Other		(98	)		(59	)		(92	)		(65	)		(69	)
Net income		2,828			3,766			3,371			2,210			1,579
Cash and cash equivalents at year-end		272			482			1,202			267			513
Total assets at year-end		37,218			29,364			25,429			20,580			17,473
Long-term debt at year-end		4,444			1,175			843			527			31
Total debt at year-end		6,287			1,647			1,207			756			140
Other long-term obligations at year-end		3,091			3,983			3,876			2,753			2,839
Shareholders’ equity at year-end		19,524			16,377			13,321			11,177			9,439
Cash flow from operating activities		3,292			4,680			4,489			3,207			1,591
Per-share information (dollars)
Net income per share - basic		3.34			4.44			3.98			2.61			1.86
Net income per share - diluted		3.32			4.42			3.95			2.59			1.84
Dividends declared		0.49			0.48			0.44			0.43			0.40

32

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 dollars	2013			2012			2011
Business uses: asset and liability perspective
Total assets		37,218			29,364			25,429
Less: total current liabilities excluding notes and loans payable		(5,245	)		(5,433	)		(5,585	)
total long-term liabilities excluding long-term debt		(6,162	)		(5,907	)		(5,316	)
Add: Imperial’s share of equity company debt		23			24			28
Total capital employed		25,834			18,048			14,556
Total company sources: debt and equity perspective
Notes and loans payable		1,843			472			364
Long-term debt		4,444			1,175			843
Shareholders’ equity		19,524			16,377			13,321
Add: Imperial’s share of equity company debt		23			24			28
Total capital employed		25,834			18,048			14,556

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 dollars	2013		2012		2011
Net income		2,828		3,766		3,371
Financing costs (after tax), including Imperial’s share of equity companies		1		1		1
Net income excluding financing costs		2,829		3,767		3,372
Average capital employed		21,941		16,302		13,261
Return on average capital employed (percent) – corporate total		12.9		23.1		25.4

33

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 dollars	2013		2012		2011
Cash from operating activities		3,292		4,680		4,489
Proceeds from asset sales		160		226		314
Total cash flow from operating activities and asset sales		3,452		4,906		4,803

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, as defined below, 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 dollars	2013		2012			2011
From Imperial’s Consolidated Statement of Income
Total expenses		29,192		26,195			26,308
Less:
Purchases of crude oil and products		20,155		18,476			18,847
Federal excise tax		1,423		1,338			1,320
Financing costs		11		(1	)		3
Subtotal		21,589		19,813			20,170
Imperial’s share of equity company expenses		37		34			39
Total operating costs		7,640		6,416			6,177

Components of Operating Costs

millions of dollars	2013		2012		2011
From Imperial’s Consolidated Statement of Income
Production and manufacturing		5,288		4,457		4,114
Selling and general		1,082		1,081		1,168
Depreciation and depletion		1,110		761		764
Exploration		123		83		92
Subtotal		7,603		6,382		6,138
Imperial’s share of equity company expenses		37		34		39
Total operating costs		7,640		6,416		6,177

34

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 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. While commodity prices remain 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. Potential investment opportunities are tested over a wide range of economic scenarios to establish the resiliency of each opportunity. Once 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

By 2040, the world’s population is projected to grow to approximately 8.8 billion people, or close to 2 billion more than in 2010. Coincident with this population increase, the company expects worldwide economic growth to average close to 3 percent per year. As economies and population 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 35 percent from 2010 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).

As expanding prosperity drives global energy demand higher, increasing use of energy-efficient and lower-emission fuels, technologies and practices 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 transportation - including cars, trucks, ships, trains and airplanes - is expected to increase by about 40 percent from 2010 to 2040. The global growth in transportation demand is likely to account for approximately 70 percent of the growth in liquid fuels demand over this period. Nearly all the world’s transportation fleets will continue to run on liquid fuels because they are abundant, widely available, easy to transport, and provide a large quantity of energy in small volumes.

Demand for electricity around the world is likely to increase approximately 90 percent by 2040, led by growth in developing countries. Consistent with this projection, power generation is expected to remain the largest and fastest-growing major segment of global energy demand. Meeting the expected growth in power demand will require a diverse set of energy sources. Natural gas demand is likely to grow most significantly and become the leading source of generated electricity by 2040, reflecting the efficiency of gas-fired power plants. Today, coal has the largest fuel share in the power sector, but its share is likely to decline significantly by 2040 as policies are gradually adopted to reduce environmental impacts including those related to local air quality and greenhouse gas emissions. Nuclear power and renewables, led by hydropower and wind, are expected to grow significantly over the period.

35

Management’s discussion and analysis of financial condition and results of operations (continued)

Liquid fuels provide the largest share of energy supplies today due to their broad-based availability, affordability and ease of transportation, distribution and storage to meet consumer needs. By 2040, global demand for liquid fuels is expected to grow to approximately 112 million barrels of oil-equivalent per day, an increase of about 25 percent from 2010. This demand will be met by a wide variety of sources. Globally, conventional crude production will likely decline slightly through 2040. However, this decline is expected to be more than offset by rising production from a wide variety of emerging supply sources - tight oil, deepwater, oil sands, natural gas liquids, and biofuels. 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 is expected to be the fastest growing major fuel source through 2040. Global demand is expected to rise about 65 percent from 2010 to 2040, with demand likely to increase in all major regions of the world. Helping meet these needs will be significant growth in supplies of unconventional gas - the natural gas found in shale and other rock formations that was once considered uneconomic to produce. About 65 percent of the growth in natural gas supplies is expected to be from unconventional sources, which will account for about one-third of global gas supplies by 2040. Growing natural gas demand will also stimulate significant growth in the worldwide liquefied natural gas (LNG) market, which is expected to reach about 15 percent of global gas demand by 2040.

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 by approximately 2025. The share of natural gas is expected to exceed 25 percent by 2040, while the share of coal falls to less than 20 percent. Nuclear power is projected to grow significantly, albeit at a slower pace than otherwise expected in the aftermath of the Fukushima incident in Japan following the earthquake and tsunami in March 2011. Total renewable energy is likely to reach close to 15 percent of total energy by 2040, with biomass, hydro and geothermal at a combined share of about 11 percent. Total energy supplied from wind, solar and biofuels is expected to increase close to 450 percent from 2010 to 2040, reaching a combined share of about 4 percent of world 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, the investment required to meet total oil and gas energy needs worldwide over the period 2012- 2035 will be close to $19 trillion (measured in 2011 dollars), or close to $800 billion per year on average.

International accords and underlying regional and national regulations for greenhouse gas reduction are evolving with uncertain timing and outcome, making it difficult to predict their business impact. Imperial’s estimates of potential costs related to possible public policies covering energy-related greenhouse gas emissions are consistent with those outlined in Exxon Mobil Corporation’s (ExxonMobil) long-term Outlook for Energy, which is used for assessing the business environment and Imperial’s investment evaluations.

The information provided in the Long-term business outlook includes internal estimates and forecasts based upon 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 into the North American markets. Crude oil and natural gas prices are determined by global and North American markets and are subject to changing supply and demand conditions. These can be influenced by a wide range of factors, including economic conditions, international political developments and weather. Prices for most of the company’s crude oil sold are referenced to West Texas Intermediate (WTI) oil markets, a common benchmark for mid-continent North American markets. In 2013, the average WTI crude oil price was higher versus 2012, leading to higher western Canadian liquids realizations for the company.

36

Management’s discussion and analysis of financial condition and results of operations (continued)

Imperial’s Upstream business strategies guide the company’s exploration, development, production, research and gas marketing activities. These strategies include identifying and selectively capturing the highest quality opportunities, and maximizing the profitability of existing production and resource value through high-impact technologies. These strategies are underpinned by a relentless focus on operational excellence, commitment to innovative technologies, development of employees and investment in the communities within which the company operates.

The company’s current Upstream activities support plans to significantly increase production this decade. The Kearl initial development, the largest capital investment in the company’s history, started up in 2013. The Kearl expansion project and the Nabiye expansion project at Cold Lake were also advanced in 2013. Other investments included the Celtic and Clyden acquisitions. To support the company’s long-term growth a variety of existing and new logistics outlets have been secured or are being developed.

Imperial has a large portfolio of oil and gas resources in Canada, both developed and undeveloped. With the relative maturity of conventional production in established producing areas, Imperial’s production is expected to come increasingly from oil sands and unconventional sources.

Downstream

The downstream industry environment is expected to continue being very competitive in the mature North America market. Crude oil, the primary raw material in a refinery operation, and its many refined products are widely traded with published international prices. Prices for these commodities are determined by the marketplace and are affected by many factors, including global and regional supply/demand balances, inventory levels, refinery operations, import/export balances, transportation logistics, currency fluctuations, seasonality and weather. With the closure of the Dartmouth refinery in the third quarter of 2013, the average prices the company paid for most of its crude oil processed at the company’s three refineries are largely set on western Canadian crude oil markets. In 2013, the average prices of western Canadian crude oils continued to be lower than that of Brent crude oil. Canadian wholesale prices of refined products in particular are largely determined by wholesale prices in adjacent U.S. regions, where wholesale prices are predominantly tied to international product markets. Lower industry refining margins in 2013 were the result of the narrower differential between product prices and cost of crude oil processed. These prices and factors are continually monitored and provide input to operating decisions about which raw materials to buy, facilities to operate and products to make. However, there are no reliable indicators of future market factors that accurately predict changes in margins from period to period.

The company will continue to focus on the business elements within its control. Imperial’s Downstream strategies are to provide customers with quality, valued products and services at the lowest total cost offer, have the lowest unit costs among industry competitors, ensure efficient and effective use of capital, maximize value from leading edge technologies and capitalize on the integration with the company’s other businesses.

Imperial owns and operates three refineries in Canada, with aggregate distillation capacity of 421,000 barrels per day. Imperial’s fuels marketing business includes retail operations across Canada serving customers through more than 1,700 Esso-branded retail service stations, of which about 470 are company-owned or leased, as well as wholesale and industrial operations through a network of 22 primary distribution terminals, as well as a secondary distribution network.

37

Management’s discussion and analysis of financial condition and results of operations (continued)

Chemical

The North American petrochemical industry environment remained favourable in 2013 reflecting improving North American economic conditions. In North America, unconventional natural gas continued to provide advantaged ethane feedstock for steam crackers and a favourable margin environment for integrated chemical producers. Feedstock to the company’s Sarnia chemical plant will achieve further cost advantages with the transition to Marcellus ethane which is expected in the first quarter of 2014. The company’s strategy for its Chemical business is to reduce costs and maximize value by continuing 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.

38

Management’s discussion and analysis of financial condition and results of operations (continued)

Results of operations

Consolidated

millions of dollars	2013		2012		2011
Net income		2,828		3,766		3,371

2013

Net income in 2013 was $2,828 million or $3.32 per share on a diluted basis, versus $3,766 million or $4.42 per share in 2012. Earnings decreased primarily due to significantly lower industry refining margins of about $700 million, higher Kearl costs of about $180 million as production contribution was more than offset by start-up and operating costs, lower volumes at Syncrude of about $120 million and lower contribution from Cold Lake of about $120 million. 2013 earnings also included an after-tax charge of $280 million associated with the conversion of the Dartmouth refinery to a terminal. These factors were partially offset by the impacts of higher liquids realizations of about $125 million, a weaker Canadian dollar versus the U.S. dollar of about $125 million, higher marketing margins of about $120 million and lower refinery maintenance costs of about $90 million.

In 2013, the average price of benchmark West Texas Intermediate (WTI) crude oil was higher when compared to 2012 and led to higher western Canadian crude oil prices and higher liquids realization in the company’s Upstream segment in 2013. Refining margins in the company’s Downstream segment, however, were negatively impacted as the overall cost of crude oil processed largely followed the upward trend of western Canadian crude oil pricing.

2012

Net income in 2012 was $3,766 million or $4.42 per share on a diluted basis, versus $3,371 million or $3.95 per share in 2011. Increased earnings were primarily attributable to stronger industry refining margins of about $975 million and lower royalty costs of about $300 million due to lower Upstream realizations. These factors were partially offset by the impacts of lower Upstream realizations of about $580 million, higher Kearl production readiness costs of about $125 million and higher refinery planned maintenance of about $80 million. Gains on asset divestments were also lower by about $85 million in 2012.

In 2012, the average price of West Texas Intermediate (WTI) crude oil and western Canadian crude oils continued to be markedly lower than that of Brent crude oil, a common benchmark for Atlantic Basin oil markets, due to supply/demand imbalances in mid-continent North American markets. This price discount negatively impacted the company’s western Canadian liquids realizations. Refining margins in the company’s Downstream segment, however, benefited as the overall cost of crude oil processed at three of the company’s four refineries followed the trend of western Canadian crude oils.

Upstream

millions of dollars	2013		2012		2011
Net income		1,712		1,888		2,457

2013

Net income for the year was $1,712 million, versus $1,888 million in 2012. Earnings decreased primarily due to higher Kearl costs of about $180 million as production contribution since start-up in late April was more than offset by year-to-date start-up and operating costs, lower volumes at Syncrude of about $120 million, and higher diluent and energy costs at Cold Lake totalling about $120 million. These factors were partially offset by higher liquids realizations of about $125 million and the impact of a weaker Canadian dollar of about $125 million.

2012

Net income for the year was $1,888 million, down $569 million from 2011. Earnings were lower primarily due to the impacts of lower realizations of about $580 million, higher Kearl production readiness costs of about $125 million and lower Cold Lake volumes of about $75 million. Gains on asset divestments were also lower by about $85 million in 2012. These factors were partially offset by lower royalty costs of about $300 million due to lower realizations and higher conventional volumes of about $45 million.

39

Management’s discussion and analysis of financial condition and results of operations (continued)

Average realizations

Canadian dollars	2013		2012		2011
Conventional crude oil realizations (per barrel)		82.41		77.19		85.22
Natural gas liquids realizations (per barrel)		39.26		42.06		59.08
Natural gas realizations (per thousand cubic feet)		3.27		2.33		3.59
Synthetic oil realizations (per barrel)		99.69		92.48		101.43
Bitumen realizations (per barrel)		60.57		59.76		63.95

2013

Prices for most of the company’s liquids production are based on WTI crude oil, a common benchmark for mid-continent North American oil markets. WTI crude oil price was up $3.90 per barrel in U.S. dollars, or about four percent in 2013, versus 2012. The company’s average realizations also increased in Canadian dollars on sales of conventional, synthetic crude oil and bitumen. The company’s average realizations on natural gas sales of $3.27 per thousand cubic feet in 2013 were higher by $0.94 per thousand cubic feet versus 2012.

2012

Prices for most of the company’s liquids production are based on WTI crude oil, a common benchmark for mid-continent North American oil markets. Compared to 2011, the average WTI crude price in U.S. dollars was lower by $0.96 per barrel or about one percent in 2012. The company’s western Canadian liquids realizations were also impacted by market discounts caused by supply/demand imbalances in mid-continent North America. In 2012, the company’s conventional and synthetic crude oil realizations in Canadian dollars decreased by about nine percent and bitumen realizations in Canadian dollars decreased by about seven percent compared to 2011.

The company’s average realizations on natural gas sales were lower by about 35 percent in 2012 in line with the decline in the average of 30-day spot prices for natural gas in Alberta.

Crude oil and NGLs - production and sales (a)

thousands of barrels per day	2013				2012				2011
	gross		net		gross		net		gross		net
Bitumen (b)		169		142		154		123		160		120
Synthetic oil (c)		67		65		72		69		72		67
Conventional crude oil		21		17		20		15		18		13
Total crude oil production		257		224		246		207		250		200
NGLs available for sale		4		3		4		3		5		4
Total crude oil and NGL production		261		227		250		210		255		204
Bitumen sales, including diluent (d)		219				201				209
NGL sales		9				8				9

40

Management’s discussion and analysis of financial condition and results of operations (continued)

Natural gas - production and sales (a)

millions of cubic feet per day	2013				2012					2011
	gross		net		gross		net			gross		net
Production (e)		201		189		192		195	(g)		254		228
Sales (f)		167				177					237

(a) Daily volumes are calculated by dividing total volumes for the year by the number of days in the year. Gross production is the company’s share of production (excluding purchases) before deducting the share of mineral owners or governments or both. Net production excludes those shares.

(b) The company’s bitumen production volumes included production volumes from the Cold Lake operation for all years presented in the table above and, beginning in 2013, also included production volumes from the Kearl initial development (16,000 barrels per day gross, 15,000 net).

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

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

(e) Production of natural gas includes amounts used for internal consumption with the exception of the amounts re-injected.

(f) Includes sales of the company’s share of production (before deduction of the mineral owners’ and/or governments’ share) and sales of gas purchased, processed and/or resold. Sales of natural gas exclude amounts used for internal consumption.

(g) Net production included favourable royalty cost adjustments.

2013

Gross production of Cold Lake bitumen was 153,000 barrels per day, compared to 154,000 barrels in 2012.

During the year, the company’s share of gross production from Syncrude averaged 67,000 barrels per day, down from 72,000 barrels in 2012. Higher planned maintenance activities were the main contributor to the lower volumes.

The company’s share of gross production of Kearl initial development was 16,000 barrels per day for the full year. Production of mined diluted bitumen began in April 2013 and continued to ramp-up throughout the remainder of the year. Since start-up, improvements have been made to equipment reliability. Although gross production rates of 100,000 barrels per day (71,000 Imperial’s share) were reached in the fourth quarter, ongoing activities to stabilize performance at these higher levels are progressing. In the fourth quarter, sales to unrelated third parties commenced as planned.

Gross production of conventional crude oil averaged 21,000 barrels per day in the year, versus 20,000 barrels in 2012.

Gross production of natural gas in 2013 was 201 million cubic feet per day, up from 192 million cubic feet in 2012. The higher production volumes reflected contributions from the Celtic acquisition and the Horn River pilot, which more than offset normal field decline.

2012

Gross production of Cold Lake bitumen averaged 154,000 barrels per day in 2012 compared with 160,000 barrels in 2011. Lower volumes were primarily due to the cyclic nature of production at Cold Lake.

The company’s share of Syncrude’s gross production averaged 72,000 barrels per day, unchanged from 2011.

Gross production of conventional crude oil averaged 20,000 barrels per day, up from the 18,000 barrels in 2011 when third-party pipeline downtime reduced production at the Norman Wells field.

Gross production of natural gas in 2012 was 192 million cubic feet per day, down from 254 million cubic feet in 2011. The lower production volume was primarily a result of producing properties divestments completed in 2011.

41

Management’s discussion and analysis of financial condition and results of operations (continued)

Downstream

millions of dollars	2013		2012		2011
Net income		1,052		1,772		884

2013

Downstream net income was $1,052 million, versus $1,772 million in 2012. Earnings were negatively impacted by significantly lower industry refining margins of about $700 million. Earnings in 2013 also included an after-tax charge of $280 million associated with the conversion of the Dartmouth refinery to a fuels terminal. These factors were partially offset by higher marketing margins of about $120 million and lower refinery maintenance costs of about $90 million.

The overall cost of crude oil processed at the company’s refineries largely followed the trend of western Canadian crude oils. Canadian wholesale prices of refined products are largely determined by wholesale prices in adjacent U.S. regions, where wholesale prices are predominately tied to international product markets. Lower Downstream earnings in 2013 when compared to 2012 were mainly the result of lower industry refining margins, partially offset by higher marketing margins.

2012

Downstream net income was $1,772 million, an increase of $888 million over 2011. Earnings in 2012 were the best annual earnings on record and were primarily due to stronger industry refining margins, partially offset by increased operating expenditures due to the impact of a higher level of refinery planned maintenance activities compared with 2011.

The overall cost of crude oil processed at three of the company’s four refineries followed the trend of western Canadian crude oils. Canadian wholesale prices of refined products are largely determined by wholesale prices in adjacent U.S. regions, where wholesale prices are predominately tied to international product markets. Stronger industry refining margins are the result of the widened differential between product prices and cost of crude oil processed.

Refinery utilization

thousands of barrels per day (a)	2013		2012		2011
Total refinery throughput (b)		426		435		430
Refinery capacity at December 31		421		506		506
Utilization of total refinery capacity (percent) (c)		88		86		85

Sales

thousands of barrels per day (a)	2013		2012		2011
Gasolines		223		221		220
Heating, diesel and jet fuels		160		151		157
Heavy fuel oils		29		30		29
Lube oils and other products		42		43		41
Net petroleum product sales		454		445		447

(a) Volumes per day are calculated by dividing total volumes for the year by the number of days in the year.

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

(c) Refinery operations at the Dartmouth refinery were discontinued on September 16, 2013. Capacity utilization is calculated based on the number of days the refineries were operated as a refinery in 2013.

2013

In the second quarter of 2013, the company announced its decision to convert the Dartmouth refinery to a fuels terminal. In the third quarter, refinery operations at the Dartmouth refinery were discontinued. The company continues to supply east coast Canadian markets with petroleum products.

Total refinery throughput was 426,000 barrels per day. Refinery throughput was 88 percent of capacity in 2013, two percent higher than the previous year. The higher rate was primarily a result of increased product sales and reduced maintenance activities. Capacity utilization in 2013 is calculated based on the number of days the refineries were operated as a refinery. Total net petroleum sales increased to 454,000 barrels per day, 9,000 barrels higher than 2012.

42

Management’s discussion and analysis of financial condition and results of operations (continued)

2012

Total refinery throughput was 435,000 barrels per day and average refinery capacity utilization increased to 86 percent from the previous year’s 85 percent. Higher volumes and utilization were primarily a result of improved refinery operations partially offset by higher planned maintenance activities at the Strathcona refinery. Total net petroleum sales decreased to 445,000 barrels per day, 2,000 barrels lower than 2011.

Chemical

millions of dollars	2013		2012		2011
Net income		162		165		122

Sales

thousands of tonnes	2013		2012		2011
Polymers and basic chemicals		712		767		748
Intermediate and others		228		277		268
Total petrochemical sales		940		1,044		1,016

2013

Chemical net income was $162 million, versus 2012’s record high of $165 million.

2012

Net income was $165 million, up $43 million from 2011. Earnings in 2012 were the best annual earnings on record. Strong operating performance along with higher polyethylene margins and sales volumes were the main contributors to the increase.

Corporate and Other

millions of dollars	2013		2012		2011
Net income		(98)		(59)		(92)

2013

For 2013, net income effects from Corporate and Other were negative $98 million, versus negative $59 million in 2012 primarily due to changes in share-based compensation charges.

2012

Net income effects from Corporate and Other were negative $59 million, compared with negative $92 million in 2011. Favourable effects were due to lower share-based compensation charges

43

Management’s discussion and analysis of financial condition and results of operations (continued)

Liquidity and capital resources

Sources and uses of cash

millions of dollars	2013			2012			2011
Cash provided by/(used in)
Operating activities		3,292			4,680			4,489
Investing activities		(7,735	)		(5,238	)		(3,593	)
Financing activities		4,233			(162	)		39
Increase/(decrease) in cash and cash equivalents		(210	)		(720	)		935
Cash and cash equivalents at end of year		272			482			1,202

Investments in 2013 were partly financed by the issuance of long-term debt and commercial paper and partly funded by internally generated funds. Cash that may be temporarily available as 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. Projects are planned or underway to increase production capacity. However, these volume increases are subject to a variety of risks, including project execution, operational outages, reservoir performance and regulatory changes.

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.

An independent actuarial valuation of the company’s registered retirement benefit plans was completed as at December 31, 2012. As a result of the valuation, the company contributed $600 million to the registered retirement benefit plans in 2013. The next required independent actuarial valuation will be as at December 31, 2013 and the company will continue to contribute within the requirements of pension regulations. 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

2013

Cash flow generated from operating activities was $3,292 million, compared with $4,680 million in 2012. Lower cash flow was primarily due to lower net income and working capital effects.

2012

Cash flow generated from operating activities was $4,680 million, compared with $4,489 million in 2011. Higher cash flow was primarily due to deferred income tax effects and higher net income partially offset by working capital effects.

44

Management’s discussion and analysis of financial condition and results of operations (continued)

Cash flow used in investing activities

2013

Investing activities used net cash of $7,735 million in 2013, compared to $5,238 million in 2012. Additions to property, plant and equipment and acquisitions totalled $7,899 million, compared with $5,478 million last year. Proceeds from asset sales were $160 million compared with $226 million in 2012.

2012

Investing activities used net cash of $5,238 million in 2012, compared to $3,593 million in 2011. Additions to property, plant and equipment were $5,478 million, compared with $3,919 million last year. Proceeds from asset sales were $226 million compared with $314 million in 2011.

Cash flow from financing activities

2013

Cash provided by financing activities was $4,233 million, compared with cash used in financing activities of $162 million in 2012.

The company raised new debt of $4,647 million; $4,572 million was drawn on existing facilities.

In the fourth quarter of 2013, the company entered into 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 (Canadian). 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. As at December 31, 2013, the company had drawn $75 million on this agreement.

At the end of 2013, total debt outstanding was $6,287 million, compared with $1,647 million at the end of 2012.

In January 2014, the company increased the capacity of its existing floating rate loan facility with an affiliated company of ExxonMobil from $5 billion to $6.25 billion. All other terms and conditions of the agreement remained unchanged.

Cash dividends of $407 million were paid in 2013 compared with $398 million in 2012. Per-share dividends paid in 2013 totalled $0.48, up from $0.47 in 2012.

2012

Cash used in financing activities was $162 million, compared with cash provided by financing activities of $39 million in 2011.

The company raised new debt of $325 million by drawing on existing facilities. Obligations under capital leases, which is a non-cash item, also increased by $115 million. At the end of 2012, total debt outstanding was $1,647 million, compared with $1,207 million at the end of 2011.

During 2012, the company did not make any share repurchases except those to offset the dilutive effects from the exercise of share-based awards. The company will continue to evaluate its share repurchase program in the context of its operating performance and overall capital project activities.

Cash dividends of $398 million were paid in 2012 compared with $373 million in 2011. Per-share dividends paid in 2012 totalled $0.47, up from $0.44 in 2011.

In the third quarter of 2012, the company increased the amount of its existing stand-by long-term bank credit facility from $200 million to $300 million and extended the maturity date to August 2014. The company has not drawn on the facility.

45

Management’s discussion and analysis of financial condition and results of operations (continued)

Financial percentages and ratios

	2013		2012		2011
Total debt as a percentage of capital (a)		24		9		9
Interest coverage ratio – earnings basis (b)		55		239		260

(a) Current and long-term debt (page 57) and the company’s share of equity company debt, divided by debt and shareholders’ equity (page 57).

(b) Net income (page 55), debt-related interest before capitalization, including the company’s share of equity company interest, and income taxes (page 55), divided by debt-related interest before capitalization, including the company’s share of equity company interest.

Debt represented 24 percent of the company’s capital structure at the end of 2013.

Debt-related interest incurred in 2013, before capitalization of interest, was $69 million, compared with $20 million in 2012. The average effective interest rate on the company’s debt was 1.4 percent in 2013, compared with 1.6 percent in 2012.

The company’s financial strength, as evidenced by the above financial ratios, represents a competitive advantage of strategic importance. The company’s sound financial position gives it the opportunity to access capital markets in the full range of market conditions and enables the company to take on large, long-term capital commitments in the pursuit of maximizing shareholder value.

The company does not use any derivative instruments to offset exposures associated with hydrocarbon prices, currency exchange rates and interest rates that arise from existing assets, liabilities and transactions. The company does not engage in speculative derivative activities nor does it use derivatives with leveraged features.

Commitments

The following table shows the company’s commitments outstanding at December 31, 2013. It combines data from the consolidated balance sheet and from individual notes to the consolidated financial statements, where appropriate.

	Financial	Payment due by period
millions of dollars	statement     note reference	2014		2015 to 2018		2019 and beyond		Total amount
Long-term debt (a)	Note 14		-		4,342		102		4,444
- Due in one year			7		-		-		7
Operating leases (b)	Note 13		177		180		32		389
Unconditional purchase obligations (c)	Note 9		91		329		237		657
Firm capital commitments (d)			2,390		556		297		3,243
Pension and other post-retirement obligations (e)	Note 4		475		231		795		1,501
Asset retirement obligations (f)	Note 5		91		381		765		1,237
Other long-term purchase agreements (g)			473		2,372		8,036		10,881

(a) Long-term debt includes a long-term loan from an affiliated company of ExxonMobil of $4,316 million and capital lease obligations of $135 million, $7 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, primarily cover office buildings, rail cars and service stations.

(c) Unconditional purchase obligations 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. They mainly pertain to pipeline throughput agreements.

(d) Firm capital commitments related to capital projects, shown on an undiscounted basis. The largest commitments outstanding at year-end 2013 were $2,005 million associated with the company’s share of the Kearl project.

(e) 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 2014 and estimated benefit payments for unfunded plans in all years.

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

(g) Other long-term purchase agreements are non-cancelable, long-term commitments other than unconditional purchase obligations. They include primarily raw material supply and transportation services agreements.

46

Management’s discussion and analysis of financial condition and results of operations (continued)

In 2013, the company entered into additional long-term transportation agreements, which have a total commitment of about $3.5 billion, to ship heavy crude oil blend and diluent. These agreements will support the company’s long-term growth in oil sands production. The company expects to fulfill these commitments in the normal course of business. The new commitment amounts are included in the “Other long–term purchase agreements” line in the table above.

Unrecognized tax benefits totaling $151 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 65.

Litigation and other contingencies

As discussed in note 9 to the consolidated financial statements on page 74, a variety of claims have been made against Imperial Oil Limited 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. 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 dollars	2013		2012
Upstream (a)		7,755		5,518
Downstream		187		140
Chemical		9		4
Other		69		21
Total		8,020		5,683

(a) Exploration expenses included.

Total capital and exploration expenditures were $8,020 million in 2013, an increase of $2,337 million from 2012.

For the Upstream segment, capital expenditures were $7,755 million, compared with $5,518 million in 2012. Expenditures included $1.9 billion on the Celtic and Clyden acquisitions and post-acquisition investments. Other investments were primarily directed towards the advancement of the Kearl expansion and Nabiye projects.

Kearl’s expansion project continued to progress per plan. At 2013 year-end, the project was 72 percent complete and remains on target for a 2015 start-up. The project is expected to produce 110,000 barrels per day gross (78,000 Imperial’s share). Cold Lake’s Nabiye project was 65 percent complete at the end of the year. In the fourth quarter, plant construction progressed somewhat slower than planned due to lower contractor productivity and harsh winter conditions. Target start-up, although under pressure, remains year-end 2014 with ultimate production of 40,000 barrels per day.

Planned capital and exploration expenditures in the Upstream segment are forecast at about $5 billion for 2014. Investments are mainly planned for the continued investment in the Kearl and Nabiye growth projects.

For the Downstream segment, capital expenditures were $187 million in 2013, compared with $140 million in 2012. In 2013, Downstream capital expenditures focused mainly on refinery projects to improve reliability, feedstock flexibility, energy efficiency and environmental performance.

Planned capital expenditures for the Downstream segment in 2014 are about $450 million, focused on investment at the Edmonton rail loading joint venture, improving refinery reliability and environmental and safety performance, as well as continuing upgrades to the retail network.

Total capital and exploration expenditures for the company in 2014 are expected to be about $5.5 billion. Actual spending could vary depending on the progress of individual projects.

47

Management’s discussion and analysis of financial condition and results of operations (continued)

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. In addition, 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. 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, of the company’s after-tax net income.

Earnings sensitivities (a)

millions of dollars, after tax
Eight dollars (U.S.) per barrel change in crude oil prices	+ (-)	435
Thirty cents per thousand cubic feet change in natural gas prices	+ (-)	9
One dollar (U.S.) per barrel change in sales margins for total petroleum products	+ (-)	130
One cent (U.S.) per pound change in sales margins for polyethylene	+ (-)	6
One-quarter percent decrease (increase) in short-term interest rates	+ (-)	11
Nine cents decrease (increase) in the value of the Canadian dollar versus the U.S. dollar	+ (-)	500

(a) The amount quoted to illustrate the impact of each sensitivity represents a change of about 10 percent in the value of the commodity or rate in question at the end of 2013. 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. While these sensitivities are applicable under current conditions, they may not apply proportionately to larger fluctuations.

The sensitivity of net income to changes in crude oil prices increased from 2012 year-end by about $5 million (after tax) a year for each one U.S. dollar change. The sensitivity of net income to changes in natural gas prices increased from 2012 year-end by about $1 million (after tax) a year for each ten-cent change. The sensitivity of net income to changes in the Canadian dollar versus the U.S. dollar increased from 2012 year-end by about $7 million (after tax) a year for each one-cent change. The increase in these areas was primarily a result of the impact of production from the Kearl initial development which began in 2013.

The sensitivity of net income to changes in short-term interest rates increased from 2012 year-end by about $8 million (after tax) a year for each one-quarter percent change as a result of the higher debt levels at 2013 year-end.

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 our projects, underscore the importance of maintaining a strong financial position. Management views the company’s financial strength as a competitive advantage.

In general, segment results are not dependent on the ability to sell and/or purchase products to/from other segments. Instead, where such sales take place, they are the result of efficiencies and competitive advantages of integrated refinery/chemical complexes. Additionally, intersegment sales are at market-based prices. The products bought and sold between segments can also be acquired in worldwide markets that have substantial liquidity, capacity and transportation capabilities. About two-thirds 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 chemical plants related to raw materials, feedstocks and finished products.

Although price levels of crude oil and natural gas may rise or fall significantly over the short to medium term, industry economics over the long term will continue to be driven by market supply and demand. Accordingly, the company tests the viability of all of its investments over a broad range of future prices. The company’s assessment is that its operations will continue to be successful in a variety of market conditions. This is the outcome of disciplined investment and asset management programs.

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 result is an efficient capital base, and the company has seldom had to write down the carrying value of assets, even during periods of low commodity prices.

48

Management’s discussion and analysis of financial condition and results of operations (continued)

Industry bitumen production may be subject to limits on transportation capacity to markets. A significant portion of the company’s Upstream production is bitumen. The company’s longer-term oil sands development plans, results of operations and cash flow may be adversely affected if, for regulatory or other reasons, necessary additional transportation infrastructure is not added in a timely fashion. The company supports increased market access including proposed pipeline expansions to the United States Gulf coast and the Canadian West coast.

The demand for crude oil, natural gas, petroleum products and petrochemical products correlates closely with general economic growth rates. 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 focus on the business elements within its controls and take a long-term view of development.

Increased demand for certain services and materials has resulted in higher capital and other project costs in industry oil sands developments. The company works to counter upward pressure on costs through effective and efficient project and procurement management. One such example is the sanctioning of the Kearl expansion project to continue from the initial development such that the initial development’s design and development infrastructure can be reused. This continuation also allows the company to retain the experienced labour resources working on the initial development thereby maintaining productivity and limiting cost growth.

To help reduce the risks of dependence on potentially limited supply sources in established, mature conventional producing areas, the company’s production is expected to come increasingly from oil sands, unconventional natural gas and tight oil. Technology improvements have played and will continue to play an important role in the economics and the environmental performance of the current and future developments of these unconventional sources.

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 commodity prices and currency rates. The benefit of integration is demonstrated by the financial results in 2013 when increases in western Canadian crude oil prices benefited the company’s Upstream realizations but negatively impacted refining margins in the Downstream segment. The company’s financial strength and debt capacity give it the opportunity to advance business plans in the pursuit of maximizing shareholder value in the full range of market conditions. Also, the company progresses large capital projects in a phased manner so that adjustments can be made when significant changes in market conditions occur. As a result, the company does not make use of derivative instruments to mitigate the impact of such changes. The company does not engage in speculative derivative activities or derivative trading activities nor does it use derivatives with leveraged features. The company maintains a system of controls that includes a policy covering the authorization, reporting and monitoring of derivative activity.

49

Management’s discussion and analysis of financial condition and results of operations (continued)

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 60.

Oil and gas reserves

Evaluations of oil and 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. Oil and gas reserve quantities are also used as the basis to calculate unit-of-production depreciation rates and to evaluate impairment.

Oil and gas reserves include both proved and unproved reserves. Proved oil and 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. Unproved reserves are those with less than reasonable certainty of recoverability and include probable reserves. Probable reserves are reserves that are more likely to be recovered than not.

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.

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 gas price levels.

Revisions can include upward or downward changes in previously estimated volumes of proved reserves for existing fields due to the evaluation or revaluation of already available geologic, reservoir or production data; new geologic, reservoir or production data; or changes in 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.

Impact of oil and gas reserves on depreciation

The calculation of unit-of-production depreciation is a critical accounting estimate that measures the depreciation of upstream assets. It is the ratio of actual volumes produced to total proved developed reserves (those reserves recoverable through existing wells with existing equipment and operating methods) applied to the asset cost. The volumes produced and asset cost are known and, while proved developed reserves have a high probability of recoverability, they are based on estimates that are subject to some variability. While the revisions the company has made in the past are an indicator of variability, they have had little impact on the unit-of-production rates of depreciation.

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

Proved oil and gas properties held and used by the company are reviewed for impairment whenever events or circumstances indicate that the carrying amounts may not be recoverable. 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.

50

Management’s discussion and analysis of financial condition and results of operations (continued)

The company estimates the future undiscounted cash flows of the affected properties to judge the recoverability of carrying amounts. Impairment analyses are generally based on reserve estimates used for internal planning and capital investment decisions. Where probable reserves exist, an appropriately risk-adjusted amount of these reserves may be included in the impairment evaluation. An asset group would be impaired if its undiscounted cash flows were less than the asset’s carrying value. Impairments are measured by the amount by which the carrying value exceeds fair value.

Significant unproved properties are assessed for impairment individually, and valuation allowances against the capitalized costs are 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 company performs asset valuation analyses on an ongoing basis as a part of its asset management program. These analyses assist the company in assessing whether the carrying amounts of any of its assets may not be recoverable. In addition to estimating oil and gas reserve volumes in conducting these analyses, it is also necessary to estimate future oil and gas prices. Potential trigger events for impairment evaluations include a significant decrease in current and projected reserve volumes, an accumulation of project costs significantly in excess of the amount originally expected, and current period operating losses combined with a history or forecast of operating or cash flow losses.

In general, the company does not view temporarily low prices or margins as a triggering event for conducting the impairment tests. The markets for crude oil and natural gas have a history of significant price volatility. Although prices will occasionally drop significantly, the relative growth/decline in supply versus demand will determine industry prices over the long term, and these cannot be accurately predicted. Accordingly, any impairment tests that the company performs make use of the company’s price assumptions developed in the annual planning and budgeting process for the crude oil and natural gas markets, petroleum products and chemicals. These are the same price assumptions that are used for capital investment decisions. Volumes are based on field production profiles, which are also updated annually.

Supplemental information regarding oil and gas results of operations, capitalized costs and reserves is provided following the notes to the consolidated financial statements. Future prices used for any impairment tests will vary from the one used in the supplemental oil and gas disclosure and could be lower or higher for any given year.

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 6.25 percent used in 2013 compares to actual returns of 6.50 percent and 8.00 percent achieved over the last 10- and 20-year periods ending December 31, 2013. 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 66. 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 less than two percent of total expenses in 2013.

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 2013, the obligations were discounted

51

Management’s discussion and analysis of financial condition and results of operations (continued)

at six percent and the accretion expense was $105 million, before tax, which was significantly less than one 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.

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.

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 65.

52

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 (1992) 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, 2013.

PricewaterhouseCoopers LLP, an independent registered public accounting firm, audited the effectiveness of the company’s internal control over financial reporting as of December 31, 2013, as stated in their report which is included herein.

/s/ Richard M. Kruger

R.M. Kruger

Chairman, president and

chief executive officer

/s/ Paul J. Masschelin

P.J. Masschelin

Senior vice-president,

finance and administration, and controller

(Principal accounting officer and principal financial officer)

February 25, 2014

53

Report of independent registered public accounting firm

To the Shareholders of Imperial Oil Limited

We have audited the accompanying consolidated balance sheet of Imperial Oil Limited as of December 31, 2013 and December 31, 2012 and the related consolidated statements of income, comprehensive income, shareholders’ equity and cash flows for each of the years in the three-year period ended December 31, 2013. We also have audited Imperial Oil Limited’s internal control over financial reporting as of December 31, 2013, based on criteria established in Internal Control - Integrated Framework (1992) issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO). 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 an opinion on these consolidated financial statements and an opinion on the company’s internal control over financial reporting based on our integrated audits.

We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States). 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 and whether effective internal control over financial reporting was maintained in all material respects. Our audits of the consolidated financial statements included examining, on a test basis, evidence supporting the amounts and disclosures in the consolidated financial statements, assessing the accounting principles used and significant estimates made by management, and evaluating the overall consolidated financial statement presentation. 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.

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.

