IMPERIAL OIL LTD - Annual Report: 2011 (Form 10-K)

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UNITED STATES SECURITIES AND EXCHANGE COMMISSION

WASHINGTON, D.C. 20549

FORM 10-K

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

SECURITIES EXCHANGE ACT OF 1934

IMPERIAL OIL LIMITED

(Exact name of registrant as specified in its charter)

Registrant’s telephone number, including area code:

1-800-567-3776

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

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

Common Shares (without par value)

(Title of Class)

Indicate by check mark if the registrant is a well-known seasoned issuer (as defined in Rule 405 of the Securities Exchange Act of 1934).

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 2011 second fiscal quarter, the aggregate market value of the voting stock held by non-affiliates of the registrant was Canadian $11,574,568,203 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 15, 2012, was 847,670,521.

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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 15, 2012, 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 $1.0035 U.S. = $1.00 Canadian.

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Forward-looking statements

Statements in this report regarding expectations, plans and future events or conditions are forward-looking statements. Actual future results, including demand growth and energy source mix; production growth and mix; project start-ups; the effect of changes in prices and other market conditions; financing sources; and capital and environmental expenditures could differ materially depending on a number of factors, such as changes in the supply of and demand for crude oil, natural gas, and petroleum and petrochemical products; political or regulatory events; project schedules; commercial negotiations; 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.

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, conventional 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 for the company are contained in the Financial section of this report under Note 2 to the consolidated financial statements: “Business segments”.

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, 2011, as detailed in the “Oil and gas reserves” part of the Financial section, starting on page 79 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 favorable or adverse event has occurred since December 31, 2011 that would cause a significant change in the estimated proved reserves as of that date, except for the following. In February 2012, the Nabiye expansion project at Cold Lake was approved by the company’s board. Proved reserves from the Nabiye project will be included in 2012 year-end reporting for the first time.

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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 2011 were based on estimates generated through the integration of available and appropriate data, utilizing well established technologies that have been demonstrated in the field to yield repeatable and consistent results.

Data used in these integrated assessments included information obtained directly from the subsurface via wellbores, such as well logs, reservoir core samples, fluid samples, static and dynamic pressure information, production test data, and surveillance and performance information. The data utilized also included subsurface information obtained through indirect measurements, including high-quality 2-D and 3-D seismic data, calibrated with available well control information. Where applicable, surface geological information was also utilized. 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 Securities and Exchange Commission (SEC) rules and regulations, review of annual changes in reserves estimates, and the reporting of 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 computerized database containing the official company reserves estimates and production data. Appropriate controls, including limitations on database access and update capabilities, are in place to ensure data integrity within this central computerized 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 will require further review and approval of the appropriate level of management within the operating organization, culminating in reviews with and approval by senior management and the company’s board of directors.

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The Operations Technical Subsurface Engineering Manager, who is an employee of the company, has evaluated the company’s reserves data and filed a report to the Canadian securities regulatory authorities. The company’s internal reserves evaluation staff consists of about 59 persons with an average of approximately 15 years of relevant experience in evaluating reserves, of whom about 37 persons are qualified reserves evaluators for purposes of Canadian securities regulatory requirements. The company’s internal reserves evaluation management team is made up of about 12 persons with an average of approximately 12 years of relevant experience in evaluating and managing the evaluation of reserves. No independent qualified reserves evaluator or auditor was involved in the preparation of the company’s reserves data.

Proved undeveloped reserves

As of December 31, 2011, approximately 60 percent of the company’s proved reserves were proved undeveloped reserves reflecting volumes of 1,904 million oil-equivalent barrels. Nearly all of those undeveloped reserves are associated with either the Kearl project or Cold Lake field. This compared to approximately 47 percent or 1,209 million oil-equivalent barrels of proved undeveloped reserves reported at the end of 2010. In December 2011, Kearl expansion was approved by the company’s board. Increased proved undeveloped reserves in 2011 were primarily due to the initial booking of the approved Kearl expansion.

