UNITED STATES SECURITIES AND EXCHANGE COMMISSION
WASHINGTON, D.C. 20549
FORM 10-K
ANNUAL REPORT PURSUANT TO SECTION 13 OR 15 (d) OF THE
SECURITIES EXCHANGE ACT OF 1934
For the fiscal year-ended December 31, 2011
Commission file number: 0-12014
IMPERIAL OIL LIMITED
(Exact name of registrant as specified in its charter)
CANADA
(State or other jurisdiction of
incorporation or organization)
98-0017682
(I.R.S. Employer
Identification No.)
237 FOURTH AVENUE S.W., CALGARY, AB, CANADA
(Address of principal executive offices)
T2P 3M9
(Postal Code)
Registrant’s telephone number, including area code:
1-800-567-3776
Securities registered pursuant to Section 12(b) of the Act:
Title of each class
None
Name of each exchange on
which registered
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).
Yesü 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).
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.
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 filerü 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.
PART I
Item 1.
Business
Upstream
Disclosure of Reserves
Proved undeveloped reserves
Oil and gas production, production prices and production costs
Drilling and other exploratory and development activities
Present activities
Delivery commitments
Oil and gas properties, wells, operations, and acreage
Downstream
Supply
Refining
Distribution
Marketing
Chemical
Research
Environmental protection
Human resources
Competition
Government regulation
The company online
Item 1A.
Risk factors
Item 1B.
Unresolved staff comments
Item 2.
Properties
Item 3.
Legal proceedings
Item 4.
Mine safety disclosures
PART II
Item 5.
Market for registrant’s common equity, related stockholder matters and issuer purchases of equity securities
Item 6.
Selected financial data
Item 7.
Management’s discussion and analysis of financial condition and results of operations
Item 7A.
Quantitative and qualitative disclosures about market risk
Item 8.
Financial statements and supplementary data
Item 9.
Changes in and disagreements with accountants on accounting and financial disclosure
Item 9A.
Controls and procedures
Item 9B.
Other information
PART III
Item 10.
Directors, executive officers and corporate governance
Item 11.
Executive compensation
Item 12.
Security ownership of certain beneficial owners and management and related stockholder matters
Item 13.
Certain relationships and related transactions, and director independence
Item 14.
Principal accountant fees and services
PART IV
Item 15.
Exhibits, financial statement schedules
Financial section
Proxy information section
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.
Rate at end of period
Average rate during period
High
Low
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.
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”.
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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Total oil-
equivalentbasis
Net proved reserves:
Developed
Undeveloped
Total net proved
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.
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.
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.
Liquids:
Bitumen (c):
Synthetic oil (d):
Total:
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.
Gross production (a) (b)
Net production (c)
Sales (d)
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.
Total production oil-equivalent basis:
- gross (a)
- net (b)
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:
Liquids
Synthetic oil
Bitumen
Natural gas
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Average unit production costs
Total oil-equivalent basis (a)
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.
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.
Net productive exploratory:
Oil and gas
Net dry exploratory:
Net productive development:
Net dry development:
Total
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.
The company is continuing to evaluate other undeveloped, mineable oil sands acreage in the Athabasca region.
Review of principal ongoing activities
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.
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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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.
Oil and gas (c)
Bitumen (c)
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:
Western provinces:
Liquids and gas
Canada lands (c):
Atlantic offshore:
Total (d):
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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.
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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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).
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:
Strathcona, Alberta
Sarnia, Ontario
Nanticoke, Ontario
Dartmouth, Nova Scotia
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.
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.
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:
Gasolines
Heating, diesel and jet fuels
Heavy fuel oils
Lube oils and other products
Net petroleum product sales
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:
Domestic petroleum product sales as a percentage of total petroleum product sales volumes
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.
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:
Total sales of petrochemicals
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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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.
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.
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.
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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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.
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.
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’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.
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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:
Declared dividend per share:
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”:
entitled “Performance graph” within the “Compensation discussion and analysis section” on page 124 of this report; and
entitled “Equity compensation plan information”, within the “Compensation discussion and analysis section”, on page 130 of this report.
Issuer purchases of equity securities
Maximumnumber
(or approximatedollar value) ofshares that mayyet be purchasedunder the plansor programs
Operating revenues
Net income
Total assets at year-end
Long term debt at year-end
Total debt at year-end
Other long term obligations at year-end
Net income/share – basic
Net income/share – diluted
Dividends/share
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:
Consolidated financial statements, together with the report thereon of PricewaterhouseCoopers LLP (PwC) dated February 23, 2012, beginning with the section entitled “Report of independent registered public accounting firm” on page 52 and continuing through note 16, “Transactions with related parties” on page 76;
“Supplemental information on oil and gas exploration and production activities” (unaudited) starting on page 77; and
“Quarterly financial and stock trading data” (unaudited) on page 81.
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.
23
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”:
“Director information”, on pages 83 to 89 of this report;
The table entitled “Audit committee” under “Board and committee structure”, on page 95 of this report; and
“Other public company directorships”, on page 103 of this report.
Reference is made to the sections under “IV. Company executives and executive compensation”:
“Named executive officers of the company” and “Other executive officers of the company”, on page 109 and page 110 of this report.
Reference is made to the sections under “V. Other important information”:
“Largest shareholder”, on page 133 of this report; and
“Ethical business conduct”, starting on page 134 of this report.
“Share ownership guidelines for directors”, on page 102 of this report; and
“Directors’ compensation program”, on pages 104 to 108 of this report.
Reference is made to the following sections under “IV. Company executives and executive compensation”:
“Report of executive resources committee on executive compensation”, starting on page 110 of this report; and
“Compensation discussion and analysis”, on pages 111 to 132 of this report.
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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.
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.
Reference is made to the section under “V. Other important information” entitled “Auditor information”, on page 134 of this report.
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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:
By-laws of the company (Incorporated herein by reference to Exhibit (3)(ii) to the company’s Quarterly Report on Form 10-Q for the quarter ended March 31, 2003 (File No. 0-12014)).
The company’s long-term debt authorized under any instrument does not exceed 10 percent of the company’s consolidated assets. The company agrees to furnish to the Commission upon request a copy of any such instrument.
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Project Approval Order No. OSR045 made under the Alberta Mines and Minerals Act and Oil Sands Royalty Regulation, 1997 in respect of the Syncrude Project (Incorporated herein by reference to Exhibit 1.01(10)(ii)(3) of the company’s Form 8-K filed on November 19, 2008 (File No. 0-12014)).
27
28
Amended Restricted Stock Unit Plan with respect to Restricted Stock Units granted in 2011 and subsequent years, as amended effective November 14, 2011 (Incorporated herein by reference to Exhibit 9.01(c)[10(iii)(A)(1)] of the company’s Form 8-K filed on February 23, 2012 (File No. 0-12014)).