In our opinion, the consolidated financial statements referred to above present fairly, in all material respects, the financial position of Imperial Oil Limited as of December 31, 2013 and December 31, 2012 and the results of its operations and its cash flows for each of the years in the three-year period ended December 31, 2013 in conformity with accounting principles generally accepted in the United States of America. Also, in our opinion, Imperial Oil Limited maintained, in all material respects, effective internal control over financial reporting as of December 31, 2013 based on criteria established in Internal Control - Integrated Framework (1992) issued by the COSO.

/s/ PricewaterhouseCoopers LLP

Chartered Accountants

Calgary, Alberta, Canada

February 25, 2014

54

Consolidated statement of income (U.S. GAAP)

millions of Canadian dollars For the years ended December 31	2013		2012		2011
Revenues and other income
Operating revenues (a)(b)		32,722		31,053		30,474
Investment and other income (note 8)		207		135		240
Total revenues and other income		32,929		31,188		30,714
Expenses
Exploration		123		83		92
Purchases of crude oil and products (c)		20,155		18,476		18,847
Production and manufacturing (d)		5,288		4,457		4,114
Selling and general		1,082		1,081		1,168
Federal excise tax (a)		1,423		1,338		1,320
Depreciation and depletion		1,110		761		764
Financing costs (note 12)		11		(1)		3
Total expenses		29,192		26,195		26,308
Income before income taxes		3,737		4,993		4,406
Income taxes (note 3)		909		1,227		1,035
Net income		2,828		3,766		3,371
Per-share information (Canadian dollars)
Net income per common share – basic (note 10)		3.34		4.44		3.98
Net income per common share – diluted (note 10)		3.32		4.42		3.95
Dividends		0.49		0.48		0.44

(a) Operating revenues include federal excise tax of $1,423 million (2012 - $1,338 million, 2011 - $1,320 million).

(b) Operating revenues include amounts from related parties of $2,385 million (2012 - $2,907 million, 2011 - $2,818 million), (note 16).

(c) Purchases of crude oil and products include amounts from related parties of $4,104 million (2012 - $3,033 million, 2011 - $3,636 million), (note 16).

(d) Production and manufacturing expenses include amounts to related parties of $319 million (2012 - $241 million, 2011 - $217 million), (note 16).

The information in the Notes to Consolidated Financial Statements is an integral part of these statements.

55

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

millions of Canadian dollars For the years ended December 31	2013		2012			2011
Net income		2,828		3,766			3,371
Other comprehensive income, net of income taxes
Post-retirement benefits liability adjustment (excluding amortization)		529		(415	)		(953	)
Amortization of post-retirement benefits liability adjustment included in net periodic benefit costs		205		198			139
Total other comprehensive income/(loss)		734		(217	)		(814	)
Comprehensive income		3,562		3,549			2,557

The information in the Notes to Consolidated Financial Statements is an integral part of these statements.

56

Consolidated balance sheet (U.S. GAAP)

millions of Canadian dollars At December 31	2013			2012
Assets
Current Assets
Cash		272			482
Accounts receivable, less estimated doubtful amounts		2,084			1,976
Inventories of crude oil and products (note 11)		1,030			827
Materials, supplies and prepaid expenses		342			280
Deferred income tax assets (note 3)		559			527
Total current assets		4,287			4,092
Long-term receivables, investments and other long-term assets		1,332			1,090
Property, plant and equipment, less accumulated depreciation and depletion (note 2)		31,320			23,922
Goodwill (note 2)		224			204
Other intangible assets, net		55			56
Total assets (note 2)		37,218			29,364
Liabilities
Current liabilities
Notes and loans payable (a)(note 12)		1,843			472
Accounts payable and accrued liabilities (b)(note 11)		4,518			4,249
Income taxes payable		727			1,184
Total current liabilities		7,088			5,905
Long-term debt (c)(note 14)		4,444			1,175
Other long-term obligations (note 5)		3,091			3,983
Deferred income tax liabilities (note 3)		3,071			1,924
Total liabilities		17,694			12,987
Commitments and contingent liabilities (note 9)
Shareholders’ equity
Common shares at stated value (d)(note 10)		1,566			1,566
Earnings reinvested		19,679			17,266
Accumulated other comprehensive income		(1,721	)		(2,455	)
Total shareholders’ equity		19,524			16,377
Total liabilities and shareholders’ equity		37,218			29,364

(a) Notes and loans payable includes amounts to related parties of $75 million (2012 – nil)

(b) Accounts payable and accrued liabilities include amounts payable to related parties of $170 million (2012 – amounts receivable of $9 million), (note 16).

(c) Long-term debt includes amounts to related parties of $4,316 million (2012 – $1,040 million).

(d) Number of common shares outstanding was 848 million (2012 - 848 million), (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	/s/ Paul J. Masschelin
R.M. Kruger	P.J. Masschelin
Chairman, president and	Senior vice-president,
chief executive officer	finance and administration, and controller

57

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

millions of Canadian dollars At December 31	2013			2012			2011
Common shares at stated value (note 10)
At beginning of year		1,566			1,528			1,511
Issued under the stock option plan		-			43			19
Share purchases at stated value		-			(5	)		(2	)
At end of year		1,566			1,566			1,528
Earnings reinvested
At beginning of year		17,266			14,031			11,090
Net income for the year		2,828			3,766			3,371
Share purchases in excess of stated value		-			(123	)		(57	)
Dividends		(415	)		(408	)		(373	)
At end of year		19,679			17,266			14,031
Accumulated other comprehensive income
At beginning of year		(2,455	)		(2,238	)		(1,424	)
Other comprehensive income		734			(217	)		(814	)
At end of year		(1,721	)		(2,455	)		(2,238	)
Shareholders’ equity at end of year		19,524			16,377			13,321

The information in the Notes to Consolidated Financial Statements is an integral part of these statements.

58

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

millions of Canadian dollars Inflow/(outflow) For the years ended December 31	2013			2012			2011
Operating activities
Net income		2,828			3,766			3,371
Adjustments for non-cash items:
Depreciation and depletion		1,110			761			764
(Gain)/loss on asset sales		(150	)		(94	)		(197	)
Deferred income taxes and other		482			619			71
Changes in operating assets and liabilities:
Accounts receivable		(74	)		300			(302	)
Inventories, materials, supplies and prepaid expenses		(260	)		(106	)		(228	)
Income taxes payable		(457	)		(84	)		390
Accounts payable and accrued liabilities		191			(67	)		846
All other items - net (a)		(378	)		(415	)		(226	)
Cash flows from (used in) operating activities		3,292			4,680			4,489
Investing activities
Additions to property, plant and equipment		(6,297	)		(5,478	)		(3,919	)
Acquisition (note 18)		(1,602	)		-			-
Proceeds from asset sales		160			226			314
Repayment of loan from equity company		4			14			12
Cash flows from (used in) investing activities		(7,735	)		(5,238	)		(3,593	)
Financing activities
Short-term debt - net		1,371			105			135
Long-term debt issued		3,276			220			320
Reduction in capitalized lease obligations		(7	)		(4	)		(3	)
Issuance of common shares under stock option plan		-			43			19
Common shares purchased (note 10)		-			(128	)		(59	)
Dividends paid		(407	)		(398	)		(373	)
Cash flows from (used in) financing activities		4,233			(162	)		39
Increase (decrease) in cash		(210	)		(720	)		935
Cash at beginning of year		482			1,202			267
Cash at end of year (b)		272			482			1,202

(a) Includes contribution to registered pension plans of $600 million (2012 - $594 million, 2011 - $361 million).

(b) 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.

The information in the Notes to Consolidated Financial Statements is an integral part of these statements.

59

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 generally accepted accounting principles in the United States of America (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. Certain reclassifications to prior years have been made to conform to the 2013 presentation. 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. Significant subsidiaries included in the consolidated financial statements include Imperial Oil Resources Limited, Imperial Oil Resources N.W.T. Limited, Imperial Oil Resources Ventures Limited and McColl-Frontenac Petroleum Inc. All of the above companies are wholly owned. 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 project.

Inventories

Inventories are recorded at the lower of cost or current market value. 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 final storage prior to delivery to a customer. 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

Property, plant and equipment are recorded at cost. Investment tax credits and other similar grants are treated as a reduction of the capitalized cost of the asset to which they apply.

The company uses the successful-efforts method to account for its exploration and development activities. Under this method, costs are accumulated on a field-by-field basis with certain exploratory expenditures and exploratory dry holes being expensed as incurred. Costs of productive wells and development dry holes are capitalized and amortized using the unit-of-production method. The company carries as an asset exploratory

60

Notes to consolidated financial statements (continued)

well costs 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. Other exploratory expenditures, including geophysical costs and annual lease rentals are expensed as incurred.

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.

Production involves lifting the oil and gas to the surface and gathering, treating, field processing and field storage of the oil and gas. The production function normally terminates at the outlet valve on the lease or field production storage tank. Production costs are those incurred to operate and maintain the company’s wells and related equipment and facilities and are expensed as incurred. They become part of the cost of oil and gas produced. These costs, sometimes referred to as lifting costs, include such items as labour cost to operate the wells and related equipment; repair and maintenance costs on the wells and equipment; materials, supplies and energy costs required to operate the wells and related equipment; and administrative expenses related to the production activity.

Acquisition costs of proved properties are amortized using a unit-of-production method, computed on the basis of total proved oil and gas reserves. 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. Unit-of-production depreciation is applied to those wells, plant and equipment assets associated with productive depletable properties, and the unit-of-production rates are based on the amount of proved developed reserves of oil and gas. Investments in extraction and upgrading facilities at oil sands mining properties are depreciated on a unit-of-production method based on proved developed reserves. Investments in mining and transportation systems at oil sands mining properties are depreciated on a straight-line basis over a maximum of 15 years. Depreciation of other plant and equipment is calculated using the straight-line method, based on the estimated service life of the asset. In general, refineries are depreciated over 25 years; other major assets, including chemical plants and service stations, are depreciated over 20 years.

Proved oil and gas properties held and used by the company are reviewed for impairment whenever events or changes in circumstances indicate that the carrying amounts may not be recoverable. 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.

The company estimates the future undiscounted cash flows of the affected properties to judge the recoverability of carrying amounts. Cash flows used in impairment evaluations are developed using annually updated corporate plan investment evaluation assumptions for crude oil and natural gas commodity prices and foreign-currency exchange rates. Annual volumes are based on field production profiles, which are also updated annually.

Impairment analyses are generally based on reserve estimates used for internal planning and capital investment decisions. Where probable reserves exist, an appropriately risk-adjusted amount of these reserves may be included in the impairment evaluation. An asset group would be impaired if the undiscounted cash flows were less than its carrying value. Impairments are measured by the amount the carrying value exceeds fair value.

Significant unproved properties are assessed for impairment individually and valuation allowances against the capitalized costs are recorded based on the estimated economic chance of success and the length of time 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 valuation allowances are reviewed at least annually.

Gains or losses on assets sold are included in “investment and other income” in the consolidated statement of income.

61

Notes to consolidated financial statements (continued)

Interest capitalization

Interest costs relating to major capital projects under construction are capitalized as part of property, plant and equipment. 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 and marketing 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 liabilities 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.

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 or 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.

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.

62

Notes to consolidated financial statements (continued)

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.

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 72 for further details.

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.

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 the distribution and marketing of 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 income in this segment primarily includes debt-related financing costs, interest income and share-based incentive compensation expenses.

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 the Corporate and Other segment. The allocation is based on a combination of fee for service, proportional segment expenses and a three-year average of capital expenditures. 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.

63

Notes to consolidated financial statements (continued)

	Upstream									Downstream									Chemical
millions of dollars	2013			2012			2011			2013			2012			2011			2013			2012			2011
Revenues and other income
Operating revenues (a)		6,016			4,674			5,278			25,450			25,077			23,909			1,256			1,302			1,287
Intersegment sales		4,026			4,110			4,460			1,978			2,603			2,784			318			299			354
Investment and other income		145			46			168			59			81			63			-			-			-
		10,187			8,830			9,906			27,487			27,761			26,756			1,574			1,601			1,641
Expenses
Exploration		123			83			92			-			-			-			-			-			-
Purchases of crude oil and products		3,778			3,056			3,581			21,628			21,316			21,642			1,065			1,115			1,222
Production and manufacturing (b)		3,389			2,704			2,484			1,695			1,569			1,451			210			185			179
Selling and general		5			1			7			886			935			973			66			67			64
Federal excise tax		-			-			-			1,423			1,338			1,320			-			-			-
Depreciation and depletion (b)		636			498			528			452			242			214			12			12			13
Financing costs (note 12)		9			(1	)		2			2			-			(1	)		-			-			-
Total expenses		7,940			6,341			6,694			26,086			25,400			25,599			1,353			1,379			1,478
Income before income taxes		2,247			2,489			3,212			1,401			2,361			1,157			221			222			163
Income taxes (note 3)
Current		(14	)		72			593			395			486			372			62			67			43
Deferred		549			529			162			(46	)		103			(99	)		(3	)		(10	)		(2	)
Total income tax expense		535			601			755			349			589			273			59			57			41
Net income		1,712			1,888			2,457			1,052			1,772			884			162			165			122
Cash flows from (used in) operating activities		1,690			2,625			3,252			1,453			1,961			1,315			198			127			53
Capital and exploration expenditures (c)		7,755			5,518			3,880			187			140			166			9			4			4
Property, plant and equipment
Cost		38,819			30,602			25,327			7,146			7,038			6,990			771			765			760
Accumulated depreciation and depletion		(10,749	)		(10,146	)		(9,747	)		(4,347	)		(3,967	)		(3,803	)		(586	)		(576	)		(560	)
Net property, plant and equipment (d)		28,070			20,456			15,580			2,799			3,071			3,187			185			189			200
Total assets (e)		30,553			22,317			17,222			5,732			6,409			6,700			397			372			397
	Corporate and Other									Eliminations									Consolidated
millions of dollars	2013			2012			2011			2013			2012			2011			2013			2012			2011
Revenues and other income
Operating revenues (a)		-			-			-			-			-			-			32,722			31,053			30,474
Intersegment sales		-			-			-			(6,322	)		(7,012	)		(7,598	)		-			-			-
Investment and other income		3			8			9			-			-			-			207			135			240
		3			8			9			(6,322	)		(7,012	)		(7,598	)		32,929			31,188			30,714
Expenses
Exploration		-			-			-			-			-			-			123			83			92
Purchases of crude oil and products		-			-			-			(6,316	)		(7,011	)		(7,598	)		20,155			18,476			18,847
Production and manufacturing (b)		-			-			-			(6	)		(1	)		-			5,288			4,457			4,114
Selling and general		125			78			124			-			-			-			1,082			1,081			1,168
Federal excise tax		-			-			-			-			-			-			1,423			1,338			1,320
Depreciation and depletion (b)		10			9			9			-			-			-			1,110			761			764
Financing costs (note 12)		-			-			2			-			-			-			11			(1	)		3
Total expenses		135			87			135			(6,322	)		(7,012	)		(7,598	)		29,192			26,195			26,308
Income before income taxes		(132	)		(79	)		(126	)		-			-			-			3,737			4,993			4,406
Income taxes (note 3)
Current		(18	)		(32	)		(53	)		-			-			-			425			593			955
Deferred		(16	)		12			19			-			-			-			484			634			80
Total income tax expense		(34	)		(20	)		(34	)		-			-			-			909			1,227			1,035
Net income		(98	)		(59	)		(92	)		-			-			-			2,828			3,766			3,371
Cash flows from (used in) operating activities		(49	)		(33	)		(131	)		-			-			-			3,292			4,680			4,489
Capital and exploration expenditures (c)		69			21			16			-			-			-			8,020			5,683			4,066
Property, plant and equipment
Cost		429			360			339			-			-			-			47,165			38,765			33,416
Accumulated depreciation and depletion		(163	)		(154	)		(144	)		-			-			-			(15,845	)		(14,843	)		(14,254	)
Net property, plant and equipment (d)		266			206			195			-			-			-			31,320			23,922			19,162
Total assets (e)		581			704			1,418			(45	)		(438	)		(308	)		37,218			29,364			25,429

64

Notes to consolidated financial statements (continued)

(a) Includes export sales to the United States of $5,217 million (2012 - $4,358 million, 2011 - $4,175 million). Export sales to the United States were recorded in all operating segments, with the largest effects in the Upstream segment.

(b) A 2013 charge in the Downstream segment of $377 million ($280 million, after-tax) associated with the company’s decision to convert the Dartmouth refinery to a terminal included the write-down of refinery plant and equipment not included in the terminal conversion of $245 million, reported as part of depreciation and depletion expenses, and decommissioning, environmental and employee-related costs of $132 million, reported as part of production and manufacturing expenses. By the end of 2013, amounts incurred associated with decommissioning, environmental and employee-related costs totalled $40 million.

(c) Capital and exploration expenditures (CAPEX) include exploration expenses, additions to property, plant, equipment and intangibles and additions to capital leases.

(d) Includes property, plant and equipment under construction of $9,234 million (2012 - $13,846 million).

(e) The majority of the goodwill has been assigned to the Downstream segment. Goodwill of $20 million was recognized in 2013 in the Upstream segment as a result of the Celtic acquisition (note 18). There have been no goodwill impairment losses or write-offs due to sales in the past three years. Fair value used in quantitative goodwill impairment tests was Level 3 (unobservable inputs).

3. Income taxes

millions of dollars	2013			2012			2011
Current income tax expense		425			593			955
Deferred income tax expense (a)		484			634			80
Total income tax expense (b)		909			1,227			1,035
Statutory corporate tax rate (percent)		25.4			25.5			25.4
Increase/(decrease) resulting from:
Enacted tax rate change		-			-			-
Other		(1.1	)		(0.9	)		(1.9	)
Effective income tax rate		24.3			24.6			23.5

(a) 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 2013, 2012 and 2011.

(b) Cash outflow from income taxes, plus investment credits earned, was $911 million in 2013 (2012 – $871 million, 2011 – $667 million).

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 dollars	2013			2012			2011
Depreciation and amortization		2,949			2,434			1,948
Successful drilling and land acquisitions		815			399			378
Pension and benefits		(376	)		(717	)		(720	)
Site restoration		(287	)		(284	)		(267	)
Capitalized interest		69			53			50
Other		(99	)		39			51
Net long-term deferred income tax liabilities		3,071			1,924			1,440
LIFO inventory valuation		(450	)		(478	)		(560	)
Other		(109	)		(49	)		(30	)
Net current deferred income tax assets		(559	)		(527	)		(590	)
Valuation allowance		-			-			-
Net deferred income tax liabilities		2,512			1,397			850

65

Notes to consolidated financial statements (continued)

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. Resolution of the related tax positions will 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’s effective tax rate will be reduced if any of these tax benefits are subsequently recognized.

The following table summarizes the movement in unrecognized tax benefits:

millions of dollars	2013			2012			2011
Balance as at January 1		143			134			147
Additions based on current year’s tax position		10			4			-
Additions for prior years’ tax positions		2			10			20
Reductions for prior years’ tax positions		(4	)		(3	)		(31	)
Reductions due to lapse of the statute of limitations		-			(2	)		(2	)
Balance as at December 31		151			143			134

The 2013, 2012 and 2011 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 2006 to 2013 are 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 2014. The impact on unrecognized tax benefits and the company’s effective income tax rate from these matters is not expected to be material.

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 United States generally accepted accounting principles. 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. At 2013 year-end, the company adopted mortality assumptions presented in the new Canadian pensioners mortality research report, per guidance provided by the Canadian Institute of Actuaries.

66

Notes to consolidated financial statements (continued)

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
	2013			2012			2013			2012
Assumptions used to determine benefit obligations at December 31 (percent)
Discount rate		4.75			3.75			4.75			3.75
Long-term rate of compensation increase		4.50			4.50			4.50			4.50
millions of dollars
Change in projected benefit obligation
Projected benefit obligation at January 1		7,336			6,646			547			508
Current service cost		181			160			11			8
Interest cost		281			288			21			21
Actuarial loss/(gain)		(504	)		616			(50	)		40
Amendments		-			-			-			-
Benefits paid (a)		(424	)		(374	)		(26	)		(30	)
Projected benefit obligation at December 31		6,870			7,336			503			547
Accumulated benefit obligation at December 31		6,263			6,560

The discount rate for calculating year-end post-retirement liabilities is based on the yield for high quality, long-term Canadian corporate bonds at year-end with an average maturity (or duration) approximately 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 2014 and subsequent years.

	Pension benefits						Other post-retirement     benefits
millions of dollars	2013			2012			2013			2012
Change in plan assets
Fair value at January 1		5,114			4,461
Actual return/(loss) on plan assets		491			374
Company contributions		600			594
Benefits paid (b)		(333	)		(315	)
Fair value at December 31		5,872			5,114
Plan assets in excess of/(less than) projected benefit obligation at December 31
Funded plans		(424	)		(1,602	)
Unfunded plans		(574	)		(620	)		(503	)		(547	)
Total (c)		(998	)		(2,222	)		(503	)		(547	)

(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.

67

Notes to consolidated financial statements (continued)

	Pension benefits						Other post-retirement benefits
millions of dollars	2013			2012			2013			2012
Amounts recorded in the consolidated balance sheet consist of:
Current liabilities		(25	)		(24	)		(28	)		(28	)
Other long-term obligations		(973	)		(2,198	)		(475	)		(519	)
Total recorded		(998	)		(2,222	)		(503	)		(547	)
Amounts recorded in accumulated other comprehensive income consist of:
Net actuarial loss/(gain)		2,303			3,210			64			124
Prior service cost		62			85			-			-
Total recorded in accumulated other comprehensive income, before tax		2,365			3,295			64			124

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 2013 long-term expected return of 6.25 percent used in the calculations of pension expense compares to an actual rate of return of 6.50 percent and 8.00 percent over the last 10- and 20-year periods ending December 31, 2013.

	Pension benefits									Other post-retirement benefits
	2013			2012			2011			2013			2012			2011
Assumptions used to determine net periodic benefit cost for years ended December 31 (percent)
Discount rate		3.75			4.25			5.50			3.75			4.25			5.50
Long-term rate of return on funded assets		6.25			6.25			7.00			-			-			-
Long-term rate of compensation increase		4.50			4.50			4.50			4.50			4.50			4.50
millions of dollars
Components of net periodic benefit cost
Current service cost		181			160			122			11			8			6
Interest cost		281			288			314			21			21			23
Expected return on plan assets		(331	)		(288	)		(308	)		-			-			-
Amortization of prior service cost		23			23			21			-			-			-
Amortization of actuarial loss/(gain)		243			235			162			10			8			3
Net periodic benefit cost		397			418			311			42			37			32
Changes in amounts recorded in accumulated other comprehensive income
Net actuarial loss/(gain)		(664	)		530			1,112			(50	)		40			81
Amortization of net actuarial (loss)/gain included in net periodic benefit cost		(243	)		(235	)		(162	)		(10	)		(8	)		(3	)
Prior service cost		-			-			86			-			-			-
Amortization of prior service cost included in net periodic benefit cost		(23	)		(23	)		(21	)		-			-			-
Total recorded in other comprehensive income		(930	)		272			1,015			(60	)		32			78
Total recorded in net periodic benefit cost and other comprehensive income, before tax		(533	)		690			1,326			(18	)		69			110

68

Notes to consolidated financial statements (continued)

Costs for defined contribution plans, primarily the employee savings plan, were $37 million in 2013 (2012 - $36 million, 2011 - $36 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 dollars	2013			2012			2011
(Charge)/credit to other comprehensive income, before tax		990			(304	)		(1,093	)
Deferred income tax (charge)/credit (note 17)		(256	)		87			279
(Charge)/credit to other comprehensive income, after tax		734			(217	)		(814	)

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 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 46 percent. The target allocation for debt securities is 49 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 2013 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, 2013, using:
millions of dollars	Total		Quoted prices in active markets for identical assets (Level 1)		Significant     other     observable     inputs     (Level 2)			Significant     unobservable     inputs     (Level 3)
Asset class
Equity securities
Canadian		932				932	(a)
Non-Canadian		1,911				1,911	(a)
Debt securities - Canadian
Corporate		654				654	(b)
Government		2,161				2,161	(b)
Asset backed		-
Mortgage funds		1							1	(c)
Equities – Venture capital		188							188	(d)
Cash		25		12		13	(e)
Total plan assets at fair value		5,872		12		5,671			189

(a) For company equity securities held in the form of fund units that are redeemable at the measurement date, the unit value is treated as a Level 2 input. The fair value of the securities owned by the funds is based on observable quoted prices on active exchanges, which are Level 1 inputs.

(b) For corporate, government and asset-backed debt securities, fair value is based on observable inputs of comparable market transactions.

(c) For mortgage funds, fair value represents the principal outstanding which is guaranteed by Canada Mortgage and Housing Corporation.

(d) For venture capital partnership investments, fair value is generally established by using revenue or earnings multiples or other relevant market data including Initial Public Offerings.

(e) For cash balances that are held in Level 2 funds prior to investment in those fund units, the cash value is treated as a Level 2 input.

69

Notes to consolidated financial statements (continued)

The change in the fair value of Level 3 assets, which use significant unobservable inputs to measure fair value, is shown in the table below:

millions of dollars	Mortgage funds		Venture capital
Fair value at January 1, 2013		1		158
Net realized gains/(losses)		-		(17	)
Net unrealized gains/(losses)		-		44
Net purchases/(sales)		-		3
Fair value at December 31, 2013		1		188

The 2012 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, 2012, using:
millions of dollars	Total		Quoted prices in active markets for identical assets (Level 1)		Significant other observable inputs (Level 2)			Significant unobservable inputs (Level 3)
Asset class
Equity securities
Canadian		811				811	(a)
Non-Canadian		1,657				1,657	(a)
Debt securities - Canadian
Corporate		473				473	(b)
Government		1,982				1,982	(b)
Asset backed		5				5	(b)
Mortgage funds		1							1	(c)
Equities – Venture capital		158							158	(d)
Cash		27		9		18	(e)
Total plan assets at fair value		5,114		9		4,946			159

(a) For company equity securities held in the form of fund units that are redeemable at the measurement date, the unit value is treated as a Level 2 input. The fair value of the securities owned by the funds is based on observable quoted prices on active exchanges, which are Level 1 inputs.

(b) For corporate, government and asset-backed debt securities, fair value is based on observable inputs of comparable market transactions.

(c) For mortgage funds, fair value represents the principal outstanding which is guaranteed by Canada Mortgage and Housing Corporation.

(d) For venture capital partnership investments, fair value is generally established by using revenue or earnings multiples or other relevant market data including Initial Public Offerings.

(e) For cash balances that are held in Level 2 funds prior to investment in those fund units, the cash value is treated as a Level 2 input.

The change in the fair value of Level 3 assets, which use significant unobservable inputs to measure fair value, is shown in the table below:

millions of dollars	Mortgage funds		Venture capital
Fair value at January 1, 2012		1		148
Net realized gains/(losses)		-		(11	)
Net unrealized gains/(losses)		-		8
Net purchases/(sales)		-		13
Fair value at December 31, 2012		1		158

70

Notes to consolidated financial statements (continued)

A summary of pension plans with accumulated benefit obligations in excess of plan assets is shown in the table below:

	Pension benefits
millions of dollars	2013		2012
For funded pension plans with accumulated benefit obligations in excess of plan assets:
Projected benefit obligation		-		6,716
Accumulated benefit obligation		-		6,025
Fair value of plan assets		-		5,114
Accumulated benefit obligation less fair value of plan assets		-		911
For unfunded plans covered by book reserves:
Projected benefit obligation		574		620
Accumulated benefit obligation		496		535

Estimated 2014 amortization from accumulated other comprehensive income

millions of dollars	Pension benefits		Other post-retirement benefits
Net actuarial loss/(gain) (a)		169		5
Prior service cost (b)		23		-

(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 dollars	Pension benefits		Other post-retirement benefits
2014		365		28
2015		375		28
2016		384		28
2017		393		28
2018		401		28
2019 - 2023		2,078		145

In 2014, the company expects to make cash contributions of about $420 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 dollars	One percent increase			One percent decrease
Rate of return on plan assets:
Effect on net benefit cost, before tax		(50	)		50
Discount rate:
Effect on net benefit cost, before tax		(80	)		100
Effect on benefit obligation		(850	)		1,050
Rate of pay increases:
Effect on net benefit cost, before tax		50			(45	)
Effect on benefit obligation		170			(150	)

71

Notes to consolidated financial statements (continued)

A one percent change in the assumed health-care cost trend rate would have the following effects:

Increase/(decrease) millions of dollars	One percent increase		One percent decrease
Effect on service and interest cost components		4		(3)
Effect on benefit obligation		45		(35)

5.   Other long-term obligations

millions of dollars	2013		2012
Employee retirement benefits (note 4)(a)		1,448		2,717
Asset retirement obligations and other environmental liabilities (b)		1,258		957
Share-based incentive compensation liabilities (note 7)		140		117
Other obligations		245		192
Total other long-term obligations		3,091		3,983

(a) Total recorded employee retirement benefit obligations also include $53 million in current liabilities (2012 – $52 million).

(b) Total asset retirement obligations and other environmental liabilities also include $154 million in current liabilities (2012 – $168 million).

Asset retirement obligations incurred in the current period were Level 3 (unobservable inputs) fair value measurements. The following table summarizes the activity in the liability for asset retirement obligations:

millions of dollars	2013		2012
Balance as at January 1		966		936
Additions		251		61
Reductions due to property sales		-		(8	)
Accretion		105		86
Settlement		(85)		(109	)
Balance as at December 31		1,237		966

6.   Derivatives and financial instruments

The company did not enter into any derivative instruments to offset exposures associated with hydrocarbon prices, foreign currency exchange rates and interest rates that arose from existing assets, liabilities and transactions in the past three years. The company did not engage in speculative derivative activities or derivative trading activities nor did it use derivatives with leveraged features. The company maintains a system of controls that includes a policy covering the authorization, reporting and monitoring of derivative activity.

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 (observable input).

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.

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 exercise, an amount equal to 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 exercise dates. Fifty percent of the units are exercised three years following the grant date, and the remainder is exercised seven years following the grant date. The company may also issue units where 50 percent of the units are exercisable five years following the grant date and the remainder is exercisable on the later of ten years following the grant date or the retirement date of the recipient.

72

Notes to consolidated financial statements (continued)

The deferred share unit plan is made available to nonemployee directors. The nonemployee directors can elect to receive all or part of their 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 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 resignation as a director and must be exercised no later than December 31 of the year following resignation. On the exercise date, the cash value to be received for the units is determined based on the average closing price of the company’s shares for the five consecutive trading days 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 to be exercised in the seventh year following the grant date. For units where 50 percent are exercisable five years following the grant date and the remainder exercisable on 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 units to be exercised.

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, 2013:

	Restricted stock units			Deferred share units
Outstanding at January 1, 2013		8,943,104			85,505
Granted		1,654,540			12,731
Exercised		(1,841,408	)		-
Forfeited and cancelled		(41,382	)		-
Outstanding at December 31, 2013		8,714,854			98,236

In 2013, the compensation expense charged against income for these programs was $92 million (2012 - $58 million, 2011 - $91 million). Income tax benefit recognized in income related to compensation expense for the year was $33 million (2012 - $20 million, 2011 - $33 million). Cash payments of $88 million were made for these programs in 2013 (2012 - $97 million, 2011 - $173 million).

As of December 31, 2013, there was $194 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 nonvested restricted stock units is 3.7 years. All units under the deferred share programs have vested as of December 31, 2013.

73

Notes to consolidated financial statements (continued)

8. Investment and other income

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

millions of dollars	2013		2012		2011
Proceeds from asset sales		160		226		314
Book value of assets sold		10		132		117
Gain/(loss) on asset sales, before tax (a)		150		94		197
Gain/(loss) on asset sales, after tax (a)		120		72		153

(a) 2013 included a gain of $85 million ($73 million after tax) for the sale of non-operating assets.

9. Litigation and other contingencies

A variety of claims have been made against Imperial Oil Limited 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.

	Payments due by period
millions of dollars	2014		2015		2016		2017		2018		After 2018		Total
Unconditional purchase obligations (a)		91		80		82		83		84		237		657

(a) Undiscounted obligations of $657 million mainly pertain to pipeline throughput agreements. Total payments under unconditional purchase obligations were $95 million (2012 - $86 million, 2011 - $73 million). The present value of these commitments, excluding imputed interest of $178 million, totalled $479 million.

74

Notes to consolidated financial statements (continued)

10. Common shares

thousands of shares	As at    Dec. 31    2013		As at Dec. 31 2012
Authorized		1,100,000		1,100,000

From 1995 through 2012, the company purchased shares under eighteen 12-month normal course issuer bid share repurchase programs, as well as an auction tender. On June 25, 2013, another 12-month normal course issuer bid program was implemented with an allowable purchase of up to a maximum of one million shares. Unlike prior programs, this maximum amount is not reduced by common shares purchased for the company’s employee savings plan, the company’s employee retirement plan and from Exxon Mobil Corporation. The results of these activities are as shown below.

Year	Purchased shares (thousands)		Millions of dollars
1995 to 2011		903,765		15,580
2012		2,776		128
2013		-		-
Cumulative purchases to date		906,541		15,708

ExxonMobil’s participation in the above maintained its ownership interest in Imperial at 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, 2011		847,599			1,511
Issued under employee share-based awards		1,262			19
Purchases at stated value		(1,262	)		(2	)
Balance as at December 31, 2011		847,599			1,528
Issued under employee share-based awards		2,776			43
Purchases at stated value		(2,776	)		(5	)
Balance as at December 31, 2012		847,599			1,566
Issued under employee share-based awards		-			-
Purchases at stated value		-			-
Balance as at December 31, 2013		847,599			1,566

75

Notes to consolidated financial statements (continued)

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

	2013		2012		2011
Net income per common share – basic
Net income (millions of dollars)		2,828		3,766		3,371
Weighted average number of common shares outstanding (millions of shares)		847.6		847.7		847.7
Net income per common share (dollars)		3.34		4.44		3.98
Net income per common share - diluted
Net income (millions of dollars)		2,828		3,766		3,371
Weighted average number of common shares outstanding (millions of shares)		847.6		847.7		847.7
Effect of employee share-based awards (millions of shares)		3.0		3.4		5.9
Weighted average number of common shares outstanding, assuming dilution (millions of shares)		850.6		851.1		853.6
Net income per common share (dollars)		3.32		4.42		3.95

11. Miscellaneous financial information

In 2013, net income included an after-tax gain of $24 million (2012 – $45 million gain, 2011 – $10 million gain) attributable to the effect of changes in last-in, first-out (LIFO) inventories. The replacement cost of inventories was estimated to exceed their LIFO carrying values at December 31, 2013 by $1,787 million (2012 – $1,769 million). Inventories of crude oil and products at year-end consisted of the following:

millions of dollars	2013		2012
Crude oil		628		473
Petroleum products		340		284
Chemical products		54		60
Natural gas and other		8		10
Total inventories of crude oil and products		1,030		827

Net research and development costs charged to expenses in 2013 were $154 million (2012 – $147 million, 2011 – $120 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 $380 million at December 31, 2013 (2012 - $377 million).

12. Financing costs and additional notes and loans payable information

millions of dollars	2013			2012			2011
Debt-related interest		69			20			16
Capitalized interest		(69	)		(20	)		(16	)
Net interest expense		-			-			-
Other interest		11			(1	)		3
Total financing costs (a)		11			(1	)		3

(a) Cash interest payments in 2013 were $69 million (2012 – $20 million, 2011 – $16 million). The weighted average interest rate on short-term borrowings in 2013 was 1.1 percent (2012 – 1.1 percent).

76

Notes to consolidated financial statements (continued)

In the fourth quarter of 2013, the company entered into 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 (Canadian). 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. As at December 31, 2013, the company had drawn $75 million on this agreement.

In the first quarter of 2013, to further support the commercial paper program, the company entered into an unsecured committed bank credit facility in the amount of $250 million that matures in March 2014. In the second quarter, the amount of this facility increased to $500 million. The company has not drawn on the facility.

13. Leased facilities

At December 31, 2013, the company held non-cancelable operating leases covering office buildings, rail cars, service stations and other properties with minimum undiscounted lease commitments totaling $389 million as indicated in the following table:

	Payments due by period
millions of dollars	2014		2015		2016		2017		2018		After 2018		Total
Lease payments under minimum commitments (a)		177		88		47		33		12		32		389

(a) Net rental cost under cancelable and non-cancelable operating leases incurred in 2013 was $287 million (2012 – $271 million, 2011 – $226 million). Related rental income was not material.

14. Long-term debt

millions of dollars	As at Dec. 31 2013		As at Dec. 31 2012
Long-term debt (a)		4,316		1,040
Capital leases (b)		128		135
Total long-term debt		4,444		1,175

 (a) Borrowed 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 $5 billion (Canadian) 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. Average effective rate for the loan was 1.3 percent in 2013.

 (b) Capitalized lease obligations primarily relate to capital leases for pipeline transportation and marine services agreements. The average imputed rate was 7.0 percent in 2013 (2012 – 9.6 percent). Total capitalized lease obligations also include $7 million in current liabilities (2012 - $7 million). Principal payments on capital leases of approximately $7 million per year are due in each of the next four years after December 31, 2014.

In the first quarter of 2013, the company increased the amount of its existing stand-by long term bank credit facility from $300 million to $500 million. In the third quarter, the company extended the maturity date of this facility to August 2015. The company has not drawn on the facility.

In January 2014, the company increased the capacity of its existing floating rate loan facility with an affiliated company of ExxonMobil from $5 billion to $6.25 billion. All other terms and conditions of the agreement remained unchanged.

77

Notes to consolidated financial statements (continued)

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.

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 dollars	2013	2012	2011
Balance as at January 1	167	163	120
Additions pending the determination of proved reserves	12	16	43
Charged to expense	-	-	-
Reclassification to wells, facilities and equipment based on the determination of proved reserves	(6)	(12)	-
Balance as at December 31	173	167	163

Period end capitalized suspended exploratory well costs:

millions of dollars	2013	2012	2011
Capitalized for a period of one year or less	6	16	43
Capitalized for a period of between one and five years	167	151	120
Capitalized for a period of greater than one year	167	151	120
Total	173	167	163

Exploration activity often involves drilling multiple wells, over a number of years, to fully evaluate a project. The table below provides a numerical breakdown of the number of projects with suspended exploratory well costs which had their first capitalized well drilled in the preceding 12 months and those that have had exploratory well costs capitalized for a period greater than 12 months.

	2013	2012	2011
Number of projects with first capitalized well drilled in the preceding 12 months	-	-	1
Number of projects that have exploratory well costs capitalized for a period of greater than 12 months	1	1	1
Total	1	1	2

The project with exploratory well costs capitalized for a period greater than 12 months as of December 31, 2013 had drilling in the preceding 12 months.

78

Notes to consolidated financial statements (continued)

16. Transactions with related parties

Revenues and expenses of the company also include the results of transactions with Exxon Mobil Corporation and affiliated companies (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 to:

a) 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) 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) provide for the delivery of management, business and technical services to Syncrude Canada Ltd. by ExxonMobil; and

d) provide for the option of equal participation in new upstream opportunities.

Certain charges from ExxonMobil have been capitalized; they are not material in the aggregate.

As at December 31, 2013, the company had outstanding long-term loans of $4,316 million (2012 – $1,040 million) and short-term loans of $75 million (2012 – nil) from ExxonMobil (see note 14, long-term debt, on page 77 and note 12, financing costs and additional notes and loans payable, on page 76 for further details).

79

Notes to consolidated financial statements (continued)

17. Other comprehensive income information

Changes in accumulated other comprehensive income:

millions of dollars	2013	2012	2011
Balance as at January 1	(2,455)	(2,238)	(1,424)
Post-retirement benefits liability adjustment:
Current period change excluding amounts reclassified from accumulated other comprehensive income	529	(415)	(953)
Amounts reclassified from accumulated other comprehensive income	205	198	139
Balance as at December 31	(1,721)	(2,455)	(2,238)

Amounts reclassified out of accumulated other comprehensive income – before tax income/(expense)

millions of dollars	2013	2012	2011
Amortization of post-retirement benefits liability adjustment included in net periodic benefit cost (a)	(276)	(266)	(186)

(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

millions of dollars	2013	2012	2011
Post-retirement benefits adjustments:
Post-retirement benefits liability adjustment (excluding amortization)	185	(155)	(326)
Amortization of post-retirement benefits liability adjustment included in net periodic benefit cost	71	68	47
Total	256	(87)	(279)

80

Notes to consolidated financial statements (continued)

18. Acquisition

Description of the Transaction: On February 26, 2013, ExxonMobil Canada acquired Celtic Exploration Ltd. (Celtic). Immediately following the acquisition, Imperial acquired a 50 percent interest in Celtic’s assets and liabilities from ExxonMobil Canada for $1.6 billion, financed by a combination of related party and third party debt. Concurrently, a general partnership was formed to hold and operate the assets of Celtic. The name of the general partnership was changed to XTO Energy Canada (XTO Canada). XTO Canada is involved in the exploration for, production of, and transportation and sale of natural gas and crude oil, condensate and natural gas liquids.

