IMPERIAL OIL LTD - Annual Report: 2014 (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:

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

Yes ü    No......

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

Yes .......No ü

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

Yes ü    No......

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

Yesü    No.....

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

Yes ü    No......

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

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

Indicate by check mark whether the registrant is a shell company (as defined in Rule 12 b-2 of the Securities Exchange Act of 1934).

Yes .......No ü

As of the last business day of the 2014 second fiscal quarter, the aggregate market value of the voting stock held by non-affiliates of the registrant was Canadian $11,729,170,628 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 11, 2015, 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 11, 2015, 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 $0.7915 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 results, including demand growth and energy source mix; production growth and mix; project plans, dates, costs and capacities; production rates and resource recoveries; cost savings; product sales; financing sources; and capital and environmental expenditures could differ materially depending on a number of factors, such as changes in the price, and supply of and demand for crude oil, natural gas, and petroleum and petrochemical products; political or regulatory events; project schedules; commercial negotiations; the receipt, in a timely manner, of regulatory and third-party approvals; unanticipated operational disruptions; unexpected technological developments; and other factors discussed in Item 1A of this annual report on Form 10-K and in the management’s discussion and analysis of financial condition and results of operations contained in Item 7. Forward-looking statements are not guarantees of future performance and involve a number of risks and uncertainties, some that are similar to other oil and gas companies and some that are unique to Imperial. Imperial’s actual results may differ materially from those expressed or implied by its forward-looking statements and readers are cautioned not to place undue reliance on them.

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

PART I

Imperial Oil Limited was incorporated under the laws of Canada in 1880 and was continued under the Canada Business Corporations Act (the “CBCA”) by certificate of continuance dated April 24, 1978. The head and principal office of the company is located at 237 Fourth Avenue S.W. Calgary, Alberta, Canada T2P 3M9; telephone 1-800-567-3776. Exxon Mobil Corporation owns approximately 69.6 percent of the outstanding shares of the company. In this report, unless the context otherwise indicates, reference to “the company” or “Imperial” includes Imperial Oil Limited and its subsidiaries.

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

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

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

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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, 2014, as detailed in the “Supplemental information on oil and gas exploration and production activities” part of the Financial section, starting on page 28 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, 2014 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 pressure declines. Furthermore, the company only records proved reserves for projects which have received significant funding commitments by management made toward the development of the reserves. Although the company is reasonably certain that proved reserves will be produced, the timing and amount recovered can be affected by a number of factors, including completion of development projects, reservoir performance, regulatory approvals and significant changes in projections of long-term oil and gas price levels.

Technologies used in establishing proved reserves estimates

Additions to Imperial’s proved reserves in 2014 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.

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

Preparation of reserves estimates

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

Key components of the reserves estimation process include technical evaluations and analysis of well and field performance and a rigorous peer review. The reserves management group maintains a central database

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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. No changes may be made to reserves estimates in the central database, including the addition of any new initial reserves estimates or subsequent revisions, unless those changes have been thoroughly reviewed and evaluated by duly authorized personnel within the base operating organization. In addition, changes to reserves estimates that exceed certain thresholds require review and endorsement by the operating organization and the reserves management group, culminating in reviews with and approval by senior management and the company’s board of directors.

The Operations Technical Subsurface Engineering Manager is a professional engineer registered in Alberta, Canada and has over 25 years of petroleum industry experience, including 21 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 50 persons with an average of 15 years of relevant technical experience in evaluating reserves, of whom 32 persons are qualified reserves evaluators for purposes of Canadian securities regulatory requirements. The company’s internal reserves evaluation management team is made up of 15 persons with an average of 11 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, 2014, approximately 43 percent of the company’s proved reserves were proved undeveloped reserves reflecting volumes of 1,704 million oil-equivalent barrels. Nearly all of those undeveloped reserves are associated with either the Kearl project or Cold Lake field. This compared to 1,509 million oil-equivalent barrels of proved undeveloped reserves reported at the end of 2013. Increased proved undeveloped reserves were primarily associated with the conclusion of technical studies supporting the lengthening of the expected useful life of the Kearl operating assets under routine maintenance and sustaining capital conditions.