Imperial Oil Resources Limited, McColl-Frontenac Petroleum Inc., Imperial Oil Resources N.W.T. Limited and Imperial Oil Resources Ventures Limited, all incorporated in Canada, are wholly-owned subsidiaries of the company. The names of all other subsidiaries of the company are omitted because, considered in the aggregate as a single subsidiary, they would not constitute a significant subsidiary as of December 31, 2011.
Consent of Independent Registered Public Accounting Firm (PricewaterhouseCoopers LLP).
Certification by principal executive officer of Periodic Financial Report pursuant to Rule 13a-14(a).
Certification by principal financial officer of Periodic Financial Report pursuant to Rule 13a-14(a).
Certification by chief executive officer of Periodic Financial Report pursuant to Rule 13a-14(b) and 18 U.S.C. Section 1350.
Copies of Exhibits may be acquired upon written request of any shareholder to the investor relations manager, Imperial Oil Limited, 237 Fourth Avenue S.W., Calgary, Alberta, Canada T2P 3M9, and payment of processing and mailing costs.
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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 23, 2012 by the undersigned, thereunto duly authorized.
Imperial Oil Limited
By /s/ Bruce H. March
(Bruce H. March, Chairman of the Board,
President and Chief Executive Officer)
Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below on February 23, 2012 by the following persons on behalf of the registrant and in the capacities indicated.
/s/ Bruce H. March
Chairman of the Board, President and
Chief Executive Officer and Director
(Principal Executive Officer)
/s/ Paul J. Masschelin
Senior Vice-President,
Finance and Administration, and Treasurer
(Principal Financial Officer and Principal
Accounting Officer)
/s/ Krystyna T. Hoeg
/s/ Jack M. Mintz
/s/ Robert C. Olsen
/s/ David S. Sutherland
/s/ Sheelagh D. Whittaker
/s/ Victor L. Young
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Financial summary (U.S. GAAP)
Frequently used terms
Overview
Business environment and risk assessment
Results of operations
Liquidity and capital resources
Capital and exploration expenditures
Market risks and other uncertainties
Critical accounting estimates
Management’s report on internal control over financial reporting
Report of independent registered public accounting firm
Consolidated statement of income (U.S. GAAP)
Consolidated balance sheet (U.S. GAAP)
Consolidated statement of shareholders’ equity (U.S. GAAP)
Consolidated statement of cash flows (U.S. GAAP)
Notes to consolidated financial statements
1. Summary of significant accounting policies
2. Business segments
3. Income taxes
4. Employee retirement benefits
5. Other long-term obligations
6. Derivatives and financial instruments
7. Share-based incentive compensation programs
8. Investment and other income
9. Litigation and other contingencies
10. Common shares
11. Miscellaneous financial information
12. Financing costs
13. Leased facilities
14. Long-term debt
15. Accounting for suspended exploratory well costs
16. Transactions with related parties
Supplemental information on oil and gas exploration and production activities
Quarterly financial and stock trading data
31
Net income by segment:
Corporate and other
Cash and cash equivalents at year end
Total assets at year end
Long-term debt at year end
Total debt at year end
Other long-term obligations at year end
Shareholders’ equity at year-end
Cash flow from operating activities
Per-share information (dollars)
Net income per share - basic
Net income per share - diluted
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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.
Business uses: asset and liability perspective
Total assets
Less: total current liabilities excluding notes and loans payable
total long-term liabilities excluding long-term debt
Add: Imperial’s share of equity company debt
Total capital employed
Total company sources: debt and equity perspective
Notes and loans payable
Long-term debt
Shareholders’ equity
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.
Financing costs (after tax), including Imperial’s share of equity companies
Net income excluding financing costs
Average capital employed
Return on average capital employed (percent) – corporate total
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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.
Cash from operating activities
Proceeds from asset sales
Total cash flow from operating activities and asset sales
Operating costs
Operating costs are the combined total production, manufacturing, selling, general, exploration, depreciation and depletion from the Consolidated Statement of Income and Imperial’s share of similar costs for equity companies. Operating costs are the costs during the period to produce, manufacture, and otherwise prepare the company’s products for sale – including energy costs, staffing, maintenance, and other costs to explore for and produce oil and gas, and operate refining and chemical plants. Distribution and marketing expenses are also included. Operating costs exclude the cost of raw materials, taxes, and financing costs. These expenses 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. Information regarding these costs is, therefore, useful in evaluating the company’s performance.
Reconciliation of Operating Costs
From Imperial’s Consolidated Statement of Income
Total expenses
Less:
Purchases of crude oil and products
Federal excise tax
Financing costs
Subtotal
Imperial’s share of equity company expenses
Total operating costs
Components of Operating Costs
Production and manufacturing
Selling and general
Depreciation and depletion
Exploration
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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.
Long-term business outlook
By 2040, the world’s population is projected to grow to approximately 8.7 billion people, or about 1.9 billion more than in 2010. Coincident with this population increase, the company expects worldwide economic growth to average close to 3 percent per year. Expanding prosperity across a growing global population is expected to coincide with an increase in primary energy demand of about 30 percent by 2040 versus 2010, even with substantial efficiency gains around the world. This demand increase is expected to be concentrated in emerging and developing countries (i.e., those that are not member nations of the Organization for Economic Cooperation and Development).
As economic progress drives demand higher, increasing penetration of energy-efficient and lower-emission fuels, technologies and practices are expected to contribute to significantly lower levels of energy consumption and emissions per unit of economic output over time. Efficiency gains will result from anticipated improvements in the transportation and power generation sectors, driven by the introduction of new technologies, as well as many other improvements that span the residential, commercial and industrial sectors.
Energy for transportation - including cars, trucks, ships, trains and airplanes - is expected to increase by about 40 percent from 2010 to 2040. The global growth in transportation demand is likely to account for approximately 75 percent of the growth in liquids demand over this period. Nearly all the world’s transportation fleets are likely to continue to run on liquid fuels because they provide a large quantity of energy in small volumes, making them easy to transport and widely available.
Demand for electricity around the world is estimated to increase approximately 80 percent by 2040, led by growth in developing countries. Consistent with this projection, power generation will 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 gain the most market share. Coal is likely to retain the leading share of power generation fuels in 2040, albeit at a much lower share than in 2010 as policies are gradually adopted to reduce environmental impacts including those related to local air quality and greenhouse gas emissions. Nuclear power and renewables, led by wind, are likely to grow significantly over the period.
Liquid fuels provide the largest share of energy supply today due to their broad-based availability, affordability and ease of transport to meet consumer needs. By 2040, global demand for liquids is expected to grow to
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Management’s discussion and analysis of financial condition and results of operations (continued)
approximately 112 million barrels of oil-equivalent a day, an increase of more than 25 percent from 2010. Global demand for liquid fuels will be met by a wide variety of sources. Conventional crude and condensate production is expected to remain relatively flat through 2040. However, growth is expected from a wide variety of sources, including deep-water resources, oil sands, tight oil, 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 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 60 percent by 2040 compared to 2010, with demand increases in major regions around the world requiring new sources of supply. We expect that a significant growth in supplies of unconventional gas - the natural gas found in shale and other rock formations that was once considered uneconomic to produce will help meet these needs. By 2040, unconventional gas is likely to account for about 30 percent of global gas supplies, up from 10 percent in 2010. Growing natural gas demand is likely to also stimulate significant growth in the worldwide liquefied natural gas (LNG) market, which is expected to reach 15% of global gas demand by 2040.