Recording of Assets Acquired and Liabilities Assumed: Imperial used the acquisition method of accounting to record its pro-rata share of the assets acquired and liabilities assumed. This method requires, among other things, that assets acquired and liabilities assumed be recognized at their fair values as of the acquisition date. The following table summarizes the assets acquired and liabilities assumed:

millions of dollars
Cash	6
Accounts receivable	38
Materials, supplies and prepaid expenses	5
Property, plant and equipment (a)	2,045
Goodwill (b)	20
Total assets acquired	2,114
Accounts payable and accrued liabilities	62
Deferred income tax liabilities (c)	377
Other long-term obligations	67
Total liabilities assumed	506
Net assets acquired	1,608

(a) Property, plant and equipment were measured primarily using an income approach. The fair value measurements of the oil and gas assets were based, in part, on significant inputs not observable in the market and thus represent a Level 3 measurement. The significant inputs included Celtic resources, assumed future production profiles, commodity prices (mainly based on observable market inputs), risk adjusted discount rate of 10 percent, inflation of 2 percent and assumptions on the timing and amount of future development and operating costs. The property, plant and equipment additions were segmented to the Upstream business, with all of the assets in Canada.

(b) Goodwill was the excess of the consideration transferred over the net assets recognized and represents the future economic benefits arising from other assets acquired that could not be individually identified and separately recognized. Goodwill was recognized in the Upstream reporting unit. Goodwill is not amortized and is not deductible for tax purposes.

(c) Deferred income taxes reflect the future tax consequences on the temporary differences between the amount of assets and liabilities recognized for financial reporting purposes and such amounts recognized for tax purposes. The deferred income taxes recorded as part of the acquisition were:

millions of dollars
Property, plant and equipment	414
Total deferred income tax liabilities	414
Asset retirement obligations	(17)
Other	(20)
Total deferred income tax assets	(37)
Net deferred income tax liabilities	377

Actual and Pro Forma Impact of the Acquisition: Revenues for XTO Canada from the acquisition date included in the company’s consolidated financial statement of income for the twelve months ended December 31, 2013 were $89 million. After-tax earnings for XTO Canada from the acquisition date through December 31, 2013 were de minimis.

Transaction costs related to the acquisition were expensed as incurred and were de minimis in the twelve months ended December 31, 2013.

Unaudited pro forma revenues, earnings and basic and diluted earnings per share information as if the acquisition had occurred at the beginning of 2013 or the comparable prior reporting period is not presented, since the effect on Imperial’s consolidated annual financial results for the year ended December 31, 2013 and the comparable prior reporting periods, would not have been material.

81

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

The information on pages 82 to 83 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 and 70.96 percent interest in proved bitumen reserves in the Kearl project are included as part of the company’s total proved oil and gas reserves in accordance with U.S. Securities and Exchange Commission (SEC) and U.S. Financial Accounting Standards Board (FASB) rules. Similarly, the company’s share of proved synthetic oil reserves from Syncrude and proved bitumen reserves from Kearl are included in the calculation of the standardized measure of discounted future cash flows. 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.

The company’s share of results of operations, costs incurred in property acquisitions, exploration and development activities and capitalized costs relating to Celtic (XTO Canada) are included in the following tables for the first time in 2013. Similarly, the company’s share of proved reserves for Celtic (XTO Canada) are 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.

Results of operations

millions of dollars	2013	2012	2011
Sales to customers (a)	2,282	2,074	2,185
Intersegment sales (a)(b)	3,905	3,534	3,828
	6,187	5,608	6,013
Production expenses	3,392	2,589	2,352
Exploration expenses	123	83	90
Depreciation and depletion	586	498	530
Income taxes	512	584	718
Results of operations	1,574	1,854	2,323

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 dollars	2013	2012	2011
Property costs (c)
Proved	34	-	-
Unproved	2,013	33	114
Exploration costs	124	109	133
Development costs	5,847	5,125	3,792
Total costs incurred in property acquisitions, exploration and development activities	8,018	5,267	4,039

(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.

82

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

Capitalized costs

millions of dollars	2013	2012
Property costs (c)
Proved	3,017	2,974
Unproved	2,621	616
Producing assets	23,811	13,322
Incomplete construction	8,286	13,062
Total capitalized cost	37,735	29,974
Accumulated depreciation and depletion	(10,686)	(10,140)
Net capitalized costs	27,049	19,834

(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.

Standardized measure of discounted future cash flows

As required by the FASB, 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 dollars	2013			2012			2011
Future cash flows		231,873			227,253			224,130
Future production costs		(92,926	)		(83,600	)		(82,903)
Future development costs		(32,126	)		(31,051	)		(27,259)
Future income taxes		(23,707	)		(25,902	)		(26,671)
Future net cash flows		83,114			86,700			87,297
Annual discount of 10 percent for estimated timing of cash flows		(58,204	)		(61,864	)		(61,277)
Discounted future cash flows		24,910			24,836			26,020

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

Balance at beginning of year	24,836		26,020		21,251
Changes resulting from:
Sales and transfers of oil and gas produced, net of production costs	(3,026	)	(3,116	)	(3,764)
Net changes in prices, development costs and production costs	(17,683	)	(6,810	)	2,845
Extensions, discoveries, additions and improved recovery, less related costs	31		2,698		1,694
Development costs incurred during the year	5,500		5,086		3,583
Revisions of previous quantity estimates	12,321		(805	)	165
Accretion of discount	1,703		997		1,725
Net change in income taxes	1,228		766		(1,479)
Net change	74		(1,184	)	4,769
Balance at end of year	24,910		24,836		26,020

83

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

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 2011		57			576			681			1,715			2,549
Revisions		4			11			(4	)		36			38
Improved recovery		-			-			-			-			-
(Sale)/purchase of reserves in place		-			(103	)		-			-			(17	)
Discoveries and extensions		-			21			-			706			709
Production		(6	)		(83	)		(24	)		(44	)		(88	)
End of year 2011		55			422			653			2,413			3,191
Revisions		5			98			(29	)		239			231
Improved recovery		-			-			-			-			-
(Sale)/purchase of reserves in place		-			(7	)		-			-			(1	)
Discoveries and extensions		-			47			-			234			242
Production		(7	)		(72	)		(25	)		(45	)		(89	)
End of year 2012		53			488			599			2,841			3,574
Revisions		6			(2	)		4			78			88
Improved recovery		-			-			-			-			-
(Sale)/purchase of reserves in place		10			261			-			-			54
Discoveries and extensions		-			-			-			-			-
Production		(7	)		(69	)		(24	)		(52	)		(94	)
End of year 2013		62			678			579			2,867			3,622
Net Proved Developed Reserves included above, as of
January 1, 2011		56			507			681			519			1,340
December 31, 2011		55			360			653			519			1,287
December 31, 2012		52			373			599			543			1,256
December 31, 2013		55			368			579			1,417			2,113
Net Proved Undeveloped Reserves included above, as of
January 1, 2011		1			69			-			1,196			1,209
December 31, 2011		-			62			-			1,894			1,904
December 31, 2012		1			115			-			2,298			2,318
December 31, 2013		7			310			-			1,450			1,509

(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 6 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 2011, 2012 and 2013. The definitions used are in accordance with the U.S. Securities and Exchange Commission’s (SEC) Rule 4-10 (a) of Regulation S-X.

Proved oil and 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.

84

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

In accordance with SEC rules, the year-end reserves volumes as well as the reserves change categories shown in the proved reserves tables were calculated using 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 revaluation of already available geologic, reservoir or production data; new geologic, reservoir or production data; or changes in prices and costs that are used in the estimation of reserves. This category can also include significant changes in either development strategy or production equipment/facility capacity.

In 2013, the quantities of proved liquids and natural gas reserves shown in the sale/purchase category reflected the company’s share of reserves from the Celtic acquisition.

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 life of each of the Cold Lake and Kearl projects, and they incorporate the Alberta government’s revised oil sands royalty regime. For synthetic oil, net proved reserves are based on the company’s best estimate of average royalty rates over the life of the project, and they incorporate amendments to the Syncrude Crown Agreement. 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.

In 2013, increased proved developed bitumen reserves were largely due to the start-up of the initial development at Kearl in the second quarter of 2013, resulting in a migration of proved undeveloped reserves to proved developed.

No independent qualified reserves evaluator or auditor was involved in the preparation of the reserves data.

85

Quarterly financial and stock trading data (a)

	2013 three months ended												2012 three months ended
	Dec. 31			Sept. 30			June 30			Mar. 31			Dec. 31			Sept. 30			June 30			Mar. 31
Financial data (millions of dollars)
Total revenues and other income		8,363			8,594			7,958			8,014			7,804			8,336			7,515			7,533
Total expenses		6,985			7,737			7,526			6,944			6,390			6,949			6,675			6,181
Income before income taxes		1,378			857			432			1,070			1,414			1,387			840			1,352
Income taxes		322			210			105			272			338			347			205			337
Net income		1,056			647			327			798			1,076			1,040			635			1,015
Segmented net income (millions of dollars)
Upstream		411			604			397			300			488			498			360			542
Downstream		625			46			(97	)		478			549			536			232			455
Chemical		46			39			42			35			44			37			49			35
Corporate and Other		(26	)		(42	)		(15	)		(15	)		(5	)		(31	)		(6	)		(17	)
Net income		1,056			647			327			798			1,076			1,040			635			1,015
Per-share information (dollars)
Net earnings – basic		1.25			0.76			0.39			0.94			1.27			1.22			0.75			1.20
Net earnings – diluted		1.24			0.76			0.38			0.94			1.26			1.22			0.75			1.19
Dividends (declared quarterly)		0.13			0.12			0.12			0.12			0.12			0.12			0.12			0.12
Share prices (dollars) (b)
Toronto Stock Exchange
High		47.57			46.10			41.82			45.44			46.25			48.32			46.68			49.26
Low		43.19			40.32			38.58			41.42			41.44			41.43			39.77			43.72
Close		47.04			45.23			40.15			41.52			42.73			45.25			42.59			45.32
NYSE MKT (U.S. dollars) (b)
High		45.67			44.65			41.15			45.16			47.02			50.00			47.36			49.32
Low		41.55			38.22			37.09			40.68			42.06			40.50			38.16			43.72
Close		44.23			43.96			38.21			40.86			43.00			46.03			41.72			45.39
Shares traded (thousands) (c)		67,673			77,781			95,600			103,979			44,615			52,065			66,394			64,643

(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 MKT LLC. Imperial has unlisted privileges on the NYSE MKT LLC, a subsidiary of NYSE Euronext. 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. For 2012, share volumes in the U.S. included NYSE and alternative platform trades and TSX volumes for Canada. Commencing in 2013 share volumes include trades on alternative Canadian platforms, information that was previously unavailable.

86

Proxy information section

Table of Contents	Page
III. Board of directors		88
Director information		88
Director qualification and selection process		96
Director orientation, education, development, tenure and performance assessment		98
Independence of the directors		99
Board and committee structure		100
Committee memberships of the directors		107
Number of meetings and director attendance in 2013		107
Share ownership guidelines		109
Other public company directorships		110
Interlocking directorships		110
Director compensation		111
Director compensation discussion and analysis		111
Director compensation details and tables		112
IV. Company executives and executive compensation		116
Named executive officers of the company		116
Other executive officers of the company		117
Letter to Shareholders from the executive resources committee on executive compensation		118
Compensation discussion and analysis		120
Overview		121
Compensation program		124
Compensation decision making process and considerations for named executive officers		129
Executive compensation tables and narratives		134
V. Other important information		141
Effective date		141
Largest shareholder		141
Transactions with Exxon Mobil Corporation		141
Auditor Information		142
Auditor fees		142
Auditor independence		142
Ethical business conduct		143
Appendix B – Board of Director and Committee Charters		144

87

III. Board of directors

Director information

The 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.

Included in these tables is information relating to the director nominees’ biographies, independence status, expertise, committee memberships, attendance, public board memberships, non-profit sector affiliations and shareholdings in the company, as well as any shareholdings in Exxon Mobil Corporation. The information is as of February 13, 2014, the effective date of this circular, unless otherwise indicated.

88

Krystyna T. Hoeg            Toronto, Ontario, Canada Age: 64 Current Position: Nonemployee director Independent Director since May 1, 2008 Normally ineligible for re-election in 2022   Skills and experience: —  Leadership of large organizations —  Project management —  Global experience —  Strategy development —  Audit committee financial expert —  Financial expertise —  Executive compensation Voting Results of 2013 Annual General Meeting: Votes For: 739,037,993 (99.83%) Votes Withheld: 1,231,781 (0.17%) Total Votes: 740,269,711

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 Sun Life Financial Inc., Shoppers Drug Mart Corporation, Canadian Pacific Railway Limited and Canadian Pacific Railway Company, and is also a director of Samuel, Son & Co. Limited, a privately owned corporation. Ms. Hoeg sits on the board of the Toronto East General Hospital.

Board and Committee Membership

Attendance in 2013

Imperial Oil Limited board

8 of 8

100%

Audit committee

5 of 5

100%

Executive resources committee (Chair)

10 of 10

100%

Environment, health and safety committee

3 of 3

100%

Nominations and corporate governance committee

4 of 4

100%

Contributions committee

3 of 3

100%

Annual meeting of shareholders

1 of 1

100%

Overall Attendance – 100%

Imperial Oil Limited Equity Ownership (a) (b) (c) (d)

As at

Common  Shares  (% of class)

Deferred  Share Units    (DSU)

Restricted  Stock Units    (RSU)

Total Common    Shares, DSU  and RSU

Total Market Value   of Common Shares,     DSU and RSU ($)

February   13, 2014

0

18,093

9,000

27,093

1,280,686

February 13, 2013

0

14,678

8,000

22,678

968,351

Change

0

3,415

1,000

4,415

312,335

Share ownership guidelines have been met.

Exxon Mobil Corporation Equity Ownership (a) (c) (e)

As at

Common Shares   (% of class)

Restricted Stock

Total Common   Shares and Restricted Stock

Total Market Value of     Common Shares and   Restricted Stock ($)

February 13, 2014

0

0

0

0

Public Company Directorships in the Past Five Years

•    Sun Life Financial Inc. (2002 – Present)   •    Shoppers Drug Mart Corporation (2006 – Present)   •    Canadian Pacific Railway Limited (2007 – Present)   •    Canadian Pacific Railway Company (2007 – Present)   •    Cineplex Galaxy Income Fund (2006 – 2010)

Public Board Interlocks

None

Other Positions in the Past Five Years (position, date office held and status of employer)

No other positions held in the last five years

Non-profit sector affiliations

•    Toronto East General Hospital (Board of Directors)

89

Richard M. Kruger              Calgary, Alberta, Canada Age: 54 Current Position: Chairman, president and chief executive officer, Imperial Oil Limited (as of March 1, 2013) Not independent 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 Voting Results of 2013 Annual General Meeting: Votes For: 721,250,808 (97.43%) Votes Withheld: 19,024,883 (2.57%) Total Votes: 740,275,691

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.

Board and Committee Membership

Attendance in 2013

Imperial Oil Limited board (Chair) (appointed March 1, 2013)

6 of 6

100%

Contributions committee (appointed March 1, 2013)

2 of 2

100%

Annual meeting of shareholders

1 of 1

100%

Overall Attendance – 100%

Imperial Oil Limited Equity Ownership (a) (b) (c) (d)

As at

Common  Shares  (% of class)

Deferred  Share Units    (DSU)

Restricted  Stock Units    (RSU)

Total Common    Shares, DSU  and RSU

Total Market Value   of Common Shares,   DSU and RSU ($)

February   13, 2014

0

0

91,400

91,400

4,320,478

Share ownership guidelines are expected to be met in 2014.

Exxon Mobil Corporation Equity Ownership (a) (c) (e)

As at

Common Shares   (% of class)

Restricted Stock

Total Common   Shares and Restricted Stock

Total Market Value of   Common Shares and   Restricted Stock ($)

February 13, 2014

8,868 (<0.01%)

229,300

238,168

23,909,719

Public Company Directorships in the Past Five Years

None

Public Board Interlocks

None

Other Positions in the Past Five Years (position, date office held and status of employer)

• Vice-president, Exxon Mobil Corporation and President, ExxonMobil Production Company, a division of Exxon Mobil Corporation (2008 - 2013) (Affiliate)

Non-profit sector affiliations

•    United Way of Calgary and Area (Board of Directors) •    University of Minnesota’s College of Engineering and Science (Advisory Board) •    Canadian Council of Chief Executives (Member) •    Society of Petroleum Engineers (Member)

90

Jack M. Mintz        Calgary, Alberta, Canada Age: 62 Current Position: Nonemployee director Independent Director since April 21, 2005 Normally ineligible for re-election in 2023   Skills and experience: —  Global experience —  Strategy development —  Financial expertise —  Government relations —   Academic/research —  Executive compensation Voting Results of 2013 Annual General Meeting: Votes For: 739,080,916 (99.84%) Votes Withheld: 1,188,775 (0.16%) Total Votes: 740,269,691

Dr. Mintz is currently the Palmer Chair in Public Policy for the University of Calgary. Prior to that he was a professor at the Joseph L. Rotman School of Management at the University of Toronto from 1989. Dr. Mintz is a director of Morneau Shepell Inc. Dr. Mintz has published widely in the fields of public economics and fiscal federalism and has frequently published articles in national newspapers and magazines.

Board and Committee Membership

Attendance in 2013

Imperial Oil Limited board

8 of 8

100%

Audit committee

5 of 5

100%

Executive resources committee

10 of 10

100%

Environment, health and safety committee (Chair)

3 of 3

100%

Nominations and corporate governance committee

4 of 4

100%

Contributions committee

3 of 3

100%

Annual meeting of shareholders

1 of 1

100%

Overall Attendance – 100%

Imperial Oil Limited Equity Ownership (a) (b) (c) (d)

As at

Common  Shares  (% of class)

Deferred  Share Units    (DSU)

Restricted  Stock Units    (RSU)

Total Common    Shares, DSU  and RSU

Total Market Value   of Common Shares,       DSU and RSU ($)

February   13, 2014

1,000

14,840

10,000

25,840

1,221,457

February 13, 2013

1,000 (<0.01%)

11,878

10,500

23,378

998,241

Change

0

2,962

(500)

2,462

223,216

Share ownership guidelines have been met.

Exxon Mobil Corporation Equity Ownership (a) (c) (e)

As at

Common Shares   (% of class)

Restricted Stock

Total Common   Shares and Restricted Stock

Total Market Value of     Common Shares and   Restricted Stock ($)

February 13, 2014

0

0

0

0

Public Company Directorships in the Past Five Years

•    Morneau Shepell Inc. (2010 - Present)   •    Brookfield Asset Management Inc. (formerly Brascan Corporation) (2002 – 2012)

Public Board Interlocks

None

Other Positions in the Past Five Years (position, date office held and status of employer)

No other positions held in the last five years

Non-profit sector affiliations

•      Social Science and Humanities Research Council of Canada (Vice-president and chair of the governing council) •      Centre for Economic Studies (CES) Ifo Institute, Germany (Research fellow) •      Oxford Centre on Business Taxation, UK (Research fellow) •      Literary Review of Canada (Board of Directors)

91

David S. Sutherland        Waterloo, Ontario, Canada Age: 64 Current Position: Nonemployee director Independent Director since April 29, 2010 Normally ineligible for re-election in 2022 Skills and experience: —   Leadership of large organizations —    Operations/technical —   Global experience —   Strategy development —   Audit committee financial expert —   Financial expertise —    Government relations —   Executive compensation Voting Results of 2013 Annual General Meeting: Votes For: 739,229,928 (99.86%) Votes Withheld: 1,039,763 (0.14%) Total Votes: 740,269,691

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 a director of GATX Corporation and Graham Construction. 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.

Board and Committee Membership

Attendance in 2013

Imperial Oil Limited board

8 of 8

100%

Audit committee

5 of 5

100%

Executive resources committee

10 of 10

100%

Environment, health and safety committee

3 of 3

100%

Nominations and corporate governance committee

4 of 4

100%

Contributions committee (Chair)

3 of 3

100%

Annual meeting of shareholders

1 of 1

100%

Overall Attendance – 100%

Imperial Oil Limited Equity Ownership (a) (b) (c) (d)

As at

Common  Shares  (% of class)

Deferred  Share Units    (DSU)

Restricted  Stock Units    (RSU)

Total Common    Shares, DSU  and RSU

Total Market Value   of Common Shares,     DSU and RSU ($)

February   13, 2014

45,000

11,736

7,000

63,736

3,012,801

February 13, 2013

45,000 (<0.01%)

8,393

6,000

59,393

2,536,081

Change

0

3,343

1,000

4,343

476,720

Share ownership guidelines have been met.

Exxon Mobil Corporation Equity Ownership (a) (c) (e)

As at

Common Shares   (% of class)

Restricted Stock

Total Common   Shares and Restricted Stock

Total Market Value of     Common Shares and   Restricted Stock ($)

February   13, 2014

5,730 (<0.01%)

0

5,730

575,236

Public Company Directorships in the Past Five Years

•    GATX Corporation (2007 - Present)   •    United States Steel Corporation, (2008 – Present) (Chairman since January 1, 2014)   •     ZCL Composites Inc. (2008 – 2010)

Public Board Interlocks

None

Other Positions in the Past Five Years (position, date office held and status of employer)

No other positions held in the last five years

Non-profit sector affiliations

•    KidsAbility, Centre for Child Development (Finance Committee)

92

Sheelagh D. Whittaker          London, England Age: 66 Current Position: Nonemployee director Independent Director since April 19, 1996 Normally ineligible for re-election in 2019 Skills and experience: — Leadership of large  organizations — Global experience — Strategy development — Audit committee financial  expert — Financial expertise — Government relations — Information technology — Executive compensation Voting Results of 2013 Annual General Meeting: Votes For: 738,522,124 (99.76%) Votes Withheld: 1,747,567 (0.24%) Total Votes: 740,269,691

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. Ms. Whittaker is also a director of Standard Life Canada.

Board and Committee Membership

Attendance in 2013

Imperial Oil Limited board

8 of 8

100%

Audit committee

5 of 5

100%

Executive resources committee

10 of 10

100%

Environment, health and safety committee

3 of 3

100%

Nominations and corporate governance committee (Chair)

4 of 4

100%

Contributions committee

3 of 3

100%

Annual meeting of shareholders

1 of 1

100%

Overall Attendance – 100%

Imperial Oil Limited Equity Ownership (a) (b) (c) (d)

As at

Common  Shares  (% of class)

Deferred  Share Units    (DSU)

Restricted  Stock Units    (RSU)

Total Common    Shares, DSU  and RSU

Total Market Value   of Common Shares,     DSU and RSU ($)

February   13, 2014

9,350

43,183

10,000

62,533

2,955,935

February 13, 2013

9,350 (<0.01%)

41,092

10,500

60,942

2,602,223

Change

0

2,091

(500)

1,591

353,712

Share ownership guidelines have been met.

Exxon Mobil Corporation Equity Ownership (a) (c) (e)

As at

Common Shares   (% of class)

Restricted Stock

Total Common Shares and Restricted Stock

Total Market Value of     Common Shares and   Restricted Stock ($)

February   13, 2014

0

0

0

0

Public Company Directorships in the Past Five Years

•    Standard Life plc (2009 – 2013)

Public Board Interlocks

None

Other Positions in the Past Five Years (position, date office held and status of employer)

No other positions held in the last five years

Non-profit sector affiliations

•    Member of the VIP Advisory Board of the European Professional Women’s Network

93

Darren W. Woods          Fairfax, Virginia, United States of America Age: 49 Current Position: Vice- president, Exxon Mobil Corporation and president ExxonMobil Refining and Supply Company Not independent Director since April 25, 2013 Skills and experience: —   Leadership of large    organizations —    Operations/technical —   Project management —   Global experience —   Strategy development —   Financial expertise —   Executive compensation Voting Results of 2013 Annual General Meeting: Votes For: 738,015,858 (99.90%) Votes Withheld: 732,833 (0.10%) Total Votes: 738,748,691

Mr. Woods is a vice-president of Exxon Mobil Corporation and is the president of ExxonMobil Refining and Supply Company, a division of Exxon Mobil Corporation, with responsibility for ExxonMobil’s global refining and supply operations. He is located in Fairfax, Virginia. Mr. Woods has worked for ExxonMobil in a range of downstream and chemical management assignments, investor relations in the United States, as well as international assignments in England, Scotland and Brussels.

Board and Committee Membership

Attendance in 2013

Imperial Oil Limited board

6 of 6

100%

Executive resources committee

6 of 6

100%

Environment, health and safety committee

2 of 2

100%

Nominations and corporate governance committee

2 of 2

100%

Contributions committee

2 of 2

100%

Annual meeting of shareholders

1 of 1

100%

(became a director and a member of the four committees noted above on April 25, 2013 )

Overall Attendance – 100%

Imperial Oil Limited Securities Held (a) (b) (c) (d)

As at

Common  Shares  (% of class)

Deferred  Share Units    (DSU)

Restricted  Stock Units    (RSU)

Total Common    Shares, DSU  and RSU

Total Market Value   of Common Shares,     DSU and RSU ($)

February   13, 2014

0

0

0

0

0

No share ownership guidelines apply.

Exxon Mobil Corporation Equity Ownership (a) (c) (e)

As at

Common Shares   (% of class)

Restricted Stock

Total Common   Shares and Restricted Stock

Total Market Value of     Common Shares and   Restricted Stock ($)

February   13, 2014

22,452 (<0.01%)

124,250

146,702

14,727,434

Public Company Directorships in the Past Five Years

None

Public Board Interlocks

None

Other Positions in the Past Five Years (position, date office held and status of employer)

•    Vice President, Supply & Transportation, ExxonMobil Refining & Supply Company (2010 - 2012)        (Affiliate)   •    Refining Director, Europe, Africa & Middle East, ExxonMobil Refining & Supply Company (2008 -         2010) (Affiliate)

Non-profit sector affiliations

•     National Association of Manufacturers (Executive Committee)   •     American Petroleum Institute (Downstream Committee)

94

Victor L. Young, O.C.        St. John’s, Newfoundland and Labrador, Canada Age: 68 Current Position: Nonemployee director Independent Director since April 23, 2002 Normally ineligible for re-election in 2018 Skills and experience: —   Leadership of large     organizations —   Strategy development —   Audit committee financial     expert —   Financial expertise —   Government relations —   Executive compensation Voting Results of 2013 Annual General Meeting: Votes For: 737,699,275 (99.85%) Votes Withheld: 1,080,416 (0.15%) Total Votes: 738,779,691

From November 1984 until May 2001, Mr. Young served as chairman and chief executive officer of Fishery Products International Limited, a frozen seafood products company. He is a director of Royal Bank of Canada and McCain Foods Limited. Mr. Young was appointed an Officer of the Order of Canada in 1996, and is currently the chair of the advisory committee on red tape reduction established by the Government of Canada.

Board and Committee Membership

Attendance in 2013

Imperial Oil Limited board

8 of 8

100%

Audit committee (Chair)

5 of 5

100%

Executive resources committee

10 of 10

100%

Environment, health and safety committee

3 of 3

100%

Nominations and corporate governance committee

4 of 4

100%

Contributions committee

3 of 3

100%

Annual meeting of shareholders

1 of 1

100%

Overall Attendance – 100%

Imperial Oil Limited Equity Ownership (a) (b) (c) (d)

As at

Common  Shares  (% of class)

Deferred  Share Units    (DSU)

Restricted  Stock Units    (RSU)

Total Common    Shares, DSU  and RSU

Total Market Value   of Common Shares,     DSU and RSU ($)

February   13, 2014

21,000

10,384

10,000

41,384

1,956,222

February 13, 2013

20,000 (<0.01%)

9,464

10,500

39,964

1,706,463

Change

1,000

920

(500)

1,420

249,759

Share ownership guidelines have been met.

Exxon Mobil Corporation Equity Ownership (a) (c) (e)

As at

Common Shares   (% of class)

Restricted Stock

Total Common   Shares and Restricted Stock

Total Market Value of     Common Shares and   Restricted Stock ($)

February   13, 2014

0

0

0

0

Public Company Directorships in the Past Five Years

•    Royal Bank of Canada (1991 – Present)   •    Bell Aliant (2002 – 2010)   •    BCE Inc. (1995 – 2010)

Public Board Interlocks

None

Other Positions in the Past Five Years (position, date office held and status of employer)

No other positions held in the last five years

Non-profit sector affiliations

•    Advisory committee on red tape reduction established by the Government of Canada (Chair)

95

Footnotes to Directors Tables on pages 89 through 95:

(a) The information includes the beneficial ownership of common shares of Imperial Oil Limited and shares of Exxon Mobil Corporation, 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 113. The company’s plan for deferred share units for nonemployee directors is described on page 112. The company’s plan for restricted stock units for selected employees is described on page 126.

(c) The numbers for the company’s restricted stock units represent the total of the restricted stock units received in 2007 through 2013 and deferred share units received since directors’ appointment. The numbers for Exxon Mobil Corporation restricted stock include restricted stock and restricted stock units granted under its restricted stock plan which is similar to the company’s restricted stock unit plan.

(d) The value for Imperial Oil Limited common shares, deferred share units, restricted stock units is based on the closing price for Imperial Oil Limited common shares on the Toronto Stock Exchange of $47.27 on February 13, 2014 and $42.70 on February 13, 2013.

(e) The value for Exxon Mobil Corporation common shares and restricted stock is based on the closing price for Exxon Mobil Corporation common shares of $91.43 U.S., which is converted to Canadian dollars at the noon rate of exchange of $1.0980 provided by the Bank of Canada for February 13, 2014.

Director qualification and selection process

The nominations and corporate governance committee is responsible for identifying and recommending new candidates for board nomination. The process for selection is described in paragraph 9(a) of the Board of Directors Charter attached as Appendix B. The committee maintains a list of potential director candidates for future consideration and reviews such list annually.

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. 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 chart on page 102)

— 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 in assessing potential nominees:

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

— providing diversity of viewpoint, individual competencies in business, other areas of endeavour in contributing to the collective experience of the directors, age, gender or regional association.

The nominations and corporate governance committee assesses the work experience and other expertise each existing director possesses and whether each nominee is able to fill any gaps in such experience and expertise. 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.

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When the committee is recommending candidates for re-nomination, it assesses such candidates against the criteria for re-nomination as set out in paragraph 9(b) of the Board of Directors Charter found in Appendix B of this circular. Candidates for re-nomination are expected to not change their principal position or thrust of involvement or regional association that would significantly detract from his or her value as a director of the corporation and are expected to continue to be compatible with the criteria that led to their selection as nominees.

Skills and Experience of the Director Nominees

The current nominees for election as director collectively have experience and expertise required to ensure effective stewardship and governance of the company. The key areas of work experience and skills and experience along with individual involvement in the not-for-profit sector for each of the nominees for election as directors can also be found in each of the directors tables on pages 89 through 95 of this circular.

The table below sets out the particular experience, qualifications, attributes, and skills of each director nominee that led the Board to conclude that such person should serve as a director of the company.

	K.T. Hoeg	R.M. Kruger	J.M. Mintz	D.S. Sutherland	S.D. Whittaker	D.W. Woods	V.L. Young
Leadership of Large Organizations	ü	ü		ü	ü	ü	ü
Operations/ Technical		ü		ü		ü
Project Management	ü	ü				ü
Global Experience	ü	ü	ü	ü	ü	ü
Strategy Development	ü	ü	ü	ü	ü	ü	ü
Audit Committee Financial Expert	ü			ü	ü		ü
Financial Expertise	ü	ü	ü	ü	ü	ü	ü
Government Relations		ü	ü	ü	ü		ü
Academic/ Research			ü
Information Technology					ü
Executive Compensation	ü	ü	ü	ü	ü	ü	ü

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Director orientation, education, development, tenure and performance assessment

Orientation, education and development

The corporate secretary organizes an orientation program for all new directors. In a series of briefings 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, security, information technology management and on critical planning and reserves processes. They also receive a comprehensive board manual which contains a record of historical information about the company, the charters of the board and its committees and other relevant company business information.

Continuing education is provided to board members by regular presentations by management on the main areas of company 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 June 2013, the board visited the Kearl site in Alberta, Canada. The site visit included a tour of the site and the Kearl project opening ceremony. In September, 2013, the board visited Toronto, Ontario. The site visit included a retail site tour and presentations relating to retail strategy. Some of the other continuing education events in 2013, presented to all directors, included a review of corporate governance and regulatory issues, a review of various aspects of risk management, a review of the science of climate change, a review of environmental public policy issues, a review of community and stakeholder engagement, a financing update, a review of crude logistics and an overview of rail operations.

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.

As part of its annual assessment process, the board members are canvassed as to whether there are any additional topics that they would like to see addressed. In addition, the directors meet prior to most regularly scheduled board meetings and this provides an opportunity for informal discussion. In some cases, where senior management is present, these gatherings provide an opportunity for a review of selected topics of interest.

Tenure

Collectively, the seven nominees for election as directors have 51 years of experience on this company’s board. The board charter provides that incumbent directors will not be renominated if they have attained the age of 72, except under exceptional circumstances at the request of the chief executive officer. 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 members of the board of directors and the year they would normally be expected to retire from the board.

Name of Director	Years of service on the board	Year of expected retirement from the board for independent directors
K.T. Hoeg	6 years	2022
R.M. Kruger	1 year	-
J.M. Mintz	9 years	2023
D.S. Sutherland	4 years	2022
S.D. Whittaker	18 years	2019
D.W. Woods	1 year	-
V.L. Young	12 years	2018
Total of 51 years of experience on the board. The average tenure is 7.2 years.

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Board performance assessment

The board and its committees, as well as the performance of the directors, are assessed on an annual basis. In 2013, the directors provided their written response to a series of questions to evaluate the responsibility and effectiveness of the board and its committees. This response formed the basis for a discussion with the nominations and corporate governance committee at its January 2014 meeting to review the effectiveness of the board and its committees. The committee also assesses the company’s response to issues raised in the previous year’s survey. Given the small board size, the directors are able to provide continuous peer performance feedback as required. The chairman, president and chief executive officer also meets with directors to discuss their performance.

Independence of the directors

The board is composed of seven directors, the majority of whom (five out of seven) are independent. The five independent directors are not employees of the company.

The Board determines independence on the basis of the standards specified by Multilateral Instrument 52-110 Audit Committees, the U.S. Securities and Exchange Commission rules and the listing standards of the NYSE MKT LLC, a subsidiary of NYSE Euronext and the New York Stock Exchange. The Board has reviewed relevant relationships between the company and each non-employee director and director nominee to determine compliance with these standards.

Based on the directors’ response 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 was appointed as a director and chairman, president and chief executive officer of the company on March 1, 2013 and not considered to be independent. The board believes that the extensive knowledge of the business of the company and Exxon Mobil Corporation held by R.M. Kruger is beneficial to the other directors and his participation enhances the effectiveness of the board.

D.W. Woods is also a non-independent director as he is an officer of Exxon Mobil Corporation. The company believes that D.W. Woods, 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
K.T. Hoeg		ü
R.M. Kruger	ü		ü	R.M. Kruger is a director and chairman, president and chief executive officer of Imperial Oil Limited effective March 1, 2013
J.M. Mintz		ü
D.S. Sutherland		ü
S.D. Whittaker		ü
D.W. Woods			ü	D.W. Woods is an officer of Exxon Mobil Corporation.
V.L. Young		ü

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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. R.M. Kruger has held these positions since March 1, 2013. 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 8(3) of the Board of Directors Charter attached as Appendix B.

Independent director executive sessions

The executive sessions of the board are 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 eight executive sessions in 2013. 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 five independent directors are members of each committee. D.W. Woods 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 five 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 B of this circular. The charters are reviewed and approved by the board annually. The charters set out the structure, position description for the chair and the process and responsibilities of that committee. The five committees of the board are:

— audit committee,

— executive resources committee,

— environment, health and safety committee,

— nominations and corporate governance committee, and

— contributions committee.

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The following tables provide additional information about the board and its five committees:

Board of Directors
Directors	—    R.M. Kruger (chair) —    K.T. Hoeg —     J.M. Mintz —     D.S. Sutherland —     S.D. Whittaker —     D.W. Woods —     V.L. Young
Number of meetings in 2013	Eight meetings of the board of directors were held in 2013. 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 eight executive sessions in 2013.
Mandate	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 B of this circular.
Highlights of 2013	—    Oversight of the Kearl project. —    Reviewed other long-term growth strategies and projects (Nabiye, Aspen, etc.). —     Reviewed risk management activities. —     Reviewed critical strategic elements affecting shareholder value. —    Strong safety record. —    Kearl site visit and retail site tour.
Role in Risk Management	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 corporate and business 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 seven directors, the majority of whom (five out of seven) are independent. The five independent directors are not employees of the company.

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Audit Committee
Committee Members	—    V.L. Young (chair) —    S.D. Whittaker (vice-chair) —     K.T. Hoeg —     J.M. Mintz —     D.S. Sutherland
Number of meetings in 2013	Five meetings of the audit committee were held in 2013. The committee members met in camera without management present at every meeting and also separately with the internal auditor and the external auditor at all meetings.
Mandate	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, reviewing the adequacy of the company’s insurance program, approving any changes in accounting principles and practices, reviewing the results of monitoring activity under the company’s business ethics compliance program and reviewing senior management’s expense accounts. The formal mandate of the audit committee can be found within the Audit Committee Charter in Appendix B of this circular.
Highlights of 2013	—    Reviewed the scope of PwC audit in light of risks to company. —     Reviewed the interim and annual financial statements and MD&A. —    Reviewed and assessed the results of the internal auditor’s audit program. —     Reviewed and assessed the external auditor plan and fees. —    Reviewed the committee’s mandate and committee self-assessment. —     Reviewed oil and gas royalty framework and current royalty issues.
Financial Expert	The company’s board of directors has determined that 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 MKT LLC.
Role in Risk Management	The audit committee also has an important role in risk management. It annually 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. It reviews financial statements and results of internal and external audit results.
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 MKT LLC, a subsidiary of NYSE Euronext and the New York Stock Exchange.

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Executive Resources Committee
Committee Members	—    K.T. Hoeg (chair) —    V.L. Young (vice-chair) —     J.M. Mintz —     D.S. Sutherland —     S.D. Whittaker —     D.W. Woods None of the members of the executive resources committee currently serves as a chief executive officer of another company.
Number of meetings in 2013	Ten meetings of the executive resources committee were held in 2013. The committee members had eight regular meetings scheduled and held two special meetings by telephone conference.
Mandate	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 B of this circular.
Highlights	—    Continued focus on succession planning for senior management positions. —     Appointment of chairman, president and chief executive officer position. —    Appointment of two vice-president and two officer positions. —     Reviewed human resources strategic priorities and knowledge transfer activities within organization.
Committee members relevant skills and experience	Ms. Hoeg, Ms. Whittaker, Mr. Woods, Mr. Sutherland and Mr. Young have 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. Ms. Hoeg, Mr. 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 Management	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.W. Woods, 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 Toronto Stock Exchange and the NYSE MKT 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. Woods as a related director and independent of management and who may participate as a member of the company’s executive resources committee. Mr. Woods’ 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.

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Environment, Health and Safety Committee
Committee Members	—    J.M. Mintz (chair) —    D.S. Sutherland (vice-chair) —     K.T. Hoeg —     S.D. Whittaker —     D.W. Woods —     V.L. Young
Number of meetings in 2013	Three meetings of the environment, health and safety committee were held in 2013.
Mandate	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 in this area. The formal mandate of the environment, health and safety committee can be found within the Environment, Health and Safety Committee Charter in Appendix B of this circular.
Highlights	—    Incident and managing systems performance review. —     Emissions performance review. —     Environmental public policy issues review including developments in climate change policy and science
Role in Risk Management	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.W. Woods.

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Nominations and Corporate Governance Committee
Committee Members	—    S.D. Whittaker (chair) —    J.M. Mintz (vice-chair) —     K.T. Hoeg —     D.S. Sutherland —     D.W. Woods —     V.L. Young
Number of meetings in 2013	Four meetings of the nominations and corporate governance committee were held in 2013.
Mandate	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 B of this circular.
Highlights	—    Two reviews of corporate governance topics. —    Reviewed non-employee director compensation. —     Reviewed watch list of potential directors. —     Approved revisions to slate of director nominees. —    Approved statement of corporate governance practices. —     Reviewed results from the survey of board effectiveness. —    Board and committee charter revisions.
Role in Risk Management	The nominations and corporate governance committee manages risk by implementing an effective program for corporate governance.
Independence	The members of the nominations and corporate governance committee are independent, with the exception of D.W. Woods, 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 Toronto Stock Exchange and the NYSE MKT 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. Woods 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. Woods’ 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.