One of the company’s requirements to report resources as proved reserves is that management has made significant funding commitments towards the development of the reserves. The company has a disciplined investment strategy and many major fields require a significant lead-time in order to be developed. The company made investments of about $3.9 billion during the year to progress the development of reported proved undeveloped reserves. The largest project under development in 2014 was the Kearl expansion project. By 2014 year-end, the Kearl expansion project construction phase was essentially complete and the commissioning of facilities commenced in preparation for start-up.

Proved undeveloped reserves at Cold Lake are associated with the ongoing drilling program and the Nabiye project. Imperial moved eight million oil-equivalent barrels in 2014 from proved undeveloped to proved developed reserves at Cold Lake through ongoing drilling programs. Production at the Nabiye project is expected in the first quarter of 2015 at which time proved undeveloped reserves will be moved to proved developed reserves.

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

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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 32 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, 2014 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, 2014 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 32 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, 2014, were as follows.

Average unit production costs

Synthetic oil production costs increased in 2014 primarily due to higher maintenance activities at Syncrude.

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

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, 2014.

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.

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

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

Wells drilling

At December 31, 2014, 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

In February 2012, the Nabiye expansion at Cold Lake was sanctioned. Facilities start-up occurred throughout December 2014 followed by initial steam injection into the reservoir in January 2015. Bitumen production is targeted in the first quarter of 2015, ultimately increasing to 40,000 barrels per day, before royalties.

To maintain production at Cold Lake, additional wells were drilled on existing phases in 2014. In 2015, a development drilling program is planned within the approved development area to add productive capacity.

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

Mackenzie Delta

In 1999, the company and three other companies entered into an agreement to study the feasibility of developing Mackenzie Delta gas, anchored by three large onshore natural gas fields. The company retains a 100 percent interest in the largest of these fields.

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

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

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

Beaufort Sea

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

In 2010, the company executed an agreement to cross-convey interests with another company to acquire a 25 percent interest in an additional Beaufort Sea exploration licence. As a result of that agreement, the company 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. Current activities continue to focus on data gathering, regulatory groundwork, and community consultation. No final drilling investment decision has been made.

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Other oil sands activity

The company filed a regulatory application for a new in-situ oil sands project at Aspen in December 2013. Steam-assisted gravity drainage (SAGD) technology would be used to develop the project in three phases producing about 45,000 barrels per day before royalties, per phase. No final investment decision has been made.

Work continues on technical evaluations to support potential Cold Lake Midzaghe (formerly Grand Rapids), Corner and Clyden in-situ development regulatory applications.

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

Liquefied natural gas (LNG) export application

In December 2013, WCC LNG Ltd., jointly owned by the company (50 percent) and ExxonMobil Canada Ltd. (50 percent), received approval from the NEB to export up to 30 million tonnes of LNG per year for a period of 25 years. The company filed a project description with the B.C. Environmental Assessment Office in December 2014. The filing, required to initiate an environmental assessment, outlines the proposed production, storage and marine transportation of LNG to global markets. No final investment decision has been made.

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

Kearl

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

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

The Kearl expansion project construction phase was essentially complete at the end of 2014, and the commissioning of facilities commenced in preparation for start-up. The project is expected to ultimately produce 110,000 barrels of bitumen per day, before royalties, of which the company’s share will be about 78,000 barrels per day.

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

Other oil sands activity

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

During 2014, average net production at Cold Lake was about 114,000 barrels per day and gross production was about 146,000 barrels per day.

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 based upon a sliding scale determined largely by the price of crude oil.

Kearl

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

Production of mined diluted bitumen began in April 2013 and continued to ramp-up in 2014. The company’s share of Kearl’s net production was about 47,000 barrels per day and gross production was about 51,000 barrels per day.

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 based upon a sliding scale determined largely by the price of crude oil.

Syncrude

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

In 2014, the company’s share of Syncrude’s net production of synthetic crude oil was about 60,000 barrels per day and gross production was about 64,000 barrels per day.