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 $3.1 billion during the year to progress the development of reported proved undeveloped reserves. The largest project under development in 2011 was the initial development of Kearl which was 87 percent complete at 2011 year-end and is expected to start-up in late 2012. Proved undeveloped reserves at Cold Lake are associated with the ongoing drilling program. In 2011, Imperial moved 68 million barrels from proved undeveloped to proved developed reserves at Cold Lake.

Oil and gas production, production prices and production costs

Average daily production of oil

The company’s average daily oil production by final products sold during the three years ended December 31, 2011 was as follows. All reported production volumes were from Canada.

In 2011, third party pipeline unplanned downtime, which resulted in reduced production at the Norman Wells field, and natural reservoir decline were the main contributors to lower conventional liquids production. Higher gross bitumen volumes were due to contributions from new wells steamed in 2010 and 2011, increased recoveries as a result of technology applications and the cyclic nature of production at Cold Lake. Synthetic oil production at Syncrude was in line with 2010.

In 2010, planned maintenance activities at the Norman Wells field and natural reservoir decline were the main contributors to the lower liquids production. Higher gross bitumen volumes in 2010 were due to improved facility reliability as well as the cyclic nature of production at Cold Lake. Net bitumen production at Cold Lake was lower due to higher royalties. Synthetic oil production at Syncrude was higher primarily due to improved operational reliability.

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Average daily production and sales of natural gas

The company’s average daily production and sales of natural gas during the three years ended December 31, 2011 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.

In 2011, lower gross gas production volume was primarily a result of natural reservoir decline.

In 2011, the company sold its interests in shallow gas properties in the Medicine Hat, Alberta area, Coleville-Hoosier natural gas producing property in Saskatchewan and the Rainbow Lake producing property in Alberta, realizing a gain of about $76 million. Production for the company’s share of the properties averaged about 56 million cubic feet of natural gas a day and one thousand barrels of crude oil a day in 2010.

In 2010, lower gross gas production volume was primarily a result of natural reservoir decline and maintenance activities.

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, 2011, were as follows:

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Average unit production costs

Canadian crude oil prices are mainly determined by international crude oil markets and the impact of foreign exchange rates.

Canadian natural gas prices are determined by North American gas markets and the impact of foreign exchange rates.

In 2011, unit production costs increased on a net basis primarily due to lower net volumes as a result of higher royalty costs, increased maintenance costs at Syncrude and pre-startup costs associated with the Kearl initial development project.

In 2010, unit production costs increased on a net basis primarily due to lower net volumes as a result of higher royalty costs.

Drilling and other exploratory and development activities

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

Wells Drilled

The following table sets forth the conventional and bitumen net exploratory and development wells that were drilled or participated in by the company during the three years ending December 31, 2011.

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

Two net exploratory gas wells were drilled in the Horn River shale gas play, as part of the company’s ongoing evaluation of its holdings in the area, and one net exploratory tight oil well was drilled to evaluate some of the company’s holdings in Alberta.

In 2010, 110 bitumen development wells were drilled to add new productive capacity from undeveloped areas of existing phases at Cold Lake. In addition, 71 gas development wells were drilled in 2010 adding productivity primarily in the shallow gas area. Additionally, one oil development well was drilled in Norman Wells and one oil development well was drilled in the Pembina area.

Also in 2010, six net exploratory gas wells were drilled in the Horn River shale gas play, as part of the company’s ongoing evaluation of its holdings in the area.

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In 2009, 60 bitumen development wells were drilled to add new productive capacity from undeveloped areas of existing phases at Cold Lake. In addition, 216 gas development wells were drilled in 2009 adding productivity primarily in the shallow gas area. Additionally, two oil development wells were drilled in Norman Wells. Also in 2009, two net exploratory gas wells were drilled in the Horn River shale gas play as part of the company’s ongoing evaluation of its holdings in the area.