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Contributions Committee
Committee Members	—    D.S. Sutherland (chair) —    K.T. Hoeg (vice-chair) —     R.M. Kruger —     J.M. Mintz —     S.D. Whittaker —     D.W. Woods —     V.L. Young
Number of meetings in 2013	Three meetings of the contributions committee were held in 2013.
Mandate	The role of the contributions committee is to oversee all of the company’s community investment activities, including charitable donations which are presently made through the Imperial Oil Foundation. The formal mandate of the contributions committee can be found within the Contributions Committee Charter in Appendix B of this circular.
Highlights	—    $16 million in community investment across Canada, with a focus on contribution programs supporting communities in which the company operates, and a focus on education in math, science and technology and Aboriginal community initiatives. —    Launch of a signature math and science initiative (STEM) with Scouts Canada. —     Funding of major grants in Fort Chipewyan and Fort McKay, Alberta. —    Committee review of the company’s approach to strategic philanthropy, contributions model and the structure of the Imperial Oil Foundation. —     Committee visit to Kearl site for opening ceremonies and meeting with local community groups.
Independence	The majority of the members of the contributions committee are independent (five out of seven) with the exception of R.M. Kruger and D.W. Woods.

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Committee memberships of the directors

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

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

(a) Not independent directors.

(b) All members of the audit committee are independent and financially literate within the meaning of Multilateral Instrument 52-110 Audit Committees and the listing standards of the NYSE MKT LLC.

(c) Audit committee financial experts under US regulatory requirements.

Number of meetings and director attendance in 2013

The chart below shows the number of board, committee and annual meetings held in 2013.

Number of meetings

Board or committee	Number of meetings held in 2013
Imperial Oil Limited board	8
Audit committee	5
Executive resources committee (a)	10
Environment, health and safety committee	3
Nominations and corporate governance committee	4
Contributions committee	3
Annual meeting of shareholders	1

(a) There were eight regularly scheduled meetings and two special meetings of the executive resources committee. The special committee meetings were held by telephone conference.

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Director attendance

The following chart provides a summary of the attendance record of each of the directors in 2013. The attendance record of each director nominee is also set out in his or her biographical information on pages 89 through 95. The attendance charts also provide 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
K.T. Hoeg	8 of 8	5 of 5	10 of 10   (chair)	3 of 3	4 of 4	3 of 3	1 of 1	34 of 34	100%
R.M. Kruger	6 of 6	-	-	-	-	2 of 2	1 of 1	9 of 9	100%
J.M. Mintz	8 of 8	5 of 5	10 of 10	3 of 3 (chair)	4 of 4	3 of 3	1 of 1	34 of 34	100%
D.S. Sutherland	8 of 8	5 of 5	10 of 10	3 of 3	4 of 4	3 of 3 (chair)	1 of 1	34 of 34	100%
S.D. Whittaker	8 of 8	5 of 5	10 of 10	3 of 3	4 of 4 (chair)	3 of 3	1 of 1	34 of 34	100%
D.W. Woods	6 of 6	-	6 of 6	2 of 2	2 of 2	2 of 2	1 of 1	19 of 19	100%
V.L. Young	8 of 8	5 of 5 (chair)	10 of 10	3 of 3	4 of 4	3 of 3	1 of 1	34 of 34	100%
Percentage by committee	100%	100%	100%	100%	100%	100%	100%	200/200	Overall  attendance  percentage  100%

Attendance for directors who ceased to be directors in 2013

The following chart shows the attendance record of B.H. March, who resigned from his position as chairman, president and chief executive officer on March 1, 2013 and the attendance record of R.C. Olsen, who did not stand for re-election as a director on April 25, 2013.

B.H. March (director until March 1, 2013)
Board and Committee Membership	Attendance in 2013
Imperial Oil Limited board		2 of 2	100%
Contributions committee		1 of 1	100%
R.C. Olsen (director until April 25, 2013)
Board and Committee Membership	Attendance in 2013
Imperial Oil Limited board		2 of 2	100%
Executive resources committee		4 of 4	100%
Environment, health and safety committee		1 of 1	100%
Nominations and corporate governance committee		2 of 2	100%
Contributions committee		1 of 1	100%

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Share ownership guidelines

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, deferred share units 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 interest of board members with the interests of all other shareholders. The chart below shows the shareholdings of the independent directors and the chairman, president and chief executive officer of the company as of February 13, 2014, the record date of the management proxy circular.

Director	Director       since	Amount acquired since last report   (February 14,     2013 to February 13, 2014)	Total holdings (includes common shares, deferred share units and   restricted stock     units)	Total at-risk     value of total holdings (a) ($)	Minimum   shareholding     requirement	Minimum requirement met or date required to achieve minimum   requirement
K.T. Hoeg	May 1, 2008	4,415	27,093	1,280,686	15,000	Minimum requirement met
R.M. Kruger	March 1, 2013	91,400	91,400	4,320,478	Five times base salary	March 1, 2016
J.M. Mintz	April 21, 2005	2,462	25,840	1,221,457	15,000	Minimum requirement met
D.S. Sutherland	April 29, 2010	4,343	63,736	3,012,801	15,000	Minimum requirement met
S.D. Whittaker	April 19, 1996	1,591	62,533	2,955,935	15,000	Minimum requirement met
V.L. Young	April 23, 2002	1,420	41,384	1,956,222	15,000	Minimum requirement met
Total accumulated value of directors’ holdings			311,986	14,747,578

(a) The amount shown in the column “Total at-risk value of total holdings” is equal to the “Total holdings” multiplied by the closing price of the company’s shares on February 13, 2014 ($47.27).

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Other public company directorships

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

Name of director or             nominee	Other reporting issuers   of which director is also a director	Type of company	Stock Symbol: Exchange	Committee appointments
K.T. Hoeg	Sun Life Financial Inc.	Financial services - Insurance	SLF: TSX, NYSE, Other	Management resources committee (Chair)
				Risk review committee
	Shoppers Drug Mart Corporation	Merchandising - specialty stores	SC:TSX	Nominating and governance committee (Chair)
	Canadian Pacific Railway Limited	Transportation and environmental services	CP: TSX, NYSE	Corporate governance and nominating committee (Chair)
				Management resources and compensation committee
	Canadian Pacific Railway Company	Transportation and environmental services	CPRY: NYSE, LSE	Corporate governance and nominating committee (Chair)
				Management resources and compensation committee
R.M. Kruger	--	--	--	--
J.M. Mintz	Morneau Shepell Inc.	Human resources consulting	MSI: TSX	Compensation, nominating and corporate governance committee
D.S. Sutherland	GATX Corporation	Commercial rail vehicles and aircraft engines – shipping	GMT: NYSE	Lead director
	United States Steel Corporation	Iron and steel	X: NYSE	Chairman of the board
S.D. Whittaker	--	--	--	--
D.W. Woods	--	--	--	--
V.L. Young	Royal Bank of Canada	Financial services - banks and trusts	RY: TSX, NYSE, Other	Audit committee (Chair)
				Risk committee

Interlocking directorships

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

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Director compensation

Director compensation discussion and analysis

Philosophy and objectives

Director compensation elements are designed to:

— ensure alignment with long-term shareholder interests;

— provide motivation to promote sustained improvement in the company’s business performance and shareholder value;

— ensure the company can attract and retain outstanding director candidates who meet the selection criteria outlined in section 9 of the Board of Directors Charter found within Appendix B of this circular;

— recognize the substantial time commitments necessary to oversee the affairs of the company; and

— support the independence of thought and action expected of directors.

Nonemployee director compensation levels are reviewed by the nominations and corporate governance committee each year, and resulting recommendations are presented to the full board for approval.

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 112.

Compensation decision making process and considerations

The nominations and corporate governance committee relies on market comparisons with a group of 23 major Canadian companies with national and international scope and complexity. The company draws its nonemployee directors from a wide variety of industrial sectors, so 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 23 comparator companies included in the benchmark sample are as follows:

Comparator companies for nonemployee directors
Bank of Montreal	Cenovus Energy Inc.	Sun Life Financial Inc.
Bank of Nova Scotia	EnCana Corporation	Suncor Energy Inc.
BCE Inc.	Husky Energy Inc.	Talisman Energy Inc.
Bombardier Inc.	Manulife Financial Corporation	TELUS Inc.
Canadian Imperial Bank of Commerce	Nexen Inc.	Thomson Reuters Corporation
Canadian National Railway Company	Potash Corporation	The Toronto-Dominion Bank
Canadian Natural Resources Limited	Power Financial Corporation	TransCanada Corporation
Canadian Pacific Railway Limited	Royal Bank of Canada

Independent consultants

Following the nominations and corporate governance committee decision to use an external research firm to assemble the comparator data for the prior year in the second quarter of each year so as to enable the committee to determine compensation for the upcoming July 1^st – June 30^th twelve month period, the committee retained Meridian Compensation Partners (“Meridian”), an independent consultant, to provide an assessment of competitive compensation and market data for directors’ compensation which assisted the committee in making a compensation recommendation for the company’s directors. The professional fees and expenses for this service totaled $27,429.

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.

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Director compensation details and tables

Compensation Details

Annual retainer

The annual retainer for board memberships was $110,000 per year. The nonemployee directors were also paid $20,000 for membership on all board committees. Additionally, each board committee chair received a retainer of $10,000 for each committee chaired. Nonemployee directors were not paid a fee for attending board and committee meetings for each of the eight regularly-scheduled meetings. However, they were eligible to receive a fee of $2,000 per board or committee meeting occurring on any other day. Two executive resources committee meetings occurred outside of the eight regularly-scheduled meeting days.

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 annual retainer for board membership, annual retainer for committee membership and annual retainer for committee chair, in the form of deferred share units.

The following table shows the portion of the annual retainer for board membership, annual retainer for committee membership and annual retainer for committee chair which each nonemployee director elected to receive in cash and deferred share units in 2013.

Director	Election for 2013 director   fees in cash (%)	Election for 2013 director fees in   deferred share units (%)	Election Term in 2013
K.T. Hoeg	0	100	Jan - Dec
J.M. Mintz	50	50	Jan - Mar
	0	100	Apr - Dec
D.S. Sutherland	0	100	Jan - Dec
S.D. Whittaker	50	50	Jan - Dec
V.L. Young	75	25	Jan - Dec

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.

A nonemployee director may only exercise these deferred share units after 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.

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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. Restricted stock units are awarded annually 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 can elect to receive one common share for each unit or a cash payment for the units to be exercised on the seventh anniversary of the date of grant of the restricted stock units. The vesting periods are not accelerated upon separation or retirement from the board, except in the event of death. The restricted stock unit plan is described in more detail on page 126. In 2013, each nonemployee director received a grant of 2,000 restricted stock units.

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.

Other reimbursement

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

Components of director compensation

The following table sets out the details of compensation paid to the nonemployee directors for 2013.

Director	Annual   retainer for   board   membership   ($)	Annual   retainer for   committee   membership   ($)	Annual   retainer for   committee   chair   ($)	Restricted   stock units   (RSU)   (#)	Fee for board and  committee meetings not  regularly scheduled		Total   fees paid   in cash   ($)   (a)	Total  value of  deferred  share units  (DSU)  ($)  (b)	Total   value of   restricted   stock   units   (RSU)   ($)   (c)	All other   compen-   sation   ($)   (d)	Total compen- sation ($)
					Number of  non-  regularly  scheduled  meetings  attended  (#)	Fee  ($2,000 x  number of  non-  regularly  scheduled  meetings  attended)  ($)
K.T. Hoeg	110,000	20,000	10,000 (ERC)	2,000	2	4,000	4,000	140,000	91,780	11,574	247,354
J.M. Mintz	110,000	20,000	10,000 (EH&S)	2,000	2	4,000	21,500	122,500	91,780	12,101	247,881
D.S. Sutherland	110,000	20,000	10,000 (CC)	2,000	2	4,000	4,000	140,000	91,780	7,400	243,180
S.D. Whittaker	110,000	20,000	10,000 (N&CG)	2,000	2	4,000	74,000	70,000	91,780	25,639	261,419
V.L. Young	110,000	20,000	10,000 (AC)	2,000	2	4,000	109,000	35,000	91,780	9,915	245,695

(a) “Total fees paid in cash” is the portion of the “Annual retainer for board membership”, “Annual retainer for committee membership” and “Annual retainer for committee chair” which the director elected to receive as cash, plus the “Fee for board and committee meetings not regularly scheduled”. This amount is reported as “Fees earned” in the Director compensation table on page 114.

(b) “Total value of deferred share units” is the portion of the “Annual retainer for board membership”, “Annual retainer for committee 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 112. This amount plus the “Total value of restricted stock units” amount is shown as “Share-based awards” in the Director compensation table on page 114.

(c) 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 $45.89.

(d) Amounts under “All other compensation” consist of dividend equivalent payments on unexercised 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 2013, K.T. Hoeg received $3,720 in dividend equivalent payments on restricted stock units and additional deferred share units valued at $7,854 in lieu of dividends on deferred share units. J.M. Mintz received $5,100 in dividend equivalent payments on restricted stock units and additional deferred share units valued at $6,321 in lieu of dividends on deferred share units. D.S. Sutherland received $2,640 in dividend equivalent payments on restricted stock units and additional deferred share units valued at $4,760 in lieu of dividends on deferred share units. S.D. Whittaker received $5,100 in dividend equivalent payments on restricted stock units and additional deferred share units valued at $20,539 in lieu of dividends on deferred share units. V.L. Young received $5,100 in dividend equivalent payments on restricted stock units and additional deferred share units valued at $4,815 in lieu of dividends on deferred share units.

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Compensation tables

The following table summarizes the compensation paid, payable, awarded or granted for 2013 to each of the nonemployee directors of the company.

Name (a)	Fees     earned     ($) (c)	Share-     based     awards   ($) (d)	Option-     based     awards   ($)	Non-equity   incentive plan   compensation  ($)	Pension     value   (#)	All other     compensation   ($) (e)	Total     ($)
K.T. Hoeg (b)	4,000	231,780	-	-	-	11,574	247,354
J.M. Mintz (b)	21,500	214,280	-	-	-	12,101	247,881
D.S. Sutherland (b)	4,000	231,780	-	-	-	7,400	243,180
S.D. Whittaker (b)	74,000	161,780	-	-	-	25,639	261,419
V.L. Young (b)	109,000	126,780	-	-	-	9,915	245,695

(a) As directors employed by the company or Exxon Mobil Corporation in 2013, R.M. Kruger and D.W. Woods did not receive compensation for acting as directors.

(b) Starting in 1999, the nonemployee directors have been able to receive all or part of their directors’ fees in the form of deferred share units.

(c) Represents all fees awarded, earned, paid or payable in cash for services as a director, including retainer fees, committee, chair and meeting fees.

(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. The dollar value of deferred share units shown is the value of the portion of the “Annual retainer for board membership”, “Annual retainer for committee membership” and “Annual retainer for committee chair” which the director elected to receive as deferred share units as noted on page 112.

(e) Amounts under “All other compensation” consist of dividend equivalent payments on unexercised 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 2013, K.T. Hoeg received $3,720 in dividend equivalent payments on restricted stock units and additional deferred share units valued at $7,854 in lieu of dividends on deferred share units. J.M. Mintz received $5,100 in dividend equivalent payments on restricted stock units and additional deferred share units valued at $6,321 in lieu of dividends on deferred share units. D.S. Sutherland received $2,640 in dividend equivalent payments on restricted stock units and additional deferred share units valued at $4,760 in lieu of dividends on deferred share units. S.D. Whittaker received $5,100 in dividend equivalent payments on restricted stock units and additional deferred share units valued at $20,539 in lieu of dividends on deferred share units. V.L. Young received $5,100 in dividend equivalent payments on restricted stock units and additional deferred share units valued at $4,815 in lieu of dividends on deferred share units.

Total compensation paid to non-employee directors
Year	Amount
2009	$1,110,500
2010	$1,089,012
2011	$ 1,149,625
2012	$1,176,166
2013	$1,245,529

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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, 2013 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)
K.T. Hoeg	-	-	-	-	27,093	1,274,455
J.M. Mintz	-	-	-	-	24,840	1,168,474
D.S. Sutherland	-	-	-	-	18,736	881,341
S.D. Whittaker	-	-	-	-	53,183	2,501,728
V.L. Young	-	-	-	-	20,384	958,863

(a) As directors employed by the company or Exxon Mobil Corporation in 2013, R.M. Kruger and D.W. Woods did not receive compensation for acting as directors.

(b) Represents restricted stock units and deferred share units held as of December 31, 2013.

(c) Value is based on the closing price of the company’s shares on December 31, 2013, which was $47.04.

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 2013.

Name   (a)	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   ($)
K.T. Hoeg (b)	-	45,980	-
J.M. Mintz (c)	-	113,825	-
D.S. Sutherland (b)	-	45,980	-
S.D. Whittaker (c)	-	113,825	-
V.L. Young (c)	-	113,825	-

(a) As directors employed by the company or Exxon Mobil Corporation in 2013, R.M. Kruger and D.W. Woods did not receive compensation for acting as directors.

(b) Represents restricted stock units granted in 2010 and vesting in 2013.

(c) Represents restricted stock units granted in 2006 and 2010, which vested in 2013.

(d) 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 exercise date and the four consecutive trading days immediately prior to the exercise date.

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IV. Company executives and executive compensation

Named executive officers of the company

The named executive officers of the company at the end of 2013 were:

Name	Age (as of February 13,   2014)	Current Position (date office held)	Other Positions in the Past Five Years (position, date office held and status of employer)
Rich M. Kruger Calgary, Alberta, Canada	54	Chairman, president and chief executive officer (March 1, 2013 - Present)	• Vice-president, Exxon Mobil Corporation and President, ExxonMobil Production Company (2008 - 2013) (Affiliate)
Paul J. Masschelin Calgary, Alberta, Canada	59	Senior vice-president, finance and administration, and controller (2012 – Present)	• Senior vice-president, finance and administration, and treasurer, (2010 - 2012) • Controller, refining & supply and research & engineering, ExxonMobil Fuels Marketing Company (2007 - 2010) (Affiliate)
T. Glenn Scott Calgary, Alberta, Canada	50	Senior vice-president, upstream (2010 – Present)	• President, ExxonMobil Canada Limited and Production manager, ExxonMobil Canada East, (2006 – 2010) (Affiliate)
Brian W. Livingston Calgary, Alberta, Canada	59	Vice-president and general counsel (October 1, 2013 – December 31, 2013)	• Vice-president, general counsel and corporate secretary (August 1, 2004 – September 30, 2013)
Bradley G. Merkel Calgary, Alberta, Canada	51	Vice-president, fuels, lubricants and specialties marketing (October 1, 2013 – Present)	• Vice-president, general manager fuels marketing (2011 - 2013) • Manager, industrial and wholesale sales (2006 - 2011)

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Other executive officers of the company

Name	Age (as of February 13,   2014)	Current Position (date office held)	Other Positions in the Past Five Years (position, date office held and status of employer)
David G. Bailey Calgary, Alberta, Canada	44	Treasurer (April, 2013 – Present)	• Manager, Dallas treasury centre Exxon Mobil Corporation (2010 - 2013) (Affiliate) • Advisor, investor relations Exxon Mobil Corporation (2007 - 2010) (Affiliate)
John W. Blowers Calgary, Alberta, Canada	56	Refining manufacturing manager, Imperial Oil Limited & North America manufacturing excellence manager, Exxon Mobil Corporation (July, 2013 – Present)	• Refinery manager, Fawley UK Exxon Mobil Corporation (2010 - 2013) (Affiliate) • Advisor, refinery operations, Singapore Exxon Mobil Corporation (2008 - 2010) (Affiliate)
Marvin E. Lamb Calgary, Alberta, Canada	58	Director, corporate tax (2001 – Present)	No other positions held in the last five years
Lara H. Pella Calgary, Alberta, Canada	44	Assistant general counsel and corporate secretary (October, 2013 – Present)	• Assistant general counsel (2010 - 2013) • Legal manager Penn West Petroleum Ltd. (2008 - 2010)

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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 and 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. It is a role the committee executes throughout the year to facilitate increasing shareholder value.

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-term vesting periods, risk of forfeiture and integration 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 with comparator companies, appropriate risk assessment and risk management practices, sound governance principles, and linkage to 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.

2013 Business Performance Results

In addition to individual performance, the committee also considered the following business results:

— strong results in the areas of safety, health and environment;

— satisfactory management of risk through effective business controls, as confirmed by independent audit;

— net income of approximately $2.8 billion, down 25 percent versus last year;

— total shareholder return of approximately 11 percent, with a ten-year annual average of approximately 10 percent;

— industry-leading return on average capital employed of approximately 13 percent, with an average of approximately 26 percent since the beginning of 2000;

— start-up of the Kearl oil sands mining project, the largest capital investment in the company’s history;

— over 80 percent of capital invested in company growth, including the Kearl and Nabiye projects and the acquisition of Celtic;

— $407 million distributed to shareholders as dividends in 2013; and

— continued AAA rating from Standard & Poor’s.

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Collectively these factors had an impact on 2013 compensation decisions for the named executive officers. The individual committee members, through their experience in compensation 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 to the company’s compensation policies and practices.

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 business model. The committee has recommended to the board that the CD&A be included in the company’s management proxy circular for the 2014 annual and special 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

J.M. Mintz

D.S. Sutherland

S.D. Whittaker

D.W. Woods

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Compensation discussion and analysis

Index	Topic	Page
Overview	—   Business environment —   Key business strategies —   Key elements of the compensation program —    Management of risk —   Other supporting compensation and staffing practices —   Hedging policy —   Business performance and basis for compensation —    Succession planning	121     121     121     121     123     123     123     123
Compensation program	—   Career orientation —   Base salary —   Annual bonus —    Long-term incentive compensation - Restricted stock units - Exercise of restricted stock units - Amendments to the restricted stock unit plan - Forfeiture risk —    Retirement benefits - Pension plan benefits - Savings plan benefits	124     125     125     126     127     127     128     128     128     129
Compensation considerations	—   Benchmarking —    Comparator companies —    Analytical tools – Compensation summary sheets —   2013 named executive officer compensation assessment —   2013 chief executive officer compensation assessment —   Pay awarded to other named executive officers —   Independent consultant —    Performance graph	129     129     130     131     132     132     133     133
Executive compensation tables and narratives	—   Summary compensation table —    Outstanding share-based awards and option-based awards table —   Incentive plan awards table for named executive officers – Value vested during the year —   Proceeds realized in 2013 from compensation awards granted in prior years —   Equity compensation plan information —   Pension plan benefits table —   Status of prior long-term incentive compensation plans	134     136     137     138     139     139     140

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Overview

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 approach and supports key business strategies as outlined below.

Business environment

— Long investment horizons;

— Large capital investments;

— Complex operating and financial risks;

— National scope of company operations; and

— Commodity-based cyclical product prices.

Key business strategies

— Personnel safety and operational excellence;

— Grow profitable sales volumes;

— Disciplined, selective and long-term focus on improving the productivity of the company’s asset mix; and

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

Focus on these key business strategies is a company priority and supports 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 environment and support key business strategies are:

— long-term career orientation with high individual performance standards (see page 124);

— base salary that rewards individual performance and experience (see page 125);

— annual bonus grants to select executives based on company performance, as well as individual performance and experience (see page 125);

— payment of a large portion of executive compensation in the form of restricted stock units with lengthy vesting periods and risk of forfeiture (see page 126); and

— retirement benefits (pension and savings plans) that provide for financial security after employment (see pages 128 through 129).

Management of risk

The company operates in an industry environment in which excellence in risk management is critical. For this reason, the company places a high premium on effective risk management, including safety, security, health, environmental, financial and reputational risks. The long-term orientation the company takes and risk of forfeiture in the compensation program reinforce this priority.

The company’s success in managing risk over multiple year periods is achieved through emphasis on flawless execution through a disciplined management framework called the Operations Integrity Management System (OIMS), which has been in place since the early 1990’s. The OIMS framework establishes common expectations for addressing risks inherent in our business and takes priority over other business and financial objectives. The compensation program is designed to ensure that senior executives have a strong financial incentive to protect the safety and security of our employees and the communities and environment in which we operate, to effectively manage risk and operate the business with effective business controls, as well as to create value for company shareholders through their actions by increasing shareholder return, net income, return on capital employed, and advancing the long-term strategic direction of the company.

The company also has strong controls and compliance programs to manage other types of risk, including fraud, regulatory compliance and litigation risks. These controls and compliance programs are reinforced by the same features of the compensation program. The influence of commodity prices on company compensation is indirect because it is limited to only one element of compensation via its effect on earnings per share or share price. The compensation program is composed of competitive salaries and performance-based incentives as the primary instruments to attract, develop and retain key personnel.

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There is no material adverse risk resulting from how the company pays its executives; to the contrary, the compensation programs and practices are designed to encourage appropriate risk assessment and risk management. The underlying design and principles inherent in the company’s compensation program, which are primarily long-term focused, discourage taking adverse risks.

The design of the compensation program helps reinforce these priorities and ensures that the compensation granted over multiple years and the shareholding net worth of senior executives are linked to the performance of the company’s stock and resulting shareholder value.

The key design features of our compensation program that discourage inappropriate risk taking are summarized below and are also described in more detail under various sections of this proxy statement.

Compensation components

The largest percentage of total compensation (excluding compensatory pension value) to senior executives is in the form of restricted stock units and an annual bonus. In the judgment of the committee, this mix of short 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 short and long- term incentives, ensure continued relevance of this mix and ongoing applicability for the company.

Restricted stock units

— Long holding periods - As noted above, 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 typically far exceed the holding periods of competitor stock programs. The lengthy holding periods are tailored to the company’s business model. The vesting provisions of the stock program are as follows:

— to the chairman, president and chief executive officer:

• 50 percent of each grant vests on the fifth anniversary of the date of grant; and

• the balance vests on the tenth anniversary of the date of grant or the date of retirement, whichever is later; and

— to all other senior executives:

• 50 percent of each grant vests on the third anniversary of the date of grant; and

• the balance vests on the seventh anniversary of the date of grant.

— 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.

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 and further discourages inappropriate risk taking.

— 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. These claw-back and forfeiture provisions also apply if an executive resigns or engages in detrimental activity.

Common programs

All executives of the company, including the named executive officers, participate in common programs (the same salary, incentive and retirement programs). Inappropriate risk taking is discouraged at all levels of the company through similar compensation design features and allocation of awards. Within these programs, the compensation of executives is differentiated based on individual performance assessment, level of responsibility and individual experience. All executives on loan assignment from Exxon Mobil Corporation also participate in common programs, which are administered by Exxon Mobil Corporation. The executive resources committee reviews and approves compensation recommendations for each named executive officer prior to implementation.

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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.

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 two elements: financial planning for senior executives and the selective use of club memberships which are largely tied to building business relationships.

— No tax assistance is provided by the company on any elements of executive officer compensation or perquisites other than relocation. The 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 distribution to shareholders;

— operating performance of the upstream, downstream and chemical segments; and

— effectiveness of actions that support the long-term strategic direction of the company.

The appraisal process involves comparative assessment of employee performance using a standard process throughout the organization and at all levels. This process 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. The decision-making process 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, which strengthens continuity of leadership at all levels, including that of the most senior positions. 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 ExxonMobil. This is an in-depth review of succession plans, including plans to address gaps, if any, for key executives. The chairman, president and chief executive officer also discusses the strengths and development needs of key succession candidates and progress each year. This provides the board an opportunity to confirm a pipeline of key 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

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 reflects this on-going strategy. Their career service ranges from approximately 28 to 36 years.

Consistent with the company’s long-term career orientation, high-performing executives typically earn substantially higher levels of compensation in the final years of their careers than in the earlier years. This pay practice reinforces the importance of a long-term focus in making decisions that are key to business success.

The compensation program emphasizes individual experience and sustained performance; executives holding similar positions may receive substantially different levels of compensation.

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. The salary program in 2013 maintained the company’s desired competitive orientation in the marketplace. 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 benefit calculation. Thus, the level of retirement benefits is also performance-based, like other elements of compensation.

Annual bonus

Annual bonuses were granted to fewer than 90 executives to reward their contributions to the business during the past year. The bonus program is established annually by the executive resources committee based on financial and operating performance, and can be highly variable depending on these results. This bonus reflects the combined value at grant of annual cash bonus and earnings bonus units.

In establishing the annual bonus program and individual executive awards, the executive resources committee:

— considers input from the chairman, president and chief executive officer on the performance of the company and from the company’s internal compensation advisors regarding compensation trends as obtained from external consultants;

— considers total shareholder return, annual net income of the company and the other key business performance indicators as described on page 123;

— 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; and

— considers a comparison with the majority shareholder.

The cost of the 2013 annual bonus program was $9.5 million versus $13.2 million in 2012. The change in the amount of the annual bonus program reflects a decrease in corporate earnings of 25 percent. The company’s net income for 2013 was approximately $2.8 billion; return on average capital employed was approximately 13 percent. Excluding capital for assets under construction, return on average capital employed would be greater than 20 percent. Changes in individual cash bonus awards vary depending on each executive’s performance assessment.

The annual bonus program incorporates unique elements to further reinforce retention and recognize performance. Awards under this program are generally delivered as:

— 50 percent cash paid in the year of grant; and

— 50 percent earnings bonus units with a delayed payout based on cumulative earnings performance.

The cash component is intended to be a short-term incentive, while the earnings bonus unit plan is intended to be a medium-term incentive. Earnings bonus units are made available to eligible executives to promote individual contribution to sustained improvement in the company’s business performance and shareholder value. Earnings bonus units are generally equal to and granted in tandem with cash bonuses.

Specifically, 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 is achieved or within three years, whichever is earlier. For earnings bonus units granted in 2013, the maximum settlement value (trigger) or cumulative earnings per share required for payout remained at $3.25. 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 continuous improvement in business performance.

If cumulative earnings per share do not reach $3.25 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 period.

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 adjusted to reflect the company’s performance relative to its comparators. The earnings bonus units are designed such that the timing and the amount of the payout is tied to the rate of the company’s future earnings. The amount of the award, once vested, will never exceed the original grant value. In so doing, the delayed portion of the annual bonus, that is the earnings bonus unit, puts part of the annual bonus at risk of forfeiture and thus reinforces the performance basis of the annual bonus grant.

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Prior to payment, the earnings bonus units may be forfeited if the executive leaves the company before age 65, or engages in activity that is detrimental to the company.

Since November 2011, for executives, the entire annual bonus is subject to a forfeiture and claw-back feature if there is a material negative restatement in the financial results of the company. This claw-back feature may require the executives to forfeit some or all of any unvested earnings bonus units granted in the three years prior to the restatement. Executives may be required to repay to the company any cash amounts received from bonus or earnings bonus units that were paid out five years prior to the restatement. In addition, the forfeiture and claw-back provisions also apply to the annual bonus in the event an executive engages in detrimental behavior during employment or up to two years after leaving the company, including working for a competitor.

Long-term incentive compensation – Restricted stock units

The company’s only long-term incentive compensation plan is a restricted stock unit plan, in place since December 2002. The current plan’s vesting periods are as follows:

— to the chairman, president and chief executive officer:

• 50 percent of each grant vests on the fifth anniversary of the date of grant; and

• the balance vests on the tenth anniversary of the date of grant or the date of retirement, whichever is later; and

— to all other senior executives:

• 50 percent of each grant vests on the third anniversary of the date of grant; and

• the balance vests on the seventh anniversary of the date of grant.

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 131. 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 near-term performance is deemed to have changed significantly at time of grant. 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.

The vesting periods, which are greater than those in use by most 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 return on the company’s stock realized by shareholders. The vesting period for restricted stock unit awards is not subject to acceleration, except in the case of death. 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 subsequent to retirement. The value of this compensation is at risk in the event that their decisions as senior executives 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, supports alignment with the long-term interests of shareholders, and reinforces retention objectives.

In 2013, the executive resources committee determined, after an analysis of the competitive orientation of the company’s restricted stock unit program, that current levels of restricted stock units continue to be appropriate. In 2013, 670 recipients, including 83 executives, were granted 1,654,540 restricted stock units.

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Exercise of restricted stock units

Restricted stock units will be exercised pursuant to the vesting provisions described in the previous section. Restricted stock units cannot be assigned.

Upon vesting, each restricted stock unit entitles the recipient 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 will be exercised 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 to be exercised 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 to be exercised on the vesting date. During the restricted period, the recipient will also receive cash payments equivalent to the cash dividends paid to holders of regular common stock.

As of February 13, 2014 there are 4,232,417 common shares that may be issued in the future with respect to outstanding restricted stock units that represent about 0.50 percent of the company’s currently outstanding common shares. The company’s directors, officers and vice-presidents as a group hold approximately 9 percent of the unexercised restricted stock units that give the recipient the right to receive common shares that represent about 0.04 percent of the company’s outstanding common shares. Currently, the maximum number of common shares that any one person may receive from the exercise of restricted stock units is 223,750 common shares, which is about 0.03 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. T.G. Scott and P.J. Masschelin hold Exxon Mobil Corporation restricted stock granted in 2009 and previous years, as well as the company’s restricted stock units granted since 2010. R.M. Kruger also holds Exxon Mobil Corporation restricted stock granted in 2012 and previous years, as well as the company’s restricted stock units granted in 2013.

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 exercised. The choice of which vesting period provision to use will be at the discretion of the company.

— Set out which amendments in the future will require shareholder approval, and which amendments will only require director approval and to set an exercise price based on the weighted average price of the company’s shares on the exercise date and the four consecutive trading days immediately prior to the exercise date.

As of November 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.

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Forfeiture risk

Restricted stock units are subject to forfeiture if:

— A recipient retires or terminates employment with the company. 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.

— During employment or during the period of two years after the termination of employment, the recipient, without the consent of the company, engaged in any business that was in competition with the company or otherwise engaged in any activity that was detrimental to the company.

Retirement benefits

Named executive officers participate in the same pension plan, including supplemental pension arrangements outside the registered plan, as other employees, except that R.M Kruger, P.J. Masschelin and T.G. Scott, participate in the Exxon Mobil Corporation pension plans (both tax-qualified and non-qualified).

Pension plan benefits

The estimated annual benefits that would be payable to each named executive officer of the company upon retirement under the company’s pension plan and the supplemental pension arrangements, or under Exxon Mobil Corporation’s tax-qualified and non-qualified pension plans, and the change in the defined benefit obligation for each named executive officer of the company in 2013 can be found in the pension plan benefits table beginning on page 139.

The current version of the company’s defined benefit plan has been in place since 1998 and is available to all employees including executives. Predecessor plans have been in place since 1919, including a historic provision with a 1.6 percent accrual formula that was closed to new participants at the end of 1997. All named executive officers, except those who are participants in Exxon Mobil Corporation’s plans (R.M Kruger, P.J. Masschelin and T.G. Scott), are participants of this historic 1.6 percent provision of the plan. It can provide an annual benefit of 1.6 percent of final three-year average earnings per each year of service, with a partial offset for applicable government pension benefits. An employee may elect to forego three of the six percent of the company’s matching contributions to the savings plan under one of the options of that plan (except for R.M. Kruger, P.J. Masschelin and T.G. Scott), to receive additional pension value equal to 0.4 percent of the employee’s final three-year average earnings, multiplied by the employee’s years of service, while foregoing such company contributions.

The company’s supplemental pension arrangements provide an annual benefit of 1.6 percent of final average bonus earnings times years of service and also address any portions of the above formula 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. Earnings, for the purpose of the company’s registered pension plan, include average base salary during the last 36 consecutive months of service prior to retirement or the highest consecutive three calendar years of earnings in the last 10 years of service prior to retirement. Earnings, for the purpose of the supplemental pension arrangement related to cash bonus and earnings bonus units, include the average annual bonus for the highest three of the last five years prior to retirement for eligible executives, but do not include long-term compensation, including restricted stock units. By limiting inclusion of bonuses only to those granted in the five years prior to retirement, there is 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 value of any earnings bonus units received, as described starting on page 125. The aggregate maximum settlement value that could be paid for earnings bonus units is included in the employee’s final three year average earnings for the year of grant of such units. The value of the earnings bonus units are expected to pay out, subject to forfeiture provisions, and are included for supplemental pension arrangement purposes in the year of grant rather than the year of payment.

The remuneration used to determine the payments on retirement to the individuals named in the summary compensation table on page 134 corresponds generally to the salary, bonus and earnings bonus units received in the current year, as described above. As of February 13, 2014, the number of completed years of service with the company was 28.4 for B.G. Merkel. B.W. Livingston retired on December 31, 2013 with 29.4 completed years of service.

R.M. Kruger, P.J. Masschelin and T.G. Scott are not participants in the company’s pension plan, but are participants in Exxon Mobil Corporation’s pension plans. Under those plans, as of February 13, 2014, R.M. Kruger has 32.6 years of credited service, P.J. Masschelin has 36.2 years of credited service and T.G. Scott

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has 27.7 years of credited service. Their respective pensions are payable in U.S. dollars. Pay for the purpose of the pension calculation is 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 out of the last five grants 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 members of the historic 1.6 percent defined-benefit pension plan, and are eligible to receive a company matching contribution of up to six percent, except for R.M. Kruger, P.J. Masschelin and T.G. Scott, who participate in the Exxon Mobil Corporation savings plan and tax-qualified and non-qualified pension plans, which have provisions different from the company plan.

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) account, subject in the latter case 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. Company matching contributions must be allocated to company shares initially, and remain in that investment for a minimum of 24 months, after which they can be redeemed for other investment options. As of February 13, 2014, employees hold 9,708,323 shares through the company savings plan and the employees are allowed to vote these shares.

During employment, withdrawals are only permitted from employee contributions and investment earnings within the tax-paid account, to a maximum of three withdrawals per year. 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 closed by the end of the 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 25 major Canadian companies with revenues in excess of $1 billion a year.

Comparator companies

The following criteria are used to select comparator companies:

— Canadian companies;

— large operating scope and complexity;

— capital intensive; and

— proven sustainability.

The 25 companies benchmarked are as follows:

Comparator companies for named executive officers
Agrium Inc.	Devon Canada Corporation	Nexen Inc.
BCE Inc.	Enbridge Inc.	NOVA Chemicals Corporation
BP Canada Energy Company	Encana Corporation	Procter & Gamble Inc.
Canadian Tire Corporation Limited	General Electric Canada	Royal Bank of Canada
Chevron Canada Limited	Husky Energy Inc.	Shell Canada Limited
Canadian Natural Resources Limited	IBM Canada Ltd.	Suncor Energy Inc.
Canadian Pacific Railway Limited	Irving Oil Limited	Talisman Energy Inc.
Cenovus Energy Inc.	Lafarge Canada Inc.	TransCanada Corporation
ConocoPhillips Canada

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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 oil and non-oil employers. Compensation trends across industries, based on survey data, are prepared annually by independent external consultant, Towers Watson, 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. Rather, the total compensation program (excluding perquisites) is focused on a range between the mid-point and the upper quartile of comparable employers, reflecting the company’s emphasis on quality management. 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 above 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 in more detail on pages 131 and 132.

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 compensation program, including salary and annual bonus and equity (long-term) compensation considerations for R.M. Kruger, P.J. Masschelin and T.G. Scott, are similar to those of the company. The data used for long-term compensation determination for R.M. Kruger, P.J. Masschelin and T.G. Scott is as described above, as they received company restricted stock units in 2013. 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 on page 132.

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2013 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 2013 salary and incentive compensation.

Business performance results for consideration

The operating and financial performance measurements 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 2013. The executive resources committee considered the results over multiple years, in recognition of the long-term nature of the company’s business.

— Strong results in the areas of safety, health and environment.

— Satisfactory management of risk through effective business controls, as confirmed by independent audit.

— Net income of approximately $2.8 billion, down 25 percent versus last year.

— Total shareholder return of approximately 11 percent, with a ten-year annual average of approximately 10 percent.

— Industry-leading return on average capital employed of approximately 13 percent, with an average of approximately 26 percent since the beginning of 2000.

— Start-up of the Kearl oil sands mining project, the largest capital investment in the company’s history.

— Over 80 percent of capital invested in company growth, including the Kearl and Nabiye projects and the acquisition of Celtic.

— $407 million distributed to shareholders as dividends in 2013.

— Continued AAA rating from Standard & Poor’s.

Performance assessment considerations

The above 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 121 and results noted above 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.

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2013 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 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. 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 $33,000 U.S. to $798,000 U.S., effective January 1, 2014.

Mr. Kruger’s 2013 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 if Mr. Kruger should leave the company before normal retirement.

The executive resources committee has determined that the overall 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.