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

Conventional oil and gas

The Norman Wells oil field in the Northwest Territories is the company’s largest conventional oil producing asset, with gross production of about 11,000 barrels per day, currently accounting for about 70 percent of the company’s gross production of conventional crude oil.

In the second quarter of 2014, the company divested three mature conventional properties; Boundary Lake, Pembina and Rocky Mountain House. Combined production from these properties totalled about 15,000 oil-equivalent barrels per day in 2013, split about evenly between oil and gas.

Delivery commitments

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

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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, 2014 and December 31, 2013, is set forth in the following table. The statistics in the table are determined in part from information received from other operators.

The total number of wells decreased in 2014 primarily due to the divestment of mature conventional properties.

Land holdings

At December 31, 2014 and 2013, 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 193,000 net acres of oil sands leases near Cold Lake and an area of about 34,000 net acres at Kearl. The company also has about 80,000 net acres of undeveloped, mineable oil sands acreage in the Athabasca region. In addition, the company has interests in other bitumen oil sands leases in the Athabasca areas totalling about 193,000 net acres, which include about 62,000 net acres of oil sands leases in the Clyden area. These 193,000 net acres are amenable to in-situ recovery techniques.

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

Oil sands leases have an exploration period of fifteen years and are continued beyond that point by meeting the minimum level of evaluation, payment of 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 1,246,000 net acres of developed and undeveloped land in western Canada related to crude oil and natural gas. Included in this number is a total acreage position of about 170,000 net acres at Horn River, British Columbia. In 2014, the company divested mature conventional properties totalling 134,000 net acres.

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

Canada lands

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

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

The company’s net acreage in Canada lands is either continued by production or held through exploration licences 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 freely negotiated prices. Purchases are made under both spot and term contracts from domestic and foreign sources, including Exxon Mobil Corporation.

Transportation

Imperial currently transports about 530,000 barrels per day of crude oil by both contracted pipelines and common carrier pipelines. The company has secured an additional 305,000 barrels per day capacity on crude oil pipeline projects set to be in service over the next several years. To mitigate uncertainty associated with the timing of pipeline projects, the company is developing rail infrastructure with potential incremental capacity up to 210,000 barrels per day. These transportation capacities are primarily to ship 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 2014, capital expenditures of about $93 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, 2014, and the daily rated capacities of the refineries as at December 31, 2014 were as follows.

In 2014, refinery throughput was 94 percent of capacity, six percent higher than the previous year. The higher rate was primarily a result of improved reliability and increased product sales. Capacity utilization in 2013 was calculated based on the number of days the refineries were operated as a refinery.

Distribution

The company maintains a nationwide distribution system, including 22 primary terminals, to handle bulk and packaged petroleum products moving from refineries to market by pipeline, tanker, rail and road transport. The company owns and operates natural gas liquids and products pipelines in Alberta, Manitoba and Ontario and has interests in the capital stock of one crude oil and two products pipeline companies.

Marketing

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

The company sells to the motoring public through Esso retail service stations. On average during the year, there were more than 1,700 retail service stations, of which about 470 were company-owned or leased, but none of which were company operated. The remaining approximately 1,200 Esso branded service stations

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operate under a branded wholesaler model. The company continues to improve its Esso retail service station network, providing customer services such as car washes and convenience stores, primarily at high volume sites in urban centres.

In January 2015, the company announced that it will evaluate its operating model for the company-owned retail stations. The assessment will evaluate the potential opportunity to extend the branded wholesaler operating model to the remaining company-owned retail stations as part of Imperial’s Esso branded growth strategy. Operating model changes, if any, should have no impact on the end user consumer.

The Canadian agriculture, residential heating and commercial markets are served by 27 branded resellers. The company also sells petroleum products to large industrial and transportation customers, independent marketers, resellers as well as other refiners.

The approximate daily volumes of net petroleum products (excluding purchases/sales contracts with the same counterparty) sold during the three years ended December 31, 2014, are set out in the following table.

