IMPERIAL OIL LTD - Annual Report: 2016 (Form 10-K)

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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

IMPERIAL OIL LIMITED

(Exact name of registrant as specified in its charter)

Registrant’s telephone number, including area code:

1-800-567-3776

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

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

Common Shares (without par value)

(Title of Class)

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

Yes ✓    No......

Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or Section 15(d) of the Securities Exchange Act of 1934.

Yes ......No ✓

Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days.

Yes ✓    No......

Indicate by check mark whether the registrant has submitted electronically and posted on its corporate web site, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files).

Yes✓     No......

Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K is not contained herein, and will not be contained, to the best of registrant’s knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-K or any amendment to this Form 10-K.

Yes ✓    No......

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, 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 ✓ 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 ✓

As of the last business day of the 2016 second fiscal quarter, the aggregate market value of the voting stock held by non-affiliates of the registrant was Canadian $10,533,578,543 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 8, 2017, was 847,599,011.

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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.

On February 8, 2017, 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 $0.7601 U.S. = $1.00 Canadian.

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Forward-looking statements

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

The term “project” as used in this report can refer to a variety of different activities and does not necessarily have the same meaning as in any government payment transparency reports.

PART I

Item 1.      Business

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

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

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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, 2016, as detailed in the “Supplemental information on oil and gas exploration and production activities” part of the Financial section, starting on page 30 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, 2016 that would cause a significant change in the estimated proved reserves as of that date.

The estimation of proved reserves, which is based on the requirement of reasonable certainty, is an ongoing process based on rigorous technical evaluations, commercial and market assessments and detailed analysis of well information such as flow rates and reservoir pressures. Furthermore, the company only records proved reserves for projects which have received significant funding commitments by management made toward the development of the reserves. Although the company is reasonably certain that proved reserves will be produced, the timing and amount recovered can be affected by a number of factors, including completion of development projects, reservoir performance, regulatory approvals, royalty framework and significant changes in projections of long-term oil and gas price levels. In addition, proved reserves could be affected by an extended period of low prices which could reduce the level of the company’s capital spending and also impact its partners’ capacity to fund their share of joint projects.

As a result of low prices during 2016, under the U.S. Securities and Exchange Commission definition of proved reserves, certain quantities of bitumen that qualified as proved reserves in prior years did not qualify as proved reserves at year-end 2016. Amounts no longer qualifying as proved reserves include the entire 2.5 billion barrels of bitumen at Kearl and approximately 0.2 billion barrels of bitumen at Cold Lake. Among the factors that would result in these amounts being recognized again as proved reserves at some point in the future are a recovery in average price levels, a further decline in costs, and / or operating efficiencies. Under the terms of certain contractual arrangements or government royalty regimes, lower prices can also increase proved reserves attributable to Imperial. The company does not expect the downward revision of reported proved reserves under the U.S. Securities and Exchange Commission definitions to affect the operation of the underlying projects or to alter its outlook for future production volumes.

Technologies used in establishing proved reserves estimates

Imperial’s proved reserves in 2016 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 3-D and 4-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.

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

Preparation of reserves estimates

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

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

The internal qualified reserves evaluator is a professional engineer registered in Alberta, Canada and has over 30 years of petroleum industry experience, including 23 years of reserves related experience. The position provides leadership to the internal reserves management group and is responsible for filing a reserves report with the Canadian securities regulatory authorities. The company’s internal reserves evaluation staff consists of 39 persons with an average of 15 years of relevant technical experience in evaluating reserves, of whom 24 persons are qualified reserves evaluators for purposes of Canadian securities regulatory requirements. The company’s internal reserves evaluation management team is made up of 19 persons with an average of 14 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, 2016, approximately 23 percent of the company’s proved reserves were proved undeveloped reserves reflecting volumes of 319 million oil-equivalent barrels. Most of the undeveloped reserves are associated with the Cold Lake field. This compared to 513 million oil-equivalent barrels of proved undeveloped reserves reported at the end of 2015. Proved undeveloped reserves decreased by 177 million oil-equivalent barrels in 2016 associated with end of field life truncation as a result of low oil and natural gas prices. Migration of proved undeveloped reserves into proved developed was not material in 2016.