Key factors considered by the committee in determining his overall compensation level include:

— safety metrics and environmental performance;

— risk management;

— continuing progress on advancing long-term strategic interests such as the Kearl and Nabiye projects;

— financial results;

— government relations;

— productivity;

— leadership;

— cost effectiveness; and

— asset management.

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. The higher level of pay for Mr. Kruger, compared to the other named executive officers, reflects his greater level of responsibility, including his ultimate responsibility for the performance of the company, and oversight of the other senior executives.

Pay awarded to other named executive officers

Within the context of the compensation program structure and performance assessment processes described above, the value of 2013 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 134.

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Independent consultant

In fulfilling its responsibilities during 2013, 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 Towers Watson, 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, Towers Watson was not retained to provide individual compensation recommendations or advice for the compensation of the chairman, president and chief executive officer or other senior executives.

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 63 oil and gas companies including integrated oil companies, oil and gas producers, oil and gas service companies and includes equity issues and income trusts.

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 171 percent, for an average annual return of 10 percent. Over the past five years, the cumulative total shareholder return was 21 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 company’s focus on growing shareholder value over the long term by linking 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 has discontinued the S&P/TSX Equity Energy Index. This has been 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 2013. 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.

Name and principal   position at the end   of 2013	Year		Salary     ($)	Share-       based       awards       ($)       (b)	Option-     based       awards       ($)       (c)	Non-equity incentive plan compensation ($)		Pension     value     ($)     (f)	All other     compensation     ($)     (g)	Total   compensation     ($)     (h)
						Annual     incentive     plans     (d)	Long- term     incentive     plans     (e)
R.M. Kruger (a) (i) Chairman, president and chief executive officer (since March 1, 2013)		2013	590,905	4,194,346	-	492,292	0	(70,900)	(1,092,583)	4,114,060
B.H. March (a) (i) Chairman, president and chief executive officer (until March 1, 2013)		2013	157,060	0	-	0	0	513,321	130,601	800,982
		2012	569,772	2,657,068	-	468,113	366,447	1,657,835	304,761	6,023,996
		2011	524,223	2,192,320	-	362,604	438,447	1,308,434	830,876	5,656,904
P.J. Masschelin (a) Senior vice-president, finance and administration, and controller		2013	454,701	1,032,525	-	122,043	0	(194,661)	834,036	2,248,644
		2012	431,244	951,975	-	174,230	183,251	633,457	(79,309)	2,294,848
		2011	414,763	994,500	-	181,401	262,248	672,897	578,196	3,104,005
T. G. Scott (a) Senior vice-president, upstream		2013	502,334	1,032,525	-	182,086	0	134,416	298,988	2,150,349
		2012	459,316	951,975	-	196,321	187,239	441,831	21,222	2,257,904
		2011	420,862	994,500	-	185,357	225,480	381,730	441,323	2,649,252
B.W. Livingston Vice-president, general counsel and corporate secretary (until December 31, 2013)		2013	448,000	1,032,525	-	183,600	0	(256,600)	126,528	1,534,053
		2012	435,750	951,975	-	201,200	189,678	402,200	75,593	2,256,396
		2011	421,167	994,500	-	189,600	249,150	567,700	73,724	2,495,841
B.G. Merkel Vice-president, fuels, lubricants and specialties marketing		2013	402,667	761,774	-	128,500	0	(399,300)	51,791	945,432
		2012	377,667	702,346	-	164,500	137,055	563,900	49,836	1,995,304
		2011	350,000	667,420	-	137,100	141,900	617,900	47,194	1,961,514

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Footnotes to the Summary compensation table for named executive officers on the preceding page

(a) R.M. Kruger, P.J. Masschelin and T.G. Scott have been on a loan assignment from Exxon Mobil Corporation since March 1, 2013, May 1, 2010 and July 1, 2010 respectively. B.H. March was on loan assignment from Exxon Mobil Corporation from January 1, 2008 until March 1, 2013. Their compensation is paid directly by Exxon Mobil Corporation in U.S. dollars, but is disclosed in Canadian dollars. They also receive employee benefits under Exxon Mobil Corporation’s employee benefit plans, and not under the company’s employee benefit plans. The company reimburses Exxon Mobil Corporation for applicable compensation paid and employee benefits provided to them. All amounts paid to R.M. Kruger, B.H. March, P.J. Masschelin and T.G. Scott in U.S. dollars were converted to Canadian dollars at the average 2013 exchange rate of 1.0299. In 2011 and 2012, the average exchange rate was 0.9891 and 0.9996 respectively.

(b) 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 2013 was $45.89, 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 2011 was $44.20 and in 2012 was $42.31, 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.

(c) The company has not granted stock options since 2002. The stock option plan expired in 2012.

(d) The amounts listed in “Annual incentive plans” column for each named executive officer represent their 2013 cash bonus.

(e) 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 plan is described on page 125. R.M. Kruger, P.J. Masschelin and T.G. Scott participate in Exxon Mobil Corporation’s earnings bonus unit program, which is similar to the company’s plan. Their payouts are also subject to a maximum settlement value (trigger) or cumulative earnings per share. In 2013, there were no earnings bonus unit payouts to any named executive officer.

(f) “Pension value” is the “Compensatory change” in pensions as of December 31, 2013 as set out in the “Pension plan benefits” table on page 139. For B.H. March, the “Compensatory change” is valued as of the end of his assignment with the company.

(g) Amounts under “All other compensation” include dividend equivalent payments on restricted stock units granted, savings plans contributions, loan assignment costs and the cost of perquisites including financial planning, business club memberships and any costs associated with parking. For each named executive officer, the aggregate value of perquisites received was not greater than $50,000 or 10 percent of the named executive officer’s base salary. It is noted that in 2013, the actual dividend equivalent payments made were $21,912 for B.H. March (for the period January to March), $28,788 for P.J. Masschelin, $28,284 for T.G. Scott, $54,390 for B.W. Livingston and $32,214 for B.G. Merkel. The dividend equivalent payments on Exxon Mobil Corporation restricted stock granted in previous years were $522,444 for R.M. Kruger (for the period April to December), $7,544 for B.H. March (for the period January to March), $53,078 for P.J. Masschelin and $41,044 for T.G. Scott. These amounts were converted to Canadian dollars at the average 2013 exchange rate of 1.0299. In 2011 and 2012, the average exchange rate was 0.9891 and 0.9996, respectively. For R.M. Kruger, B.H. March, P.J. Masschelin and T.G. Scott the amounts under “All other compensation” also include loan assignment costs which consist mainly of expatriate allowances and the net effect of tax equalization costs in the year associated with their assignments in Canada, the impact of which may be positive or negative in the year.

(h) “Total compensation” for 2013 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”.

(i) Although R.M. Kruger’s assignment was effective March 1, 2013, and B.H. March’s ended the same day, the company reimbursed Exxon Mobil Corporation for applicable compensation costs beginning April 1, 2013 for R.M. Kruger and ending March 31, 2013 for B.H. March as well as for any trailing compensation associated with B.H. March’s assignment period with the company.

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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 as at December 31, 2013 for each of the named executive officers of the company.

	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     (#)     (e)	Market or     payout value     of share-     based awards     that have not     vested     ($)     (e)	Market or   payout value of   vested share-   based awards   not paid out or   distributed   ($)
R.M. Kruger (a)	-	-	-	-	91,400	4,299,456	-
B.H. March (b)	-	-	-	-	223,750	10,525,200	-
P.J. Masschelin (c)	-	-	-	-	77,800	3,659,712	-
T.G. Scott (d)	-	-	-	-	77,275	3,635,016	-
B.W. Livingston	-	-	-	-	112,250	5,280,240	-
B.G. Merkel	-	-	-	-	72,100	3,391,584	-

(a) R.M. Kruger was granted restricted stock units in 2013 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 229,300 Exxon Mobil Corporation restricted stock whose value on December 31, 2013 was $24,681,008 based on a closing price for Exxon Mobil Corporation shares on December 31, 2013 of $101.20 U.S., which was converted to Canadian dollars at the noon-rate for December 31, 2013 of 1.0636 provided by the Bank of Canada.

(b) B.H. March was granted restricted stock units from 2008 to 2012 under the company’s plan, while on assignment with the company.

(c) P.J. Masschelin was granted restricted stock units from 2010 to 2013 under the company’s plan. With respect to previous years, P.J. Masschelin participated in Exxon Mobil Corporation’s restricted stock plan, which is similar to the company’s restricted stock unit plan. Under that plan, P.J. Masschelin held 15,450 Exxon Mobil Corporation restricted stock whose value on December 31, 2013 was $1,662,981 based on a closing price for Exxon Mobil Corporation shares on December 31, 2013 of $101.20 U.S., which was converted to Canadian dollars at the noon-rate for December 31, 2013 of 1.0636 provided by the Bank of Canada.

(d) T.G. Scott was granted restricted stock units from 2010 to 2013 under the company’s plan. With respect to previous years, T.G. Scott participated in Exxon Mobil Corporation’s restricted stock plan, which is similar to the company’s restricted stock unit plan. Under that plan, T.G. Scott held 12,150 Exxon Mobil Corporation restricted stock whose value on December 31, 2013 was $1,307,781 based on a closing price for Exxon Mobil Corporation shares on December 31, 2013 of $101.20 U.S., which was converted to Canadian dollars at the noon-rate for December 31, 2013 of 1.0636 provided by the Bank of Canada.

(e) Represents the total of the restricted stock units received from the company plan in 2007 through 2013. The value is based on the closing price of the company’s shares on December 31, 2013 of $47.04.

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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 for each named executive officer of the company for the year.

Name	Option-based awards –   Value vested during   the year   ($)	Share-based awards – Value   vested during the year   ($)   (e)	Non-equity incentive plan   compensation – Value   earned during the year   ($)   (f)
R.M. Kruger (a)	-	-	-
B.H. March (b)	-	-	-
P.J. Masschelin (c)	-	473,594	-
T.G. Scott (d)	-	449,455	-
B.W. Livingston	-	1,014,805	183,600
B.G. Merkel	-	547,860	128,500

(a) Although R.M. Kruger received restricted stock units under the company’s plan in 2013, 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, under which the grantee may receive Exxon Mobil Corporation restricted stock. In 2013, restrictions were removed on 39,100 Exxon Mobil Corporation restricted stock having a value as at December 31, 2013 of $4,208,580 based on the closing price of Exxon Mobil Corporation common shares of $101.20 U.S., which was converted to Canadian dollars at the noon-rate for December 31, 2013 of 1.0636 provided by the Bank of Canada. R.M. Kruger received an annual bonus from Exxon Mobil Corporation in 2013 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 received $492,292 with respect to the annual bonus awarded in 2013, which amount was paid in U.S. dollars and is converted to Canadian dollars at the average 2013 exchange rate of 1.0299. In 2013, no earnings bonus units paid out.

(b) B.H. March received restricted stock units under the company’s plan from 2008 to 2012. In 2013, after his assignment with the company had ended, 21,650 units of the 2008 grant vested, having a value at vest of $979,230.

(c) P.J. Masschelin received restricted stock units under the company’s plan from 2010 to 2013. In 2013, the first 50 percent of the 2010 grant vested. In previous years, P.J. Masschelin participated in Exxon Mobil Corporation’s restricted stock plan, which is similar to the company’s restricted stock unit plan, under which the grantee may receive Exxon Mobil Corporation restricted stock. In 2013, restrictions were removed on 5,500 Exxon Mobil Corporation restricted stock having a value as at December 31, 2013 of $592,000 based on the closing price of Exxon Mobil Corporation common shares of $101.20 U.S., which was converted to Canadian dollars at the noon-rate for December 31, 2013 of 1.0636 provided by the Bank of Canada. P.J. Masschelin received an annual bonus from Exxon Mobil Corporation in 2013 and participates in Exxon Mobil Corporation’s earnings bonus unit plan, which is similar to the company’s earnings bonus unit plan. P.J. Masschelin received $122,043 with respect to the annual bonus awarded in 2013, which amount was paid in U.S. dollars and is converted to Canadian dollars at the average 2013 exchange rate of 1.0299. In 2013, no earnings bonus units paid out.

(d) T.G. Scott received restricted stock units under the company’s plan from 2010 to 2013. In 2013, the first 50 percent of the 2010 grant vested. In previous years, T.G. Scott participated in Exxon Mobil Corporation’s restricted stock plan, which is similar to the company’s restricted stock unit plan, under which the grantee may receive Exxon Mobil Corporation restricted stock. In 2013, restrictions were removed on 4,050 Exxon Mobil Corporation restricted stock having a value as at December 31, 2013 of $435,927 based on the closing price of Exxon Mobil Corporation common shares of $101.20 U.S., which was converted to Canadian dollars at the noon-rate for December 31, 2013 of 1.0636 provided by the Bank of Canada. T.G. Scott received an annual bonus from Exxon Mobil Corporation in 2013 and participates in Exxon Mobil Corporation’s earnings bonus unit plan, which is similar to the company’s earnings bonus unit plan. T.G. Scott received $182,086 with respect to the annual bonus awarded in 2013, which amount was paid in U.S. dollars and is converted to Canadian dollars at the average 2013 exchange rate of 1.0299. In 2013, no earnings bonus units paid out.

(e) These values show restricted stock units granted by the company that vested in 2013. 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 P.J. Masschelin and T.G. Scott the values represent restricted stock units granted in 2010, which vested in 2013. For B.W. Livingston and B.G. Merkel the value represents restricted stock units granted in 2006 and 2010, which vested in 2013.

(f) These values include the annual cash bonus received in 2013 and any earnings bonus unit payouts related to prior year grants. In 2013, no earnings bonus units paid out.

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Proceeds realized in 2013 from compensation awards granted in prior years - restricted stock units, stock options and earnings bonus units

Name	Proceeds from exercise     of restricted stock units     ($)     (e)	Proceeds from exercise     of stock options     ($)	Receipt of proceeds of     earnings bonus units     ($)     (f)
R.M. Kruger (a)	-	-	-
B.H. March (b)	-	-	-
P.J. Masschelin (c)	473,594	-	-
T.G. Scott (d)	449,455	-	-
B.W. Livingston	1,014,805	-	0
B.G. Merkel	547,860	-	0

(a) Although R.M. Kruger received restricted stock units under the company’s plan in 2013, 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, under which the grantee may receive Exxon Mobil Corporation restricted stock. In 2013, restrictions were removed on 39,100 Exxon Mobil Corporation restricted stock having a value as at December 31, 2013 of $4,208,580 based on the closing price of Exxon Mobil Corporation common shares of $101.20 U.S., which was converted to Canadian dollars at the noon-rate for December 31, 2013 of 1.0636 provided by the Bank of Canada. In 2013, no earnings bonus units paid out.

(b) B.H. March received restricted stock units under the company’s plan from 2008 to 2012. In 2013, after his assignment with the company had ended, 21,650 units of the 2008 grant vested, having a value at vest of $979,230.

(c) P.J. Masschelin received restricted stock units under the company’s plan from 2010 to 2013. In 2013, the first 50 percent of the 2010 grant vested. In previous years, P.J. Masschelin participated in Exxon Mobil Corporation’s restricted stock plan, which is similar to the company’s restricted stock unit plan, under which the grantee may receive Exxon Mobil Corporation restricted stock. In 2013, restrictions were removed on 5,500 Exxon Mobil Corporation restricted stock having a value as at December 31, 2013 of $592,000 based on the closing price of Exxon Mobil Corporation common shares of $101.20 U.S., which was converted to Canadian dollars at the noon-rate for December 31, 2013 of 1.0636 provided by the Bank of Canada. In 2013, no earnings bonus units paid out.

(d) T.G. Scott received restricted stock units under the company’s plan from 2010 to 2013. In 2013, the first 50 percent of the 2010 grant vested. In previous years, T.G. Scott participated in Exxon Mobil Corporation’s restricted stock plan, which is similar to the company’s restricted stock unit plan, under which the grantee may receive Exxon Mobil Corporation restricted stock. In 2013, restrictions were removed on 4,050 Exxon Mobil Corporation restricted stock having a value as at December 31, 2013 of $435,927 based on the closing price of Exxon Mobil Corporation common shares of $101.20 U.S., which was converted to Canadian dollars at the noon-rate for December 31, 2013 of 1.0636 provided by the Bank of Canada. In 2013, no earnings bonus units paid out.

(e) For P.J. Masschelin and T.G. Scott represents the proceeds of restricted stock units granted in 2010, which vested in 2013. For B.W. Livingston and B.G. Merkel represents the proceeds of restricted stock units granted in 2006 and 2010, which vested in 2013.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.

(f) Represents the proceeds of earnings bonus unit payouts related to prior year grants. In 2013, no earnings bonus units paid out.

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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 2013 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)	4,232,417	-	6,258,295
Total	4,232,417		6,258,295

(a)	The company’s stock option plan expired in 2012.
(b)	This is a restricted stock unit plan, which is described on page 126.
(c)	The number of securities reserved for the restricted stock unit plan represents the securities reserved for restricted stock units issued in 2007 through 2013 and still outstanding.

Pension plan benefits table

Name	Number of years credited service (as of   December 31,   2013) (#)	Annual benefits payable ($)		Opening present value of defined benefit   obligation   ($) (e)	Compensatory   change ($) (f)	Non-   compensatory   change ($) (g)	Closing present value of defined benefit   obligation ($) (h)
		At year-   end (c)	At age   65 (d)
R.M. Kruger (a)	-	-	-	-	-	-	-
B.H. March (a)	-	-	-	-	-	-	-
P.J. Masschelin (a)	-	-	-	-	-	-	-
T.G. Scott (a)	-	-	-	-	-	-	-
B.W. Livingston (b)	29.4	403,700	403,700	5,967,600	(256,600)	473,300	6,184,300
B.G. Merkel (b)	28.3	324,900	476,200	5,598,000	(399,300)	(510,400)	4,688,300

(a) Member of the Exxon Mobil Corporation pension plans, including tax-qualified and non-qualified plans. As of December 31, 2013, R.M. Kruger had 32.5 years of credited service, P.J. Masschelin had 36.1 years, T.G. Scott had 27.6 years and as of the end of his assignment, B.H. March had 32.7 years of credited service. All amounts referenced were converted from U.S. dollars to Canadian dollars at the average 2013 exchange rate of 1.0299.

(b) Member of the company’s 1.6 percent pension plan as supplemented by payments from the company for amounts beyond the regulatory limits for the registered plan. B.W. Livingston retired December 31, 2013. The member accrued a full year of service in 2013. The annual benefits payable and the benefit obligation (determined based on pension-in-pay status) shown at December 31, 2013 are the member’s benefits payable from the registered plan and supplemented by payments from the company for amounts beyond the regulatory limits for the registered plan.

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(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 supplemented by payments from the company. For members of the Exxon Mobil Corporation pension plans, the annual benefits include the accrued annual lifetime pension from the Exxon Mobil Corporation tax-qualified plan and the accrued annual amount calculated under the Exxon Mobil Corporation non-qualified plans. For R.M. Kruger this value was $989,169, for P.J. Masschelin, this value was $450,846 and for T.G. Scott, this value was $368,327. For B.H. March, as of the end of his assignment, this value was $684,674. Non-qualified plan benefits are payable only as a lump sum equivalent upon retirement.

(d) 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 supplemented by payments from the company that would be earned to age 65 assuming final average earnings as at December 31, 2013. For members of the Exxon Mobil Corporation pension plans, the annual benefits include the annual lifetime pension from Exxon Mobil Corporation’s tax-qualified plan and the annual amount calculated under the Exxon Mobil Corporation non-qualified plans that would be earned to age 65 assuming final average earnings as at December 31, 2013. For R.M. Kruger this value was $1,302,097, for P.J. Masschelin this value was $527,696 and for T.G. Scott this value was $570,362. For B.H. March, as of the end of his assignment, this value was $863,556. Non-qualified plan benefits are payable only as a lump sum equivalent upon retirement.

(e) For members of the company’s pension plan, the “Opening present value of defined benefit obligation” is defined for purposes of authoritative guidance under U.S. generally accepted accounting principles (GAAP) for defined benefit pension plans and is calculated based on 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, December 31, 2012. 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 in the fourth quarter of 2012 projected to retirement. For members of the Exxon Mobil Corporation pension plans, the “Opening present value of defined benefit obligation” is defined under GAAP and is calculated based on earnings eligible for pension as described previously. The calculations assume that the U.S. Social Security offset against the Exxon Mobil Corporation qualified plan benefit is calculated on the basis of the Social Security law in effect as of year-end 2012. For R.M. Kruger this value was $12,376,925, for B.H. March this value was $10,138,651, for P.J. Masschelin this value was $6,918,616 and for T.G. Scott this value was $3,352,200.

(f) The value for “Compensatory change” includes service cost for 2013 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 2013 and the actual salary and bonus received in 2013 as described previously. For members of the Exxon Mobil Corporation pension plans, these values are calculated using the individual’s additional pensionable service in 2013 and the projected salary and bonus. There were no plan amendments in 2013 that affected these benefits. These values are calculated on a basis that is consistent with GAAP and with the valuation that was performed for accounting purposes for the plans. For R.M. Kruger this value was ($70,900), for P.J. Masschelin this value was ($194,661) and for T.G. Scott this value was $134,416. For B.H. March, as of the end of his assignment, this value was $513,321.

(g) The value for “Non-compensatory change” includes 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 2013 increased to 4.75 percent, from 3.75 percent at the end of 2012, which had a negative impact on the non-compensatory change element. For members of the Exxon Mobil Corporation 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 5.0 percent at the end of 2013, up from 4.0 percent at the end of 2012, and operation of the plan’s rules for converting annuities to lump sums upon retirement. For R.M. Kruger this value was ($73,108), for P.J. Masschelin this value was ($722,376) and for T.G. Scott this value was $495,495. For B.H. March, as of the end of his assignment, this value was ($1,827,745).

(h) For members of the company’s pension plan, the “Closing present value of defined benefit obligation” is defined under GAAP and is calculated based on earnings eligible for pension as described previously and YMPE, projected to retirement and pro-rated on service to the date of valuation, December 31, 2013. The calculations assume that the Canada Pension Plan offset is based on the annual maximum benefit at retirement and the OAS offset is based on the OAS benefit in the fourth quarter of 2013 projected to retirement. For members of the Exxon Mobil Corporation pension plans, the “Closing present value of defined benefit obligation” is defined under GAAP and is calculated based on earnings eligible for pension as described previously. The calculations assume that the U.S. Social Security offset against the Exxon Mobil Corporation qualified plan benefit is calculated on the basis of the Social Security law in effect as of year-end 2013. For R.M. Kruger this value was $12,232,917, for P.J. Masschelin this value was $6,001,579 and for T.G. Scott this value was $3,982,111. For B.H. March, as of the end of his assignment, this value was $8,824,227.

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 page 126. There are no units outstanding for any historical plan.

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V. Other important information

Effective date

The effective date of this management proxy circular is February 13, 2014.

Largest shareholder

To the knowledge of the directors and executive officers of the company, the only shareholder who, as of February 13, 2014, 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 589,928,303 common shares, representing 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 MKT 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 25, 2012, the company implemented a 12-month “normal course” share purchase program under which it purchased none of its outstanding shares during the program between June 25, 2012 and June 24, 2013. On June 25, 2013, a 12-month share purchase program was implemented under which the company may purchase up to 1,000,000 of its outstanding shares. In 2013, there were no such share purchases and none from Exxon Mobil Corporation.

The amounts of purchases and sales by the company and its subsidiaries for other transactions in 2013 with Exxon Mobil Corporation and affiliates of Exxon Mobil Corporation were $4,423 million and $2,385 million, respectively. These transactions 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 services. Transactions with Exxon Mobil Corporation 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 Exxon Mobil Corporation 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 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.

As at December 31, 2013, the company had an outstanding loan of $4,316 million under an existing agreement with ExxonMobil that provides for a long term, variable rate loan from ExxonMobil to the company of $5 billion at market interest rates. The agreement is effective until July 31, 2020, cancellable if ExxonMobil provides at least 370 days advance written notice. In January 2014, the company increased the capacity of the loan facility to $6.25 billion; all other terms and conditions of the agreement remained unchanged. 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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Auditor Information

PricewaterhouseCoopers LLP (“PwC”) have been the auditors 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, 2013 and December 31, 2012 were as follows:

thousands of dollars	2013		2012
Audit fees		1,357		1,221
Audit-related fees		123		66
Tax fees		50		0
All other fees		0		0
Total fees		1,530		1,287

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 2013.

Audit-related fees included other assurance services including the audit of the company’s retirement plan and royalty statement audits for oil and gas producing entities.

Tax fees related to corporate tax returns and compliance matters associated with the Celtic acquisition.

The company did not engage the auditor for any other services.

The audit committee recommends the external auditor be appointed by the shareholders, fixes its remuneration and oversees its 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 has confirmed that they are independent with respect to the company within the meaning of the Rules of Professional Conduct of the Institute of Chartered Accountants of Alberta and the rules of the U.S. Securities and Exchange Commission. The company has concluded that the auditors’ independence has been maintained.

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Ethical business conduct

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. 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 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 five 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.W. Woods, 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. Eight executive sessions were held in 2013. There has been no material change reports filed in the past 12 months pertaining to conduct of a director or executive officer that constitutes a departure from the Code.

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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Appendix B – 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

1) 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 policy 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) 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) meet with the frequency necessary to consider the range of items listed below;

(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;

(o) direct the distribution to them 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 clause 5;

(p) review the mandates of the board and of the committees and their effectiveness at least annually; and,

(q) undertake such additional activities within the scope of their responsibilities as may be deemed appropriate in their discretion.

4. Range of items to be considered by the board

1) 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

2) 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.

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5. Information to be received by the board

1) 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:

Information manual (Directors’ Digest)

— 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

2) All material distributed to employee directors shall be through normal corporation channels. All material distributed to nonemployee directors shall be through the office of the corporate secretary.

6. Unrelated and independent directors

1) Subject to occasions when there is a temporary vacancy in respect of a director who is unrelated and independent or when there is a need to accommodate succession for one or more senior executives who are directors, the board intends to be composed of a majority of unrelated and independent directors.

2) 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 unrelated or 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.

3) The term “unrelated director”, as defined by the Toronto Stock Exchange, means a director who is independent of management and is free from any interest and any business or other relationship which could, or could reasonably be perceived to, materially interfere with the director’s ability to act with a view to the best interests of the corporation, other than interests and relationships arising from shareholding.

4) The term “independent”, within the meaning of applicable law, means that the director may not, other than in his or her capacity as a member of the board of directors, or any other board committee,

(i) accept any consulting, advisory, or other compensatory fee from the issuer; or

(ii) be an affiliated person of the issuer or any subsidiary thereof.

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7. Independent legal or other advice

The board and, with the approval of the board, any director, may engage independent counsel and other advisors at the expense of the corporation.

8. Meetings of the unrelated and independent directors in the absence of members of management

1) Meetings of the unrelated and independent directors (“executive sessions of the board”) shall be held in conjunction with all board meetings including unscheduled telephonic board meetings.

2) The chair of the executive sessions of the board shall be chosen by the unrelated and independent directors.

3) The chair of the executive sessions of the board, or in the chair’s absence an unrelated and independent director chosen by the unrelated and independent directors, shall

(a) preside at executive sessions of the board;

(b) ensure that meetings of the unrelated and independent directors are held in accordance with this charter; and

(c) 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.

4) The purposes of the executive sessions of the board shall include the following:

(a) to raise substantive issues that are more appropriately discussed in the absence of management;

(b) to discuss the need to communicate to the chairman of the board any matter of concern raised by any committee or any director;

(c) to address issues raised but not resolved at meetings of the board and assess any follow-up needs with the chairman of the board;

(d) to discuss the quality, quantity, and timeliness of the flow of information from management that is necessary for the unrelated and independent directors to effectively and responsibly perform their duties, and advise the chairman of the board of any changes required; and

(e) to seek feedback about board processes.

9. Selection and tenure of directors

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. 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)

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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; and

— providing diversity of viewpoint, individual competencies in business, other areas of endeavour in contributing to the collective experience of the directors, 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.

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;

— 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;

— 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:

Ø 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;

Ø 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;

Ø 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.

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(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;

— 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 chief executive officer, 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, 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;

— develops a conflict of interest, such as

Ø 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;

Ø 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;

Ø 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;

Ø 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.

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10. Chairman and chief executive officer

(a) Position description

The chairman and chief executive officer shall

1. Plan and organize all activities of the board of directors;

2. Ensure that the Board receives sufficient, timely information on all material aspects of the corporation’s operations and financial affairs;

3. Chair annual and special meetings of the shareholders;

4. Conduct the general management and direction of the business and affairs of the corporation;

5. 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;

6. 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;

7. 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;

8. 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;

9. Ensure compliance with the corporation’s code of ethics and business conduct so as to foster a culture of integrity throughout the company; and

10. 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, deferred share units and restricted stock units, of a value no less than five times his base salary.

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Audit Committee Charter

  The structure, process and responsibilities of the audit committee shall include the following items and matters:

1.	(1)	The committee shall consist of five members, to be appointed by the board of directors from among the unrelated and independent directors, who shall serve during the pleasure of the board but only so long as they continue to be directors of the corporation and are unrelated and independent.
	(2)	The committee shall, if possible, have one or more members who is an “audit committee financial expert” within the meaning of applicable law.
	(3)	Each member of the committee shall be able to read and understand fundamental financial statements, including a company’s balance sheet, income statement, and cash flow statement.
	(4)	No committee member shall serve on the audit committee of more than two other public companies, unless the Board of Directors determines that such simultaneous service would not impair the ability of such director to effectively serve on the audit committee.
2.	The chair and vice-chair shall be appointed by the board from among the members 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 audit 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.
3.	The committee shall designate its secretariat.
4.	A quorum for the meetings of the committee shall be three members.
5.	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.
6.	The committee and, with the approval of the committee, any member, may engage independent counsel and other advisors at the expense of the corporation.
7.	The external auditors and the internal auditor of the corporation shall report directly to the audit committee.
8.	The committee shall:
	(a)	recommend the external auditors to be appointed by the shareholders, fix their remuneration, which shall be paid by the corporation, and oversee their work.
	(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.

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(e) 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.

(f) approve the proposed current year audit program of the internal auditors and assess the results of the program after the end of each quarter.

(g) review annually the adequacy of the corporation’s liability and property insurance program.

(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.

(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 annual and quarterly financial statements of the corporation, 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 financial statements by the board of directors.

(l) review the results of the monitoring activity under the corporation’s business ethics compliance program.

(m) review annually a summary of senior management expense accounts.

(n) require attendances at its meetings by members of management, as the committee may direct.

(o) review its mandate and its effectiveness at least annually.

(p) undertake such additional activities within the scope of its responsibilities as may be deemed appropriate in its discretion.

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Environment, Health and Safety Committee Charter

The structure, process and responsibilities of the environment, health and safety committee shall include the following items and matters:

1. The committee shall consist of no fewer than five members, to be appointed by the board of directors from among (a) the unrelated and independent directors; and (b) the non-independent directors who are not members of the corporation’s management, who shall serve during the pleasure of the board but only so long as they continue to be directors of the corporation.

2. The chair and vice-chair shall be appointed by the board from among the members 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 environment health and safety 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.

3. The committee shall designate its secretariat.

4. A quorum for the meetings of the committee shall be three members.

5. Meetings of the committee may be called by any member.

6. The committee and, with the approval of the committee, any member, may engage independent counsel and other advisors at the expense of the corporation.

7. The committee shall:

(a) review and monitor the corporation’s policies and practices in matters of the environment, health and safety.

(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) review its mandate and its effectiveness at least annually.

(h) undertake such additional activities within the scope of its responsibilities as may be deemed appropriate in its discretion.

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Executive Resources Committee Charter

The structure, process and responsibilities of the executive resources committee shall include the following items and matters:

1. The committee shall consist of no fewer than five members, to be appointed by the board of directors from among the (a) unrelated and independent directors; and (b) the non-independent members who are not members of the corporation’s management, who shall serve during the pleasure of the board but only so long as they continue to be directors of the corporation.

2. The chair and vice-chair shall be appointed by the board from among the members 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 executive resources 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.

3. The committee shall designate its secretariat.

4. A quorum for the meetings of the committee shall be three members.

5. Meetings of the committee may be called by any member.

6. 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.

7. The committee shall:

(a) monitor the performance of the chief executive officer.

(b) review and approve corporate goals and objectives relevant to compensation of the chief executive officer and evaluate his performance in light of those goals and objectives.

(c) review data on competitive compensation practices and review and evaluate policies and programs through which the corporation compensates its employees.

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(d) approve salaries and other compensation (including supplemental compensation such as cash bonuses and IEBU’s, long-term incentive compensation such as RSU’s, and any other payments for service), for the chief executive officer and other key senior executive management positions reporting directly to the chief executive officer, including all officers of the corporation.

(e) produce an annual report on compensation for inclusion in the corporation’s management proxy circular in accordance with applicable legal requirements.

(f) review the executive development system to ensure that it:

i. foresees the company’s senior management requirements;

ii. provides for early identification and development of key resources.

(g) approve specific succession plans for the chief executive officer and other key senior executive management positions reporting directly to the chief executive officer, including all officers of the corporation.

(h) review the company’s process in respect of employee conflicts of interest and directorships in non-affiliated commercial, financial and industrial organizations and the disclosures thereof.

(i) require attendance at its meetings by members of management, as the committee may direct.

(j) review its mandate and its effectiveness at least annually.

(k) undertake such additional activities within the scope of its responsibilities as may be deemed appropriate in its discretion.

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Nominations and Corporate Governance Committee Charter

The structure, process and responsibilities of the nominations and corporate governance committee shall include the following items and matters:

1. The committee shall consist of no fewer than five members, to be appointed by the board of directors from among (a) the unrelated and independent directors; and the (b) the non-independent directors who are not members of the company’s management, who shall serve during the pleasure of the board but only so long as they continue to be directors of the corporation.

2. The chair and vice-chair shall be appointed by the board from among the members 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 nominations and corporate governance 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.

3. The committee shall designate its secretariat.

4. A quorum for the meetings of the committee shall be three members.

5. Meetings of the committee may be called by any member.

6. The committee and, with the approval of the committee, any member, may engage independent counsel and other advisors at the expense of the corporation.

7. The committee shall:

(a) oversee issues of corporate governance as they apply to the corporation, including the effectiveness of the system of corporate governance, the evaluation of the overall performance of the board, and the board’s relationship with management, and to report to the board on such matters.

(b) make recommendations to the board as to the appropriate size of the board with a view to facilitating effective decision-making.

(c) review and recommend to the board of directors the procedure for identifying potential nominees for directorships, including guidelines to be used in the selection process.

(d) review and recommend to the board of directors any modifications to the charters of the board or any of its committees.

(e) review and recommend to the board of directors guidelines to be adopted relating to tenure of directors.

(f) assist the chief executive officer to assess potential candidates for directorships and recommend to the board of directors proposed candidates for board membership to fill anticipated vacancies.

(g) apply guidelines for board membership to incumbent directors and recommend to the chief executive officer and to the board of directors the slate of director candidates to be proposed for election by the shareholders at the annual meeting.

(h) review and recommend the nonemployee directors’ compensation.

156

(i) require attendances at its meetings by members of management, as the committee may direct.

(j) review its mandate and its effectiveness at least annually.

(k) undertake such additional activities within the scope of its responsibilities as may be deemed appropriate in its discretion.

(l) make a recommendation to the board of directors as to whether to accept or reject any resignation tendered by a director as provided in subclause 9(b)(ii) of the board of directors charter.

157

Contributions Committee Charter

The structure, process and responsibilities of the contributions and community investment committee shall include the following items and matters:

1. The committee shall consist of no fewer than five members, to be appointed by the board of directors from among the directors, who shall serve during the pleasure of the board but only so long as they continue to be directors of the corporation.

2. The chair and vice-chair shall be appointed by the board from among the members 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 contributions and community investment 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.

3. The committee shall designate its secretariat.

4. A quorum for the meetings of the committee shall be three members.

5. Meetings of the committee may be called by any member.

6. The committee and, with the approval of the committee, any member, may engage independent counsel and other advisors at the expense of the corporation.

7. 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, including those made by means of the Imperial Oil Foundation;

(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 subparagraph 7(a)(ii) above by joint ventures operated by other companies;

(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, and make such recommendations to the Board with respect thereto as it may deem advisable;

158

(c) approve the proposed budget for charitable contributions and local community contributions, as described in subparagraphs 7(a)(i) and (ii), of the corporation and its consolidated affiliates, and review the proposed budget for charitable contributions for the Imperial Oil Foundation prior to the meeting of the Imperial Oil Foundation to approve such budget, 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 other than as described in subparagraphs 7(a)(i) and (ii) 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 subparagraphs 7(a)(i) and (ii) above $300,000;

(f) require attendances at its meetings by members of management, as the committee may direct;

(g) review its mandate and its effectiveness at least annually; and

(h) undertake such additional activities within the scope of its responsibilities as may be deemed appropriate in its discretion.

159

EX-23.II.A

Exhibit (23)(ii)(A)

Consent of Independent Registered Public Accounting Firm

We hereby consent to the incorporation by reference in the Offering Circular constituting part of the Registration Statement on Form S-3 (File No. 033-41418) filed with the Securities and Exchange Commission on June 27, 1991 of our report dated February 25, 2014 relating to the financial statements and the effectiveness of internal control over financial reporting, which appears in the Annual Report to Shareholders, on page 54 in Imperial Oil Limited’s Annual Report on Form 10-K for the year ended December 31, 2013. We also consent to the reference to us under the heading “Experts” in such Offering Circular.

      /s/ PricewaterhouseCoopers LLP

      Chartered Accountants

      Calgary, Alberta, Canada

      Date: February 25, 2014

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;

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 controls over financial reporting.

Date: February 25, 2014

    /s/ Richard M. Kruger

     Richard M. Kruger

     Chairman of the Board, President

     and

     Chief Executive Officer

     (Principal Executive Officer)

EX-31.2

Exhibit (31.2)

Certifications

I, Paul J. Masschelin, 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;

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 controls over financial reporting.

Date: February 25, 2014

    /s/ Paul J. Masschelin

     Paul J. Masschelin

     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 the 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, 2013, 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 25, 2014

    /s/ Richard M. Kruger

     Richard M. Kruger

     Chairman of the Board, 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 the purposes of 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002, the undersigned, Paul J. Masschelin, the chief financial 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, 2013, 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 25, 2014

    /s/ Paul J. Masschelin

     Paul J. Masschelin

     Senior Vice-President,

     Finance and Administration, and

     Controller

     (Chief Financial Officer)

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Leased facilities (Tables)

12 Months Ended

Dec. 31, 2013

Schedule of Operating Leases

At December 31, 2013, the company held non-cancelable operating leases covering office buildings, rail cars, service stations and other properties with minimum undiscounted lease commitments totaling $389 million as indicated in the following table:

	Payments due by period
millions of dollars	2014		2015		2016		2017		2018		After 2018		Total
Lease payments under minimum commitments (a)		177		88		47		33		12		32		389

(a) Net rental cost under cancelable and non-cancelable operating leases incurred in 2013 was $287 million (2012 – $271 million, 2011 – $226 million). Related rental income was not material.

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Change in Plan Assets and Plan Assets in Excess of Less Than Projected Benefit Obligation (Detail) (CAD) In Millions, unless otherwise specified	12 Months Ended
	Dec. 31, 2013		Dec. 31, 2012
Defined Benefit Plan Disclosure [Line Items]
Fair value at December 31	5,872		5,114
Pension benefits
Defined Benefit Plan Disclosure [Line Items]
Fair value at January 1	5,114		4,461
Actual return/(loss) on plan assets	491		374
Company contributions	600		594
Benefits paid	(333)	[1]	(315)	[1]
Fair value at December 31	5,872		5,114
Funded plans	(424)		(1,602)
Unfunded plans	(574)		(620)
Total	(998)	[2]	(2,222)	[2]
Other post-retirement benefits
Defined Benefit Plan Disclosure [Line Items]
Unfunded plans	(503)		(547)
Total	(503)	[2]	(547)	[2]

[1] Benefit payments for funded plans only.

[2] Fair value of assets less projected benefit obligation shown above.