Total Downstream capital expenditures were $572 million in 2014.

Chemical

The company’s Chemical operations manufacture and market ethylene, 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.

Infrastructure required to implement a long-term supply agreement for ethane from the nearby Marcellus shale gas development was completed and first deliveries of this feedstock to the Sarnia chemical plant were received in the second quarter of 2014.

The company’s total sales volumes of petrochemicals during the three years ended December 31, 2014, were as follows.

Higher sales volumes in 2014 were primarily due to strong demand in polymers and basic chemicals.

Capital expenditures in 2014 were $26 million.

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Research

In 2014, the company’s total gross research expenditures, before credits, were about $175 million, as compared with $199 million in 2013, and $201 million in 2012. Research expenditures are mainly for developing technologies to improve bitumen recovery, reduce costs, 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 Exxon Mobil Corporation, which provide for technical and engineering work to be performed by all parties, the exchange of technical information and the assignment and licensing of patents and patent rights. These agreements provide mutual access to scientific and operating data related to nearly every phase of the petroleum and petrochemical operations of the parties.

Environmental protection

The company 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 deal with existing, and to anticipate potential, environmental protection issues. In the past five years, the company has made capital and operating expenditures of about $5.6 billion on environmental protection and facilities. In 2014, the company’s environmental capital and operating expenditures totalled approximately $1.7 billion, which was spent primarily on water and tailings treatment and emission reductions at both company owned facilities and Syncrude and remediation of idled facilities and operations. Capital and operating expenditures relating to environmental protection are expected to be about $1.7 billion in 2015.

Human resources

The increase in career employees in 2014 is primarily associated with the company’s preparation for the 2015 start-up of the Kearl expansion project. About seven percent of the company’s employees are members of unions.

Competition

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

Government regulation

Petroleum and natural gas rights

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

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

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

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Crude oil

Production

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

Exports

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

Natural gas

Production

The maximum allowable gross production of natural gas from wells in Canada is subject to limitations by various regulatory authorities. These limitations are to ensure oil recovery is not adversely impacted by accelerated gas production practices. These limitations do not impact gas reserves, only the timing of production of the reserves and did not have a significant impact on 2014 gas production rates.

Exports

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

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

Royalties

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

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

Investment Canada Act

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

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

The company online

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

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

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Volatility of oil and natural gas prices

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

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

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

Environmental risks

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

Environmental legislation imposes, among other things, restrictions, liabilities and obligations in connection with the generation, handling, storage, transportation, treatment and disposal of hazardous substances and waste and in connection with spills, releases and emissions of various substances to the environment. As well, environmental regulations are imposed on the qualities and compositions of the products sold and imported. Environmental legislation also requires that wells, facility sites and other properties associated with the company’s operations be operated, maintained, 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 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 to the air from its operations and result in increased capital expenditures. Changes in environmental regulations or other laws (including changes in laws related to hydraulic fracturing) may increase our cost of compliance or reduce or delay available business opportunities. Future changes in environmental legislation could occur and result in stricter standards and enforcement, larger fines and liability, and increased capital expenditures and operating costs, which could have a material adverse effect on the company’s financial condition or results of operations.

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

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Climate change

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 emissions. These include adoption of cap and trade regimes, carbon taxes, increased efficiency standards, and incentives or mandates for renewable energy. These requirements could make our products more expensive, lengthen project implementation times, and reduce demand for hydrocarbons, as well as shift hydrocarbon demand toward lower-carbon sources such as natural gas. Current and pending greenhouse regulations may also increase our compliance costs, such as for monitoring or sequestering emissions.

Currency

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

Reserves replacement

The company’s future liquids, bitumen, synthetic oil and natural gas reserves and production, and therefore cash flows, are highly dependent upon the company’s success in exploiting its current reserve base and acquiring or discovering additional reserves. Without additions to the company’s reserves through exploration, acquisition or development activities, reserves and production will decline over time as reserves are depleted. To the extent cash flows from operations are insufficient to fund capital expenditures and external sources of capital become limited or unavailable, the company’s ability to make the necessary capital investments to maintain and expand oil and natural gas reserves will be impaired. In addition, the company may be unable to find and develop or acquire additional reserves to replace oil and natural gas production at acceptable costs.