Wells drilling

At December 31, 2011, the company was participating in the drilling of the following exploratory and development wells. All wells were located in Canada.

Exploratory and development activities regarding oil and gas resources

Cold Lake

To maintain production at Cold Lake, capital expenditures for additional production wells and associated facilities are required periodically. In 2011, the company executed a development drilling program of 34 wells on existing phases.

In 2012, a development drilling program is planned within the approved development area to add productive capacity from undeveloped areas of existing Cold Lake phases. In February 2012, the Nabiye expansion project at Cold Lake was approved by the company’s board and appropriated for $2 billion. The expansion is expected to bring on additional production of more than 40,000 barrels a day, before royalties, at Cold Lake. Start-up is expected to be year-end 2014.

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

Western provinces

In 2011, drilling and facility construction were underway on the production pilot of an eight horizontal-well pad (four net wells) in the Horn River shale gas acreage to evaluate well productivity and cost performance. The pilot production is scheduled to start-up in late 2012.

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.

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, support from northern parties, regulatory approvals, environmental considerations, pipeline participation, fiscal framework and the cost of constructing, operating and abandoning the field production and pipeline facilities.

In October 2004, the company and its co-venturers filed regulatory applications and environmental impact statements for the project with the National Energy Board (NEB) and other boards, panels and agencies responsible for assessing and regulating energy developments in the Northwest Territories. All the scheduled public hearings by the Joint Review Panel (JRP) and the NEB were concluded in late 2007. The JRP report was released in late 2009. In late 2010, the NEB announced its approval of plans to build and operate the project and 264 conditions in areas such as engineering, safety and environmental protection. Federal cabinet approved the project in early 2011.

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. In 2009, 2010 and 2011, the company carried out data collection programs to support environmental studies and safe exploration drilling operations.

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In 2010, the company executed an agreement to cross-convey interests with another company to acquire a 25 percent interest in an additional Beaufort Sea exploration licence. As a result of that agreement, the company’s interest in its original licence was reduced to 25 percent.

Atlantic offshore

The company holds a 15 percent interest in deepwater exploration blocks in the Orphan Basin, located off the east coast of Newfoundland. In 2004 and 2005, the company participated in 3-D seismic surveys in this area. Exploration wells were drilled in 2007 and 2010. In 2009, the company participated in a remote reservoir resistivity survey of the area.

Other oil sands activity

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.

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

Kearl project

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 will recover shallow deposits of oil sands using open-pit mining methods. The project is located approximately 40 miles north of Fort McMurray, Alberta.

The Kearl project received 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 is expected to be at an initial rate of approximately 110,000 barrels of bitumen a day, before royalties, of which the company’s share would be about 78,000 barrels a day. In 2011, the initial development was reconfigured with a capital appropriation of $10.9 billion, of which the company’s share would be $7.7 billion. At the end of 2011, initial development was 87 percent complete, with expected start-up in late 2012.

In 2011, the expansion was approved by the company’s board and appropriated for $8.9 billion, of which the company’s share is $6.3 billion. It is expected to bring on additional production of 110,000 barrels of bitumen a day, before royalties, by late 2015, of which the company’s share would be about 78,000 barrels a day.

Future debottlenecking of both the initial development and expansion will increase output to reach the regulatory capacity of 345,000 barrels a day by 2020.

Bitumen from the Kearl project will be extracted from oil sands produced from open-pit mining operations and processed through a bitumen extraction and froth treatment plant. The product, a blend of bitumen and diluent, is planned to be shipped via pipelines for distribution to North American markets. Diluent is natural gas condensate or other light hydrocarbons added to the crude bitumen to facilitate transportation to market by pipeline.

Kearl will be subject to the revised Alberta generic oil sands royalty regime, which took effect in 2009. Royalty rates are based upon a sliding scale determined by the price of crude oil.

Other oil sands activity

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

Present activities

Review of principal ongoing activities

Cold Lake

During 2011, average net production at Cold Lake was about 120,000 barrels a day and gross production was about 160,000 barrels a day.