Proved undeveloped reserves that have remained undeveloped for five years or more represent about 22 percent (71 million oil-equivalent barrels) of proved undeveloped reserves and are primarily associated with Cold Lake’s ongoing drilling program. These undeveloped reserves are planned to be developed in a staged approach to align with operational capacity and efficient capital spending commitment over the life of the field. The company is reasonably certain that these proved reserves will be produced; however the timing and amount recovered can be affected by a number of factors including completion of development projects, reservoir performance, and significant changes in long-term oil prices.

One of the company’s requirements to report resources as proved reserves is that management has made significant funding commitments towards the development of the reserves. The company has a disciplined investment strategy and many major fields require a long lead-time in order to be developed. The company made investments of about $105 million during the year to progress the development of reported proved undeveloped reserves in the Montney and Duvernay formations, and at Cold Lake. These investments represented about 12 percent of the $896 million in total reported Upstream capital and exploration expenditures. Investments made by the company to develop quantities which no longer meet the SEC definition of proved reserves due to 2016 average prices are included in the $896 million of Upstream capital and exploration expenditures.

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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 34 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, 2016 was as follows. All reported production volumes were from Canada.

Average daily production and production available for sale of natural gas

The company’s average daily production and production available for sale of natural gas during the three years ended December 31, 2016 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 34 of this report for a narrative discussion on the material changes.

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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.

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, 2016 were as follows.

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

Unit sales prices decreased in 2015, primarily driven by the decline in the global crude oil and natural gas price environment.

Average unit production costs

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

Bitumen unit production costs were lower in 2015, primarily driven by Kearl expansion project start-up and cost management.

Synthetic oil unit production costs were lower in 2015, primarily driven by cost management.

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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, 2016.

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

In 2014, the following wells were drilled to add productive capacity: 90 development wells at Cold Lake, of which 74 development wells relate to the Cold Lake Nabiye expansion project, eight net tight gas wells and 13 net other wells.

Wells drilling

At December 31, 2016, the company was participating in the drilling of the following exploratory and development wells. All wells were located in Canada.

Exploratory and development activities regarding oil and gas resources

Cold Lake

To maintain production at Cold Lake, capital expenditures for additional production wells and associated facilities are required periodically. Additional wells were drilled on existing phases in 2015. No wells were drilled in 2016.

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

Aspen, Cold Lake expansion and other oil sands activities

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

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

In March 2016, Imperial filed a regulatory application for the Cold Lake Expansion project to develop the Grand Rapids interval using SA-SAGD technology. The project is proposed to produce 50,000 barrels per day, before royalties. Development timing is subject to regulatory approval and market conditions. No final investment decision has been made.

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

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

Other activities

The company is continuing to evaluate other undeveloped natural gas resources in the Montney and Duvernay formations in the western provinces.

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.

In 2016, the Federal Government of Canada approved the extension of the pipeline and gathering system construction permits to December 31, 2022. 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 operates both licences and its interest in the original licence was reduced to 25 percent. The exploration licences are held through 2019 and 2020, respectively.

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

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

Liquefied natural gas (LNG) activity

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

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

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

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Present activities

Review of principal ongoing activities

Cold Lake

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

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. Royalties are subject to the oil sands royalty regulations which are based upon a sliding scale determined largely by the price of crude oil.

During 2016, net production at Cold Lake was about 138,000 barrels per day and gross production was about 161,000 barrels per day.

As a result of low prices during 2016, under the SEC definition of proved reserves, approximately 0.2 billion barrels of bitumen at Cold Lake no longer qualified as proved reserves at year-end 2016. The company does not expect the downward revision of reported proved reserves under SEC definitions to affect the Cold Lake operation or to alter Imperial’s outlook for future production volumes. Among the factors that would result in these amounts being recognized again as proved reserves at some point in the future are a recovery in average price levels, a further decline in costs, and / or operating efficiencies.