The world’s energy mix is highly diverse and will remain so through 2040. Oil is expected to remain the largest source of energy with its share remaining close to one-third in 2040. Coal is currently the second largest source of energy, but it is likely to lose that position to natural gas by approximately 2025. The share of natural gas is expected to exceed 25% by 2040, while the share of coal falls to less than 20 percent. Nuclear power is projected to grow significantly, albeit at a slower pace than otherwise expected in the aftermath of the Fukushima incident in Japan following the earthquake and tsunami in March 2011. Total renewable energy is likely to reach close to 15 percent of total energy by 2040, including biomass, hydro and geothermal at a combined share of about 11 percent. Total energy supplied from wind, solar and biofuels is expected to increase close to 500 percent from 2010 to 2040, reaching a combined share of approximately 4 percent of world energy.
The company anticipates that the world’s available oil and gas resource base will grow not only from new discoveries, but also from reserve increases in previously discovered fields. Technology will underpin these increases. The cost to develop and supply these resources will be significant. According to the International Energy Agency, the investment required to meet total oil and gas energy needs worldwide over the period 2011- 2035 will be close to $20 trillion (measured in 2010 dollars), or close to $780 billion per year on average.
International accords and underlying regional and national regulations for greenhouse gas reduction are evolving with uncertain timing and outcome, making it difficult to predict their business impact. Imperial’s estimates of potential costs related to possible public policies covering energy-related greenhouse gas emissions are consistent with those incorporated in ExxonMobil’s long-term Energy Outlook, which is used for assessing the business environment and Imperial’s investment evaluations.
The information provided in the Long-term Business Outlook includes internal estimates and forecasts based upon internal data and analyses as well as publicly available information from external sources including the International Energy Agency.
Imperial produces crude oil and natural gas for sale into the North American markets. Crude oil and natural gas prices are determined by global and North American markets and are subject to changing supply and demand conditions. These can be influenced by a wide range of factors, including economic conditions, international political developments and weather. Prices for most of the company’s crude oil sold are set on West Texas Intermediate (WTI) oil markets, a common benchmark for mid-continent North American markets. In 2011, the average price of WTI crude oil diverged from historical pattern due to WTI market weakness and was markedly lower than that of Brent crude oil, a common benchmark for Atlantic Basin oil markets.
Imperial’s Upstream business strategies guide the company’s exploration, development, production, research and gas marketing activities. These strategies include identifying and pursuing all attractive exploration opportunities, investing in projects that deliver superior returns and maximizing profitability of existing
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production and resource value through high-impact technologies. These strategies are underpinned by a relentless focus on operational excellence, commitment to innovative technologies, development of employees and investment in the communities in which the company operates.
Imperial’s proven development approach supported the company’s continued investment in several key growth projects during a weak and uncertain economic environment following the global financial crisis in 2008. In 2012, the company will be entering its third year of a decade-long growth strategy in which $35 to $40 billion will be invested resulting in an Upstream production of about 600,000 oil-equivalent barrels a day, which is approximately double the current volumes. Actual spending and production volumes could vary depending on the progress of individual projects.
Imperial has a large portfolio of oil and gas resources in Canada, both developed and undeveloped, which helps reduce the risks of dependence on potentially limited supply sources in the Upstream. With the relative maturity of conventional production in established producing areas, Imperial’s production is expected to come increasingly from unconventional and frontier sources, particularly oil sands, unconventional natural gas and from Canada’s North, where Imperial has large undeveloped resource opportunities.
The downstream business environment is expected to continue being very competitive in the mature North America market. Over the prior 20-year period, inflation adjusted refining margins have been flat, reflecting an excess of refining capacity and an increase in regulatory-related policies. Crude oil, the primary raw material in a refinery operation, and its many refined products are widely traded with published international prices. Prices for these commodities are determined by the marketplace and are affected by many factors, including global and regional supply/demand balances, inventory levels, refinery operations, import/export balances, transportation logistics, currency fluctuations, seasonality and weather. The average prices the company paid for most of its crude oil processed at three of the company’s four refineries are set on WTI markets. In 2011, the average price of WTI crude oil diverged from historical pattern due to WTI market weakness and was markedly lower than that of Brent crude oil. Canadian wholesale prices of refined products in particular are largely determined by wholesale prices in adjacent U.S. regions. These prices and factors are continually monitored and provide input to operating decisions about which raw materials to buy, facilities to operate and products to make. However, there are no reliable indicators of future market factors that accurately predict changes in margins from period to period.
The company will continue to focus on the business elements within its control. Imperial’s Downstream strategies are to provide customers with quality, valued products and services at the lowest total cost offer, have the lowest unit costs among industry competitors, ensure efficient and effective use of capital, maximize value from leading edge technologies and capitalize on the integration with the company’s other businesses.
Imperial owns and operates four refineries in Canada, with aggregate distillation capacity of 506,000 barrels a day and lubricant manufacturing capacity of about 2,900 barrels a day. Imperial’s fuels marketing business includes retail operations across Canada serving customers through more than 1,800 Esso-branded retail service stations, of which about 480 are company-owned or leased, as well as wholesale and industrial operations through a network of 22 primary distribution terminals, as well as a secondary distribution network.
The North American petrochemical industry continued to improve in 2011 from the weak levels experienced in the recent economic recession. In North America, unconventional natural gas continued to provide advantaged ethane feedstock for steam crackers and a favourable margin environment for integrated chemical producers. In 2011, the company signed a long-term supply agreement for ethane from the Marcellus shale formation to use as cost advantaged feedstock for the Sarnia chemical plant. The company’s strategy for its Chemical business is to reduce costs and maximize value by continuing to increase the integration of its chemical plants at Sarnia and Dartmouth with the refineries. The company also benefits from its integration within ExxonMobil’s North American chemical businesses, enabling Imperial to maintain a leadership position in its key market segments.
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Consolidated
2011
Net income in 2011 was $3,371 million or $3.95 a share on a diluted basis, versus $2,210 million or $2.59 a share in 2010. Increased earnings were primarily attributable to higher crude oil commodity prices, stronger industry refining margins and increased Cold Lake bitumen production. These factors were partially offset by the unfavourable impacts of higher royalty costs, the stronger Canadian dollar and lower conventional crude oil volumes due to third-party pipeline reliability issues. 2011 earnings also included higher gains of about $70 million on asset divestments.