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

The Province of Alberta, in its capacity as lessor of Cold Lake oil sands leases, is entitled to a royalty on production at Cold Lake. Cold Lake is subject to the revised Alberta generic oil sands royalty regime, which took effect in 2009. Royalty rates are based upon a sliding scale determined by the price of crude oil.

Syncrude operations

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

In 2011, Syncrude’s net production of synthetic crude oil was about 268,000 barrels a day and gross production was about 288,000 barrels a day. The company’s share of net production in 2011 was about 67,000 barrels a day.

There are no approved plans for major future expansion projects.

In November 2008, Imperial, along with the other Syncrude joint-venture owners, signed an agreement with the Government of Alberta to amend the existing Syncrude Crown Agreement. 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.

On May 1, 2007, the company implemented a management services agreement under which Syncrude will be provided with operational, technical and business management services from Imperial and Exxon Mobil Corporation. The agreement has an initial term of 10 years, automatically renews for successive five-year periods and may be terminated with at least two years prior written notice.

Conventional oil and gas

The company’s largest conventional oil producing asset is the Norman Wells oil field in the Northwest Territories, which currently accounts for about 60 percent of the company’s gross production of conventional crude oil. In 2011, gross production of crude oil from Norman Wells was about 11,000 barrels a day. Production was adversely impacted due to third party pipeline reliability issues in the second and third quarter of 2011. The Government of Canada has a one-third carried interest and receives a production royalty of five percent in the Norman Wells oil field. The Government of Canada’s carried interest entitles it to receive payment of a one-third share of an amount based on revenues from the sale of Norman Wells production, net of operating and capital costs.

Most of the company’s larger oil fields in the Western provinces have been in production for several decades, and the amount of oil that is produced from conventional fields is declining.

The company produces natural gas from a large number of gas fields located in the Western provinces, primarily in Alberta. The company also has a nine percent interest in a project to develop and produce natural gas reserves in the Sable Island area off the coast of the Province of Nova Scotia.

Delivery commitments

The company is contractually committed to deliver approximately 30 billion cubic feet of natural gas in Canada for the period from 2012 through 2014, which is substantially less than the company’s proved natural gas reserves.

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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, 2011 and 2010, is set forth in the following table. The statistics in the table are determined in part from information received from other operators.

The decrease in natural gas wells is primarily attributed to the company’s divestments in 2011.

Land holdings

At December 31, 2011 and 2010, the company held the following oil and gas rights, bitumen and synthetic oil leases, all of which are located in Canada, specifically in the Western provinces, in the Canada lands and in the Atlantic offshore:

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Western provinces

The company’s bitumen leases include about 194,000 acres of oil sands leases near Cold Lake and an area of about 34,000 net acres at Kearl. The company has about 89,000 net acres of undeveloped, mineable oil sands acreage in the Athabasca region. In addition, the company also has interests in other bitumen oil sands leases in the Athabasca and Peace River areas totaling about 149,000 net acres. In 2011, the company exchanged oil sands leases in the Athabasca area with a third party, where two leases totaling about 21,000 acres were relinquished in exchange for rights to one strategic lease of about 12,000 acres.

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

The company holds interest in an additional 1,050,000 net acres of developed and undeveloped land in Western Canada related to conventional 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 2011, the company relinquished a total of about 256,000 net acres in Western Canada.

Canada lands

In the Arctic Islands, the company has an interest in 16 significant discovery licences granted by the Government of Canada. These licences are managed by another company on behalf of all participants and total about 50,000 net acres. The company has not participated in wells drilled in this area since 1984.

Also within the Canada lands, the company holdings in the Mackenzie Delta include majority interests in 21, and minority interests in six, significant discovery licences granted by the Government of Canada, as the result of previous oil and gas discoveries, all of which are managed by the company, and majority interests in two, and minority interests in 17, other significant discovery licences managed by others. Total acreage held in the Mackenzie Delta is 184,000 net acres.