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Income Taxes (Parenthetical) (Detail) (CAD) In Millions, unless otherwise specified	12 Months Ended
	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
Schedule Of Income Tax [Line Items]
Cash outflow from income taxes, plus investment credits earned	911	871	667

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Summarized Information About Incentive Share, Deferred Share and Restricted Stock Units (Detail)	12 Months Ended
	Dec. 31, 2013
Restricted Stock Units (RSUs)
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Outstanding at January 1, 2013	8,943,104
Granted	1,654,540
Exercised	(1,841,408)
Forfeited and cancelled	(41,382)
Outstanding at December 31, 2013	8,714,854
Deferred Share Units
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Outstanding at January 1, 2013	85,505
Granted	12,731
Outstanding at December 31, 2013	98,236

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Amounts Recorded in Consolidated Balance Sheet and Accumulated Other Comprehensive Income (Detail) (CAD) In Millions, unless otherwise specified	Dec. 31, 2013		Dec. 31, 2012
Defined Benefit Plan Disclosure [Line Items]
Current liabilities	(53)		(52)
Other long-term obligations	(1,448)	[1]	(2,717)	[1]
Pension benefits
Defined Benefit Plan Disclosure [Line Items]
Current liabilities	(25)		(24)
Other long-term obligations	(973)		(2,198)
Total recorded	(998)		(2,222)
Net actuarial loss/(gain)	2,303		3,210
Prior service cost	62		85
Total recorded in accumulated other comprehensive income, before tax	2,365		3,295
Other post-retirement benefits
Defined Benefit Plan Disclosure [Line Items]
Current liabilities	(28)		(28)
Other long-term obligations	(475)		(519)
Total recorded	(503)		(547)
Net actuarial loss/(gain)	64		124
Total recorded in accumulated other comprehensive income, before tax	64		124

[1] Total recorded employee retirement benefit obligations also include $53 million in current liabilities (2012 - $52 million).

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Common Share Activities (Detail) (CAD) In Millions, except Share data in Thousands, unless otherwise specified	12 Months Ended			192 Months Ended	216 Months Ended
	Dec. 31, 2012		Dec. 31, 2011	Dec. 31, 2011	Dec. 31, 2013
Class of Stock [Line Items]
Common stock beginning balance, shares	847,599		847,599
Issued under employee share-based awards	2,776		1,262
Purchases at stated value, shares	(2,776)		(1,262)	(903,765)	(906,541)
Common stock, ending balance, shares	847,599		847,599	847,599	847,599
Common stock beginning balance, value	1,528		1,511
Issued under employee share-based awards, value	43		19
Purchases at stated value, value	(128)			(15,580)	(15,708)
Common stock, ending balance, value	1,566	[1]	1,528	1,528	1,566	[1]
Common Stock
Class of Stock [Line Items]
Purchases at stated value, value	(5)		(2)

[1] Number of common shares outstanding was 848 million (2012 - 848 million), (note 10).

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Business Segments (Parenthetical) (Detail) (CAD) In Millions, unless otherwise specified	12 Months Ended
	Dec. 31, 2013		Dec. 31, 2012		Dec. 31, 2011
Segment Reporting Information [Line Items]
Operating revenues	32,722	[1],[2],[3]	31,053	[1],[2],[3]	30,474	[1],[2],[3]
Write-down of refinery plant and equipment reported as depreciation and depletion expenses	245
Decommissioning, environmental and employee-related costs reported as production and manufacturing expenses	132
Amount incurred related to decommissioning, environmental and employee related cost	40
Property plant and equipment under construction	9,234		13,846
Goodwill	224		204
Pre Tax
Segment Reporting Information [Line Items]
Charges related to conversion of refinery to terminal	377
After Tax
Segment Reporting Information [Line Items]
Charges related to conversion of refinery to terminal	280
United States Exports
Segment Reporting Information [Line Items]
Operating revenues	5,217		4,358		4,175
Upstream
Segment Reporting Information [Line Items]
Operating revenues	6,016	[3]	4,674	[3]	5,278	[3]
Goodwill	20

[1] Operating revenues include federal excise tax of $1,423 million (2012 - $1,338 million, 2011 - $1,320 million).

[2] Operating revenues include amounts from related parties of $2,385 million (2012 - $2,907 million, 2011 - $2,818 million), (note 16).

[3] Includes export sales to the United States of $5,217 million (2012 - $4,358 million, 2011 - $4,175 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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Share-based incentive compensation programs (Tables)

12 Months Ended

Dec. 31, 2013

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, 2013:

	Restricted stock units			Deferred share units
Outstanding at January 1, 2013		8,943,104			85,505
Granted		1,654,540			12,731
Exercised		(1,841,408	)		-
Forfeited and cancelled		(41,382	)		-
Outstanding at December 31, 2013		8,714,854			98,236

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Net Income Per Share (Detail) (CAD) In Millions, except Per Share data, unless otherwise specified	12 Months Ended
	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
Net income per common share - basic
Net income (millions of dollars)	2,828	3,766	3,371
Weighted average number of common shares outstanding (millions of shares)	847.6	847.7	847.7
Net income per common share (dollars)	3.34	4.44	3.98
Net income per common share - diluted
Net income (millions of dollars)	2,828	3,766	3,371
Weighted average number of common shares outstanding (millions of shares)	847.6	847.7	847.7
Effect of employee share-based awards (millions of shares)	3.0	3.4	5.9
Weighted average number of common shares outstanding, assuming dilution (millions of shares)	850.6	851.1	853.6
Net income per common share (dollars)	3.32	4.42	3.95

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Schedule of Unconditional Purchase Obligations (Detail) (CAD) In Millions, unless otherwise specified	Dec. 31, 2013
Unrecorded Unconditional Purchase Obligation [Line Items]
Unconditional purchase obligations payments due 2014	91	[1]
Unconditional purchase obligations payments due 2015	80	[1]
Unconditional purchase obligations payments due 2016	82	[1]
Unconditional purchase obligations payments due 2017	83	[1]
Unconditional purchase obligations payments due 2018	84	[1]
Unconditional purchase obligations payments due after 2018	237	[1]
Unconditional Purchase Obligation, Total	657	[1]

[1] Undiscounted obligations of $657 million mainly pertain to pipeline throughput agreements. Total payments under unconditional purchase obligations were $95 million (2012 - $86 million, 2011 - $73 million). The present value of these commitments, excluding imputed interest of $178 million, totalled $479 million.

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Long Term Debt (Parenthetical) (Detail) (CAD)	12 Months Ended
	Dec. 31, 2013 D	Dec. 31, 2012
Debt Instrument [Line Items]
Maximum long-term borrowing from affiliate	5,000,000,000
Cancellation period long-term borrowing from affiliate, days	370
Average effective rate for affiliate long-term borrowing	1.30%
Capitalized lease obligations for marine services, average imputed rate	7.00%	9.60%
Total capitalized lease obligations in current liabilities	7,000,000	7,000,000
Principal payments on capital leases, in two years	7,000,000
Principal payments on capital leases, in three years	7,000,000
Principal payments on capital leases, in four years	7,000,000
Principal payments on capital leases, in five years	7,000,000

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Components of Net Periodic Benefit Cost and Changes in Amounts Recorded in Accumulated Other Comprehensive Income (Detail) (CAD) In Millions, unless otherwise specified	12 Months Ended
	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
Pension benefits
Defined Benefit Plan Disclosure [Line Items]
Current service cost	181	160	122
Interest cost	281	288	314
Expected return on plan assets	(331)	(288)	(308)
Amortization of prior service cost	23	23	21
Amortization of actuarial loss/(gain)	243	235	162
Net periodic benefit cost	397	418	311
Net actuarial loss/(gain)	(664)	530	1,112
Amortization of net actuarial (loss)/gain included in net periodic benefit cost	(243)	(235)	(162)
Prior service cost			86
Amortization of prior service cost included in net periodic benefit cost	(23)	(23)	(21)
Total recorded in other comprehensive income	(930)	272	1,015
Total recorded in net periodic benefit cost and other comprehensive income, before tax	(533)	690	1,326
Other post-retirement benefits
Defined Benefit Plan Disclosure [Line Items]
Current service cost	11	8	6
Interest cost	21	21	23
Amortization of actuarial loss/(gain)	10	8	3
Net periodic benefit cost	42	37	32
Net actuarial loss/(gain)	(50)	40	81
Amortization of net actuarial (loss)/gain included in net periodic benefit cost	(10)	(8)	(3)
Total recorded in other comprehensive income	(60)	32	78
Total recorded in net periodic benefit cost and other comprehensive income, before tax	(18)	69	110

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Common Shares - Additional Information (Detail) In Millions, unless otherwise specified	12 Months Ended
	Dec. 31, 2013
Class of Stock [Line Items]
Normal course issuer bid share repurchase shares authorized	1
Normal course issuer bid share repurchase programs	18
Normal course issuer bid share repurchase term, months	12 months
Exxon Mobil Corporation's ownership interest in Imperial	69.60%

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Schedule of Non Cancelable Operating Leases (Detail) (CAD) In Millions, unless otherwise specified	Dec. 31, 2013
Operating Leased Assets [Line Items]
Lease payments under minimum commitments, 2014	177	[1]
Lease payments under minimum commitments, 2015	88	[1]
Lease payments under minimum commitments, 2016	47	[1]
Lease payments under minimum commitments, 2017	33	[1]
Lease payments under minimum commitments, 2018	12	[1]
Lease payments under minimum commitments, After 2018	32	[1]
Total lease payments under minimum commitments	389	[1]

[1] Net rental cost under cancelable and non-cancelable operating leases incurred in 2013 was $287 million (2012 - $271 million, 2011 - $226 million). Related rental income was not material.

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Inventories of Crude Oil and Products (Detail) (CAD) In Millions, unless otherwise specified	Dec. 31, 2013	Dec. 31, 2012
Product Information [Line Items]
Crude oil	628	473
Petroleum products	340	284
Chemical products	54	60
Natural gas and other	8	10
Total inventories of crude oil and products	1,030	827

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Schedule of Non Cancelable Operating Leases (Parenthetical) (Detail) (CAD) In Millions, unless otherwise specified	12 Months Ended
	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
Operating Leased Assets [Line Items]
Net rental cost incurred for operating leases	287	271	226

XML

Results of Share Repurchase Program Activities (Detail) (CAD) In Millions, except Share data in Thousands, unless otherwise specified	12 Months Ended		192 Months Ended	216 Months Ended
	Dec. 31, 2012	Dec. 31, 2011	Dec. 31, 2011	Dec. 31, 2013
Schedule Of Common Share Purchase [Line Items]
Cumulative purchases to date, shares	2,776	1,262	903,765	906,541
Cumulative purchases to date, value	128		15,580	15,708

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Gains and Losses on Asset Sales (Detail) (CAD) In Millions, unless otherwise specified	12 Months Ended
	Dec. 31, 2013		Dec. 31, 2012		Dec. 31, 2011
Investment And Other Income [Line Items]
Proceeds from asset sales	160		226		314
Book value of assets sold	10		132		117
Gain/(loss) on asset sales, before tax	150	[1]	94	[1]	197	[1]
Gain/(loss) on asset sales, after tax	120	[1]	72	[1]	153	[1]

[1] 2013 included a gain of $85 million ($73 million after tax) for the sale of non-operating assets.

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Transactions with related parties

12 Months Ended

Dec. 31, 2013

Transactions with related parties

16. Transactions with related parties

Revenues and expenses of the company also include the results of transactions with Exxon Mobil Corporation and affiliated companies (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 to:

a) 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) 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) provide for the delivery of management, business and technical services to Syncrude Canada Ltd. by ExxonMobil; and

d) provide for the option of equal participation in new upstream opportunities.

Certain charges from ExxonMobil have been capitalized; they are not material in the aggregate.

As at December 31, 2013, the company had outstanding long-term loans of $4,316 million (2012 – $1,040 million) and short-term loans of $75 million (2012 – nil) from ExxonMobil (see note 14, long-term debt, on page 77 and note 12, financing costs and additional notes and loans payable, on page 76 for further details).

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Unrecognized Tax Benefits (Detail) (CAD) In Millions, unless otherwise specified	12 Months Ended
	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
Schedule of Unrecognized Tax Benefits [Line Items]
January 1 balance	143	134	147
Additions based on current year's tax position	10	4
Additions for prior years' tax positions	2	10	20
Reductions for prior years' tax positions	(4)	(3)	(31)
Reductions due to lapse of the statute of limitations		(2)	(2)
December 31 balance	151	143	134

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Other comprehensive income information (Tables)

12 Months Ended

Dec. 31, 2013

Changes in Accumulated Other Comprehensive Income

Changes in accumulated other comprehensive income:

millions of dollars	2013			2012			2011
Balance as at January 1		(2,455	)		(2,238	)		(1,424	)
Post-retirement benefits liability adjustment:
Current period change excluding amounts reclassified from accumulated other comprehensive income		529			(415	)		(953	)
Amounts reclassified from accumulated other comprehensive income		205			198			139
Balance as at December 31		(1,721	)		(2,455	)		(2,238	)

Amounts Reclassified Out of Accumulated Other Comprehensive Income Before-Tax Income/(Expense)

Amounts reclassified out of accumulated other comprehensive income – before tax income/(expense)

millions of dollars	2013			2012			2011
Amortization of post-retirement benefits liability adjustment included in net periodic benefit cost (a)		(276	)		(266	)		(186	)

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

Schedule of Income Tax Expense/(Credit) for Components of Other Comprehensive Income

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

millions of dollars	2013		2012			2011
Post-retirement benefits adjustments:
Post-retirement benefits liability adjustment (excluding amortization)		185		(155	)		(326	)
Amortization of post-retirement benefits liability adjustment included in net periodic benefit cost		71		68			47
Total		256		(87	)		(279	)

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Summary of Common Shares (Detail) In Thousands, unless otherwise specified	Dec. 31, 2013	Dec. 31, 2012
Class of Stock [Line Items]
Authorized	1,100,000	1,100,000

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Acquisition - Additional Information (Detail) (Celtic, CAD)	1 Months Ended	12 Months Ended
	Feb. 26, 2013	Dec. 31, 2013
Celtic
Business Acquisition [Line Items]
Consideration paid for acquisition	1,600,000,000
Ownership interest acquired	50.00%
Revenues		89,000,000

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Miscellaneous financial information (Tables)

12 Months Ended

Dec. 31, 2013

Inventories of Crude Oil and Products

Inventories of crude oil and products at year-end consisted of the following:

millions of dollars	2013		2012
Crude oil		628		473
Petroleum products		340		284
Chemical products		54		60
Natural gas and other		8		10
Total inventories of crude oil and products		1,030		827

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Change in Projected Benefit Obligation (Detail) (CAD) In Millions, unless otherwise specified	12 Months Ended
	Dec. 31, 2013		Dec. 31, 2012		Dec. 31, 2011
Pension benefits
Defined Benefit Plan Disclosure [Line Items]
Projected benefit obligation at January 1	7,336		6,646
Current service cost	181		160		122
Interest cost	281		288		314
Actuarial loss/(gain)	(504)		616
Amendments
Benefits paid	(424)	[1]	(374)	[1]
Projected benefit obligation at December 31	6,870		7,336		6,646
Accumulated benefit obligation at December 31	6,263		6,560
Other post-retirement benefits
Defined Benefit Plan Disclosure [Line Items]
Projected benefit obligation at January 1	547		508
Current service cost	11		8		6
Interest cost	21		21		23
Actuarial loss/(gain)	(50)		40
Amendments
Benefits paid	(26)	[1]	(30)	[1]
Projected benefit obligation at December 31	503		547		508

[1] Benefit payments for funded and unfunded plans.

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Other Long-Term Obligations (Parenthetical) (Detail) (CAD) In Millions, unless otherwise specified	Dec. 31, 2013	Dec. 31, 2012
Schedule of Other Liabilities [Line Items]
Employee retirement benefits obligations in current liabilities	53	52
Asset retirement obligations and other environmental liabilities in current liabilities	154	168

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Pension Plan with Accumulated Benefit Obligation in Excess of Plan Assets (Detail) (CAD) In Millions, unless otherwise specified	Dec. 31, 2013	Dec. 31, 2012
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	5,872	5,114
Funded Pension Plans
Defined Benefit Plan Disclosure [Line Items]
Projected benefit obligation		6,716
Accumulated benefit obligation		6,025
Fair value of plan assets		5,114
Accumulated benefit obligation less fair value of plan assets		911
Unfunded Pension Plans
Defined Benefit Plan Disclosure [Line Items]
Projected benefit obligation	574	620
Accumulated benefit obligation	496	535

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Income Taxes (Detail) (CAD) In Millions, unless otherwise specified	12 Months Ended
	Dec. 31, 2013		Dec. 31, 2012		Dec. 31, 2011
Schedule Of Income Tax [Line Items]
Current income tax expense	425		593		955
Deferred income tax expense	484	[1]	634	[1]	80	[1]
Total income tax expense	909	[2]	1,227	[2]	1,035	[2]
Statutory corporate tax rate (percent)	25.40%		25.50%		25.40%
Enacted tax rate change
Other	(1.10%)		(0.90%)		(1.90%)
Effective income tax rate	24.30%		24.60%		23.50%

[1] 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 2013, 2012 and 2011.

[2] Cash outflow from income taxes, plus investment credits earned, was $911 million in 2013 (2012 - $871 million, 2011 - $667 million).

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Consolidated Statement of Cash Flows (U.S. GAAP) (Parenthetical) (CAD) In Millions, unless otherwise specified	12 Months Ended
	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
Included contribution to registered pension plans	600	594	361

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Estimated 2014 Amortization from Accumulated Other Comprehensive Income (Detail) (CAD) In Millions, unless otherwise specified	12 Months Ended
	Dec. 31, 2013
Pension benefits
Defined Benefit Plan Disclosure [Line Items]
Net actuarial loss/(gain)	169	[1]
Prior service cost	23	[2]
Other post-retirement benefits
Defined Benefit Plan Disclosure [Line Items]
Net actuarial loss/(gain)	5	[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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Acquisition (Tables)

12 Months Ended

Dec. 31, 2013

Summary of Assets Acquired and Liabilities Assumed

The following table summarizes the assets acquired and liabilities assumed:

millions of dollars
Cash	6
Accounts receivable	38
Materials, supplies and prepaid expenses	5
Property, plant and equipment (a)	2,045
Goodwill (b)	20
Total assets acquired	2,114
Accounts payable and accrued liabilities	62
Deferred income tax liabilities (c)	377
Other long-term obligations	67
Total liabilities assumed	506
Net assets acquired	1,608

(a) Property, plant and equipment were measured primarily using an income approach. The fair value measurements of the oil and gas assets were based, in part, on significant inputs not observable in the market and thus represent a Level 3 measurement. The significant inputs included Celtic resources, assumed future production profiles, commodity prices (mainly based on observable market inputs), risk adjusted discount rate of 10 percent, inflation of 2 percent and assumptions on the timing and amount of future development and operating costs. The property, plant and equipment additions were segmented to the Upstream business, with all of the assets in Canada.

(b) Goodwill was the excess of the consideration transferred over the net assets recognized and represents the future economic benefits arising from other assets acquired that could not be individually identified and separately recognized. Goodwill was recognized in the Upstream reporting unit. Goodwill is not amortized and is not deductible for tax purposes.

(c) Deferred income taxes reflect the future tax consequences on the temporary differences between the amount of assets and liabilities recognized for financial reporting purposes and such amounts recognized for tax purposes. The deferred income taxes recorded as part of the acquisition were:

millions of dollars
Property, plant and equipment	414
Total deferred income tax liabilities	414
Asset retirement obligations	(17	)
Other	(20	)
Total deferred income tax assets	(37	)
Net deferred income tax liabilities	377

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Business segments (Tables)

12 Months Ended

Dec. 31, 2013

Business Segments

Assets and liabilities that are not identifiable by segment are allocated.

	Upstream									Downstream									Chemical
millions of dollars	2013			2012			2011			2013			2012			2011			2013			2012			2011
Revenues and other income
Operating revenues (a)		6,016			4,674			5,278			25,450			25,077			23,909			1,256			1,302			1,287
Intersegment sales		4,026			4,110			4,460			1,978			2,603			2,784			318			299			354
Investment and other income		145			46			168			59			81			63			-			-			-
		10,187			8,830			9,906			27,487			27,761			26,756			1,574			1,601			1,641
Expenses
Exploration		123			83			92			-			-			-			-			-			-
Purchases of crude oil and products		3,778			3,056			3,581			21,628			21,316			21,642			1,065			1,115			1,222
Production and manufacturing (b)		3,389			2,704			2,484			1,695			1,569			1,451			210			185			179
Selling and general		5			1			7			886			935			973			66			67			64
Federal excise tax		-			-			-			1,423			1,338			1,320			-			-			-
Depreciation and depletion (b)		636			498			528			452			242			214			12			12			13
Financing costs (note 12)		9			(1	)		2			2			-			(1	)		-			-			-
Total expenses		7,940			6,341			6,694			26,086			25,400			25,599			1,353			1,379			1,478
Income before income taxes		2,247			2,489			3,212			1,401			2,361			1,157			221			222			163
Income taxes (note 3)
Current		(14	)		72			593			395			486			372			62			67			43
Deferred		549			529			162			(46	)		103			(99	)		(3	)		(10	)		(2	)
Total income tax expense		535			601			755			349			589			273			59			57			41
Net income		1,712			1,888			2,457			1,052			1,772			884			162			165			122
Cash flows from (used in) operating activities		1,690			2,625			3,252			1,453			1,961			1,315			198			127			53
Capital and exploration expenditures (c)		7,755			5,518			3,880			187			140			166			9			4			4
Property, plant and equipment
Cost		38,819			30,602			25,327			7,146			7,038			6,990			771			765			760
Accumulated depreciation and depletion		(10,749	)		(10,146	)		(9,747	)		(4,347	)		(3,967	)		(3,803	)		(586	)		(576	)		(560	)
Net property, plant and equipment (d)		28,070			20,456			15,580			2,799			3,071			3,187			185			189			200
Total assets (e)		30,553			22,317			17,222			5,732			6,409			6,700			397			372			397
	Corporate and Other									Eliminations									Consolidated
millions of dollars	2013			2012			2011			2013			2012			2011			2013			2012			2011
Revenues and other income
Operating revenues (a)		-			-			-			-			-			-			32,722			31,053			30,474
Intersegment sales		-			-			-			(6,322	)		(7,012	)		(7,598	)		-			-			-
Investment and other income		3			8			9			-			-			-			207			135			240
		3			8			9			(6,322	)		(7,012	)		(7,598	)		32,929			31,188			30,714
Expenses
Exploration		-			-			-			-			-			-			123			83			92
Purchases of crude oil and products		-			-			-			(6,316	)		(7,011	)		(7,598	)		20,155			18,476			18,847
Production and manufacturing (b)		-			-			-			(6	)		(1	)		-			5,288			4,457			4,114
Selling and general		125			78			124			-			-			-			1,082			1,081			1,168
Federal excise tax		-			-			-			-			-			-			1,423			1,338			1,320
Depreciation and depletion (b)		10			9			9			-			-			-			1,110			761			764
Financing costs (note 12)		-			-			2			-			-			-			11			(1	)		3
Total expenses		135			87			135			(6,322	)		(7,012	)		(7,598	)		29,192			26,195			26,308
Income before income taxes		(132	)		(79	)		(126	)		-			-			-			3,737			4,993			4,406
Income taxes (note 3)
Current		(18	)		(32	)		(53	)		-			-			-			425			593			955
Deferred		(16	)		12			19			-			-			-			484			634			80
Total income tax expense		(34	)		(20	)		(34	)		-			-			-			909			1,227			1,035
Net income		(98	)		(59	)		(92	)		-			-			-			2,828			3,766			3,371
Cash flows from (used in) operating activities		(49	)		(33	)		(131	)		-			-			-			3,292			4,680			4,489
Capital and exploration expenditures (c)		69			21			16			-			-			-			8,020			5,683			4,066
Property, plant and equipment
Cost		429			360			339			-			-			-			47,165			38,765			33,416
Accumulated depreciation and depletion		(163	)		(154	)		(144	)		-			-			-			(15,845	)		(14,843	)		(14,254	)
Net property, plant and equipment (d)		266			206			195			-			-			-			31,320			23,922			19,162
Total assets (e)		581			704			1,418			(45	)		(438	)		(308	)		37,218			29,364			25,429

(a) Includes export sales to the United States of $5,217 million (2012 - $4,358 million, 2011 - $4,175 million). Export sales to the United States were recorded in all operating segments, with the largest effects in the Upstream segment.

(b) A 2013 charge in the Downstream segment of $377 million ($280 million, after-tax) associated with the company’s decision to convert the Dartmouth refinery to a terminal included the write-down of refinery plant and equipment not included in the terminal conversion of $245 million, reported as part of depreciation and depletion expenses, and decommissioning, environmental and employee-related costs of $132 million, reported as part of production and manufacturing expenses. By the end of 2013, amounts incurred associated with decommissioning, environmental and employee-related costs totalled $40 million.

(c) Capital and exploration expenditures (CAPEX) include exploration expenses, additions to property, plant, equipment and intangibles and additions to capital leases.

(d) Includes property, plant and equipment under construction of $9,234 million (2012 - $13,846 million).

(e) The majority of the goodwill has been assigned to the Downstream segment. Goodwill of $20 million was recognized in 2013 in the Upstream segment as a result of the Celtic acquisition (note 18). There have been no goodwill impairment losses or write-offs due to sales in the past three years. Fair value used in quantitative goodwill impairment tests was Level 3 (unobservable inputs).

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Summary of significant accounting policies (Policies)

12 Months Ended

Dec. 31, 2013

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. Significant subsidiaries included in the consolidated financial statements include Imperial Oil Resources Limited, Imperial Oil Resources N.W.T. Limited, Imperial Oil Resources Ventures Limited and McColl-Frontenac Petroleum Inc. All of the above companies are wholly owned. 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 project.

Inventories

Inventories

Inventories are recorded at the lower of cost or current market value. 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 final storage prior to delivery to a customer. 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

Property, plant and equipment are recorded at cost. Investment tax credits and other similar grants are treated as a reduction of the capitalized cost of the asset to which they apply.

The company uses the successful-efforts method to account for its exploration and development activities. Under this method, costs are accumulated on a field-by-field basis with certain exploratory expenditures and exploratory dry holes being expensed as incurred. Costs of productive wells and development dry holes are capitalized and amortized using the unit-of-production method. The company carries as an asset exploratory well costs 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. Other exploratory expenditures, including geophysical costs and annual lease rentals are expensed as incurred.

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.

Production involves lifting the oil and gas to the surface and gathering, treating, field processing and field storage of the oil and gas. The production function normally terminates at the outlet valve on the lease or field production storage tank. Production costs are those incurred to operate and maintain the company’s wells and related equipment and facilities and are expensed as incurred. They become part of the cost of oil and gas produced. These costs, sometimes referred to as lifting costs, include such items as labour cost to operate the wells and related equipment; repair and maintenance costs on the wells and equipment; materials, supplies and energy costs required to operate the wells and related equipment; and administrative expenses related to the production activity.

Acquisition costs of proved properties are amortized using a unit-of-production method, computed on the basis of total proved oil and gas reserves. 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. Unit-of-production depreciation is applied to those wells, plant and equipment assets associated with productive depletable properties, and the unit-of-production rates are based on the amount of proved developed reserves of oil and gas. Investments in extraction and upgrading facilities at oil sands mining properties are depreciated on a unit-of-production method based on proved developed reserves. Investments in mining and transportation systems at oil sands mining properties are depreciated on a straight-line basis over a maximum of 15 years. Depreciation of other plant and equipment is calculated using the straight-line method, based on the estimated service life of the asset. In general, refineries are depreciated over 25 years; other major assets, including chemical plants and service stations, are depreciated over 20 years.

Proved oil and gas properties held and used by the company are reviewed for impairment whenever events or changes in circumstances indicate that the carrying amounts may not be recoverable. 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.

The company estimates the future undiscounted cash flows of the affected properties to judge the recoverability of carrying amounts. Cash flows used in impairment evaluations are developed using annually updated corporate plan investment evaluation assumptions for crude oil and natural gas commodity prices and foreign-currency exchange rates. Annual volumes are based on field production profiles, which are also updated annually.

Impairment analyses are generally based on reserve estimates used for internal planning and capital investment decisions. Where probable reserves exist, an appropriately risk-adjusted amount of these reserves may be included in the impairment evaluation. An asset group would be impaired if the undiscounted cash flows were less than its carrying value. Impairments are measured by the amount the carrying value exceeds fair value.

Significant unproved properties are assessed for impairment individually and valuation allowances against the capitalized costs are recorded based on the estimated economic chance of success and the length of time 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 valuation allowances are reviewed at least annually.

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 relating to major capital projects under construction are capitalized as part of property, plant and equipment. 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 and marketing 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 liabilities 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.

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 or 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.

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.

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 72 for further details.

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.

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Assumptions Used to Determine Periodic Benefit Cost (Detail)	12 Months Ended
	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
Defined Benefit Plan Disclosure [Line Items]
Long-term rate of return on funded assets	6.25%
Pension benefits
Defined Benefit Plan Disclosure [Line Items]
Discount rate	3.75%	4.25%	5.50%
Long-term rate of return on funded assets	6.25%	6.25%	7.00%
Long-term rate of compensation increase	4.50%	4.50%	4.50%
Other post-retirement benefits
Defined Benefit Plan Disclosure [Line Items]
Discount rate	3.75%	4.25%	5.50%
Long-term rate of compensation increase	4.50%	4.50%	4.50%

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Summary of significant accounting policies - Additional Information (Detail)	12 Months Ended
	Dec. 31, 2013 Y
Significant Accounting Policies [Line Items]
Estimated service life of the asset refineries, in years	25
Estimated service life of other major assets, in years	20
Amortization of computer software development costs, in years	15
Amortization of customer lists, in years	10 years
Maximum
Significant Accounting Policies [Line Items]
Investments in mining and transportation systems at oil sands mining properties, useful life	15 years
Syncrude Joint Venture
Significant Accounting Policies [Line Items]
Undivided interest in oil and gas activities	25.00%
Kearl Project
Significant Accounting Policies [Line Items]
Undivided interest in oil and gas activities	70.96%

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Income taxes (Tables)

12 Months Ended

Dec. 31, 2013

Summary of Income Tax Expense (Benefit)

millions of dollars	2013		2012		2011
Current income tax expense		425		593		955
Deferred income tax expense (a)		484		634		80
Total income tax expense (b)		909		1,227		1,035
Statutory corporate tax rate (percent)		25.4		25.5		25.4
Increase/(decrease) resulting from:
Enacted tax rate change				-		-
Other		(1.1)		(0.9)		(1.9)
Effective income tax rate		24.3		24.6		23.5

(a) 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 2013, 2012 and 2011.

(b) Cash outflow from income taxes, plus investment credits earned, was $911 million in 2013 (2012 – $871 million, 2011 – $667 million).

Components of Deferred Income Tax Liabilities and Assets

Components of deferred income tax liabilities and assets as at December 31 were:

millions of dollars	2013			2012			2011
Depreciation and amortization		2,949			2,434			1,948
Successful drilling and land acquisitions		815			399			378
Pension and benefits		(376	)		(717	)		(720	)
Site restoration		(287	)		(284	)		(267	)
Capitalized interest		69			53			50
Other		(99	)		39			51
Net long-term deferred income tax liabilities		3,071			1,924			1,440
LIFO inventory valuation		(450	)		(478	)		(560	)
Other		(109	)		(49	)		(30	)
Net current deferred income tax assets		(559	)		(527	)		(590	)
Valuation allowance		-			-			-
Net deferred income tax liabilities		2,512			1,397			850

Unrecognized Tax Benefits

The following table summarizes the movement in unrecognized tax benefits:

millions of dollars	2013			2012			2011
Balance as at January 1		143			134			147
Additions based on current year’s tax position		10			4			-
Additions for prior years’ tax positions		2			10			20
Reductions for prior years’ tax positions		(4	)		(3	)		(31	)
Reductions due to lapse of the statute of limitations		-			(2	)		(2	)
Balance as at December 31		151			143			134

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Employee retirement benefits (Tables)

12 Months Ended

Dec. 31, 2013

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
	2013			2012			2013			2012
Assumptions used to determine benefit obligations at December 31 (percent)
Discount rate		4.75			3.75			4.75			3.75
Long-term rate of compensation increase		4.50			4.50			4.50			4.50
millions of dollars
Change in projected benefit obligation
Projected benefit obligation at January 1		7,336			6,646			547			508
Current service cost		181			160			11			8
Interest cost		281			288			21			21
Actuarial loss/(gain)		(504	)		616			(50	)		40
Amendments		-			-			-			-
Benefits paid (a)		(424	)		(374	)		(26	)		(30	)
Projected benefit obligation at December 31		6,870			7,336			503			547
Accumulated benefit obligation at December 31		6,263			6,560

Change in Plan Assets of Pension and Other Postretirement Benefits

	Pension benefits						Other post-retirement benefits
millions of dollars	2013			2012			2013			2012
Change in plan assets
Fair value at January 1		5,114			4,461
Actual return/(loss) on plan assets		491			374
Company contributions		600			594
Benefits paid (b)		(333	)		(315	)
Fair value at December 31		5,872			5,114
Plan assets in excess of/(less than) projected benefit obligation at December 31
Funded plans		(424	)		(1,602	)
Unfunded plans		(574	)		(620	)		(503	)		(547	)
Total (c)		(998	)		(2,222	)		(503	)		(547	)

(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 dollars	2013			2012			2013			2012
Amounts recorded in the consolidated balance sheet consist of:
Current liabilities		(25	)		(24	)		(28	)		(28	)
Other long-term obligations		(973	)		(2,198	)		(475	)		(519	)
Total recorded		(998	)		(2,222	)		(503	)		(547	)
Amounts recorded in accumulated other comprehensive income consist of:
Net actuarial loss/(gain)		2,303			3,210			64			124
Prior service cost		62			85			-			-
Total recorded in accumulated other comprehensive income, before tax		2,365			3,295			64			124

Assumptions Used to Determine Periodic Benefit Cost

	Pension benefits									Other post-retirement benefits
	2013			2012			2011			2013			2012			2011
Assumptions used to determine net periodic benefit cost for years ended December 31 (percent)
Discount rate		3.75			4.25			5.50			3.75			4.25			5.50
Long-term rate of return on funded assets		6.25			6.25			7.00			-			-			-
Long-term rate of compensation increase		4.50			4.50			4.50			4.50			4.50			4.50
millions of dollars
Components of net periodic benefit cost
Current service cost		181			160			122			11			8			6
Interest cost		281			288			314			21			21			23
Expected return on plan assets		(331	)		(288	)		(308	)		-			-			-
Amortization of prior service cost		23			23			21			-			-			-
Amortization of actuarial loss/(gain)		243			235			162			10			8			3
Net periodic benefit cost		397			418			311			42			37			32
Changes in amounts recorded in accumulated other comprehensive income
Net actuarial loss/(gain)		(664	)		530			1,112			(50	)		40			81
Amortization of net actuarial (loss)/gain included in net periodic benefit cost		(243	)		(235	)		(162	)		(10	)		(8	)		(3	)
Prior service cost		-			-			86			-			-			-
Amortization of prior service cost included in net periodic benefit cost		(23	)		(23	)		(21	)		-			-			-
Total recorded in other comprehensive income		(930	)		272			1,015			(60	)		32			78
Total recorded in net periodic benefit cost and other comprehensive income, before tax		(533	)		690			1,326			(18	)		69			110

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 dollars	2013			2012			2011
(Charge)/credit to other comprehensive income, before tax		990			(304	)		(1,093	)
Deferred income tax (charge)/credit (note 17)		(256	)		87			279
(Charge)/credit to other comprehensive income, after tax		734			(217	)		(814	)

Fair Value of Pension Plan Assets Including Level within Fair Value Hierarchy

The 2013 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, 2013, using:
millions of dollars	Total		Quoted prices in active markets for identical assets (Level 1)		Significant other observable inputs (Level 2)			Significant unobservable inputs (Level 3)
Asset class
Equity securities
Canadian		932				932	(a)
Non-Canadian		1,911				1,911	(a)
Debt securities - Canadian
Corporate		654				654	(b)
Government		2,161				2,161	(b)
Asset backed		-
Mortgage funds		1							1	(c)
Equities – Venture capital		188							188	(d)
Cash		25		12		13	(e)
Total plan assets at fair value		5,872		12		5,671			189

(a) For company equity securities held in the form of fund units that are redeemable at the measurement date, the unit value is treated as a Level 2 input. The fair value of the securities owned by the funds is based on observable quoted prices on active exchanges, which are Level 1 inputs.

(b) For corporate, government and asset-backed debt securities, fair value is based on observable inputs of comparable market transactions.

(c) For mortgage funds, fair value represents the principal outstanding which is guaranteed by Canada Mortgage and Housing Corporation.

(d) For venture capital partnership investments, fair value is generally established by using revenue or earnings multiples or other relevant market data including Initial Public Offerings.

(e) For cash balances that are held in Level 2 funds prior to investment in those fund units, the cash value is treated as a Level 2 input.

The 2012 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, 2012, using:
millions of dollars	Total		Quoted prices in active markets for identical assets (Level 1)		Significant other observable inputs (Level 2)			Significant unobservable inputs (Level 3)
Asset class
Equity securities
Canadian		811				811	(a)
Non-Canadian		1,657				1,657	(a)
Debt securities - Canadian
Corporate		473				473	(b)
Government		1,982				1,982	(b)
Asset backed		5				5	(b)
Mortgage funds		1							1	(c)
Equities – Venture capital		158							158	(d)
Cash		27		9		18	(e)
Total plan assets at fair value		5,114		9		4,946			159

(a) For company equity securities held in the form of fund units that are redeemable at the measurement date, the unit value is treated as a Level 2 input. The fair value of the securities owned by the funds is based on observable quoted prices on active exchanges, which are Level 1 inputs.

(b) For corporate, government and asset-backed debt securities, fair value is based on observable inputs of comparable market transactions.

(c) For mortgage funds, fair value represents the principal outstanding which is guaranteed by Canada Mortgage and Housing Corporation.

(d) For venture capital partnership investments, fair value is generally established by using revenue or earnings multiples or other relevant market data including Initial Public Offerings.

(e) For cash balances that are held in Level 2 funds prior to investment in those fund units, the cash value is treated as a Level 2 input.

Change in Fair Value of Level 3 Assets

The change in the fair value of Level 3 assets, which use significant unobservable inputs to measure fair value, is shown in the table below:

millions of dollars	Mortgage funds		Venture capital
Fair value at January 1, 2013		1		158
Net realized gains/(losses)		-		(17	)
Net unrealized gains/(losses)		-		44
Net purchases/(sales)		-		3
Fair value at December 31, 2013		1		188

The change in the fair value of Level 3 assets, which use significant unobservable inputs to measure fair value, is shown in the table below:

millions of dollars	Mortgage funds		Venture capital
Fair value at January 1, 2012		1		148
Net realized gains/(losses)		-		(11	)
Net unrealized gains/(losses)		-		8
Net purchases/(sales)		-		13
Fair value at December 31, 2012		1		158

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 dollars	2013		2012
For funded pension plans with accumulated benefit obligations in excess of plan assets:
Projected benefit obligation		-		6,716
Accumulated benefit obligation		-		6,025
Fair value of plan assets		-		5,114
Accumulated benefit obligation less fair value of plan assets		-		911
For unfunded plans covered by book reserves:
Projected benefit obligation		574		620
Accumulated benefit obligation		496		535

Estimated 2014 Amortization from Accumulated Other Comprehensive Income

Estimated 2014 amortization from accumulated other comprehensive income
millions of dollars	Pension benefits		Other post-retirement benefits
Net actuarial loss/(gain) (a)		169		5
Prior service cost (b)		23		-

(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

Cash flows
Benefit payments expected in:
millions of dollars	Pension benefits		Other post-retirement benefits
2014		365		28
2015		375		28
2016		384		28
2017		393		28
2018		401		28
2019 - 2023		2,078		145

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 dollars	One percent increase			One percent decrease
Rate of return on plan assets:
Effect on net benefit cost, before tax		(50	)		50
Discount rate:
Effect on net benefit cost, before tax		(80	)		100
Effect on benefit obligation		(850	)		1,050
Rate of pay increases:
Effect on net benefit cost, before tax		50			(45	)
Effect on benefit obligation		170			(150	)

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 dollars	One percent increase		One percent decrease
Effect on service and interest cost components		4		(3	)
Effect on benefit obligation		45		(35	)

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Consolidated Statement of Cash Flows (U.S. GAAP) (CAD) In Millions, unless otherwise specified	12 Months Ended
	Dec. 31, 2013		Dec. 31, 2012		Dec. 31, 2011
Operating activities
Net income	2,828		3,766		3,371
Adjustments for non-cash items:
Depreciation and depletion	1,110	[1]	761	[1]	764	[1]
(Gain)/loss on asset sales	(150)	[2]	(94)	[2]	(197)	[2]
Deferred income taxes and other	482		619		71
Changes in operating assets and liabilities:
Accounts receivable	(74)		300		(302)
Inventories, materials, supplies and prepaid expenses	(260)		(106)		(228)
Income taxes payable	(457)		(84)		390
Accounts payable and accrued liabilities	191		(67)		846
All other items - net	(378)	[3]	(415)	[3]	(226)	[3]
Cash flows from (used in) operating activities	3,292		4,680		4,489
Investing activities
Additions to property, plant and equipment	(6,297)		(5,478)		(3,919)
Acquisition (note 18)	(1,602)
Proceeds from asset sales	160		226		314
Repayment of loan from equity company	4		14		12
Cash flows from (used in) investing activities	(7,735)		(5,238)		(3,593)
Financing activities
Short-term debt - net	1,371		105		135
Long-term debt issued	3,276		220		320
Reduction in capitalized lease obligations	(7)		(4)		(3)
Issuance of common shares under stock option plan			43		19
Common shares purchased (note 10)			(128)		(59)
Dividends paid	(407)		(398)		(373)
Cash flows from (used in) financing activities	4,233		(162)		39
Increase (decrease) in cash	(210)		(720)		935
Cash at beginning of year	482	[4]	1,202	[4]	267
Cash at end of year	272	[4]	482	[4]	1,202	[4]

[1] A 2013 charge in the Downstream segment of $377 million ($280 million, after-tax) associated with the company's decision to convert the Dartmouth refinery to a terminal included the write-down of refinery plant and equipment not included in the terminal conversion of $245 million, reported as part of depreciation and depletion expenses, and decommissioning, environmental and employee-related costs of $132 million, reported as part of production and manufacturing expenses. By the end of 2013, amounts incurred associated with decommissioning, environmental and employee-related costs totalled $40 million.