Research and development

In light of the technological nature of our business and the need for continuous efficiency improvement, the company relies upon the research and development organizations of the company and ExxonMobil, with whom the company conducts shared research.

Safety, business controls and environmental risk management

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

Emergency preparedness

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

Other business risks

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

Other factors that may affect the demand for oil, gas and petrochemicals, and therefore impact the company’s results, include technological improvements in energy efficiency; seasonal weather patterns, which affect the demand for energy associated with heating and cooling; increased competitiveness of alternative energy

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sources; and changes in technology or consumer preferences that alter fuels choices, such as toward alternative fueled vehicles.

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

Reserve estimates

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

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

Project factors

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

None.

Reference is made to Item 1 above.

Not applicable.

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, a subsidiary of NYSE Euronext. Reference is made to the “Quarterly financial and stock trading data” portion of the Financial section on page 82 of this report. The closing price for Imperial Oil Limited common shares on the Toronto Stock Exchange was $49.74 as at February 11, 2015.

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 five percent on dividends paid to a corporation resident in the U.S. that owns at least ten percent of the voting shares of the company.

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

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

As of February 11, 2015 there were 11,867 holders of record of common shares of the company.

Between October 1, 2014 and December 31, 2014, pursuant to the company’s restricted stock unit plan, 1,375 shares were issued to employees outside the U.S. in reliance on Regulation S under the Securities Act, and 1,100 shares were issued to a seconded employee in reliance on the section 4(a)(2) exemption under the Securities Act.

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Securities authorized for issuance under equity compensation plans

Sections of the company’s management proxy circular are contained in the Proxy information section, starting on page 83. The company’s management proxy circular is prepared in accordance with Canadian securities regulations.

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

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 32 of this report.

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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.

Reference is made to the table of contents in the Financial section on page 28 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, 2014. 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 49 of this report for “Management’s report on internal control over financial reporting” and page 50 for the “Report of independent registered public accounting firm” on the company’s internal control over financial reporting as of December 31, 2014.

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

The company currently has seven directors. The articles of the company require that the board have between five and fifteen directors. Each director is elected to hold office until the close of the next annual meeting. Each of the seven individuals listed in the section entitled “Director information” on pages 84 to 92 of this report have been nominated for election at the annual meeting of shareholders to be held April 30, 2015. All of the nominees are directors and have been since the dates indicated.

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

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

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

Sections of the company’s management proxy circular are contained in the Proxy information section, starting on page 83. The company’s management proxy circular is prepared in accordance with Canadian securities regulations.

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

Reference is made to the following sections under “IV. 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 83. The company’s management proxy circular is prepared in accordance with Canadian securities regulations.

Reference is made to the section under “IV. Company executives and executive compensation” entitled “Equity compensation plan information”, within the “Compensation discussion and analysis” section, on page 135 of this report.

Reference is made to the section under “V. Other important information” entitled “Largest shareholder”, on page 137 of this report.

Reference is also made to the security ownership information for directors and executive officers of the company under the preceding Items 10 and 11. As of February 11, 2015, P.J. Masschelin was the owner of 3,000 common shares of the company and held 89,050 restricted stock units of the company. T.G. Scott held 88,525 restricted stock units of the company. W.J. Harnett was the owner of 12,858 common shares of the company and held 80,825 restricted stock units of the company. B.G. Merkel was the owner of 6,978 common shares of the company and held 75,950 restricted stock units of the company.

The directors and the executive officers of the company, whose compensation for the year-ended December 31, 2014 is described in the sections under “III. Board of directors” starting on page 84 and “IV. Company executives and executive compensation” starting on page 113, consist of 15 persons, who, as a group, own beneficially 102,081 common shares of the company, being approximately 0.01 percent of the total number of outstanding shares of the company, and 557,875 shares of Exxon Mobil Corporation (including 426,800 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 443,275 common shares of the company, as of February 11, 2015.