In 2011, two exploration licences were acquired from the Government of Canada in the Summit Creek area of central Mackenzie Valley totaling 222,000 net acres.

In 2007, the company acquired a 50 percent interest in an offshore exploration licence in the Beaufort Sea of about 507,000 gross acres. In 2010, the company reduced its interest to 25 percent and acquired a 25 percent interest in another Beaufort Sea exploration licence, as part of a cross-conveyance agreement, of about 500,000 gross acres. The company holds interest in the Beaufort Sea of about 252,000 net acres.

The balance of the Canada lands acreage, 16,000 net acres, consists of multiple leases and significant discovery licences throughout the Northwest Territories and Yukon.

Atlantic offshore

The company manages five significant discovery licences granted by the Government of Canada in the Atlantic offshore. The company also has minority interests, managed by others, in 27 significant discovery licences, and six production licences.

In early 2004, the company acquired a 25 percent interest in eight deep-water exploration licences offshore Newfoundland in the Orphan Basin for about 5,251,000 gross acres. In February 2005, the company reduced its interest to 15 percent through an agreement with another company. In early 2009, one exploration licence in its entirety and most of a second exploration licence, for about 1,069,000 gross acres, expired. The remaining exploration licences were consolidated into two exploration licences, for a total of about 627,000 net acres. In 2011, one exploration licence and a portion of the second exploration licence, for about 403,000 net acres, were surrendered. The remaining total Orphan Basin acreage is 224,000 net acres.

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Downstream

Supply

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

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

Crude oil from foreign sources is purchased by the company at market prices mainly through Exxon Mobil Corporation (which has beneficial access to major market sources of crude oil throughout the world).

Refining

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

In 2011, capital expenditures of about $85 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 five years ended December 31, 2011, and the daily rated capacities of the refineries at December 31, 2011 and 2006, were as follows:

Refinery throughput was 85 percent of capacity in 2011, three percent lower than the previous year. The lower rate was primarily a result of higher planned and unplanned maintenance activities.

Distribution

The company maintains a nation-wide 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 580 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 1,800 retail service stations, of which about 480 were company owned or leased, but none of which were company operated. The company continues to improve its Esso retail service station network, providing more customer services such as car washes and convenience stores, primarily at high volume sites in urban centres.

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The Canadian farm, residential heating and small commercial markets are served through about 70 branded agents and resellers. The company also sells petroleum products to large industrial and commercial accounts as well as to other refiners and marketers.

The approximate daily volumes of net petroleum products (excluding purchases/sales contracts with the same counterparty) sold during the five years ended December 31, 2011, are set out in the following table:

The total domestic sales of petroleum products, as a percentage of total sales of petroleum products during the five years ended December 31, 2011, were as follows:

The company continues to evaluate and adjust its Esso retail service station and distribution system to increase productivity and efficiency. During 2011, the company closed or debranded about 86 Esso retail service stations, about 13 of which were company owned, and added about 51 sites. The company’s average annual throughput in 2011 per Esso retail service station was about 25 thousand barrels (4.0 million litres), unchanged from 2010. Average throughput per company owned or leased Esso retail service station was about 45 thousand barrels (7.2 million litres) in 2011, unchanged from 2010.

Total Downstream capital expenditures were $166 million in 2011 and are expected to be about $200 million in 2012.

Chemical

The company’s Chemical operations manufacture and market ethylene, benzene, aromatic and aliphatic solvents, plasticizer intermediates and polyethylene resin. Its major petrochemical and polyethylene manufacturing operations are located in Sarnia, Ontario, adjacent to the company’s petroleum refinery. There is also a heptene and octene plant located in Dartmouth, Nova Scotia.

The company’s total sales volumes of petrochemicals during the five years ended December 31, 2011, were as follows:

Higher volumes in 2011 were primarily due to lower planned maintenance activities at the Sarnia facility.