[2] 2013 included a gain of $85 million ($73 million after tax) for the sale of non-operating assets.

[3] Includes contribution to registered pension plans of $600 million (2012 - $594 million, 2011 - $361 million).

[4] 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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Other long-term obligations (Tables)

12 Months Ended

Dec. 31, 2013

Other Long-Term Obligations

millions of dollars	2013		2012
Employee retirement benefits (note 4)(a)		1,448		2,717
Asset retirement obligations and other environmental liabilities (b)		1,258		957
Share-based incentive compensation liabilities (note 7)		140		117
Other obligations		245		192
Total other long-term obligations		3,091		3,983

(a) Total recorded employee retirement benefit obligations also include $53 million in current liabilities (2012 – $52 million).

(b) Total asset retirement obligations and other environmental liabilities also include $154 million in current liabilities (2012 – $168 million).

Schedule of Asset Retirement Obligations

The following table summarizes the activity in the liability for asset retirement obligations:

millions of dollars	2013			2012
Balance as at January 1		966			936
Additions		251			61
Reductions due to property sales		-			(8	)
Accretion		105			86
Settlement		(85	)		(109	)
Balance as at December 31		1,237			966

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Financing costs and additional notes and loans payable information (Parenthetical) (Detail) (CAD) In Millions, unless otherwise specified	12 Months Ended
	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
Cash interest payments	69	20	16
Weighted average interest rate on short-term borrowings	1.10%	1.10%

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Long-term debt (Tables)

12 Months Ended

Dec. 31, 2013

Long-Term Debt

millions of dollars	As at Dec. 31 2013		As at Dec. 31 2012
Long-term debt (a)		4,316		1,040
Capital leases (b)		128		135
Total long-term debt		4,444		1,175

(a) Borrowed 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 $5 billion (Canadian) 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. Average effective rate for the loan was 1.3 percent in 2013.

(b) Capitalized lease obligations primarily relate to capital leases for pipeline transportation and marine services agreements. The average imputed rate was 7.0 percent in 2013 (2012 – 9.6 percent). Total capitalized lease obligations also include $7 million in current liabilities (2012 - $7 million). Principal payments on capital leases of approximately $7 million per year are due in each of the next four years after December 31, 2014.

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Employee Retirement Benefits - Additional Information (Detail) (CAD) In Millions, unless otherwise specified	12 Months Ended			120 Months Ended	240 Months Ended
	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011	Dec. 31, 2013	Dec. 31, 2013
Defined Benefit Plan Disclosure [Line Items]
Health care cost trend rate assumed in 2014	4.50%
Long-term expected return	6.25%
Actual rate of return				6.50%	8.00%
Cost for defined contributions plans	37	36	36
Plan assets invested in venture capital partnerships	5.00%
Cash contributions to pension plans	420
Equity Securities
Defined Benefit Plan Disclosure [Line Items]
Target allocation securities	46.00%
Debt Securities
Defined Benefit Plan Disclosure [Line Items]
Target allocation securities	49.00%

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Gains and Losses on Asset Sales (Parenthetical) (Detail) (CAD) In Millions, unless otherwise specified	12 Months Ended
	Dec. 31, 2013		Dec. 31, 2012		Dec. 31, 2011
Investment And Other Income [Line Items]
Gain/(loss) on asset sales, before tax	150	[1]	94	[1]	197	[1]
Gain/(loss) on asset sales, after tax	120	[1]	72	[1]	153	[1]
Non-Operating Assets
Investment And Other Income [Line Items]
Gain/(loss) on asset sales, before tax	85
Gain/(loss) on asset sales, after tax	73

[1] 2013 included a gain of $85 million ($73 million after tax) for the sale of non-operating assets.

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Consolidated Statement Of Income (U.S. GAAP) (CAD) In Millions, except Per Share data, unless otherwise specified	12 Months Ended
	Dec. 31, 2013		Dec. 31, 2012		Dec. 31, 2011
Revenues and other income
Operating revenues	32,722	[1],[2],[3]	31,053	[1],[2],[3]	30,474	[1],[2],[3]
Investment and other income (note 8)	207		135		240
Total revenues and other income	32,929		31,188		30,714
Expenses
Exploration	123		83		92
Purchases of crude oil and products	20,155	[4]	18,476	[4]	18,847	[4]
Production and manufacturing	5,288	[5],[6]	4,457	[5],[6]	4,114	[5],[6]
Selling and general	1,082		1,081		1,168
Federal excise tax	1,423	[1]	1,338	[1]	1,320	[1]
Depreciation and depletion	1,110	[6]	761	[6]	764	[6]
Financing costs (note 12)	11	[7]	(1)	[7]	3	[7]
Total expenses	29,192		26,195		26,308
Income before income taxes	3,737		4,993		4,406
Income taxes (note 3)	909	[8]	1,227	[8]	1,035	[8]
Net income	2,828		3,766		3,371
Per-share information (Canadian dollars)
Net income per common share - basic (note 10)	3.34		4.44		3.98
Net income per common share - diluted (note 10)	3.32		4.42		3.95
Dividends	0.49		0.48		0.44

[1] Operating revenues include federal excise tax of $1,423 million (2012 - $1,338 million, 2011 - $1,320 million).

[2] Operating revenues include amounts from related parties of $2,385 million (2012 - $2,907 million, 2011 - $2,818 million), (note 16).

[3] Includes export sales to the United States of $5,217 million (2012 - $4,358 million, 2011 - $4,175 million). Export sales to the United States were recorded in all operating segments, with the largest effects in the Upstream segment.

[4] Purchases of crude oil and products include amounts from related parties of $4,104 million (2012 - $3,033 million, 2011 - $3,636 million), (note 16).

[5] Production and manufacturing expenses include amounts to related parties of $319 million (2012 - $241 million, 2011 - $217 million), (note 16).

[6] A 2013 charge in the Downstream segment of $377 million ($280 million, after-tax) associated with the company's decision to convert the Dartmouth refinery to a terminal included the write-down of refinery plant and equipment not included in the terminal conversion of $245 million, reported as part of depreciation and depletion expenses, and decommissioning, environmental and employee-related costs of $132 million, reported as part of production and manufacturing expenses. By the end of 2013, amounts incurred associated with decommissioning, environmental and employee-related costs totalled $40 million.

[7] Cash interest payments in 2013 were $69 million (2012 - $20 million, 2011 - $16 million). The weighted average interest rate on short-term borrowings in 2013 was 1.1 percent (2012 - 1.1 percent).

[8] Cash outflow from income taxes, plus investment credits earned, was $911 million in 2013 (2012 - $871 million, 2011 - $667 million).

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Business Segments (Detail) (CAD) In Millions, unless otherwise specified	12 Months Ended
	Dec. 31, 2013		Dec. 31, 2012		Dec. 31, 2011
Revenues and other income
Operating revenues	32,722	[1],[2],[3]	31,053	[1],[2],[3]	30,474	[1],[2],[3]
Investment and other income	207		135		240
Total revenues and other income	32,929		31,188		30,714
Expenses
Exploration	123		83		92
Purchases of crude oil and products	20,155	[4]	18,476	[4]	18,847	[4]
Production and manufacturing	5,288	[5],[6]	4,457	[5],[6]	4,114	[5],[6]
Selling and general	1,082		1,081		1,168
Federal excise tax	1,423	[1]	1,338	[1]	1,320	[1]
Depreciation and depletion	1,110	[6]	761	[6]	764	[6]
Financing costs (note 12)	11	[7]	(1)	[7]	3	[7]
Total expenses	29,192		26,195		26,308
Income before income taxes	3,737		4,993		4,406
Income taxes (note 3)
Current	425		593		955
Deferred	484	[8]	634	[8]	80	[8]
Total income tax expense	909	[9]	1,227	[9]	1,035	[9]
Net income	2,828		3,766		3,371
Cash flows from (used in) operating activities	3,292		4,680		4,489
Capital and exploration expenditures	8,020	[10]	5,683	[10]	4,066	[10]
Property, plant and equipment Cost	47,165		38,765		33,416
Accumulated depreciation and depletion	(15,845)		(14,843)		(14,254)
Net property, plant and equipment	31,320	[11]	23,922	[11]	19,162	[11]
Total assets	37,218	[12]	29,364	[12]	25,429	[12]
Upstream
Revenues and other income
Operating revenues	6,016	[3]	4,674	[3]	5,278	[3]
Intersegment sales	4,026		4,110		4,460
Investment and other income	145		46		168
TOTAL OPERATING REVENUES, INTERSEGMENT SALES, INVESTMENT AND OTHER INCOME	10,187		8,830		9,906
Expenses
Exploration	123		83		92
Purchases of crude oil and products	3,778		3,056		3,581
Production and manufacturing	3,389	[6]	2,704	[6]	2,484	[6]
Selling and general	5		1		7
Depreciation and depletion	636	[6]	498	[6]	528	[6]
Financing costs (note 12)	9		(1)		2
Total expenses	7,940		6,341		6,694
Income before income taxes	2,247		2,489		3,212
Income taxes (note 3)
Current	(14)		72		593
Deferred	549		529		162
Total income tax expense	535		601		755
Net income	1,712		1,888		2,457
Cash flows from (used in) operating activities	1,690		2,625		3,252
Capital and exploration expenditures	7,755	[10]	5,518	[10]	3,880	[10]
Property, plant and equipment Cost	38,819		30,602		25,327
Accumulated depreciation and depletion	(10,749)		(10,146)		(9,747)
Net property, plant and equipment	28,070	[11]	20,456	[11]	15,580	[11]
Total assets	30,553	[12]	22,317	[12]	17,222	[12]
Downstream
Revenues and other income
Operating revenues	25,450	[3]	25,077	[3]	23,909	[3]
Intersegment sales	1,978		2,603		2,784
Investment and other income	59		81		63
TOTAL OPERATING REVENUES, INTERSEGMENT SALES, INVESTMENT AND OTHER INCOME	27,487		27,761		26,756
Expenses
Purchases of crude oil and products	21,628		21,316		21,642
Production and manufacturing	1,695	[6]	1,569	[6]	1,451	[6]
Selling and general	886		935		973
Federal excise tax	1,423		1,338		1,320
Depreciation and depletion	452	[6]	242	[6]	214	[6]
Financing costs (note 12)	2				(1)
Total expenses	26,086		25,400		25,599
Income before income taxes	1,401		2,361		1,157
Income taxes (note 3)
Current	395		486		372
Deferred	(46)		103		(99)
Total income tax expense	349		589		273
Net income	1,052		1,772		884
Cash flows from (used in) operating activities	1,453		1,961		1,315
Capital and exploration expenditures	187	[10]	140	[10]	166	[10]
Property, plant and equipment Cost	7,146		7,038		6,990
Accumulated depreciation and depletion	(4,347)		(3,967)		(3,803)
Net property, plant and equipment	2,799	[11]	3,071	[11]	3,187	[11]
Total assets	5,732	[12]	6,409	[12]	6,700	[12]
Chemical
Revenues and other income
Operating revenues	1,256	[3]	1,302	[3]	1,287	[3]
Intersegment sales	318		299		354
TOTAL OPERATING REVENUES, INTERSEGMENT SALES, INVESTMENT AND OTHER INCOME	1,574		1,601		1,641
Expenses
Purchases of crude oil and products	1,065		1,115		1,222
Production and manufacturing	210	[6]	185	[6]	179	[6]
Selling and general	66		67		64
Depreciation and depletion	12	[6]	12	[6]	13	[6]
Total expenses	1,353		1,379		1,478
Income before income taxes	221		222		163
Income taxes (note 3)
Current	62		67		43
Deferred	(3)		(10)		(2)
Total income tax expense	59		57		41
Net income	162		165		122
Cash flows from (used in) operating activities	198		127		53
Capital and exploration expenditures	9	[10]	4	[10]	4	[10]
Property, plant and equipment Cost	771		765		760
Accumulated depreciation and depletion	(586)		(576)		(560)
Net property, plant and equipment	185	[11]	189	[11]	200	[11]
Total assets	397	[12]	372	[12]	397	[12]
Corporate and Other
Revenues and other income
Investment and other income	3		8		9
TOTAL OPERATING REVENUES, INTERSEGMENT SALES, INVESTMENT AND OTHER INCOME	3		8		9
Expenses
Selling and general	125		78		124
Depreciation and depletion	10	[6]	9	[6]	9	[6]
Financing costs (note 12)					2
Total expenses	135		87		135
Income before income taxes	(132)		(79)		(126)
Income taxes (note 3)
Current	(18)		(32)		(53)
Deferred	(16)		12		19
Total income tax expense	(34)		(20)		(34)
Net income	(98)		(59)		(92)
Cash flows from (used in) operating activities	(49)		(33)		(131)
Capital and exploration expenditures	69	[10]	21	[10]	16	[10]
Property, plant and equipment Cost	429		360		339
Accumulated depreciation and depletion	(163)		(154)		(144)
Net property, plant and equipment	266	[11]	206	[11]	195	[11]
Total assets	581	[12]	704	[12]	1,418	[12]
Consolidation, Eliminations
Revenues and other income
Intersegment sales	(6,322)		(7,012)		(7,598)
TOTAL OPERATING REVENUES, INTERSEGMENT SALES, INVESTMENT AND OTHER INCOME	(6,322)		(7,012)		(7,598)
Expenses
Purchases of crude oil and products	(6,316)		(7,011)		(7,598)
Production and manufacturing	(6)	[6]	(1)	[6]
Total expenses	(6,322)		(7,012)		(7,598)
Income taxes (note 3)
Total assets	(45)	[12]	(438)	[12]	(308)	[12]

[1] Operating revenues include federal excise tax of $1,423 million (2012 - $1,338 million, 2011 - $1,320 million).

[2] Operating revenues include amounts from related parties of $2,385 million (2012 - $2,907 million, 2011 - $2,818 million), (note 16).

[3] Includes export sales to the United States of $5,217 million (2012 - $4,358 million, 2011 - $4,175 million). Export sales to the United States were recorded in all operating segments, with the largest effects in the Upstream segment.

[4] Purchases of crude oil and products include amounts from related parties of $4,104 million (2012 - $3,033 million, 2011 - $3,636 million), (note 16).

[5] Production and manufacturing expenses include amounts to related parties of $319 million (2012 - $241 million, 2011 - $217 million), (note 16).

[6] A 2013 charge in the Downstream segment of $377 million ($280 million, after-tax) associated with the company's decision to convert the Dartmouth refinery to a terminal included the write-down of refinery plant and equipment not included in the terminal conversion of $245 million, reported as part of depreciation and depletion expenses, and decommissioning, environmental and employee-related costs of $132 million, reported as part of production and manufacturing expenses. By the end of 2013, amounts incurred associated with decommissioning, environmental and employee-related costs totalled $40 million.

[7] Cash interest payments in 2013 were $69 million (2012 - $20 million, 2011 - $16 million). The weighted average interest rate on short-term borrowings in 2013 was 1.1 percent (2012 - 1.1 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 2013, 2012 and 2011.

[9] Cash outflow from income taxes, plus investment credits earned, was $911 million in 2013 (2012 - $871 million, 2011 - $667 million).

[10] Capital and exploration expenditures (CAPEX) include exploration expenses, additions to property, plant, equipment and intangibles and additions to capital leases.

[11] Includes property, plant and equipment under construction of $9,234 million (2012 - $13,846 million).

[12] The majority of the goodwill has been assigned to the Downstream segment. Goodwill of $20 million was recognized in 2013 in the Upstream segment as a result of the Celtic acquisition (note 18). There have been no goodwill impairment losses or write-offs due to sales in the past three years. Fair value used in quantitative goodwill impairment tests was Level 3 (unobservable inputs).

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Income Tax Expense/(Credit) for Components of Other Comprehensive Income (Detail) (CAD) In Millions, unless otherwise specified	12 Months Ended
	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
Accumulated Other Comprehensive Income (Loss) [Line Items]
Post-retirement benefits liability adjustment (excluding amortization)	185	(155)	(326)
Amortization of post-retirement benefits liability adjustment included in net periodic benefit cost	71	68	47
Total	256	(87)	(279)

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Consolidated Balance Sheet (U.S. GAAP) (Parenthetical) (CAD) In Millions, except Share data in Thousands, unless otherwise specified	Dec. 31, 2013	Dec. 31, 2012
Due to related parties, current	75
Amounts (payable) receivable from related parties	(170)	9
Due to related parties, noncurrent	4,316	1,040
Common shares outstanding	847,599	847,599

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Changes in Accumulated Other Comprehensive Income (Detail) (CAD) In Millions, unless otherwise specified	12 Months Ended
	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
Accumulated Other Comprehensive Income (Loss) [Line Items]
Balance as at January 1	(2,455)	(2,238)	(1,424)
Current period change excluding amounts reclassified from accumulated other comprehensive income	529	(415)	(953)
Amounts reclassified from accumulated other comprehensive income	205	198	139
Balance as at December 31	(1,721)	(2,455)	(2,238)

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Fair Value of Pension Plan Assets Including Level Within Fair Value Hierarchy (Detail) (CAD) In Millions, unless otherwise specified	Dec. 31, 2013		Dec. 31, 2012
Defined Benefit Plan Disclosure [Line Items]
Total plan assets at fair value	5,872		5,114
Canadian Equity Securities
Defined Benefit Plan Disclosure [Line Items]
Total plan assets at fair value	932		811
Non-Canadian Equity Securities
Defined Benefit Plan Disclosure [Line Items]
Total plan assets at fair value	1,911		1,657
Corporate Debt Securities
Defined Benefit Plan Disclosure [Line Items]
Total plan assets at fair value	654		473
Government Debt Securities
Defined Benefit Plan Disclosure [Line Items]
Total plan assets at fair value	2,161		1,982
Asset Backed Debt Securities
Defined Benefit Plan Disclosure [Line Items]
Total plan assets at fair value			5
Mortgage Funds
Defined Benefit Plan Disclosure [Line Items]
Total plan assets at fair value	1		1
Equities - Venture Capital
Defined Benefit Plan Disclosure [Line Items]
Total plan assets at fair value	188		158
Cash
Defined Benefit Plan Disclosure [Line Items]
Total plan assets at fair value	25		27
Quoted Prices In Active Markets For Identical Assets (Level 1)
Defined Benefit Plan Disclosure [Line Items]
Total plan assets at fair value	12		9
Quoted Prices In Active Markets For Identical Assets (Level 1) | Cash
Defined Benefit Plan Disclosure [Line Items]
Total plan assets at fair value	12		9
Significant Other Observable Inputs (Level 2)
Defined Benefit Plan Disclosure [Line Items]
Total plan assets at fair value	5,671		4,946
Significant Other Observable Inputs (Level 2) | Canadian Equity Securities
Defined Benefit Plan Disclosure [Line Items]
Total plan assets at fair value	932	[1]	811	[1]
Significant Other Observable Inputs (Level 2) | Non-Canadian Equity Securities
Defined Benefit Plan Disclosure [Line Items]
Total plan assets at fair value	1,911	[1]	1,657	[1]
Significant Other Observable Inputs (Level 2) | Corporate Debt Securities
Defined Benefit Plan Disclosure [Line Items]
Total plan assets at fair value	654	[2]	473	[2]
Significant Other Observable Inputs (Level 2) | Government Debt Securities
Defined Benefit Plan Disclosure [Line Items]
Total plan assets at fair value	2,161	[2]	1,982	[2]
Significant Other Observable Inputs (Level 2) | Asset Backed Debt Securities
Defined Benefit Plan Disclosure [Line Items]
Total plan assets at fair value			5	[2]
Significant Other Observable Inputs (Level 2) | Cash
Defined Benefit Plan Disclosure [Line Items]
Total plan assets at fair value	13	[3]	18	[3]
Significant Unobservable Inputs (Level 3)
Defined Benefit Plan Disclosure [Line Items]
Total plan assets at fair value	189		159
Significant Unobservable Inputs (Level 3) | Mortgage Funds
Defined Benefit Plan Disclosure [Line Items]
Total plan assets at fair value	1	[4]	1	[4]
Significant Unobservable Inputs (Level 3) | Equities - Venture Capital
Defined Benefit Plan Disclosure [Line Items]
Total plan assets at fair value	188	[5]	158	[5]

[1] For company equity securities held in the form of fund units that are redeemable at the measurement date, the unit value is treated as a Level 2 input. The fair value of the securities owned by the funds is based on observable quoted prices on active exchanges, which are Level 1 inputs.

[2] For corporate, government and asset-backed debt securities, fair value is based on observable inputs of comparable market transactions.

[3] For cash balances that are held in Level 2 funds prior to investment in those fund units, the cash value is treated as a Level 2 input.

[4] For mortgage funds, fair value represents the principal outstanding which is guaranteed by Canada Mortgage and Housing Corporation.

[5] For venture capital partnership investments, fair value is generally established by using revenue or earnings multiples or other relevant market data including Initial Public Offerings.

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Summary of Assets Acquired and Liabilities Assumed (Parenthetical) (Detail) (CAD) In Millions, unless otherwise specified	1 Months Ended
	Feb. 26, 2013	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
Business Acquisition [Line Items]
Risk adjusted discount rate	10.00%
Inflation rate	2.00%
Property, plant and equipment		2,949	2,434	1,948
Asset retirement obligations		(287)	(284)	(267)
Other		(109)	(49)	(30)
Net deferred income tax liabilities		2,512	1,397	850
Celtic
Business Acquisition [Line Items]
Property, plant and equipment	414
Total deferred income tax liabilities	414
Asset retirement obligations	(17)
Other	(20)
Total deferred income tax assets	(37)
Net deferred income tax liabilities	377

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Litigation and other contingencies (Tables)

12 Months Ended

Dec. 31, 2013

Schedule of Unconditional Purchase Obligations

	Payments due by period
millions of dollars	2014		2015		2016		2017		2018		After 2018		Total
Unconditional purchase obligations (a)		91		80		82		83		84		237		657

(a) Undiscounted obligations of $657 million mainly pertain to pipeline throughput agreements. Total payments under unconditional purchase obligations were $95 million (2012 - $86 million, 2011 - $73 million). The present value of these commitments, excluding imputed interest of $178 million, totalled $479 million.

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Effect of One Percent Change in Assumed Health-Care Cost Trend Rate (Detail) (CAD) In Millions, unless otherwise specified	12 Months Ended
	Dec. 31, 2013
Defined Benefit Plan Disclosure [Line Items]
Effect on service and interest cost components, One percent increase	4
Effect on service and interest cost components, One percent decrease	(3)
Effect on benefit obligation, One percent increase	45
Effect on benefit obligation, One percent decrease	(35)

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Leased facilities

12 Months Ended

Dec. 31, 2013

Leased facilities

13. Leased facilities

At December 31, 2013, the company held non-cancelable operating leases covering office buildings, rail cars, service stations and other properties with minimum undiscounted lease commitments totaling $389 million as indicated in the following table:

	Payments due by period
millions of dollars	2014		2015		2016		2017		2018		After 2018		Total
Lease payments under minimum commitments (a)		177		88		47		33		12		32		389

(a) Net rental cost under cancelable and non-cancelable operating leases incurred in 2013 was $287 million (2012 – $271 million, 2011 – $226 million). Related rental income was not material.

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Common shares (Tables)

12 Months Ended

Dec. 31, 2013

Summary of Common Shares

thousands of shares	As at Dec. 31 2013		As at Dec. 31 2012
Authorized		1,100,000		1,100,000

Results of Share Repurchase Program Activities

The results of these activities are as shown below.

Year	Purchased shares (thousands)		Millions of dollars
1995 to 2011		903,765		15,580
2012		2,776		128
2013		-		-
Cumulative purchases to date		906,541		15,708

Common Share Activities

The company’s common share activities are summarized below:

	Thousands of shares			Millions of dollars
Balance as at January 1, 2011		847,599			1,511
Issued under employee share-based awards		1,262			19
Purchases at stated value		(1,262	)		(2	)
Balance as at December 31, 2011		847,599			1,528
Issued under employee share-based awards		2,776			43
Purchases at stated value		(2,776	)		(5	)
Balance as at December 31, 2012		847,599			1,566
Issued under employee share-based awards		-			-
Purchases at stated value		-			-
Balance as at December 31, 2013		847,599			1,566

Calculation of Basic and Diluted Earnings Per Share

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

	2013		2012		2011
Net income per common share – basic
Net income (millions of dollars)		2,828		3,766		3,371
Weighted average number of common shares outstanding
(millions of shares)		847.6		847.7		847.7
Net income per common share (dollars)		3.34		4.44		3.98
Net income per common share - diluted
Net income (millions of dollars)		2,828		3,766		3,371
Weighted average number of common shares outstanding
(millions of shares)		847.6		847.7		847.7
Effect of employee share-based awards (millions of shares)		3.0		3.4		5.9
Weighted average number of common shares outstanding, assuming dilution (millions of shares)		850.6		851.1		853.6
Net income per common share (dollars)		3.32		4.42		3.95

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Summary of Assets Acquired and Liabilities Assumed (Detail) (CAD) In Millions, unless otherwise specified	Dec. 31, 2013	Dec. 31, 2012	Feb. 26, 2013 Celtic
Business Acquisition [Line Items]
Cash			6
Accounts receivable			38
Materials, supplies and prepaid expenses			5
Property, plant and equipment			2,045	[1]
Goodwill	224	204	20	[2]
Total assets acquired			2,114
Accounts payable and accrued liabilities			62
Deferred income tax liabilities			377	[3]
Other long-term obligations			67
Total liabilities assumed			506
Net assets acquired			1,608

[1] Property, plant and equipment were measured primarily using an income approach. The fair value measurements of the oil and gas assets were based, in part, on significant inputs not observable in the market and thus represent a Level 3 measurement. The significant inputs included Celtic resources, assumed future production profiles, commodity prices (mainly based on observable market inputs), risk adjusted discount rate of 10 percent, inflation of 2 percent and assumptions on the timing and amount of future development and operating costs. The property, plant and equipment additions were segmented to the Upstream business, with all of the assets in Canada.

[2] Goodwill was the excess of the consideration transferred over the net assets recognized and represents the future economic benefits arising from other assets acquired that could not be individually identified and separately recognized. Goodwill was recognized in the Upstream reporting unit. Goodwill is not amortized and is not deductible for tax purposes.

[3] Deferred income taxes reflect the future tax consequences on the temporary differences between the amount of assets and liabilities recognized for financial reporting purposes and such amounts recognized for tax purposes. The deferred income taxes recorded as part of the acquisition were:

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Accounting for suspended exploratory well costs

12 Months Ended

Dec. 31, 2013

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.

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 dollars	2013			2012			2011
Balance as at January 1		167			163			120
Additions pending the determination of proved reserves		12			16			43
Charged to expense		-			-			-
Reclassification to wells, facilities and equipment based on the determination of proved reserves		(6	)		(12	)		-
Balance as at December 31		173			167			163
Period end capitalized suspended exploratory well costs:
millions of dollars	2013			2012			2011
Capitalized for a period of one year or less		6			16			43
Capitalized for a period of between one and five years		167			151			120
Capitalized for a period of greater than one year		167			151			120
Total		173			167			163

Exploration activity often involves drilling multiple wells, over a number of years, to fully evaluate a project. The table below provides a numerical breakdown of the number of projects with suspended exploratory well costs which had their first capitalized well drilled in the preceding 12 months and those that have had exploratory well costs capitalized for a period greater than 12 months.

	2013		2012		2011
Number of projects with first capitalized well drilled in the preceding 12 months		-		-		1
Number of projects that have exploratory well costs capitalized for a period of greater than 12 months		1		1		1
Total		1		1		2

The project with exploratory well costs capitalized for a period greater than 12 months as of December 31, 2013 had drilling in the preceding 12 months.

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Schedule of Asset Retirement Obligations (Detail) (CAD) In Millions, unless otherwise specified	12 Months Ended
	Dec. 31, 2013	Dec. 31, 2012
Reconciliation of Changes in Asset Retirement Obligations [Line Items]
Balance as at January 1	966	936
Additions	251	61
Reductions due to property sales		(8)
Accretion	105	86
Settlement	(85)	(109)
Balance as at December 31	1,237	966

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Consolidated statement of shareholders' equity (U.S. GAAP) (CAD) In Millions	Total	Common shares at stated value (note 10)	Earnings reinvested	Accumulated other comprehensive income
At beginning of year at Dec. 31, 2010		1,511	11,090	(1,424)
Net income for the year	3,371		3,371
Issued under the stock option plan		19
Other comprehensive income	(814)			(814)
Share purchases in excess of stated value			(57)
Share purchases at stated value		(2)
Dividends			(373)
At end of year at Dec. 31, 2011	13,321	1,528	14,031	(2,238)
Net income for the year	3,766		3,766
Issued under the stock option plan		43
Other comprehensive income	(217)			(217)
Share purchases in excess of stated value			(123)
Share purchases at stated value	(128)	(5)
Dividends			(408)
At end of year at Dec. 31, 2012	16,377	1,566	17,266	(2,455)
Net income for the year	2,828		2,828
Other comprehensive income	734			734
Dividends			(415)
At end of year at Dec. 31, 2013	19,524	1,566	19,679	(1,721)

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Consolidated Statement Of Income (U.S. GAAP) (Parenthetical) (CAD) In Millions, unless otherwise specified	12 Months Ended
	Dec. 31, 2013		Dec. 31, 2012		Dec. 31, 2011
Federal excise tax included in operating revenues	1,423	[1]	1,338	[1]	1,320	[1]
Amounts from related parties included in operating revenues	2,385		2,907		2,818
Amounts from related parties included in purchases of crude oil and products	4,104		3,033		3,636
Amounts to related parties included in production and manufacturing expenses	319		241		217

[1] Operating revenues include federal excise tax of $1,423 million (2012 - $1,338 million, 2011 - $1,320 million).

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Investment and other income

12 Months Ended

Dec. 31, 2013

Investment and other income

8. Investment and other income

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

millions of dollars	2013		2012		2011
Proceeds from asset sales		160		226		314
Book value of assets sold		10		132		117
Gain/(loss) on asset sales, before tax (a)		150		94		197
Gain/(loss) on asset sales, after tax (a)		120		72		153

(a) 2013 included a gain of $85 million ($73 million after tax) for the sale of non-operating assets.

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Transaction With related Parties - Additional Information (Detail) (CAD) In Millions, unless otherwise specified	Dec. 31, 2013	Dec. 31, 2012
Long-Term Loans
Related Party Transaction [Line Items]
Outstanding loans from an affiliate	4,316	1,040
Short-Term Loans
Related Party Transaction [Line Items]
Outstanding loans from an affiliate	75

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Period End Capitalized Suspended Exploratory Well Costs (Detail) (CAD) In Millions, unless otherwise specified	12 Months Ended
	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
Projects with Exploratory Well Costs Capitalized for More than One Year [Line Items]
Capitalized suspended exploratory well costs, total	173	167	163
Beginning Balance	167	163	120
Additions pending the determination of proved reserves	12	16	43
Charged to expense
Reclassification to wells, facilities and equipment based on the determination of proved reserves	(6)	(12)
Ending Balance	173	167	163
Capitalized for a period of one year or less	6	16	43
Capitalized For A Period Of Between One And Five Years
Projects with Exploratory Well Costs Capitalized for More than One Year [Line Items]
Capitalized suspended exploratory well costs	167	151	120
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	167	151	120

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Document and Entity Information (CAD)	12 Months Ended
	Dec. 31, 2013	Feb. 13, 2014	Jun. 30, 2013
Document Information [Line Items]
Document Type	10-K
Amendment Flag	false
Document Period End Date	Dec. 31, 2013
Document Fiscal Year Focus	2013
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		847,599,011
Entity Public Float			10,345,478,926

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Litigation and other contingencies

12 Months Ended

Dec. 31, 2013

Litigation and other contingencies

9. Litigation and other contingencies

A variety of claims have been made against Imperial Oil Limited 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.

	Payments due by period
millions of dollars	2014		2015		2016		2017		2018		After 2018		Total
Unconditional purchase obligations (a)		91		80		82		83		84		237		657

(a) Undiscounted obligations of $657 million mainly pertain to pipeline throughput agreements. Total payments under unconditional purchase obligations were $95 million (2012 - $86 million, 2011 - $73 million). The present value of these commitments, excluding imputed interest of $178 million, totalled $479 million.

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Miscellaneous Financial Information - Additional Information (Detail) (CAD) In Millions, unless otherwise specified	12 Months Ended
	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
Additional Financial Information [Line Items]
Effect of LIFO inventory liquidation on income	24	45	10
Difference between LIFO carrying values and replacement cost of inventories	1,787	1,769
Research and development costs charged to expenses	154	147	120
Accounts payable and accrued liabilities included accrued taxes other than income taxes	380	377

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Long Term Debt - Additional Information (Detail) (CAD) In Millions, unless otherwise specified	3 Months Ended
	Sep. 30, 2013 Stand-by long term credit facility	Mar. 31, 2013 Stand-by long term credit facility	Dec. 31, 2012 Stand-by long term credit facility	Dec. 31, 2013 Floating Rate Loan Facility Exxon Mobil	Jan. 31, 2014 Subsequent Event Floating Rate Loan Facility Exxon Mobil
Line of Credit Facility [Line Items]
Debt instrument, maturity date	Aug. 31, 2015
Line of Credit maximum borrowing capacity		500	300	5,000	6,250

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Consolidated Statement of Comprehensive Income (U.S. GAAP) (CAD) In Millions, unless otherwise specified	12 Months Ended
	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
Net income	2,828	3,766	3,371
Other comprehensive income, net of income taxes
Post-retirement benefits liability adjustment (excluding amortization)	529	(415)	(953)
Amortization of post-retirement benefits liability adjustment included in net periodic benefit costs	205	198	139
Total other comprehensive income/(loss)	734	(217)	(814)
Comprehensive income	3,562	3,549	2,557

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Income taxes

12 Months Ended

Dec. 31, 2013

Income taxes

3. Income taxes

millions of dollars	2013		2012		2011
Current income tax expense		425		593		955
Deferred income tax expense (a)		484		634		80
Total income tax expense (b)		909		1,227		1,035
Statutory corporate tax rate (percent)		25.4		25.5		25.4
Increase/(decrease) resulting from:
Enacted tax rate change				-		-
Other		(1.1)		(0.9)		(1.9)
Effective income tax rate		24.3		24.6		23.5

(a) 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 2013, 2012 and 2011.

(b) Cash outflow from income taxes, plus investment credits earned, was $911 million in 2013 (2012 – $871 million, 2011 – $667 million).

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 dollars	2013			2012			2011
Depreciation and amortization		2,949			2,434			1,948
Successful drilling and land acquisitions		815			399			378
Pension and benefits		(376	)		(717	)		(720	)
Site restoration		(287	)		(284	)		(267	)
Capitalized interest		69			53			50
Other		(99	)		39			51
Net long-term deferred income tax liabilities		3,071			1,924			1,440
LIFO inventory valuation		(450	)		(478	)		(560	)
Other		(109	)		(49	)		(30	)
Net current deferred income tax assets		(559	)		(527	)		(590	)
Valuation allowance		-			-			-
Net deferred income tax liabilities		2,512			1,397			850

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. Resolution of the related tax positions will 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’s effective tax rate will be reduced if any of these tax benefits are subsequently recognized.

The following table summarizes the movement in unrecognized tax benefits:

millions of dollars	2013			2012			2011
Balance as at January 1		143			134			147
Additions based on current year’s tax position		10			4			-
Additions for prior years’ tax positions		2			10			20
Reductions for prior years’ tax positions		(4	)		(3	)		(31	)
Reductions due to lapse of the statute of limitations		-			(2	)		(2	)
Balance as at December 31		151			143			134

The 2013, 2012 and 2011 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 2006 to 2013 are 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 2014. The impact on unrecognized tax benefits and the company’s effective income tax rate from these matters is not expected to be material.

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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Business segments

12 Months Ended

Dec. 31, 2013

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 the distribution and marketing of 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 income in this segment primarily includes debt-related financing costs, interest income and share-based incentive compensation expenses.

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 the Corporate and Other segment. The allocation is based on a combination of fee for service, proportional segment expenses and a three-year average of capital expenditures. 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 dollars	2013			2012			2011			2013			2012			2011			2013			2012			2011
Revenues and other income
Operating revenues (a)		6,016			4,674			5,278			25,450			25,077			23,909			1,256			1,302			1,287
Intersegment sales		4,026			4,110			4,460			1,978			2,603			2,784			318			299			354
Investment and other income		145			46			168			59			81			63			-			-			-
		10,187			8,830			9,906			27,487			27,761			26,756			1,574			1,601			1,641
Expenses
Exploration		123			83			92			-			-			-			-			-			-
Purchases of crude oil and products		3,778			3,056			3,581			21,628			21,316			21,642			1,065			1,115			1,222
Production and manufacturing (b)		3,389			2,704			2,484			1,695			1,569			1,451			210			185			179
Selling and general		5			1			7			886			935			973			66			67			64
Federal excise tax		-			-			-			1,423			1,338			1,320			-			-			-
Depreciation and depletion (b)		636			498			528			452			242			214			12			12			13
Financing costs (note 12)		9			(1	)		2			2			-			(1	)		-			-			-
Total expenses		7,940			6,341			6,694			26,086			25,400			25,599			1,353			1,379			1,478
Income before income taxes		2,247			2,489			3,212			1,401			2,361			1,157			221			222			163
Income taxes (note 3)
Current		(14	)		72			593			395			486			372			62			67			43
Deferred		549			529			162			(46	)		103			(99	)		(3	)		(10	)		(2	)
Total income tax expense		535			601			755			349			589			273			59			57			41
Net income		1,712			1,888			2,457			1,052			1,772			884			162			165			122
Cash flows from (used in) operating activities		1,690			2,625			3,252			1,453			1,961			1,315			198			127			53
Capital and exploration expenditures (c)		7,755			5,518			3,880			187			140			166			9			4			4
Property, plant and equipment
Cost		38,819			30,602			25,327			7,146			7,038			6,990			771			765			760
Accumulated depreciation and depletion		(10,749	)		(10,146	)		(9,747	)		(4,347	)		(3,967	)		(3,803	)		(586	)		(576	)		(560	)
Net property, plant and equipment (d)		28,070			20,456			15,580			2,799			3,071			3,187			185			189			200
Total assets (e)		30,553			22,317			17,222			5,732			6,409			6,700			397			372			397
	Corporate and Other									Eliminations									Consolidated
millions of dollars	2013			2012			2011			2013			2012			2011			2013			2012			2011
Revenues and other income
Operating revenues (a)		-			-			-			-			-			-			32,722			31,053			30,474
Intersegment sales		-			-			-			(6,322	)		(7,012	)		(7,598	)		-			-			-
Investment and other income		3			8			9			-			-			-			207			135			240
		3			8			9			(6,322	)		(7,012	)		(7,598	)		32,929			31,188			30,714
Expenses
Exploration		-			-			-			-			-			-			123			83			92
Purchases of crude oil and products		-			-			-			(6,316	)		(7,011	)		(7,598	)		20,155			18,476			18,847
Production and manufacturing (b)		-			-			-			(6	)		(1	)		-			5,288			4,457			4,114
Selling and general		125			78			124			-			-			-			1,082			1,081			1,168
Federal excise tax		-			-			-			-			-			-			1,423			1,338			1,320
Depreciation and depletion (b)		10			9			9			-			-			-			1,110			761			764
Financing costs (note 12)		-			-			2			-			-			-			11			(1	)		3
Total expenses		135			87			135			(6,322	)		(7,012	)		(7,598	)		29,192			26,195			26,308
Income before income taxes		(132	)		(79	)		(126	)		-			-			-			3,737			4,993			4,406
Income taxes (note 3)
Current		(18	)		(32	)		(53	)		-			-			-			425			593			955
Deferred		(16	)		12			19			-			-			-			484			634			80
Total income tax expense		(34	)		(20	)		(34	)		-			-			-			909			1,227			1,035
Net income		(98	)		(59	)		(92	)		-			-			-			2,828			3,766			3,371
Cash flows from (used in) operating activities		(49	)		(33	)		(131	)		-			-			-			3,292			4,680			4,489
Capital and exploration expenditures (c)		69			21			16			-			-			-			8,020			5,683			4,066
Property, plant and equipment
Cost		429			360			339			-			-			-			47,165			38,765			33,416
Accumulated depreciation and depletion		(163	)		(154	)		(144	)		-			-			-			(15,845	)		(14,843	)		(14,254	)
Net property, plant and equipment (d)		266			206			195			-			-			-			31,320			23,922			19,162
Total assets (e)		581			704			1,418			(45	)		(438	)		(308	)		37,218			29,364			25,429

(a) Includes export sales to the United States of $5,217 million (2012 - $4,358 million, 2011 - $4,175 million). Export sales to the United States were recorded in all operating segments, with the largest effects in the Upstream segment.