Kearl

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

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

During 2016, the company’s share of Kearl’s net bitumen production was about 118,000 barrels per day and gross production was about 120,000 barrels per day. Increased production in the year was due to the start-up of the expansion project.

Potential future debottlenecking of the Kearl operation would increase output to reach the regulatory capacity of 345,000 barrels of bitumen per day, of which the company’s share would be about 245,000 barrels per day. Such debottlenecking remains under evaluation.

As a result of low prices during 2016, under the SEC definition of proved reserves, the entire 2.5 billion barrels of bitumen at Kearl no longer qualified as proved reserves at year-end 2016. The company does not expect the downward revision of reported proved reserves under SEC definitions to affect the Kearl operation or to alter Imperial’s outlook for future production volumes. Among the factors that would result in these amounts being recognized again as proved reserves at some point in the future are a recovery in average price levels, a further decline in costs, and / or operating efficiencies.

Syncrude

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

The Province of Alberta, in its capacity as lessor of Syncrude oil sands leases, is entitled to a royalty on production at Syncrude. In 2016, Syncrude transitioned to the new generic oil sands royalty regulations which are based on a sliding scale determined largely by the price of crude oil. Syncrude’s royalties are based on bitumen value with upgrading costs and revenues excluded from the calculation.

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In 2016, the company’s share of Syncrude’s net production of synthetic crude oil was about 67,000 barrels per day and gross production was about 68,000 barrels per day.

Delivery commitments

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

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, 2016 and December 31, 2015, is set forth in the following table. The statistics in the table are determined in part from information received from other operators.

Land holdings

At December 31, 2016 and 2015, the company held the following oil and gas rights, and bitumen and synthetic oil leases, all of which are located in Canada, specifically in the western provinces, in the Canada lands and in the Atlantic offshore.

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Western provinces

The company’s bitumen leases include about 194,000 net acres of oil sands leases near Cold Lake and an area of about 34,000 net acres at Kearl. The company also has about 80,000 net acres of undeveloped, mineable oil sands acreage in the Athabasca region. In addition, the company has interests in other bitumen oil sands leases in the Athabasca areas totalling about 193,000 net acres, which include about 62,000 net acres of oil sands leases in the Clyden area, about 34,000 net acres of oil sands in the Aspen area and about 30,000 net acres of oil sands in the Corner area. 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, by payment of escalating rentals, or by production. The majority of the acreage in Cold Lake, Kearl and Syncrude is continued by production.

The company holds interests in an additional 1,185,000 net acres of developed and undeveloped land in the western provinces related to crude oil and natural gas.

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

Canada lands

Land holdings in Canada lands primarily include exploration licence (EL) acreage in the Beaufort Sea of about 252,000 net acres and significant discovery licence (SDL) acreage in the Mackenzie Delta and Beaufort Sea areas of about 183,000 net acres. In 2016, the company surrendered its interest in the Summit Creek area of central Mackenzie Valley totalling about 222,000 net acres.

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

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

Atlantic offshore

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

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Downstream

Supply

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

Transportation

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

Refining

The company owns and operates three refineries, which process predominantly Canadian crude oil. The Strathcona refinery operates lubricating oil production facilities. In addition to crude oil, the company purchases finished products to supplement its refinery production.

In 2016, capital expenditures of about $95 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, 2016, and the daily rated capacities of the refineries as at December 31, 2016 were as follows.

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

In 2015, refinery throughput was 92 percent of capacity, 2  percent lower than the previous year. The lower rate was primarily a result of planned maintenance.

Distribution

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

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Marketing

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

The company supplies petroleum products to the motoring public through Esso-branded retail sites and independent marketers. In 2016, the company completed the sale of its remaining company-owned Esso-branded retail sites completing the conversion to a branded wholesaler operating model. On average during the year, there were more than 1,700 retail sites, which by the end of 2016 were all operating under a branded wholesaler model whereby Imperial supplies fuel to independent third parties who own and operate retail sites in alignment with Esso brand standards.

Imperial sells petroleum products to large industrial and transportation customers, independent marketers, resellers as well as other refiners. The company serves agriculture, residential heating and commercial markets through branded resellers.