Capital expenditures in 2011 were $4 million, with planned expenditures in 2012 of about $14 million.

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Research

In 2011, the company’s total gross research expenditures, before credits, were about $163 million, as compared with $119 million in 2010, and $138 million in 2009. Total gross research expenditures included capital expenditures of $1 million, $3 million and $19 million in 2011, 2010 and 2009, respectively. These expenditures were used mainly for developing technologies to reduce the environmental impact and improve bitumen recovery in the Upstream and for supporting environmental and process improvements in the refineries, as well as accessing ExxonMobil’s data worldwide.

A research facility to support the company’s Upstream operations is located in Calgary, Alberta. Research in these laboratories is aimed at developing new technology for the production and processing of crude bitumen. About 40 people were involved in this type of research in 2011. The company also participated in bitumen recovery and processing research for oil sands development through its interest in Syncrude, which maintains research facilities in Edmonton, Alberta. The company also participated in research arrangements with others, including for tailings management.

In company laboratories in Sarnia, Ontario, research and advanced technical support is focused on several areas including supporting environmental and process improvements, and the refineries’ readiness to process Kearl crude. About 105 people were employed in this type of research and advanced technical support at the end of 2011.

The company has scientific research agreements with affiliates of Exxon Mobil Corporation, which provide for technical and engineering work to be performed by all parties, the exchange of technical information and the assignment and licensing of patents and patent rights. These agreements provide mutual access to scientific and operating data related to nearly every phase of the petroleum and petrochemical operations of the parties.

Environmental protection

The company is concerned with and active in protecting the environment in connection with its various operations. The company works in cooperation with government agencies, industry associations and communities to deal with existing, and to anticipate potential, environmental protection issues. In the past five years, the company has made capital and operating expenditures of about $3.3 billion on environmental protection and facilities. In 2011, the company’s environmental capital and operating expenditures totaled approximately $724 million, which was spent primarily on emissions reductions at company owned facilities and Syncrude, remediation of idled facilities and operations, as well as on protection of freshwater near Imperial facilities. Capital and operating expenditures relating to environmental protection are expected to be about $1.1 billion in 2012.

Human resources

At December 31, 2011, the company employed about 5,085 persons on a full-time basis, compared with about 4,970 at the end of 2010 and about 5,015 at the end of 2009. About eight percent of the company’s employees are members of unions. The company continues to maintain a broad range of benefits, including health, dental, disability and survivor benefits, vacation, savings plan and pension plan.

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.

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Government regulation

Petroleum and natural gas rights

Most of the company’s petroleum and natural gas rights were acquired from governments, either federal or provincial. These rights in the form of leases or licences are generally acquired for cash. A lease or licence entitles the holder to produce petroleum and/or natural gas from the leased lands. The holder of a lease or licence relating to Canada lands and the Atlantic Offshore is generally required to make cash payments or to undertake specified work commitments or exploration expenditures in order to retain the holder’s interest in the land, and may become entitled to produce petroleum or natural gas from the leased or licenced land.

Crude oil

Production

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

Exports

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

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 2011 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 royalty rates for Norman Wells, 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.

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The company online

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

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, proven 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. As a result, the price received for bitumen is generally lower than the price for medium and light oil. Future differentials are uncertain and increases in the bitumen differentials could have a material adverse effect on the company’s business.

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

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

Competitive factors

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

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

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Environmental risks

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

Environmental legislation imposes, among other things, restrictions, liabilities and obligations in connection with the generation, handling, storage, transportation, treatment and disposal of hazardous substances and waste and in connection with spills, releases and emissions of various substances to the environment. As well, environmental regulations are imposed on the qualities and compositions of the products sold and imported. Environmental legislation also requires that wells, facility sites and other properties associated with the company’s operations be operated, maintained, abandoned and reclaimed to the satisfaction of applicable regulatory authorities. In addition, certain types of operations, including exploration and development projects and significant changes to certain existing projects, may require the submission and approval of environmental impact assessments. Compliance with environmental legislation can require significant expenditures and failure to comply with environmental legislation may result in the imposition of fines and penalties and liability for clean up costs and damages. The company cannot assure that the costs of complying with environmental legislation in the future will not have a material adverse effect on its 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. 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.