In 2011, there was an unusually large spread between the prices of Brent crude oil and WTI crude oil, two common benchmarks for world oil markets. Increase in 2011 in the average Brent crude oil price more than doubled that of the average WTI price due to continued weakness in WTI crude oil markets. Increases in the company’s Upstream realizations in 2011 followed more closely the trend of WTI prices, while margins in the company’s Downstream segment benefited as the overall cost of crude oil processed at three of the company’s four refineries were more in line with WTI prices.
2010
Net income in 2010 was $2,210 million or $2.59 a share on a diluted basis, versus $1,579 million or $1.84 a share for the full year 2009. Earnings increased primarily due to the impacts of higher upstream commodity prices, improved refinery operations and lower refinery maintenance activities, increased Cold Lake bitumen production and Syncrude volumes, and higher Downstream sales volumes and margins. These factors were partially offset by the unfavourable effects of the stronger Canadian dollar and higher royalty costs due to higher commodity prices. Gains from sale of non-operating assets in 2010 were about $40 million higher than the previous year.
Net income for the year was $2,457 million, up $693 million from 2010. Earnings increased primarily due to the impacts of higher crude oil commodity prices of about $925 million and increased Cold Lake bitumen production of about $260 million. These factors were partially offset by the unfavourable effects of higher royalty costs due to higher crude oil commodity prices of about $245 million, the stronger Canadian dollar of about $150 million, and lower conventional crude oil volumes of about $150 million, of which about $80 million was a result of third-party pipeline reliability issues. Included in 2011 earnings were gains of $116 million on asset divestments, about $95 million higher than 2010.
Net income for the year was $1,764 million, up $440 million from 2009. Higher crude oil and natural gas commodity prices in 2010 increased revenues, contributing to higher earnings of about $880 million. Earnings were also positively impacted by higher Cold Lake bitumen production of about $90 million and higher Syncrude volumes, reflecting improved reliability, of about $70 million. These factors were partially offset by the impact of the stronger Canadian dollar of about $320 million and higher royalty costs due to higher commodity prices of about $255 million. Third-party pipeline reliability issues in the second half of 2010 negatively impacted the supply and transportation of western crude oil. The company estimates the negative impact on earnings of about $80 million mostly from lower realizations in the third quarter and October of 2010, the net effect of which has been reflected in the commodity price factor above.
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Average realizations
Conventional crude oil realizations (a barrel)
Natural gas liquids realizations (a barrel)
Natural gas realizations (a thousand cubic feet)
Synthetic oil realizations (a barrel)
Bitumen realizations (a barrel)
The average price of Brent crude oil in U.S. dollars, a common benchmark for Atlantic Basin oil markets, was $111.29 a barrel in 2011, up about 40 percent from the previous year. Increase in the average price of West Texas Intermediate (WTI) crude oil, a common benchmark for mid-continent North American oil markets, was limited to 19 percent, due to the continued weakness in WTI crude oil markets. Increases in the company’s average realizations on sales of Canadian conventional crude oil and synthetic crude oil were in line with that of WTI.
The company’s average bitumen realizations in Canadian dollars in 2011 increased ten percent to $63.95 per barrel as the price spread between light crude oil and Cold Lake bitumen widened.
Canadian natural gas prices in 2011 were lower than the previous year. The average of 30-day spot prices for natural gas in Alberta at $3.67 a thousand cubic feet were down from $4.39 in 2010. The company’s realizations for natural gas averaged $3.59 a thousand cubic feet, down from $4.04 in 2010.
The average price of Brent crude oil in U.S. dollars, a common benchmark for Atlantic Basin oil markets, was $79.50 a barrel in 2010, up about 29 percent from the previous year. The company’s average realizations on sales of Canadian conventional crude oil and synthetic oil from Syncrude production also increased.
The company’s average bitumen realizations were higher in 2010, but by less than the relative increase in light crude oil prices, reflecting a widened price spread between the lighter crude oils and Cold Lake bitumen, primarily attributable to third-party pipeline outages.
Canadian natural gas prices in 2010 were unchanged from the previous year. The average of 30-day spot prices for natural gas in Alberta at $4.39 a thousand cubic feet were the same as in 2009. The company’s realizations for natural gas averaged $4.04 a thousand cubic feet, down slightly from $4.11 in 2009.
Crude oil and NGLs - production and sales (a)
Conventional crude oil
Total crude oil production
NGLs available for sale
Total crude oil and NGL production
Cold Lake sales, including diluent (b)
NGL sales
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Natural gas - production and sales (a)
Production (c)
Sales
Gross production of Cold Lake bitumen increased to a record 160,000 barrels a day in 2011 from 144,000 barrels in 2010. Increased 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.
The company’s share of gross production from Syncrude averaged 72,000 barrels a day, in line with 73,000 barrels in 2010.
Gross production of conventional crude oil averaged 18,000 barrels a day, compared with 23,000 barrels in 2010. Lower volumes were primarily due to third-party pipeline unplanned downtime, which reduced production at the Norman Wells field, along with natural reservoir decline.
Gross production of natural gas in 2011 was 254 million cubic feet a day, down from 280 million cubic feet in 2010. The lower 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, the 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. Also in the year, the company recorded a gain of about $40 million from an exchange of oil sands leases with a third party.
Gross production of Cold Lake bitumen increased to 144,000 barrels a day in 2010 from 141,000 barrels in 2009. Higher volumes in 2010 were due to improved facility reliability as well as the cyclic nature of production at Cold Lake.
The company’s share of gross production from Syncrude averaged 73,000 barrels a day, up from 70,000 barrels in 2009. Increased production was due to improved operational reliability.
Gross production of conventional crude oil averaged 23,000 barrels a day, compared with 25,000 barrels in 2009. Planned maintenance activities at the Norman Wells field and natural reservoir decline were the main contributors to the lower production.
Gross production of natural gas in 2010 was 280 million cubic feet a day, down from 295 million cubic feet in 2009. The lower production volume was primarily a result of natural reservoir decline and maintenance activities.
Net income was $884 million, an increase of $442 million over 2010. Higher earnings were primarily due to the favourable impact of stronger industry refining margins of about $590 million. Refining margins benefited as the overall cost of crude oil processed at three of the company’s four refineries followed the trend of WTI prices.
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This factor was partially offset by the unfavourable impacts of higher maintenance activities on refinery operations and expenses totalling about $60 million and the stronger Canadian dollar of about $55 million. Earnings in 2010 included a gain of about $25 million from sale of non-operating assets.
Net income was $442 million, an increase of $164 million over 2009. Higher earnings were primarily due to favourable impacts of about $145 million associated with improved refinery operations and lower refinery maintenance activities, improved sales volumes of about $35 million and an additional contribution from sale of non-operating assets of about $35 million. Stronger overall margins also contributed about $30 million to the earnings increase, despite a negative impact from alternate sourcing of crude oil as a result of third-party pipeline outages. These factors were partially offset by the unfavourable effects of the stronger Canadian dollar of about $90 million.