The approximate daily volumes of net petroleum products (excluding purchases / sales contracts with the same counterparty) sold during the three years ended December 31, 2016, are set out in the following table.

Total Downstream capital expenditures were $190 million in 2016.

Chemical

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

The company’s total sales volumes of petrochemicals during the three years ended December 31, 2016, were as follows.

Lower sales volumes in 2016 were primarily due to higher plant maintenance and feedstock availability.

Total Chemical capital expenditures were $26  million in 2016.

Research

The approximate total gross research expenditures, before credits, during the three years ended December 31, 2016, were as follows.

Research expenditures are mainly for developing technologies to improve bitumen recovery, reduce costs and reduce the environmental impact of upstream operations, supporting environmental and process improvements in the refineries, as well as accessing ExxonMobil’s research worldwide.

The company has scientific research agreements with affiliates of ExxonMobil, which provide

for technical and engineering work to be performed by all parties, the exchange of technical information and the assignment and licensing of patents and patent rights. These agreements provide mutual access to scientific and operating data related to nearly every phase of the petroleum and petrochemical operations of the parties.

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In 2016, Imperial completed its Calgary Research Centre in Quarry Park, a state-of-the-art facility focused on oil sands innovation and technology.

Environmental protection

The company regards protecting the environment in connection with its various operations a priority. The company works in cooperation with government agencies, industry associations and communities to address existing, and to anticipate potential, environmental protection issues. In the past five years, the company has made capital and operating expenditures of about $6.1 billion on environmental protection and facilities. In 2016, the company’s environmental capital and operating expenditures totalled approximately $0.7 billion, which was spent primarily on water treatment, tailings treatment and emission reductions at company-owned facilities and Syncrude; and on remediation of idled facilities and operations. Capital and operating expenditures relating to environmental protection are expected to be about $0.7 billion in 2017.

Human resources

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

Competition

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

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.

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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 2016 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 ExxonMobil, the company is considered to be an entity which is not controlled by Canadians.

Competition Act

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

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

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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.

Item 1A.    Risk factors

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

Volatility of commodity prices

The company’s operations and earnings may be significantly affected by changes in oil and gas prices and by changes in margins on refined products and petrochemicals. Crude oil, natural gas, petrochemical and product prices and margins depend on local, regional, and global events or conditions that affect supply and demand for the relevant commodity.

Demand related factors which could impact Imperial’s results include economic conditions, where periods of low or negative economic growth will typically have an adverse impact on results; technological improvements in energy efficiency; seasonal weather patterns, which affect the demand for energy associated with heating and cooling; increased competitiveness of alternative energy sources; and changes in technology or consumer preferences that affect the market for petroleum products.

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

Commodity prices have been volatile, and the company expects that volatility to continue. Any material decline in crude oil prices could have a material adverse effect on Imperial’s Upstream operations, financial position, proved reserves and the amount spent to develop reserves.

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

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

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Government and political factors

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

Environmental risks

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

Environmental legislation imposes, among other things, restrictions, liabilities and obligations in connection with the generation, handling, storage, transportation, treatment and disposal of hazardous substances and waste and in connection with spills, releases and emissions of various substances 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, monitored, abandoned and reclaimed to the satisfaction of applicable regulatory authorities. In addition, certain types of operations, including exploration and development projects and significant changes to certain existing projects, may require the submission and approval of environmental impact assessments. Compliance with environmental legislation can require significant expenditures and failure to comply with environmental legislation may result in the cessation of operations, imposition of fines and penalties and liability for clean-up costs and damages.

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

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

Climate change and greenhouse gas restrictions

Due to concern over the risk of climate change, a number of provinces and the Government of Canada have adopted, or are considering the adoption of, regulatory frameworks to reduce greenhouse gas (GHG) emissions. These include adoption of carbon emissions pricing, cap and trade regimes, carbon taxes, emissions limits, increased efficiency standards, and incentives or mandates for renewable energy. These requirements could make Imperial’s products more expensive, reduce or delay available business opportunities, reduce demand for hydrocarbons, and shift hydrocarbon demand toward lower GHG emission energy sources. Current and pending GHG regulations may also increase compliance and abatement costs, lengthen project implementation times, and affect operations.