The company’s activities in deep water oil and gas exploration are limited. However, 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 such as a deepwater well blowout. Accordingly, the company’s primary focus is on prevention, including through its rigorous operations integrity management system. The company’s future results will depend on the continued effectiveness of these efforts.

Climate change

In April 2007, the Government of Canada announced its intent to introduce a set of regulations to limit emissions of greenhouse gas and air pollutants from major industrial facilities in Canada, although the details of the regulations have not been finalized. In the fall of 2009, the Government further expressed its intent that Canadian policy in this area be aligned with that of the U.S., which also remains under development. Consequently, attempts to assess the impact on the company are premature. The company will continue to monitor the development of legal requirements in this area.

In the Province of Alberta, regulations governing greenhouse gas emissions from large industrial facilities came into effect July 1, 2007. These regulations cover industrial facilities emitting more than 100,000 tonnes (carbon dioxide equivalent) of greenhouse gas emissions annually and require a reduction by 12 percent in the greenhouse gas emissions per unit of production from each facility’s average annual intensity compared with the period 2003 through 2005. Allowed compliance measures include participation in an Alberta emission-trading system or payment (at a rate of $15 per excess tonne of emissions) to Alberta’s Climate Change and Emissions Management Fund. Impact on the overall operations of the company has not been material.

The Province of British Columbia introduced a carbon tax in 2008 at an initial rate of $10 per tonne of carbon dioxide and applicable to purchases of hydrocarbon fuels and emissions of greenhouse gases. The applicable tax rate was increased to $25 in 2011, and a further increase of $5 per tonne to a level of $30 per tonne is planned in 2012. It is the current policy of the Government of British Columbia to offset revenues from this tax by reductions in corporate and personal income taxes. Impacts on the company and its operations have not been and are not expected to be material.

The Province of Quebec announced in 2011 that it would regulate greenhouse gas emissions from industrial facilities starting in 2012 and from transportation sources in 2015, with a cap-and-trade system. There are no company operations affected by the regulations for industrial facilities. As there are currently limited details on the planned inclusion of the transportation sources in the cap-and-trade system, attempts to assess the impact of these plans on the company are premature.

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The Province of Ontario has passed legislation authorizing the issuing of regulations for the creation of a provincial cap-and-trade system controlling greenhouse gas emissions. However, details on such possible regulations have not been provided and consequently attempts to assess any impacts on the company are premature.

The Province of British Columbia has introduced Low Carbon Fuel Standard (LCFS) regulations requiring suppliers of transportation fuels to report the carbon intensity of fuels sold in British Columbia, and beginning in 2013 to reduce the carbon intensity by an increasing amount over a 10-year period. California has introduced similar requirements and some other U.S. states are considering comparable measures. Such measures in California and other U.S. states may have implications for the company’s marketing of oil sands production, but the impact cannot be determined at this time. The company’s marketing in British Columbia will not be significantly impacted in the early years of the LCFS regulations.

The U.S. Energy Independence and Security Act of 2007 precludes agencies of the U.S. Federal Government from procuring motive fuels from non-conventional petroleum sources that have lifecycle greenhouse gas emissions greater than equivalent conventional fuel. To date, sales of the company’s oil sands production have not been affected by this Act.

Further federal or provincial legislation or regulation controlling greenhouse gas emissions could occur and result in increased capital expenditures and operating costs, affect demand and have a material adverse effect on the company’s financial condition or results of operations, but any potential impact cannot be estimated at this time.