Sections of the company’s management proxy circular are contained in the Proxy information section, starting on page 83. The company’s management proxy circular is prepared in accordance with Canadian securities regulations.

Reference is made to the section under “V. Other important information” entitled “Transactions with Exxon Mobil Corporation”, on page 137 of this report.

Reference is made to the section under “III. Board of directors” entitled “Independence of the directors”, on page 96 of this report.

D.G. (Jerry) Wascom is deemed a non-independent member of the executive resources committee, environmental, health and safety committee, nominations and corporate governance committee and contributions committee under the relevant standards. As an employee of ExxonMobil Refining & 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.

Sections of the company’s management proxy circular are contained in the Proxy information section, starting on page 83. The company’s management proxy circular is prepared in accordance with Canadian securities regulations.

Reference is made to the section under “V. Other important information” entitled “Auditor information”, on page 138 of this report.

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PART IV

Reference is made to the table of contents in the Financial section on page 28 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, 237 Fourth Avenue S.W., Calgary, Alberta, Canada T2P 3M9, and payment of processing and mailing costs.

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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 24, 2015 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 24, 2015 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 summary (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, as defined below, represent the expenses most directly under the company’s control and therefore, are useful in evaluating the company’s performance.

Reconciliation of Operating Costs

Components 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. While commodity prices remain volatile on a short-term basis depending upon supply and demand, Imperial’s investment decisions are based on its long-term business outlook, using a disciplined approach in selecting and pursuing the most attractive investment opportunities. The corporate plan is a fundamental annual management process that is the basis for setting near-term operating and capital objectives, in addition to providing the longer-term economic assumptions used for investment evaluation purposes. Potential investment opportunities are tested over a wide range of economic scenarios to establish the resiliency of each opportunity. Once investments are made, a reappraisal process is completed to ensure relevant lessons are learned and improvements are incorporated into future projects.

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

Business environment and risk assessment

Long-term business outlook

By 2040, the world’s population is projected to grow to approximately nine billion people, or about two billion more than in 2010. Coincident with this population increase, the company expects worldwide economic growth to average close to three percent per year. As economies and population grow, and as living standards improve for billions of people, the need for energy will continue to rise. Even with significant efficiency gains, global energy demand is projected to rise by about 35 percent from 2010 to 2040. This demand increase is expected to be concentrated in developing countries (i.e., those that are not member nations of the Organization for Economic Cooperation and Development).

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

Energy for transportation - including cars, trucks, ships, trains and airplanes - is expected to increase by about 40 percent from 2010 to 2040. The 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 85 percent by 2040, led by growth in developing countries. Consistent with this projection, power generation is expected to remain the largest and fastest-growing major segment of global energy demand. Meeting the expected growth in power demand will require a diverse set of energy sources. Natural gas demand is likely to grow most significantly and become the leading source of generated electricity by 2040, reflecting the efficiency of gas-fired power plants. Today, coal has the largest fuel share in the power sector, but its share is likely to decline significantly by 2040 as policies are gradually adopted to reduce environmental impacts including those related to local air quality and

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

greenhouse gas emissions. Nuclear power and renewables, led by hydropower and wind, are expected to grow significantly over the period.

Liquid fuels provide the largest share of global energy supplies today due to their broad-based availability, affordability and ease of transportation, distribution and storage to meet consumer needs. By 2040, global demand for liquid fuels is expected to grow to approximately 115 million barrels of oil-equivalent per day, an increase of almost 30 percent from 2010. 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, deepwater, oil sands, natural gas liquids, and biofuels. The world’s resource base is sufficient to meet projected demand through 2040 as technology advances continue to expand the availability of economic supply options. However, access to resources and timely investments will remain critical to meeting global needs with reliable, affordable supplies.