Currency

Prices for commodities produced by the company are commonly benchmarked in U.S. dollars. The majority of Imperial’s sales and purchases are related to these industry U.S. dollar benchmarks. As the company records and reports its financial results in Canadian dollars, to the extent that the value of the Canadian dollar strengthens, the company’s earnings will be negatively affected.

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Other business risks

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

Management effectiveness

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

Project management

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

Operational efficiency

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

Research and development

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

Safety, business controls and environmental risk management

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

Business risks also include the risk of cybersecurity breaches. If systems for protecting against cybersecurity risks prove insufficient, 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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Reserves

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

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

Preparedness

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

Item 1B.   Unresolved staff comments

Not applicable.

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

Market information

The company’s common shares trade on the Toronto Stock Exchange and the NYSE MKT LLC. Reference is made to the “Quarterly financial and stock trading data” portion of the Financial section on page 85 of this report. The closing price for Imperial Oil Limited common shares on the Toronto Stock Exchange was $42.30 as at February 8, 2017.

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.

Information for security holders outside Canada

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

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

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

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

As of February 8, 2017 there were 11,238 holders of record of common shares of the company.

Between October 1, 2016 and December 31, 2016, pursuant to the company’s restricted stock unit plan, 400 shares were issued to employees outside the U.S. in reliance on Regulation S under the Securities Act, and 650 shares were issued to a seconded employee in reliance on the section 4(a)(2) exemption under the Securities Act.

Securities authorized for issuance under equity compensation plans

Sections of the company’s management proxy circular are contained in the Proxy information section, starting on page 86. The company’s management proxy circular is prepared in accordance with Canadian securities regulations.

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

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Issuer purchases of equity securities

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.

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 34 of this report.

Reference is made to the section entitled “Market risks and other uncertainties” in the Financial section, starting on page 44 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.

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Reference is made to the table of contents in the Financial section on page 30 of this report:

None.

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, 2016. 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 51 of this report for “Management’s report on internal control over financial reporting” and page 52 for the “Report of independent registered public accounting firm” on the company’s internal control over financial reporting as of December 31, 2016.

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.

None.

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PART III

Sections of the company’s management proxy circular are contained in the Proxy information section, starting on page 86. 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 nominee information” on pages 87 to 95 of this report have been nominated for election at the annual meeting of shareholders to be held April 28, 2017. All of the nominees are directors and have been since the dates indicated.

Reference is made to the section under “Director nominee information”:

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

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

Sections of the company’s management proxy circular are contained in the Proxy information section, starting on page 86. The company’s management proxy circular is prepared in accordance with Canadian securities regulations.

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

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

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Sections of the company’s management proxy circular are contained in the Proxy information section, starting on page 86. The company’s management proxy circular is prepared in accordance with Canadian securities regulations.

Reference is made to the section under “Company executives and executive compensation” entitled “Equity compensation plan information”, within the “Compensation discussion and analysis” section, on page 146 of this report.

Reference is made to the section under “Corporate governance disclosure” entitled “Largest shareholder”, on page 120 of this report.

Reference is also made to the security ownership information for directors and executive officers of the company under the preceding Items 10 and 11. With respect to named executive officers who are not directors of the company, as of February 8, 2017, B.A. Babcock was the owner of 25,539 common shares of the company and held 111,500 restricted stock units of the company. B.P. Cahir held 32,400 restricted stock units of the company. W.J. Hartnett was the owner of 14,925 common shares of the company and held 96,800 restricted stock units of the company. T.B. Redburn was the owner of 3,215 common shares of the company and held 76,950 restricted stock units of the company.

The directors and the executive officers of the company, whose compensation for the year-ended December 31, 2016 is described in the sections under “Director nominee information” starting on page 87 and “Company executives and executive compensation” starting on page 121, consist of 18 persons, who, as a group, as of February 8, 2017, beneficially own 161,024 common shares of the company, being approximately 0.02 percent of the total number of outstanding shares of the company, and 457,483 shares of Exxon Mobil Corporation (including 398,050 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 724,758 common shares of the company, as of February 8, 2017.