Other regulatory risk

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

Need to replace reserves

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

Other business risks

Exploring for, producing and transporting petroleum substances involve many risks, which even a combination of experience, knowledge and careful evaluation may not be able to mitigate. These activities are subject to a number of hazards, which may result in fires, explosions, spills, blow-outs or other unexpected or dangerous conditions causing personal injury, property damage, environmental damage and interruption of operations. The company’s insurance may not provide adequate coverage in certain unforeseen circumstances.

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

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Uncertainty of reserve estimates

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

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

Project factors

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

Not applicable.

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 Amex LLC, a subsidiary of NYSE Euronext.

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 nonresident withholding tax of 15 percent.

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

Imperial is a qualified foreign corporation for purposes of the reduced U.S. capital gains tax rates (15 percent and as low as zero percent for certain individuals), 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 nonresidents not carrying on business in Canada.

Reference is made to the “Quarterly financial and stock trading data” portion of the Financial section on page 81 of this report.

As of February 15, 2012 there were 12,711 holders of record of common shares of the company.

During the period October 1, 2011 to December 31, 2011, the company issued 233,148 common shares to employees or former employees outside the U.S. for $15.50 per share upon the exercise of stock options. During the period October 1, 2011 to December 31, 2011, the company issued 3,903 shares to employees or former employees outside the U.S. under its restricted stock unit plan. These issuances were not registered under the Securities Act in reliance on Regulation S thereunder.

In June, 2011 the company received approval from the Toronto Stock Exchange for a new normal course issuer bid to replace its existing share-purchase program that expired on June 24, 2011. The new share-purchase program enables the company to repurchase up to about 42 million shares during the period from June 25, 2011 to June 24, 2012, including shares purchased for the company’s employee savings plan, the company’s employee retirement plan and from ExxonMobil. If not previously terminated, the program will end on June 24, 2012.

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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 82. 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 35 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 47 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 31 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, 2011. Based on that evaluation, these officers have concluded that the company’s disclosure controls and procedures are effective in ensuring that information required to be disclosed by the company in the reports that it files or submits under the Securities Exchange Act of 1934, as amended, is accumulated and communicated to them in a manner that allows for timely decisions regarding required disclosures and are effective in ensuring that such information is recorded, processed, summarized and reported within the time periods specified in the SEC’s rules and forms.

Reference is made to page 51 of this report for “Management’s report on internal control over financial reporting” and page 52 for the “Report of independent registered public accounting firm” on the company’s internal control over financial reporting as of December 31, 2011.

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 82. 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 83 to 89 of this report has been nominated for election at the annual meeting of shareholders to be held May 2, 2012. 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 82. 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 82. 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 130 of this report.

Reference is made to the section under “V. Other important information” entitled “Largest shareholder”, on page 133 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 15, 2012, P.J. Masschelin was the owner of 4,554 common shares of the company and held 43,100 restricted stock units of the company. T.G. Scott did not own any common shares of the company and held 42,050 restricted stock units of the company. R.G. Courtemanche was the owner of 65,684 common shares of the company and held 114,250 restricted stock units of the company. B.W. Livingston was the owner of 36,222 common shares of the company and held 117,250 restricted stock units of the company.

The directors and the executive officers of the company, whose compensation for the year-ended December 31, 2011 is described in the sections under “III. Board of directors” starting on pages 83 and “IV. Company executives and executive compensation” starting on pages 109, consist of 14 persons, who, as a group, own beneficially 212,642 common shares of the company, being approximately 0.02 percent of the total number of outstanding shares of the company, and 523,398 shares of Exxon Mobil Corporation (including 307,645 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 options to acquire 6,000 common shares of the company and held restricted stock units to acquire 449,300 common shares of the company, as of February 15, 2012.

Sections of the company’s management proxy circular are contained in the Proxy information section, starting on page 82. 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 133 of this report.

Reference is made to the section under “III. Board of directors” entitled “Independence of the directors”, on page 92 of this report.

R.C. Olsen 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 Production Company, R.C. Olsen 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 82. 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 134 of this report.

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PART IV

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

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