Natural gas is a versatile fuel, suitable for a wide variety of applications, and is expected to be the fastest growing major fuel source through 2040. Global demand is expected to rise about 65 percent from 2010 to 2040, with about half of that increase in the Asia Pacific region. Helping meet these needs will be significant growth in supplies of unconventional gas - the natural gas found in shale and other rock formations that was once considered uneconomic to produce. About two-thirds of the growth in natural gas supplies is expected to be from unconventional sources, which will account for close to 35 percent of global gas supplies by 2040. The worldwide liquefied natural gas market is expected to more than triple by 2040, stimulated by growing natural gas demand.

The world’s energy mix is highly diverse and will remain so through 2040. Oil is expected to remain the largest source of energy with its share remaining close to one-third in 2040. Coal is currently the second largest source of energy, but it is likely to lose that position to natural gas by approximately 2025 to 2030 timeframe. The share of natural gas is expected to exceed 25 percent by 2040, while the share of coal falls to less than 20 percent. Nuclear power is projected to grow significantly, as many nations expand nuclear capacity to address rising electricity needs as well as energy security and environmental issues. Total renewable energy is likely to reach close to 15 percent of total energy by 2040, with biomass, hydro and geothermal contributing combined share of more than ten percent. Total energy supplied from wind, solar and biofuels is expected to increase close to 450 percent from 2010 to 2040, when they will be approaching four percent of world energy.

The company anticipates that the world’s available oil and gas resource base will grow not only from new discoveries, but also from reserve increases in previously discovered fields. Technology will underpin these increases. The cost to develop and supply these resources will be significant. According to the International Energy Agency, the investment required to meet total oil and gas energy needs worldwide over the period 2014 to 2040 will be about $28 trillion (measured in 2013 dollars), or more than one trillion per year on average.

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

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

to innovative technologies, development of employees and investment in the communities within which the company operates.

The company’s current Upstream activities support plans to significantly increase production this decade. The Kearl initial development, the largest capital investment in the company’s history, started up in 2013. The Kearl expansion project and the Nabiye expansion project at Cold Lake were also advanced in 2014 and are expected to commence production in 2015. To support the company’s long-term growth a variety of existing and new logistics outlets have been secured or are being developed.

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

Prices for most of the company’s crude oil sold are referenced to West Texas Intermediate (WTI) oil markets, a common benchmark for mid-continent North American markets. In 2014, the average WTI crude oil price, in U.S. dollars, was lower versus 2013. This negative impact, however, was more than offset by the effect of the weaker Canadian dollar. The markets for crude oil and natural gas have a history of significant price volatility. After some years of relatively stable prices, the end of 2014 saw prices drop to levels not seen since 2009. 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. To manage the risks associated with price, Imperial evaluates annual plans and all investments across a wide range of price scenarios. The company’s assessment is that its operations will continue to be successful in a variety of market conditions. This is the outcome of disciplined investment, cost management, and asset enhancement programs.

Downstream

Imperial’s Downstream serves predominately 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 421,000 barrels per day. Imperial’s fuels marketing business includes retail operations across Canada serving customers through more than 1,700 Esso-branded retail service stations, as well as wholesale and industrial operations through a network of 22 primary distribution terminals.

Globally, the downstream industry environment remains challenging. Slowing demand growth and overcapacity in the refining sector will continue to increase competitive pressure. In Canada, in recent years, access to price-advantaged feedstock, as a result of North American crude logistics constraints and increasing North American crude oil production, along with lower natural gas prices have strengthened refining margins.

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.

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

In the retail fuels marketing business, about 470 of the 1,700 Esso-branded retail site network are company-owned. The remainder operates under a branded wholesaler model whereby Imperial supplies fuels to

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independent third parties who own and operate retail sites in alignment with Esso brand standards. In January 2015, the company announced that it will evaluate its operating model for the company-owned retail service stations. The assessment will evaluate the potential opportunity to extend the branded wholesaler model to the remaining 470 sites as part of Imperial’s Esso brand growth strategy.

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 Sarnia chemical plant achieved a further feedstock cost advantage with access to Marcellus ethane beginning in the second quarter of 2014. The company’s strategy for its Chemical business is to reduce costs and maximize value by continuing the integration of its chemical plant in Sarnia with the refinery. The company also benefits from its integration within ExxonMobil’s North American chemical businesses, enabling Imperial to maintain a leadership position in its key market segments.