Sections of the company’s management proxy circular are contained in the Proxy information section, starting on page 86. The company’s management proxy circular is prepared in accordance with Canadian securities regulations.

Reference is made to the section under “Corporate governance disclosure” entitled “Independence of our board nominees”, on page 99 of this report.

Reference is made to the section under “Corporate governance disclosure” entitled “Transactions with Exxon Mobil Corporation”, on page 120 of this report.

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

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Auditor information

The audit committee of the board of directors recommends that PricewaterhouseCoopers LLP (“PwC”) be reappointed as the auditor of the company until the close of the next annual meeting. PwC have been the auditor of the company for more than five years and are located in Calgary, Alberta. PwC are 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, 2016 and December 31, 2015 were as follows:

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 2016. Audit-related fees consisted of other assurance services including the audit of the company’s retirement plan and royalty statement audits for oil and gas producing entities. The company did not engage the auditor for any other services.

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

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

Auditor independence

The audit committee continually discusses with PwC their independence from the company and from management. PwC have confirmed that they are independent with respect to the company within the meaning of the Rules of Professional Conduct of the Institute of Chartered Professional Accountants of Alberta and the rules of the U.S. Securities and Exchange Commission. The company has concluded that the auditor’s independence has been maintained.

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PART IV

Reference is made to the table of contents in the Financial section on page 30 of this report.

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

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

Item 16.    Form 10-K summary

Not applicable.

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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 22, 2017 by the undersigned, thereunto duly authorized.

Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below on February 22, 2017 by the following persons on behalf of the registrant and in the capacities indicated.

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Financial section

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 Financial information (U.S. GAAP)

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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.

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.

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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.

Operating costs

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

 Reconciliation of operating costs

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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. The company’s integrated business model, with significant investments in Upstream, Downstream and Chemical segments, reduces the company’s risk from changes in commodity prices. While commodity prices are volatile on a short-term basis depending upon supply and demand, Imperial’s investment decisions are based on its long-term business outlook, using a disciplined approach in selecting and pursuing the most attractive investment opportunities. The corporate plan is a fundamental annual management process that is the basis for setting near-term operating and capital objectives, in addition to providing the longer-term economic assumptions used for investment evaluation purposes. Major investment opportunities are tested over a wide range of economic scenarios. Once major investments are made, a reappraisal process is completed to ensure relevant lessons are learned and improvements are incorporated into future projects.

The term “project” as used in this report can refer to a variety of different activities and does not necessarily have the same meaning as in any government payment transparency reports.

Business environment and risk assessment

Long-term business outlook

By 2040, the world’s population is projected to grow to approximately nine billion people, or about 1.8 billion more people than in 2015. Coincident with this population increase, the company expects worldwide economic growth to average close to 3 percent per year. As economies and populations grow, and as living standards improve for billions of people, the need for energy will continue to rise. Even with significant efficiency gains, global energy demand is projected to rise by about 25 percent from 2015 to 2040. This demand increase is expected to be concentrated in developing countries (i.e., those that are not member nations of the Organization for Economic Cooperation and Development). Canada is expected to see flat to modest local energy demand growth through to 2040 and will continue to be a large supplier of energy exports to help meet rising global energy needs.

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

Energy for global transportation – including cars, trucks, ships, trains and airplanes – is expected to increase by about 25 percent from 2015 to 2040. The growth in transportation energy demand is likely to account for approximately 60 percent of the growth in liquid fuels demand worldwide over this period. Nearly all the world’s transportation fleets will continue to run on liquid fuels, which 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 60 percent from 2015 to 2040, led by a doubling of demand 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. In 2015 coal-fired generation provided about 40 percent of the world’s electricity, however by 2040 coal-fired generation is likely to decline

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to less than 30 percent, in part as a result of policies to improve air quality as well as reduce greenhouse gas emissions to address the risks of climate change. From 2015 to 2040, the amount of electricity generated using natural gas, nuclear power, and renewables is likely to approximately double, and account for 90 percent of the growth in electricity supplies. By 2040, coal, natural gas and renewables are projected to each generate a similar share of electricity worldwide, although significant differences will exist across regions reflecting a wide range of factors including the cost and availability of energy types.