Refinery utilization
Total refinery throughput (b)
Refinery capacity at December 31
Utilization of total refinery capacity (percent)
Total refinery throughput was 430,000 barrels a day, down from 2010, and average refinery capacity utilization decreased to 85 percent from the previous year’s 88 percent. Lower volumes and utilization were primarily a result of higher planned and unplanned maintenance activities. Total net petroleum sales increased to 447,000 barrels a day, 5,000 barrels higher than 2010.
Total refinery throughput was 444,000 barrels a day, up from 2009, and average refinery capacity utilization increased to 88 percent from the previous year’s 82 percent. Improved reliability and lower maintenance activities as well as improved market conditions helped to increase volumes and utilization. Total net petroleum sales also increased and were up to 442,000 barrels a day, compared to the low levels of 409,000 barrels in 2009.
Polymers and basic chemicals
Intermediate and others
Total petrochemical sales
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Net income was $122 million, up $53 million from 2010. Improved margins for intermediate and aromatic products, lower costs due to lower planned maintenance activities and higher polyethylene sales volumes were the main contributors to the increase. These factors were partially offset by lower margins for polyethylene products.
Net income was $69 million, up $23 million from 2009. Improved industry margins were partially offset by lower sales volumes for polyethylene products and higher costs due to planned maintenance activities.
Net income effects were negative $92 million, versus negative $65 million reported last year. Unfavourable effects in 2011 were primarily due the impact of the share price change on share-based compensation charges.
Net income effects were negative $65 million, in line with the negative $69 million reported last year.
Sources and uses of cash
Cash provided by/(used in)
Operating activities
Investing activities
Financing activities
Increase/(decrease) in cash and cash equivalents
Cash and cash equivalents at end of year
Although the company issues long-term debt from time to time and maintains a commercial paper program, internally generated funds largely cover the majority of its financial requirements. Cash that may be temporarily surplus to the company’s immediate needs is carefully managed through counterparty quality and investment guidelines to ensure that it is secure and readily available to meet the company’s cash requirements.
Cash flows from operating activities are highly dependent on crude oil and natural gas prices, as well as petroleum and chemical product margins. In addition, to provide for cash flow in future periods, the company needs to continually find and develop new resources, and continue to develop and apply new technologies to existing fields, in order to maintain or increase production. Projects are planned or underway to increase production capacity. However, these volume increases are subject to a variety of risks, including project execution, operational outages, reservoir performance and regulatory changes.
The company’s financial strength enables it to make large, long-term capital expenditures. Imperial’s portfolio of development opportunities and the complementary nature of its business segments help mitigate the overall risks for the company and its cash flows. Further, due to its financial strength, debt capacity and portfolio of opportunities, the risk associated with failure or delay of any single project would not have a significant impact on the company’s liquidity or ability to generate sufficient cash flows for its operations and fixed commitments.
An independent actuarial valuation of the company’s registered retirement benefit plans was completed as at December 31, 2010. As a result of the valuation, the company contributed $361 million to the registered retirement benefit plans in 2011. The next required independent actuarial valuation will be as at December 31,
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2011 and the company will continue to contribute within the requirements of pension regulations. Future funding requirements are not expected to affect the company’s existing capital investment plans or its ability to pursue new investment opportunities.
Cash flow generated from operating activities was $4,489 million, an increase of $1,282 million from 2010 and in line with the earnings increase versus 2010.
Cash flow generated from operating activities was $3,207 million, an increase of $1,616 million from the full year 2009. Higher cash flow was primarily due to higher earnings and working capital effects, partially offset by higher 2010 funding contributions to the company’s registered pension plans.
Cash flow from investing activities
Investing activities used net cash of $3,593 million in 2011, compared to $3,709 million in 2010. Additions to property, plant and equipment were $3,919 million, compared with $3,856 million last year. Proceeds from asset sales were $314 million compared with $144 million in 2010.
Investing activities used net cash of $3,709 million in 2010, compared to $2,216 million in 2009. Additions to property, plant and equipment were $3,856 million, compared with $2,285 million last year. Proceeds from asset sales were $144 million compared with $67 million in 2009.
Cash flow from financing activities
Cash from financing activities was $39 million, compared with $256 million in 2010.
The company raised new debt of $455 million by drawing on existing facilities. At the end of 2011, total debt outstanding was $1,207 million, compared with $756 million at the end of 2010.
During 2011, the company did not make any share repurchases except those to offset the dilutive effects from the exercise of share-based awards. The company will continue to evaluate its share repurchase program in the context of its operating performance and overall capital project activities.
Cash dividends of $373 million were paid in 2011 compared with $356 million in 2010. Per-share dividends paid in 2011 totaled $0.44, up from $0.42 in 2010.
In the second quarter, the company extended the maturity date of its existing stand-by $200 million long term bank credit facility to July 2013. The company has not drawn on this facility.
Cash from financing activities was $256 million, compared with cash used in financing activities of $836 million in 2009.
The company raised new debt of $620 million by drawing on existing facilities. At the end of 2010, total debt outstanding was $756 million, compared with $140 million at the end of 2009.
During 2010, the company did not make any share repurchases except those to offset the dilutive effects from the exercise of share-based awards. The company will continue to evaluate its share repurchase program in the context of its overall capital project activities.
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Cash dividends of $356 million were paid in 2010 compared with dividends of $341 million in 2009. Per-share dividends paid in 2010 totaled $0.42, up from $0.40 in 2009.
In the third quarter, to support the commercial paper program, the company entered into an unsecured committed bank credit facility in the amount of $200 million that matures in July 2012. The company has not drawn on this facility.
Financial percentages and ratios
Total debt as a percentage of capital (a)
Interest coverage ratio – earnings basis (b)
Debt represented nine percent of the company’s capital structure at the end of 2011, two percent higher than 2010.
Debt-related interest incurred in 2011, before capitalization of interest, was $16 million, compared with $6 million in 2010. The average effective interest rate on the company’s debt was 1.5 percent in 2011, compared with 1.3 percent in 2010.
The company’s financial strength, as evidenced by the above financial ratios, represents a competitive advantage of strategic importance. The company’s sound financial position gives it the opportunity to access capital markets in the full range of market conditions and enables the company to take on large, long-term capital commitments in the pursuit of maximizing shareholder value.
The company does not use any derivative instruments to offset exposures associated with hydrocarbon prices, currency exchange rates and interest rates that arise from existing assets, liabilities and transactions. The company does not engage in speculative derivative activities nor does it use derivatives with leveraged features.
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Commitments
The following table shows the company’s commitments outstanding at December 31, 2011. It combines data from the consolidated balance sheet and from individual notes to the consolidated financial statements.
Financial
statementnote reference
2013
to 2016
Long-term debt (a)
- Due in one year
Operating leases (b)
Unconditional purchase obligations (c)
Firm capital commitments (d)
Pension and other post-retirement obligations (e)
Asset retirement obligations (f)
Other long-term purchase agreements (g)
Unrecognized tax benefits totalling $134 million have not been included in the company’s commitments table because the company does not expect there will be any cash impact from the final settlements as sufficient funds have been deposited with the Canada Revenue Agency. Further details on the unrecognized tax benefits can be found in note 3 to the financial statements on page 62.