Results of operations

Consolidated

2014

Net income in 2014 was $3,785 million or $4.45 per share on a diluted basis, versus $2,828 million or $3.32 per share in 2013. Earnings improved in all operating segments in 2014 with Downstream earnings higher by $542 million, Upstream earnings by $347 million and Chemical earnings by $67 million.

2013

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

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

Upstream

2014

Upstream net income in 2014 was $2,059 million, $347 million higher than 2013. Earnings in 2014 included a gain of $478 million from the divestment of conventional upstream producing assets, whereas 2013 included a $73 million gain for the sale of non-operating assets. Earnings also increased due to the impacts of a weaker Canadian dollar of about $280 million and higher liquids volumes of about $100 million, reflecting the incremental contribution from Kearl production. These factors were partially offset by higher royalty costs of about $220 million mainly associated with higher Canadian bitumen realizations, reduced allowable costs and the ramp up of Kearl production, as well as higher energy and other operating costs of about $130 million, and the impact of lower crude oil realizations of about $50 million.

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2013

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

Average realizations

2014

Prices for most of the company’s liquids production are based on WTI crude oil, a common benchmark for mid-continent North American oil markets. WTI was down about $5.14 per barrel in U.S. dollars, or about five percent in 2014, versus 2013. The company’s average bitumen realizations in Canadian dollars in 2014 were $67.20 per barrel versus $60.57 per barrel in 2013, with the lower WTI benchmark price more than offset by the effect of the weaker Canadian dollar and the narrower price spread between light crude oil and bitumen. The company’s average realizations from the sale of synthetic crude oil were largely unchanged from 2013, as the decrease in WTI crude oil benchmark price was essentially offset by the impact of a weaker Canadian dollar. The company’s average realizations on natural gas sales of $4.54 per thousand cubic feet in 2014 were higher by $1.27 per thousand cubic feet versus 2013.

2013

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

Crude oil and NGLs - production and sales (a)

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Natural gas - production and production available for sale (e)

2014

Gross production of Cold Lake bitumen averaged 146,000 barrels per day in 2014, down from 153,000 barrels in 2013. Lower volumes were primarily due to the cyclic nature of steaming and associated production and the impact of several unplanned third-party power outages in the first quarter.

During the year, the company’s share of gross production from Syncrude averaged 64,000 barrels per day, down from 67,000 barrels in 2013, primarily due to higher scheduled and unscheduled maintenance activities.

The company’s share of gross production from the Kearl initial development in 2014 was 51,000 barrels per day versus 16,000 barrels in 2013. Production at the Kearl initial development continued to ramp-up in 2014.

Gross production of conventional crude oil averaged 18,000 barrels per day in the year, versus 21,000 barrels in 2013. The lower production volume was primarily due to the impact of properties divested during the first half of 2014.

Gross production of natural gas in 2014 was 168 million cubic feet per day, down from 201 million cubic feet in 2013. The lower production volume was primarily the result of the impact of divested properties.

2013

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

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

The company’s share of gross production of Kearl initial development was 16,000 barrels per day for the full year. Production of mined diluted bitumen began in April 2013 and continued to ramp-up in 2014. Since start-up, improvements have been made to equipment reliability. Although gross production rates of 100,000 barrels per day (71,000 Imperial’s share) were reached in the fourth quarter, ongoing activities to stabilize performance at these higher levels are progressing. In the fourth quarter, sales to unrelated third parties commenced as planned.

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

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

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Downstream

2014

Downstream net income was $1,594 million, up $542 million from 2013. Earnings in 2013 included a charge of $280 million associated with the conversion of the Dartmouth refinery to a fuels terminal. Earnings also increased due to the impacts of improved refinery reliability and accessing advantaged crudes of about $330 million, a weaker Canadian dollar of about $130 million and higher marketing margins and sales volumes totalling about $105 million. These factors were partially offset by lower refining margins of about $230 million.

2013

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

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

Refinery utilization

Sales