Liquid fuels provide the largest share of global energy supplies today due to their broad-based availability, affordability, ease of distribution and storage. By 2040, global demand for liquid fuels is expected to grow to approximately 112 million barrels of oil-equivalent per day, an increase of almost 20 percent from 2015. Globally, crude production from traditional conventional sources will likely decline slightly through 2040, with significant development activity mostly offsetting natural declines from these fields. However, this decline is expected to be more than offset by rising production from a wide variety of emerging supply sources – including tight oil, deep-water, 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 it is expected to be the fastest-growing major fuel source from 2015 to 2040, meeting about 40 percent of energy demand growth. Global demand is expected to rise about 45 percent from 2015 to 2040, with about 45 percent of that increase in the Asia Pacific region. Helping meet these needs will lead to significant growth in supplies of unconventional gas - the natural gas found in shale and other rock formations that was once considered uneconomic to produce. In total, about 60 percent of the growth in natural gas supplies is expected to be from unconventional sources. However, it is expected conventionally-produced natural gas will remain the cornerstone of supply, meeting about two-thirds of global demand in 2040. Worldwide liquefied natural gas (LNG) trade will expand significantly, likely reaching more than 2.5 times the level of 2015 by 2040, with much of this supply expected to meet rising demand in Asia Pacific.

The world’s energy mix is highly diverse and will remain so through 2040. Oil is expected to remain the largest source of energy with its share remaining close to one-third in 2040. Coal is currently the second largest source of energy, but it is likely to lose that position to natural gas in the 2025 to 2030 timeframe. The share of natural gas is expected to reach 25 percent by 2040, while the share of coal falls to about 20 percent. Nuclear power is projected to grow significantly, as many nations are likely to expand nuclear capacity to address rising electricity needs as well as energy security and environmental issues. Total renewable energy is likely to reach about 15 percent of total energy by 2040, with biomass, hydro and geothermal contributing a combined share of more than 10 percent. Total energy supplied from wind, solar and biofuels is expected to increase rapidly, growing over 200 percent from 2015 to 2040, when they will approach 4 percent of the world’s energy.

The company anticipates that the world’s available oil and gas resource base will grow not only from new discoveries but also from reserve increases in previously discovered fields. Technology will underpin these increases. The cost to develop and supply these resources will be significant. According to the International Energy Agency, the investment required to meet oil and natural gas supply requirements worldwide over the period 2016 to 2040 will be about US$23 trillion (measured in 2015 dollars) or approximately US$900 billion per year on average.

International accords and underlying regional and national regulations covering greenhouse gas emissions continue to evolve with uncertain timing and outcome, making it difficult to predict their business impact. Imperial’s estimate of potential costs related to possible public policies covering energy-related greenhouse gas emissions are consistent with those outlined in ExxonMobil’s long-term Outlook for Energy, which is used as a foundation 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 predominantly into the North American markets. Imperial’s Upstream business strategies guide the company’s exploration, development, production, research and gas marketing activities. These strategies include capturing material and accretive opportunities to

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continually high-grade the resource portfolio, exercising a disciplined approach to investing and cost management, developing and applying high-impact technologies, pursuing productivity and efficiency gains, and growing profitable oil and gas production. 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.

Imperial has a significant oil and gas resource base and a large inventory of potential projects. The company continues to evaluate opportunities to support the company’s long-term growth. Actual volumes will vary from year to year due to the factors described in Item 1A. Risk factors.