(b) A 2013 charge in the Downstream segment of $377 million ($280 million, after-tax) associated with the company’s decision to convert the Dartmouth refinery to a terminal included the write-down of refinery plant and equipment not included in the terminal conversion of $245 million, reported as part of depreciation and depletion expenses, and decommissioning, environmental and employee-related costs of $132 million, reported as part of production and manufacturing expenses. By the end of 2013, amounts incurred associated with decommissioning, environmental and employee-related costs totalled $40 million.

(c) Capital and exploration expenditures (CAPEX) include exploration expenses, additions to property, plant, equipment and intangibles and additions to capital leases.

(d) Includes property, plant and equipment under construction of $9,234 million (2012 - $13,846 million).

(e) The majority of the goodwill has been assigned to the Downstream segment. Goodwill of $20 million was recognized in 2013 in the Upstream segment as a result of the Celtic acquisition (note 18). There have been no goodwill impairment losses or write-offs due to sales in the past three years. Fair value used in quantitative goodwill impairment tests was Level 3 (unobservable inputs).

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Long-term debt

12 Months Ended

Dec. 31, 2013

Long-term debt

14. Long-term debt

millions of dollars	As at Dec. 31 2013		As at Dec. 31 2012
Long-term debt (a)		4,316		1,040
Capital leases (b)		128		135
Total long-term debt		4,444		1,175

(a) Borrowed 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 $5 billion (Canadian) 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. Average effective rate for the loan was 1.3 percent in 2013.

(b) Capitalized lease obligations primarily relate to capital leases for pipeline transportation and marine services agreements. The average imputed rate was 7.0 percent in 2013 (2012 – 9.6 percent). Total capitalized lease obligations also include $7 million in current liabilities (2012 - $7 million). Principal payments on capital leases of approximately $7 million per year are due in each of the next four years after December 31, 2014.

In the first quarter of 2013, the company increased the amount of its existing stand-by long term bank credit facility from $300 million to $500 million. In the third quarter, the company extended the maturity date of this facility to August 2015. The company has not drawn on the facility.

In January 2014, the company increased the capacity of its existing floating rate loan facility with an affiliated company of ExxonMobil from $5 billion to $6.25 billion. All other terms and conditions of the agreement remained unchanged.

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Common shares

12 Months Ended

Dec. 31, 2013

Common shares

10. Common shares

thousands of shares	As at Dec. 31 2013		As at Dec. 31 2012
Authorized		1,100,000		1,100,000

From 1995 through 2012, the company purchased shares under eighteen 12-month normal course issuer bid share repurchase programs, as well as an auction tender. On June 25, 2013, another 12-month normal course issuer bid program was implemented with an allowable purchase of up to a maximum of one million shares. Unlike prior programs, this maximum amount is not reduced by common shares purchased for the company’s employee savings plan, the company’s employee retirement plan and from Exxon Mobil Corporation. The results of these activities are as shown below.

Year	Purchased shares (thousands)		Millions of dollars
1995 to 2011		903,765		15,580
2012		2,776		128
2013		-		-
Cumulative purchases to date		906,541		15,708

ExxonMobil’s participation in the above maintained its ownership interest in Imperial at 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, 2011		847,599			1,511
Issued under employee share-based awards		1,262			19
Purchases at stated value		(1,262	)		(2	)
Balance as at December 31, 2011		847,599			1,528
Issued under employee share-based awards		2,776			43
Purchases at stated value		(2,776	)		(5	)
Balance as at December 31, 2012		847,599			1,566
Issued under employee share-based awards		-			-
Purchases at stated value		-			-
Balance as at December 31, 2013		847,599			1,566

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

	2013		2012		2011
Net income per common share – basic
Net income (millions of dollars)		2,828		3,766		3,371
Weighted average number of common shares outstanding
(millions of shares)		847.6		847.7		847.7
Net income per common share (dollars)		3.34		4.44		3.98
Net income per common share - diluted
Net income (millions of dollars)		2,828		3,766		3,371
Weighted average number of common shares outstanding
(millions of shares)		847.6		847.7		847.7
Effect of employee share-based awards (millions of shares)		3.0		3.4		5.9
Weighted average number of common shares outstanding, assuming dilution (millions of shares)		850.6		851.1		853.6
Net income per common share (dollars)		3.32		4.42		3.95

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Financing Costs and Additional Notes and Loans Payable Information - Additional Information (Detail) (CAD) In Millions, unless otherwise specified	3 Months Ended
	Mar. 31, 2013 Unsecured committed bank credit facility	Jun. 30, 2013 Unsecured committed bank credit facility	Dec. 31, 2013 Exxon Mobil Revolving demand loan
Financing Activities [Line Items]
Line of Credit maximum borrowing capacity	250	500	75
Non-interest bearing, revolving demand loan, outstanding amount			75
Debt instrument, maturity date	Mar. 31, 2014

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Derivatives and financial instruments

12 Months Ended

Dec. 31, 2013

Derivatives and financial instruments

6. Derivatives and financial instruments

The company did not enter into any derivative instruments to offset exposures associated with hydrocarbon prices, foreign currency exchange rates and interest rates that arose from existing assets, liabilities and transactions in the past three years. The company did not engage in speculative derivative activities or derivative trading activities nor did it use derivatives with leveraged features. The company maintains a system of controls that includes a policy covering the authorization, reporting and monitoring of derivative activity.

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 (observable input).

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Changes in Fair Value of Level 3 Assets (Detail) (CAD) In Millions, unless otherwise specified				12 Months Ended
	Dec. 31, 2013 Mortgage Funds	Dec. 31, 2012 Mortgage Funds	Dec. 31, 2011 Mortgage Funds	Dec. 31, 2013 Venture Capital	Dec. 31, 2012 Venture Capital
Defined Benefit Plan Disclosure [Line Items]
Fair value at beginning	1	1	1	158	148
Net realized gains/(losses)				(17)	(11)
Net unrealized gains/(losses)				44	8
Net purchases/(sales)				3	13
Fair value at ending	1	1	1	188	158

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Employee retirement benefits

12 Months Ended

Dec. 31, 2013

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 United States generally accepted accounting principles. 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. At 2013 year-end, the company adopted mortality assumptions presented in the new Canadian pensioners mortality research report, per guidance provided by the Canadian Institute of Actuaries.

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
	2013			2012			2013			2012
Assumptions used to determine benefit obligations at December 31 (percent)
Discount rate		4.75			3.75			4.75			3.75
Long-term rate of compensation increase		4.50			4.50			4.50			4.50
millions of dollars
Change in projected benefit obligation
Projected benefit obligation at January 1		7,336			6,646			547			508
Current service cost		181			160			11			8
Interest cost		281			288			21			21
Actuarial loss/(gain)		(504	)		616			(50	)		40
Amendments		-			-			-			-
Benefits paid (a)		(424	)		(374	)		(26	)		(30	)
Projected benefit obligation at December 31		6,870			7,336			503			547
Accumulated benefit obligation at December 31		6,263			6,560

The discount rate for calculating year-end post-retirement liabilities is based on the yield for high quality, long-term Canadian corporate bonds at year-end with an average maturity (or duration) approximately 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 2014 and subsequent years.

	Pension benefits						Other post-retirement benefits
millions of dollars	2013			2012			2013			2012
Change in plan assets
Fair value at January 1		5,114			4,461
Actual return/(loss) on plan assets		491			374
Company contributions		600			594
Benefits paid (b)		(333	)		(315	)
Fair value at December 31		5,872			5,114
Plan assets in excess of/(less than) projected benefit obligation at December 31
Funded plans		(424	)		(1,602	)
Unfunded plans		(574	)		(620	)		(503	)		(547	)
Total (c)		(998	)		(2,222	)		(503	)		(547	)

(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 dollars	2013			2012			2013			2012
Amounts recorded in the consolidated balance sheet consist of:
Current liabilities		(25	)		(24	)		(28	)		(28	)
Other long-term obligations		(973	)		(2,198	)		(475	)		(519	)
Total recorded		(998	)		(2,222	)		(503	)		(547	)
Amounts recorded in accumulated other comprehensive income consist of:
Net actuarial loss/(gain)		2,303			3,210			64			124
Prior service cost		62			85			-			-
Total recorded in accumulated other comprehensive income, before tax		2,365			3,295			64			124

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 2013 long-term expected return of 6.25 percent used in the calculations of pension expense compares to an actual rate of return of 6.50 percent and 8.00 percent over the last 10- and 20-year periods ending December 31, 2013.

	Pension benefits									Other post-retirement benefits
	2013			2012			2011			2013			2012			2011
Assumptions used to determine net periodic benefit cost for years ended December 31 (percent)
Discount rate		3.75			4.25			5.50			3.75			4.25			5.50
Long-term rate of return on funded assets		6.25			6.25			7.00			-			-			-
Long-term rate of compensation increase		4.50			4.50			4.50			4.50			4.50			4.50
millions of dollars
Components of net periodic benefit cost
Current service cost		181			160			122			11			8			6
Interest cost		281			288			314			21			21			23
Expected return on plan assets		(331	)		(288	)		(308	)		-			-			-
Amortization of prior service cost		23			23			21			-			-			-
Amortization of actuarial loss/(gain)		243			235			162			10			8			3
Net periodic benefit cost		397			418			311			42			37			32
Changes in amounts recorded in accumulated other comprehensive income
Net actuarial loss/(gain)		(664	)		530			1,112			(50	)		40			81
Amortization of net actuarial (loss)/gain included in net periodic benefit cost		(243	)		(235	)		(162	)		(10	)		(8	)		(3	)
Prior service cost		-			-			86			-			-			-
Amortization of prior service cost included in net periodic benefit cost		(23	)		(23	)		(21	)		-			-			-
Total recorded in other comprehensive income		(930	)		272			1,015			(60	)		32			78
Total recorded in net periodic benefit cost and other comprehensive income, before tax		(533	)		690			1,326			(18	)		69			110

Costs for defined contribution plans, primarily the employee savings plan, were $37 million in 2013 (2012 - $36 million, 2011 - $36 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 dollars	2013			2012			2011
(Charge)/credit to other comprehensive income, before tax		990			(304	)		(1,093	)
Deferred income tax (charge)/credit (note 17)		(256	)		87			279
(Charge)/credit to other comprehensive income, after tax		734			(217	)		(814	)

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 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 46 percent. The target allocation for debt securities is 49 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 2013 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, 2013, using:
millions of dollars	Total		Quoted prices in active markets for identical assets (Level 1)		Significant other observable inputs (Level 2)			Significant unobservable inputs (Level 3)
Asset class
Equity securities
Canadian		932				932	(a)
Non-Canadian		1,911				1,911	(a)
Debt securities - Canadian
Corporate		654				654	(b)
Government		2,161				2,161	(b)
Asset backed		-
Mortgage funds		1							1	(c)
Equities – Venture capital		188							188	(d)
Cash		25		12		13	(e)
Total plan assets at fair value		5,872		12		5,671			189

(a) For company equity securities held in the form of fund units that are redeemable at the measurement date, the unit value is treated as a Level 2 input. The fair value of the securities owned by the funds is based on observable quoted prices on active exchanges, which are Level 1 inputs.

(b) For corporate, government and asset-backed debt securities, fair value is based on observable inputs of comparable market transactions.

(c) For mortgage funds, fair value represents the principal outstanding which is guaranteed by Canada Mortgage and Housing Corporation.

(d) For venture capital partnership investments, fair value is generally established by using revenue or earnings multiples or other relevant market data including Initial Public Offerings.

(e) For cash balances that are held in Level 2 funds prior to investment in those fund units, the cash value is treated as a Level 2 input.

The change in the fair value of Level 3 assets, which use significant unobservable inputs to measure fair value, is shown in the table below:

millions of dollars	Mortgage funds		Venture capital
Fair value at January 1, 2013		1		158
Net realized gains/(losses)		-		(17	)
Net unrealized gains/(losses)		-		44
Net purchases/(sales)		-		3
Fair value at December 31, 2013		1		188

The 2012 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, 2012, using:
millions of dollars	Total		Quoted prices in active markets for identical assets (Level 1)		Significant other observable inputs (Level 2)			Significant unobservable inputs (Level 3)
Asset class
Equity securities
Canadian		811				811	(a)
Non-Canadian		1,657				1,657	(a)
Debt securities - Canadian
Corporate		473				473	(b)
Government		1,982				1,982	(b)
Asset backed		5				5	(b)
Mortgage funds		1							1	(c)
Equities – Venture capital		158							158	(d)
Cash		27		9		18	(e)
Total plan assets at fair value		5,114		9		4,946			159

(a) For company equity securities held in the form of fund units that are redeemable at the measurement date, the unit value is treated as a Level 2 input. The fair value of the securities owned by the funds is based on observable quoted prices on active exchanges, which are Level 1 inputs.

(b) For corporate, government and asset-backed debt securities, fair value is based on observable inputs of comparable market transactions.

(c) For mortgage funds, fair value represents the principal outstanding which is guaranteed by Canada Mortgage and Housing Corporation.

(d) For venture capital partnership investments, fair value is generally established by using revenue or earnings multiples or other relevant market data including Initial Public Offerings.

(e) For cash balances that are held in Level 2 funds prior to investment in those fund units, the cash value is treated as a Level 2 input.

The change in the fair value of Level 3 assets, which use significant unobservable inputs to measure fair value, is shown in the table below:

millions of dollars	Mortgage funds		Venture capital
Fair value at January 1, 2012		1		148
Net realized gains/(losses)		-		(11	)
Net unrealized gains/(losses)		-		8
Net purchases/(sales)		-		13
Fair value at December 31, 2012		1		158

A summary of pension plans with accumulated benefit obligations in excess of plan assets is shown in the table below:

	Pension benefits
millions of dollars	2013		2012
For funded pension plans with accumulated benefit obligations in excess of plan assets:
Projected benefit obligation		-		6,716
Accumulated benefit obligation		-		6,025
Fair value of plan assets		-		5,114
Accumulated benefit obligation less fair value of plan assets		-		911
For unfunded plans covered by book reserves:
Projected benefit obligation		574		620
Accumulated benefit obligation		496		535
Estimated 2014 amortization from accumulated other comprehensive income
millions of dollars	Pension benefits		Other post-retirement benefits
Net actuarial loss/(gain) (a)		169		5
Prior service cost (b)		23		-

(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 dollars	Pension benefits			Other post-retirement benefits
2014		365			28
2015		375			28
2016		384			28
2017		393			28
2018		401			28
2019 - 2023		2,078			145
In 2014, the company expects to make cash contributions of about $420 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 dollars	One percent increase			One percent decrease
Rate of return on plan assets:
Effect on net benefit cost, before tax		(50	)		50
Discount rate:
Effect on net benefit cost, before tax		(80	)		100
Effect on benefit obligation		(850	)		1,050
Rate of pay increases:
Effect on net benefit cost, before tax		50			(45	)
Effect on benefit obligation		170			(150	)

A one percent change in the assumed health-care cost trend rate would have the following effects:

Increase/(decrease) millions of dollars	One percent increase		One percent decrease
Effect on service and interest cost components		4		(3	)
Effect on benefit obligation		45		(35	)

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Other long-term obligations

12 Months Ended

Dec. 31, 2013

Other long-term obligations

5. Other long-term obligations

millions of dollars	2013		2012
Employee retirement benefits (note 4)(a)		1,448		2,717
Asset retirement obligations and other environmental liabilities (b)		1,258		957
Share-based incentive compensation liabilities (note 7)		140		117
Other obligations		245		192
Total other long-term obligations		3,091		3,983

(a) Total recorded employee retirement benefit obligations also include $53 million in current liabilities (2012 – $52 million).

(b) Total asset retirement obligations and other environmental liabilities also include $154 million in current liabilities (2012 – $168 million).

Asset retirement obligations incurred in the current period were Level 3 (unobservable inputs) fair value measurements. The following table summarizes the activity in the liability for asset retirement obligations:

millions of dollars	2013			2012
Balance as at January 1		966			936
Additions		251			61
Reductions due to property sales		-			(8	)
Accretion		105			86
Settlement		(85	)		(109	)
Balance as at December 31		1,237			966

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Share-based incentive compensation programs

12 Months Ended

Dec. 31, 2013

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.

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 exercise, an amount equal to 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 exercise dates. Fifty percent of the units are exercised three years following the grant date, and the remainder is exercised seven years following the grant date. The company may also issue units where 50 percent of the units are exercisable five years following the grant date and the remainder is exercisable on the later of ten years following the grant date or the retirement date of the recipient.

The deferred share unit plan is made available to nonemployee directors. The nonemployee directors can elect to receive all or part of their 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 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 resignation as a director and must be exercised no later than December 31 of the year following resignation. On the exercise date, the cash value to be received for the units is determined based on the average closing price of the company’s shares for the five consecutive trading days 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 to be exercised in the seventh year following the grant date. For units where 50 percent are exercisable five years following the grant date and the remainder exercisable on 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 units to be exercised.

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, 2013:

	Restricted stock units			Deferred share units
Outstanding at January 1, 2013		8,943,104			85,505
Granted		1,654,540			12,731
Exercised		(1,841,408	)		-
Forfeited and cancelled		(41,382	)		-
Outstanding at December 31, 2013		8,714,854			98,236

In 2013, the compensation expense charged against income for these programs was $92 million (2012 - $58 million, 2011 - $91 million). Income tax benefit recognized in income related to compensation expense for the year was $33 million (2012 - $20 million, 2011 - $33 million). Cash payments of $88 million was made for these programs in 2013
(2012 - $97 million, 2011 - $173 million).

As of December 31, 2013, there was $194 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 nonvested restricted stock units is 3.7 years. All units under the deferred share programs have vested as of December 31, 2013.

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Effect of One Percent Change in Assumptions at Which Retirement Liabilities Could be Effectively Settled (Detail) (CAD) In Millions, unless otherwise specified	12 Months Ended
	Dec. 31, 2013
Defined Benefit Plan Disclosure [Line Items]
Effect on net benefit cost, before tax, One percent increase - Rate of return on plan assets	(50)
Effect on net benefit cost, before tax, One percent increase - Discount rate	(80)
Effect on benefit obligation, One percent increase - Discount rate	(850)
Effect on net benefit cost, before tax, One percent increase- Rate of pay increases	50
Effect on benefit obligation, One percent increase - Rate of pay increases	170
Effect on net benefit cost, before tax, One percent decrease - Rate of return on plan assets	50
Effect on net benefit cost, before tax, One percent decrease - Discount rate	100
Effect on benefit obligation, One percent decrease - Discount rate	1,050
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	(150)

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Leased Facilities - Additional Information (Detail) (CAD) In Millions, unless otherwise specified	Dec. 31, 2013
Operating Leased Assets [Line Items]
Minimum undiscounted lease commitments	389	[1]

[1] Net rental cost under cancelable and non-cancelable operating leases incurred in 2013 was $287 million (2012 - $271 million, 2011 - $226 million). Related rental income was not material.

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Other Long-Term Obligations (Detail) (CAD) In Millions, unless otherwise specified	Dec. 31, 2013		Dec. 31, 2012
Schedule of Other Liabilities [Line Items]
Employee retirement benefits (note 4)	1,448	[1]	2,717	[1]
Asset retirement obligations and other environmental liabilities	1,258	[2]	957	[2]
Share-based incentive compensation liabilities (note 7)	140		117
Other obligations	245		192
Total other long-term obligations	3,091		3,983

[1] Total recorded employee retirement benefit obligations also include $53 million in current liabilities (2012 - $52 million).

[2] Total asset retirement obligations and other environmental liabilities also include $154 million in current liabilities (2012 - $168 million).

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Expected Benefit Payments (Detail) (CAD) In Millions, unless otherwise specified	Dec. 31, 2013
Pension benefits
Defined Benefit Plan Disclosure [Line Items]
2014	365
2015	375
2016	384
2017	393
2018	401
2019 - 2023	2,078
Other post-retirement benefits
Defined Benefit Plan Disclosure [Line Items]
2014	28
2015	28
2016	28
2017	28
2018	28
2019 - 2023	145

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Number of Projects with Suspended Exploratory Well Costs (Detail)	12 Months Ended
	Dec. 31, 2013 Project	Dec. 31, 2012 Project	Dec. 31, 2011 Project
Exploratory Wells Drilled [Line Items]
Number of projects with first capitalized well drilled in the preceding 12 months			1
Number of projects that have exploratory well costs capitalized for a period of greater than 12 months	1	1	1
Total projects	1	1	2

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Investment and other income (Tables)

12 Months Ended

Dec. 31, 2013

Gains and Losses on Asset Sales

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

millions of dollars	2013		2012		2011
Proceeds from asset sales		160		226		314
Book value of assets sold		10		132		117
Gain/(loss) on asset sales, before tax (a)		150		94		197
Gain/(loss) on asset sales, after tax (a)		120		72		153

(a) 2013 included a gain of $85 million ($73 million after tax) for the sale of non-operating assets.

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Assumptions Used to Determine Benefit Obligations (Detail)	Dec. 31, 2013	Dec. 31, 2012
Pension benefits
Defined Benefit Plan Disclosure [Line Items]
Discount rate	4.75%	3.75%
Long-term rate of compensation increase	4.50%	4.50%
Other post-retirement benefits
Defined Benefit Plan Disclosure [Line Items]
Discount rate	4.75%	3.75%
Long-term rate of compensation increase	4.50%	4.50%

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Financing costs and additional notes and loans payable information

12 Months Ended

Dec. 31, 2013

Financing costs and additional notes and loans payable information

12. Financing costs and additional notes and loans payable information

millions of dollars	2013			2012			2011
Debt-related interest		69			20			16
Capitalized interest		(69	)		(20	)		(16	)
Net interest expense		-			-			-
Other interest		11			(1	)		3
Total financing costs (a)		11			(1	)		3

(a) Cash interest payments in 2013 were $69 million (2012 – $20 million, 2011 – $16 million). The weighted average interest rate on short-term borrowings in 2013 was 1.1 percent (2012 – 1.1 percent).

In the fourth quarter of 2013, the company entered into 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 (Canadian). 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. As at December 31, 2013, the company had drawn $75 million on this agreement.

In the first quarter of 2013, to further support the commercial paper program, the company entered into an unsecured committed bank credit facility in the amount of $250 million that matures in March 2014. In the second quarter, the amount of this facility increased to $500 million. The company has not drawn on the facility.

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Other comprehensive income information

12 Months Ended

Dec. 31, 2013

Other comprehensive income information

17. Other comprehensive income information

Changes in accumulated other comprehensive income:

millions of dollars	2013			2012			2011
Balance as at January 1		(2,455	)		(2,238	)		(1,424	)
Post-retirement benefits liability adjustment:
Current period change excluding amounts reclassified from accumulated other comprehensive income		529			(415	)		(953	)
Amounts reclassified from accumulated other comprehensive income		205			198			139
Balance as at December 31		(1,721	)		(2,455	)		(2,238	)

Amounts reclassified out of accumulated other comprehensive income – before tax income/(expense)

millions of dollars	2013			2012			2011
Amortization of post-retirement benefits liability adjustment included in net periodic benefit cost (a)		(276	)		(266	)		(186	)

(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

millions of dollars	2013		2012			2011
Post-retirement benefits adjustments:
Post-retirement benefits liability adjustment (excluding amortization)		185		(155	)		(326	)
Amortization of post-retirement benefits liability adjustment included in net periodic benefit cost		71		68			47
Total		256		(87	)		(279	)

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Amounts Reclassified Out of Accumulated Other Comprehensive Income (Detail) (Reclassification Adjustment out of Accumulated Other Comprehensive Income, CAD) In Millions, unless otherwise specified	12 Months Ended
	Dec. 31, 2013		Dec. 31, 2012		Dec. 31, 2011
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	(276)	[1]	(266)	[1]	(186)	[1]

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

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Components of Deferred Income Tax Liabilities and Assets (Detail) (CAD) In Millions, unless otherwise specified	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
Components Of Deferred Tax Assets And Liabilities [Line Items]
Depreciation and amortization	2,949	2,434	1,948
Successful drilling and land acquisitions	815	399	378
Pension and benefits	(376)	(717)	(720)
Site restoration	(287)	(284)	(267)
Capitalized interest	69	53	50
Other	(99)	39	51
Net long-term deferred income tax liabilities	3,071	1,924	1,440
LIFO inventory valuation	(450)	(478)	(560)
Other	(109)	(49)	(30)
Net current deferred income tax assets	(559)	(527)	(590)
Valuation allowance
Net deferred income tax liabilities	2,512	1,397	850

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Accounting for suspended exploratory well costs (Tables)

12 Months Ended

Dec. 31, 2013

Change in Capitalized Suspended Exploratory Well Costs

Change in capitalized suspended exploratory well costs:

millions of dollars	2013			2012			2011
Balance as at January 1		167			163			120
Additions pending the determination of proved reserves		12			16			43
Charged to expense		-			-			-
Reclassification to wells, facilities and equipment based on the determination of proved reserves		(6	)		(12	)		-
Balance as at December 31		173			167			163

Schedule of Aging of Capitalized Exploratory Well Costs

Period end capitalized suspended exploratory well costs:
millions of dollars	2013		2012		2011
Capitalized for a period of one year or less		6		16		43
Capitalized for a period of between one and five years		167		151		120
Capitalized for a period of greater than one year		167		151		120
Total		173		167		163

Number of Projects With Suspended Exploratory Well Costs

The table below provides a numerical breakdown of the number of projects with suspended exploratory well costs which had their first capitalized well drilled in the preceding 12 months and those that have had exploratory well costs capitalized for a period greater than 12 months.

	2013		2012		2011
Number of projects with first capitalized well drilled in the preceding 12 months		-		-		1
Number of projects that have exploratory well costs capitalized for a period of greater than 12 months		1		1		1
Total		1		1		2

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Consolidated Balance Sheet (U.S. GAAP) (CAD) In Millions, unless otherwise specified	Dec. 31, 2013		Dec. 31, 2012
Current Assets
Cash	272	[1]	482	[1]
Accounts receivable, less estimated doubtful amounts	2,084		1,976
Inventories of crude oil and products (note 11)	1,030		827
Materials, supplies and prepaid expenses	342		280
Deferred income tax assets (note 3)	559		527
Total current assets	4,287		4,092
Long-term receivables, investments and other long-term assets	1,332		1,090
Property, plant and equipment, less accumulated depreciation and depletion (note 2)	31,320	[2]	23,922	[2]
Goodwill (note 2)	224		204
Other intangible assets, net	55		56
Total assets (note 2)	37,218	[3]	29,364	[3]
Current liabilities
Notes and loans payable (note 12)	1,843	[4]	472	[4]
Accounts payable and accrued liabilities (note 11)	4,518	[5]	4,249	[5]
Income taxes payable	727		1,184
Total current liabilities	7,088		5,905
Long-term debt (note 14)	4,444	[6]	1,175	[6]
Other long-term obligations (note 5)	3,091		3,983
Deferred income tax liabilities (note 3)	3,071		1,924
Total liabilities	17,694		12,987
Commitments and contingent liabilities (note 9)
Shareholders' equity
Common shares at stated value (note 10)	1,566	[7]	1,566	[7]
Earnings reinvested	19,679		17,266
Accumulated other comprehensive income	(1,721)		(2,455)
Total shareholders' equity	19,524		16,377
Total liabilities and shareholders' equity	37,218		29,364

[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] Includes property, plant and equipment under construction of $9,234 million (2012 - $13,846 million).

[3] The majority of the goodwill has been assigned to the Downstream segment. Goodwill of $20 million was recognized in 2013 in the Upstream segment as a result of the Celtic acquisition (note 18). There have been no goodwill impairment losses or write-offs due to sales in the past three years. Fair value used in quantitative goodwill impairment tests was Level 3 (unobservable inputs).

[4] Notes and loans payable includes amounts to related parties of $75 million (2012 - nil)

[5] Accounts payable and accrued liabilities include amounts payable to related parties of $170 million (2012 - amounts receivable of $9 million), (note 16).

[6] Long-term debt includes amounts to related parties of $4,316 million (2012 - $1,040 million).

[7] Number of common shares outstanding was 848 million (2012 - 848 million), (note 10).

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Long Term Debt (Detail) (CAD) In Millions, unless otherwise specified	Dec. 31, 2013		Dec. 31, 2012
Debt Instrument [Line Items]
Long-term debt	4,316	[1]	1,040	[1]
Capital leases	128	[2]	135	[2]
Total long-term debt	4,444	[3]	1,175	[3]

[1] Borrowed 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 $5 billion (Canadian) 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. Average effective rate for the loan was 1.3 percent in 2013.

[2] Capitalized lease obligations primarily relate to capital leases for pipeline transportation and marine services agreements. The average imputed rate was 7.0 percent in 2013 (2012 - 9.6 percent). Total capitalized lease obligations also include $7 million in current liabilities (2012 - $7 million). Principal payments on capital leases of approximately $7 million per year are due in each of the next four years after December 31, 2014.

[3] Long-term debt includes amounts to related parties of $4,316 million (2012 - $1,040 million).

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Summary of significant accounting policies

12 Months Ended

Dec. 31, 2013

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. Significant subsidiaries included in the consolidated financial statements include Imperial Oil Resources Limited, Imperial Oil Resources N.W.T. Limited, Imperial Oil Resources Ventures Limited and McColl-Frontenac Petroleum Inc. All of the above companies are wholly owned. 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 project.

Inventories

Inventories are recorded at the lower of cost or current market value. 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 final storage prior to delivery to a customer. 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

Property, plant and equipment are recorded at cost. Investment tax credits and other similar grants are treated as a reduction of the capitalized cost of the asset to which they apply.

The company uses the successful-efforts method to account for its exploration and development activities. Under this method, costs are accumulated on a field-by-field basis with certain exploratory expenditures and exploratory dry holes being expensed as incurred. Costs of productive wells and development dry holes are capitalized and amortized using the unit-of-production method. The company carries as an asset exploratory well costs 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. Other exploratory expenditures, including geophysical costs and annual lease rentals are expensed as incurred.

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.

Production involves lifting the oil and gas to the surface and gathering, treating, field processing and field storage of the oil and gas. The production function normally terminates at the outlet valve on the lease or field production storage tank. Production costs are those incurred to operate and maintain the company’s wells and related equipment and facilities and are expensed as incurred. They become part of the cost of oil and gas produced. These costs, sometimes referred to as lifting costs, include such items as labour cost to operate the wells and related equipment; repair and maintenance costs on the wells and equipment; materials, supplies and energy costs required to operate the wells and related equipment; and administrative expenses related to the production activity.

Acquisition costs of proved properties are amortized using a unit-of-production method, computed on the basis of total proved oil and gas reserves. 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. Unit-of-production depreciation is applied to those wells, plant and equipment assets associated with productive depletable properties, and the unit-of-production rates are based on the amount of proved developed reserves of oil and gas. Investments in extraction and upgrading facilities at oil sands mining properties are depreciated on a unit-of-production method based on proved developed reserves. Investments in mining and transportation systems at oil sands mining properties are depreciated on a straight-line basis over a maximum of 15 years. Depreciation of other plant and equipment is calculated using the straight-line method, based on the estimated service life of the asset. In general, refineries are depreciated over 25 years; other major assets, including chemical plants and service stations, are depreciated over 20 years.

Proved oil and gas properties held and used by the company are reviewed for impairment whenever events or changes in circumstances indicate that the carrying amounts may not be recoverable. 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.

The company estimates the future undiscounted cash flows of the affected properties to judge the recoverability of carrying amounts. Cash flows used in impairment evaluations are developed using annually updated corporate plan investment evaluation assumptions for crude oil and natural gas commodity prices and foreign-currency exchange rates. Annual volumes are based on field production profiles, which are also updated annually.

Impairment analyses are generally based on reserve estimates used for internal planning and capital investment decisions. Where probable reserves exist, an appropriately risk-adjusted amount of these reserves may be included in the impairment evaluation. An asset group would be impaired if the undiscounted cash flows were less than its carrying value. Impairments are measured by the amount the carrying value exceeds fair value.

Significant unproved properties are assessed for impairment individually and valuation allowances against the capitalized costs are recorded based on the estimated economic chance of success and the length of time 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 valuation allowances are reviewed at least annually.

Gains or losses on assets sold are included in “investment and other income” in the consolidated statement of income.

Interest capitalization

Interest costs relating to major capital projects under construction are capitalized as part of property, plant and equipment. 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 and marketing 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 liabilities 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.

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 or 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.

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.

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 72 for further details.

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.

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Summary of Change in Accumulated Other Comprehensive Income (Detail) (CAD) In Millions, unless otherwise specified	12 Months Ended
	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
Defined Benefit Plan Disclosure [Line Items]
(Charge)/credit to other comprehensive income, before tax	990	(304)	(1,093)
Deferred income tax (charge)/credit (note 17)	(256)	87	279
(Charge)/credit to other comprehensive income, after tax	734	(217)	(814)

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Financing costs and additional notes and loans payable information (Detail) (CAD) In Millions, unless otherwise specified	12 Months Ended
	Dec. 31, 2013		Dec. 31, 2012		Dec. 31, 2011
Debt-related interest	69		20		16
Capitalized interest	(69)		(20)		(16)
Net interest expense
Other interest	11		(1)		3
Total financing costs	11	[1]	(1)	[1]	3	[1]

[1] Cash interest payments in 2013 were $69 million (2012 - $20 million, 2011 - $16 million). The weighted average interest rate on short-term borrowings in 2013 was 1.1 percent (2012 - 1.1 percent).

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Share-Based Incentive Compensation Programs - Additional Information (Detail) (CAD) In Millions, unless otherwise specified	12 Months Ended
	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Compensation expense charged against income	92	58	91
Income tax benefit recognized in income related to compensation expense	33	20	33
Cash payment for compensation expense	88	97	173
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
Restricted Stock Units (RSUs)
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Before-tax unrecognized compensation expense related to non-vested restricted stock	194
Weighted average vesting period of nonvested restricted stock	3 years 8 months 12 days
Restricted Stock Units (RSUs) | Restricted Stock Unit Plan 1
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Percentage restricted stock units exercisable three years following grant date	50.00%
Percentage restricted stock units exercisable seven years following grant date	50.00%
Restricted Stock Units (RSUs) | Restricted Stock Unit Plan 2
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Percentage restricted stock units exercisable five years following grant date	50.00%
Percentage restricted stock units exercisable ten years following grant date	50.00%

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Acquisition

12 Months Ended

Dec. 31, 2013

Acquisition

18. Acquisition

Description of the Transaction: On February 26, 2013, ExxonMobil Canada acquired Celtic Exploration Ltd. (Celtic). Immediately following the acquisition, Imperial acquired a 50 percent interest in Celtic’s assets and liabilities from ExxonMobil Canada for $1.6 billion, financed by a combination of related party and third party debt. Concurrently, a general partnership was formed to hold and operate the assets of Celtic. The name of the general partnership was changed to XTO Energy Canada (XTO Canada). XTO Canada is involved in the exploration for, production of, and transportation and sale of natural gas and crude oil, condensate and natural gas liquids.

Recording of Assets Acquired and Liabilities Assumed: Imperial used the acquisition method of accounting to record its pro-rata share of the assets acquired and liabilities assumed. This method requires, among other things, that assets acquired and liabilities assumed be recognized at their fair values as of the acquisition date. The following table summarizes the assets acquired and liabilities assumed:

millions of dollars
Cash	6
Accounts receivable	38
Materials, supplies and prepaid expenses	5
Property, plant and equipment (a)	2,045
Goodwill (b)	20
Total assets acquired	2,114
Accounts payable and accrued liabilities	62
Deferred income tax liabilities (c)	377
Other long-term obligations	67
Total liabilities assumed	506
Net assets acquired	1,608

(a) Property, plant and equipment were measured primarily using an income approach. The fair value measurements of the oil and gas assets were based, in part, on significant inputs not observable in the market and thus represent a Level 3 measurement. The significant inputs included Celtic resources, assumed future production profiles, commodity prices (mainly based on observable market inputs), risk adjusted discount rate of 10 percent, inflation of 2 percent and assumptions on the timing and amount of future development and operating costs. The property, plant and equipment additions were segmented to the Upstream business, with all of the assets in Canada.

(b) Goodwill was the excess of the consideration transferred over the net assets recognized and represents the future economic benefits arising from other assets acquired that could not be individually identified and separately recognized. Goodwill was recognized in the Upstream reporting unit. Goodwill is not amortized and is not deductible for tax purposes.

(c) Deferred income taxes reflect the future tax consequences on the temporary differences between the amount of assets and liabilities recognized for financial reporting purposes and such amounts recognized for tax purposes. The deferred income taxes recorded as part of the acquisition were:

millions of dollars
Property, plant and equipment	414
Total deferred income tax liabilities	414
Asset retirement obligations	(17	)
Other	(20	)
Total deferred income tax assets	(37	)
Net deferred income tax liabilities	377

Actual and Pro Forma Impact of the Acquisition: Revenues for XTO Canada from the acquisition date included in the company’s consolidated financial statement of income for the twelve months ended December 31, 2013 were $89 million. After-tax earnings for XTO Canada from the acquisition date through December 31, 2013 were de minimis.

Transaction costs related to the acquisition were expensed as incurred and were de minimis in the twelve months ended December 31, 2013.

Unaudited pro forma revenues, earnings and basic and diluted earnings per share information as if the acquisition had occurred at the beginning of 2013 or the comparable prior reporting period is not presented, since the effect on Imperial’s consolidated annual financial results for the year ended December 31, 2013 and the comparable prior reporting periods, would not have been material.

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Schedule of Unconditional Purchase Obligations (Parenthetical) (Detail) (CAD) In Millions, unless otherwise specified	12 Months Ended
	Dec. 31, 2013		Dec. 31, 2012	Dec. 31, 2011
Unrecorded Unconditional Purchase Obligation [Line Items]
Undiscounted obligations mainly pertaining to pipeline throughput agreements	657	[1]
Total payments under unconditional purchase obligations	95		86	73
Imputed interest on commitments	178
Total present value of commitments excluding imputed interest	479

[1] Undiscounted obligations of $657 million mainly pertain to pipeline throughput agreements. Total payments under unconditional purchase obligations were $95 million (2012 - $86 million, 2011 - $73 million). The present value of these commitments, excluding imputed interest of $178 million, totalled $479 million.

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Financing costs and additional notes and loans payable information (Tables)

12 Months Ended

Dec. 31, 2013

Schedule Of Financing Costs

millions of dollars	2013			2012			2011
Debt-related interest		69			20			16
Capitalized interest		(69	)		(20	)		(16	)
Net interest expense		-			-			-
Other interest		11			(1	)		3
Total financing costs (a)		11			(1	)		3

(a) Cash interest payments in 2013 were $69 million (2012 – $20 million, 2011 – $16 million). The weighted average interest rate on short-term borrowings in 2013 was 1.1 percent (2012 – 1.1 percent).

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Miscellaneous financial information

12 Months Ended

Dec. 31, 2013

Miscellaneous financial information

11. Miscellaneous financial information

In 2013, net income included an after-tax gain of $24 million (2012 – $45 million gain, 2011 – $10 million gain) attributable to the effect of changes in last-in, first-out (LIFO) inventories. The replacement cost of inventories was estimated to exceed their LIFO carrying values at December 31, 2013 by $1,787 million (2012 – $1,769 million). Inventories of crude oil and products at year-end consisted of the following:

millions of dollars	2013		2012
Crude oil		628		473
Petroleum products		340		284
Chemical products		54		60
Natural gas and other		8		10
Total inventories of crude oil and products		1,030		827

Net research and development costs charged to expenses in 2013 were $154 million (2012 – $147 million, 2011 – $120 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 $380 million at December 31, 2013 (2012 - $377 million).