Litigation and other contingencies
As discussed in note 9 to the consolidated financial statements on page 71, a variety of claims have been made against Imperial Oil Limited and its subsidiaries. Based on a consideration of all relevant facts and circumstances, the company does not believe the ultimate outcome of any currently pending lawsuits against the company will have a material adverse effect on the company’s operations, financial condition, or financial statements taken as a whole. There are no events or uncertainties beyond those already included in reported financial information that would indicate a material change in future operating results or financial condition.
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Upstream (a)
Other
Total capital and exploration expenditures were $4,066 million in 2011, an increase of $21 million from 2010.
The funds were used mainly to advance the Kearl oil sands project, advance other Upstream growth projects and invest in environmental performance initiatives.
For the Upstream segment, capital expenditures were $3,880 million, compared with $3,844 million in 2010. Expenditures were primarily directed towards the advancement of the initial development and expansion at Kearl. Other investments included advancing the Nabiye expansion project at Cold Lake, environmental and efficiency projects at Syncrude, as well as the advancement of the production pilot at Horn River and acreage acquisitions.
In 2011, Kearl 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, Kearl initial development was 87 percent complete with expected start up in late 2012.
In 2011, Kearl 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.
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 by year-end 2014.
Planned capital and exploration expenditures in the Upstream segment are forecast at about $5 billion for 2012. Investments are mainly planned for Kearl initial development and expansion. Other investments include advancing the Nabiye expansion project at Cold Lake, environmental and efficiency projects at Syncrude, as well as exploration drilling and the advancement of the production pilot at Horn River.
For the Downstream segment, capital expenditures were $166 million in 2011, compared with $184 million in 2010. In 2011, Downstream capital expenditures focused mainly on refinery projects to improve reliability, feedstock flexibility, energy efficiency and environmental performance.
Planned capital expenditures for the Downstream segment in 2012 are about $200 million focused on improving refinery reliability and environmental and safety performance, as well as continuing upgrades to the retail network.
In 2012, the company will be entering the third year of a decade-long growth strategy in which between $35 billion and $40 billion will be invested. Total capital and exploration expenditures for the company in 2012 are expected to be about $5 billion. Actual spending could vary depending on the progress of individual projects.
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Crude oil, natural gas, petroleum product and chemical prices have fluctuated in response to changing market forces. The impacts of these price fluctuations on earnings from Upstream, Downstream and Chemical operations have varied. In addition, industry crude oil and natural gas commodity prices and petroleum and chemical product prices are commonly benchmarked in U.S. dollars. The majority of Imperial’s sales and purchases are related to these industry U.S. dollar benchmarks. As the company records and reports its financial results in Canadian dollars, to the extent that the Canadian/U.S. dollar exchange rate fluctuates, the company’s earnings will be affected. The company’s potential exposure to commodity price and margin and Canadian/U.S. dollar exchange rate fluctuations is summarized in the earnings sensitivities table below, which shows the estimated annual effect, under current conditions, of the company’s after-tax net income.
Earnings sensitivities (a)
Ten dollars (U.S.) a barrel change in crude oil prices
Thirty cents a thousand cubic feet change in natural gas prices
One dollar (U.S.) a barrel change in sales margins for total petroleum products
One cent (U.S.) a pound change in sales margins for polyethylene
One-quarter percent decrease (increase) in short-term interest rates
Ten cents decrease (increase) in the value of the Canadian dollar versus the U.S. dollar
The sensitivity of net income to changes in crude oil prices decreased from year-end 2010 by about $4 million (after tax) a year for each one U.S. dollar change. The decrease was primarily a result of the combined impacts of higher royalty costs for bitumen production due to higher crude oil commodity prices and lower conventional crude oil production.
The global energy markets can give rise to extended periods in which market conditions are adverse to one or more of the company’s businesses. Such conditions, along with the capital-intensive nature of the industry and very long lead times associated with many of our projects, underscore the importance of maintaining a strong financial position. Management views the company’s financial strength as a competitive advantage.
In general, segment results are not dependent on the ability to sell and/or purchase products to/from other segments. Instead, where such sales take place, they are the result of efficiencies and competitive advantages of integrated refinery/chemical complexes. Additionally, intersegment sales are at market-based prices. The products bought and sold between segments can also be acquired in worldwide markets that have substantial liquidity, capacity and transportation capabilities. About 60 percent of the company’s intersegment sales are crude oil produced by the Upstream and sold to the Downstream. Other intersegment sales include those between refineries and chemical plants related to raw materials, feedstocks and finished products.
Although price levels of crude oil and natural gas may rise or fall significantly over the short to medium term, industry economics over the long term will continue to be driven by market supply and demand. Accordingly, the company tests the viability of all of its investments over a broad range of future prices. The company’s assessment is that its operations will continue to be successful in a variety of market conditions. This is the outcome of disciplined investment and asset management programs.
The company has an active asset management program in which underperforming assets are either improved to acceptable levels or considered for divestment. The asset management program includes a disciplined, regular review to ensure that all assets are contributing to the company’s strategic objectives. The result is an efficient capital base, and the company has seldom had to write down the carrying value of assets, even during periods of low commodity prices.
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Risk management
The company’s size, strong capital structure and the complementary nature of the Upstream, Downstream and Chemical businesses reduce the company’s enterprise-wide risk from changes in commodity prices and currency rates. The company’s financial strength and debt capacity give it the opportunity to advance business plans in the pursuit of maximizing shareholder value in the full range of market conditions. Also, the company progresses large capital projects in a phased manner so that adjustments can be made when significant changes in market conditions occur. As a result, the company does not make use of derivative instruments to mitigate the impact of such changes. The company does not engage in speculative derivative activities or derivative trading activities nor does it use derivatives with leveraged features. The company maintains a system of controls that includes a policy covering the authorization, reporting and monitoring of derivative activity.
The company’s financial statements have been prepared in accordance with United States generally accepted accounting principles (GAAP). GAAP requires management to make estimates and judgments that affect the reported amounts of assets, liabilities, revenues and expenses and the disclosure of contingent assets and liabilities. The company’s accounting and financial reporting fairly reflect its straightforward business model. Imperial does not use financing structures for the purpose of altering accounting outcomes or removing debt from the balance sheet. The company’s significant accounting policies are summarized in note 1 to the consolidated financial statements on page 57.
Oil and gas reserves
Evaluations of oil and gas reserves are important to the effective management of Upstream assets. They are integral to making investment decisions about oil and gas properties such as whether development should proceed. Oil and gas reserve quantities are also used as the basis for calculating unit-of-production depreciation rates and for evaluating impairment.