Prices for most of the company’s crude oil sold are referenced to West Texas Intermediate (WTI) and Western Canada Select (WCS) oil markets. In 2016, the average WTI and WCS crude oil prices, in U.S. dollars, were lower versus 2015. The upstream industry environment has been challenged in recent years with abundant crude oil supply causing crude oil prices to decrease to levels not seen since 2004. However, current market conditions are not necessarily indicative of future conditions. The markets for crude oil and natural gas have a history of significant price volatility. Imperial believes prices over the long term will continue to be driven by market supply and demand, with the demand side largely being a function of global economic growth. On the supply side, prices may be significantly impacted by political events, the actions of OPEC and other large government resource owners, and other factors. To manage the risks associated with price, Imperial evaluates annual plans and all major investments across a range of price scenarios.

Downstream

Imperial’s Downstream serves predominantly Canadian markets with refining, logistics and marketing assets. Imperial’s Downstream business strategies guide the company’s activities. These strategies include targeting best-in-class operations in all aspects of the business, maximizing value from advanced technologies, capitalizing on integration across Imperial’s businesses, selectively investing for resilient and advantaged returns, operating efficiently and effectively, and providing valued products and services to customers.

Imperial owns and operates three refineries in Canada, with aggregate distillation capacity of 423,000 barrels per day. Imperial’s fuels marketing business across Canada serves customers through more than 1,700 Esso-branded retail sites, as well as wholesale and industrial operations through a network of primary distribution terminals.

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

While demand remained strong in 2016, margins weakened as surplus distillate and gasoline production capacity created higher inventory. North American refineries have benefitted from cost-competitive feedstock and energy supplies, but that benefit decreased in 2016.

Imperial’s long-term outlook is that the North American refining industry will remain subject to intense competition. Additionally, as described in more detail in Item 1A. Risk Factors, proposed carbon policy and other climate-related regulations, as well as the continued growth in biofuels mandates, could have negative impacts on the downstream business. Imperial’s integration across the value chain, from refining to marketing, enhances overall value in both fuels and lubricants businesses.

The company supplies petroleum products to the motoring public through Esso-branded retail sites and independent marketers. In 2016, the company completed the sale of its remaining company-owned Esso-branded retail sites completing the conversion to a branded wholesaler operating model. On average during the year, there were more than 1,700 retail sites, which by the end of 2016 were all operating under a branded wholesaler model whereby Imperial supplies fuel to independent third parties who own and operate retail sites in alignment with Esso brand standards.

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Chemical

In North America, unconventional natural gas continued to provide advantaged ethane feedstock for steam crackers and a favourable margin environment for integrated chemical producers. 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.

Results of operations

 Consolidated

2016

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

2015

Net income in 2015 was $1,122 million, or $1.32 per share on a diluted basis, versus $3,785 million or $4.45 per share in 2014. Upstream recorded a net loss of $704 million, compared to a net income of $2,059 million in 2014. Downstream earnings decreased by $8 million and Chemical earnings increased by $58 million.

 Upstream

2016

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

2015

Upstream recorded a net loss of $704 million in 2015, compared to net income of $2,059 million in the same period of 2014. Earnings in 2015 reflected lower crude oil and gas realizations of about $3,790 million, a net charge of $327 million associated with increased Alberta corporate income taxes, higher depreciation expense of about $180 million, lower liquids and gas volumes of about $80 million reflecting the impact of divested properties in the prior year and a net charge of about $60 million associated with the inventory carrying value. These factors were partially offset by the impact of a weaker Canadian dollar of about $770 million, the favourable impact of lower royalties of about $700 million, higher volumes from Kearl and Cold Lake of about $670 million and lower energy costs of about $140 million.

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 Average realizations

2016

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

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

2015

The average price for WTI, the main benchmark crude for North America, decreased by 47 percent compared to the same period in 2014. The company’s average Canadian dollar realizations for synthetic crude oil and bitumen decreased about 38 and 52 percent in 2015 to $61.33 and $32.48 per barrel respectively, as the decline in benchmark crude and increased light-heavy differentials were partially offset by the weaker Canadian dollar. The company’s average realizations on sales of natural gas of $2.78 per thousand cubic feet in 2015 were lower by $1.76 per thousand cubic feet, versus 2014.

 Crude oil and NGLs - production and sales (a)