Oil and gas reserves include both proved and unproved reserves. Proved oil and gas reserves are those quantities of oil and gas, which, by analysis of geoscience and engineering data, can be estimated with reasonable certainty to be economically producible. Unproved reserves are those with less than reasonable certainty of recoverability and include probable reserves. Probable reserves are reserves that are more likely to be recovered than not.
The estimation of proved reserves is an ongoing process based on rigorous technical evaluations, commercial and market assessment, and detailed analysis of well information such as flow rates and reservoir pressure declines. The estimation of proved reserves is controlled by the company through long-standing approval guidelines. Reserve changes are made within a well-established, disciplined process driven by senior level geoscience and engineering professionals, assisted by the reserves management group which has significant technical experience, culminating in reviews with and approval by senior management and the company’s board of directors. Notably, the company does not use specific quantitative reserve targets to determine compensation. Key features of the reserve estimation process are covered in Disclosure of Reserves in Item 1.
Although the company is reasonably certain that proved reserves will be produced, the timing and amount recovered can be affected by a number of factors, including completion of development projects, reservoir performance, regulatory approvals and significant changes in long-term oil and gas price levels.
Revisions can include upward or downward changes in previously estimated volumes of proved reserves for existing fields due to the evaluation or revaluation of already available geologic, reservoir or production data; new geologic, reservoir or production data; or changes in prices and costs that are used in the estimation of reserves. Revisions can also result from significant changes in either development strategy or production equipment/facility capacity.
The company uses the successful-efforts method to account for its exploration and production activities. Under this method, costs are accumulated on a field-by-field basis with certain exploratory expenditures and exploratory dry holes being expensed as incurred. Costs of productive wells and development dry holes are capitalized and amortized using the unit-of-production method.
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Impact of oil and gas reserves on depreciation
The calculation of unit-of-production depreciation is a critical accounting estimate that measures the depreciation of upstream assets. It is the ratio of actual volumes produced to total proved developed reserves (those reserves recoverable through existing wells with existing equipment and operating methods) applied to the asset cost. The volumes produced and asset cost are known and, while proved developed reserves have a high probability of recoverability, they are based on estimates that are subject to some variability. While the revisions the company has made in the past are an indicator of variability, they have had little impact on the unit-of-production rates of depreciation.
Impact of oil and gas reserves and prices on testing for impairment
Proved oil and gas properties held and used by the company are reviewed for impairment whenever events or circumstances indicate that the carrying amounts may not be recoverable. Assets are grouped at the lowest level for which there are identifiable cash flows that are largely independent of the cash flows of other groups of assets.
The company estimates the future undiscounted cash flows of the affected properties to judge the recoverability of carrying amounts. In general, impairment analyses are based on reserve estimates used for internal planning and capital investment decisions. Where probable reserves exist, an appropriately risk-adjusted amount of these reserves may be included in the impairment evaluation. An asset would be impaired if the undiscounted cash flows were less than the asset’s carrying value. Impairments are measured by the amount by which the asset’s carrying value exceeds its fair value.
Significant unproved properties are assessed for impairment individually and valuation allowances against the capitalized costs are recorded based on the estimated economic chance of success and the length of time that the company expects to hold the properties. Properties that are not individually significant are aggregated by groups and amortized based on development risk and average holding period.
The company performs asset valuation analyses on an ongoing basis as a part of its asset management program. These analyses assist the company in assessing whether the carrying amounts of any of its assets may not be recoverable. In addition to estimating oil and gas reserve volumes in conducting these analyses, it is also necessary to estimate future oil and gas prices. Trigger events for impairment evaluations include a significant decrease in current and projected prices or reserve volumes, an accumulation of project costs significantly in excess of the amount originally expected and historical and forecast operating losses.
In general, the company does not view temporarily low oil prices as a triggering event for conducting impairment tests. The markets for crude oil and natural gas have a history of significant price volatility. Although prices will occasionally drop significantly, the relative growth/decline in supply versus demand will determine industry prices over the long term, and these cannot be accurately predicted. Accordingly, any impairment tests that the company performs make use of the company’s price assumptions developed in the annual planning and budgeting process for crude oil and natural gas markets, petroleum products and chemicals. These are the same price assumptions that are used for capital investment decisions. Volumes are based on field production profiles, which are also updated annually.
Supplemental information regarding oil and gas results of operations, capitalized costs and reserves is provided following the notes to the consolidated financial statements. Future prices used for any impairment tests will vary from the one used in the supplemental oil and gas disclosure and could be lower or higher for any given year.
Pension benefits
The company’s pension plan is managed in compliance with the requirements of governmental authorities and meets funding levels as determined by independent third-party actuaries. Pension accounting requires explicit assumptions regarding, among others, the discount rate for the benefit obligations, the expected rate of return on plan assets and the long-term rate of future compensation increases. All pension assumptions are reviewed annually by senior management. These assumptions are adjusted only as appropriate to reflect long-term changes in market rates and outlook. The long-term expected rate of return on plan assets of 7.00 percent used in 2011 compares to actual returns of 6.0 percent and 8.3 percent achieved over the last 10- and 20-year periods ending December 31, 2011. If different assumptions are used, the expense and obligations could
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increase or decrease as a result. The company’s potential exposure to changes in assumptions is summarized in note 4 to the consolidated financial statements on page 63. At Imperial, differences between actual returns on plan assets and the long-term expected returns are not recorded in pension expense in the year the differences occur. Such differences are deferred, along with other actuarial gains and losses, and are amortized into pension expense over the expected average remaining service life of employees. Employee benefit expense represented less than two percent of total expenses in 2011.
Asset retirement obligations and other environmental liabilities
Legal obligations associated with site restoration on the retirement of assets with determinable useful lives are recognized when they are incurred, which is typically at the time the assets are installed. The obligations are initially measured at fair value and discounted to present value. Over time, the discounted asset retirement obligation amount will be accreted for the change in its present value, with this effect included in production and manufacturing expenses. As payments to settle the obligations occur on an ongoing basis and will continue over the lives of the operating assets, which can exceed 25 years, the discount rate will be adjusted only as appropriate to reflect long-term changes in market rates and outlook. For 2011, the obligations were discounted at six percent and the accretion expense was $46 million, before tax, which was significantly less than one percent of total expenses in the year. There would be no material impact on the company’s reported financial results if a different discount rate had been used.
Asset retirement obligations are not recognized for assets with an indeterminate useful life. Asset retirement obligations for these facilities generally become firm at the time the facilities are permanently shut down and dismantled. These obligations may include the costs of asset disposal and additional soil remediation. However, these sites have indeterminate lives based on plans for continued operations, and as such, the fair value of the conditional legal obligations cannot be measured, since it is impossible to estimate the future settlement dates of such obligations. For these and non-operating assets, the company accrues provisions for environmental liabilities when it is probable that obligations have been incurred and the amount can be reasonably estimated.
Asset retirement obligations and other environmental liabilities are based on engineering estimated costs, taking into account the anticipated method and extent of remediation consistent with legal requirements, current technology and the possible use of the location. Since these estimates are specific to the locations involved, there are many individual assumptions underlying the company’s total asset retirement obligations and provision for other environmental liabilities. While these individual assumptions can be subject to change, none of them is individually significant to the company’s reported financial results.
Suspended exploratory well costs
The company carries exploratory well costs as an asset when the well has found a sufficient quantity of reserves to justify its completion as a producing well and where the company is making sufficient progress assessing the reserves and the economic and operating viability of the project. Exploratory well costs not meeting these criteria are charged to expense. The facts and circumstances that support continued capitalization of suspended wells as of year-end 2011 are disclosed in note 15 to the consolidated financial statements.
Tax contingencies
The operations of the company are complex, and related tax interpretations, regulations and legislation are continually changing. Significant management judgment is required in the accounting for income tax contingencies and tax disputes because the outcomes are often difficult to predict.
The benefits of uncertain tax positions that the company has taken or expects to take in its income tax returns are recognized in the financial statements if management concludes that it is more likely than not that the position will be sustained with the tax authorities. For a position that is likely to be sustained, the benefit recognized in the financial statements is measured at the largest amount that is greater than 50 percent likely of being realized. A reserve is established for the difference between a position taken or expected to be taken in an income tax return and the amount recognized in the financial statements. The company’s unrecognized tax benefits and a description of open tax years are summarized in note 3 to the consolidated financial statements on page 62.
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Management, including the company’s chief executive officer and principal accounting officer and principal financial officer, is responsible for establishing and maintaining adequate internal control over the company’s financial reporting. Management conducted an evaluation of the effectiveness of internal control over financial reporting based on criteria established in Internal Control - Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission. Based on this evaluation, management concluded that Imperial Oil Limited’s internal control over financial reporting was effective as of December 31, 2011.
PricewaterhouseCoopers LLP, an independent registered public accounting firm, audited the effectiveness of the company’s internal control over financial reporting as of December 31, 2011, as stated in their report which is included herein.
B.H. March
Chairman, president and
chief executive officer
P.J. Masschelin
Senior vice-president,
finance and administration, and treasurer
(Principal accounting officer and principal financial officer)
February 23, 2012
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To the Shareholders of Imperial Oil Limited
We have audited the accompanying consolidated balance sheet of Imperial Oil Limited as of December 31, 2011 and December 31, 2010 and the related consolidated statements of income, shareholders’ equity and cash flows for each of the years in the three-year period ended December 31, 2011. We also have audited Imperial Oil Limited’s internal control over financial reporting as of December 31, 2011, based on criteria established in Internal Control - Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO). Management is responsible for these financial statements, for maintaining effective internal control over financial reporting, and for its assessment of the effectiveness of internal control over financial reporting, included in the accompanying management’s report on internal control over financial reporting. Our responsibility is to express an opinion on these consolidated financial statements and an opinion on the company’s internal control over financial reporting based on our audits.
We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audits to obtain reasonable assurance about whether the consolidated financial statements are free of material misstatement and whether effective internal control over financial reporting was maintained in all material respects. Our audits of the consolidated financial statements included examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, assessing the accounting principles used and significant estimates made by management, and evaluating the overall financial statement presentation. Our audit of internal control over financial reporting included obtaining an understanding of internal control over financial reporting, assessing the risk that a material weakness exists, and testing and evaluating the design and operating effectiveness of internal control based on the assessed risk. Our audits also included performing such other procedures as we considered necessary in the circumstances. We believe that our audits provide a reasonable basis for our opinions.
A company’s internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. A company’s internal control over financial reporting includes those policies and procedures that: (i) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (ii) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the company are being made only in accordance with authorizations of management and directors of the company; and (iii) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the company’s assets that could have a material effect on the financial statements. Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.
In our opinion, the consolidated financial statements referred to above present fairly, in all material respects, the financial position of Imperial Oil Limited as of December 31, 2011 and December 31, 2010 and the results of its operations and its cash flows for each of the years in the three-year period ended December 31, 2011 in conformity with accounting principles generally accepted in the United States of America. Also in our opinion, Imperial Oil Limited maintained, in all material respects, effective internal control over financial reporting as of December 31, 2011, based on criteria established in Internal Control - Integrated Framework issued by the COSO.
/s/ PricewaterhouseCoopers LLP
Chartered Accountants
Calgary, Alberta, Canada
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millions of Canadian dollars
For the years ended December 31
Revenues and other income
Operating revenues (a)(b)
Investment and other income (note 8)
Total revenues and other income
Expenses
Purchases of crude oil and products (c)
Production and manufacturing (d)
Federal excise tax (a)
Financing costs (note 12)
Income before income taxes
Income taxes (note 3)
Per-share information (Canadian dollars)
Net income per common share - basic (note 10)
Net income per common share - diluted (note 10)
The information in the Notes to Consolidated Financial Statements is an integral part of these statements.
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At December 31
Assets
Current Assets
Cash
Accounts receivable, less estimated doubtful amounts
Inventories of crude oil and products (note 11)
Materials, supplies and prepaid expenses
Deferred income tax assets (note 3)
Total current assets
Long-term receivables, investments and other long-term assets
Property, plant and equipment, less accumulated depreciation and depletion (note 2)
Goodwill (note 2)
Other intangible assets, net
Total assets (note 2)
Liabilities
Current liabilities
Accounts payable and accrued liabilities (a) (note 11)
Income taxes payable
Total current liabilities
Long-term debt (b)(note 14)
Other long-term obligations (note 5)
Deferred income tax liabilities (note 3)
Total liabilities
Commitments and contingent liabilities (note 9)
Common shares at stated value (c)(note 10)
Earnings reinvested
Accumulated other comprehensive income
Total shareholders’ equity
Total liabilities and shareholders’ equity
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Common shares at stated value (note 10)
At beginning of year
Issued under the stock option plan
Share purchases at stated value
At end of year
Net income for the year
Share purchases in excess of stated value
Post-retirement benefits liability adjustment (note 4)
Amortization of post-retirement benefits liability adjustment included in net periodic benefit cost
Shareholders’ equity at end of year
Comprehensive income for the year
Other comprehensive income
Post-retirement benefits liability adjustment
Total comprehensive income for the year
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Inflow/(outflow)
Adjustments for non-cash items:
(Gain)/loss on asset sales
Deferred income taxes and other
Changes in operating assets and liabilities:
Accounts receivable
Inventories and prepaids
Accounts payable
All other items - net (a)
Cash flows from (used in) operating activities
Additions to property, plant and equipment and intangibles
Repayment of loan from equity company
Cash flows from (used in) investing activities
Short-term debt - net
Long-term debt issued
Reduction in capitalized lease obligations
Issuance of common shares under stock option plan
Common shares purchased (note 10)
Dividends paid
Cash flows from (used in) financing activities
Increase (decrease) in cash
Cash at beginning of year
Cash at end of year (b)
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The accompanying consolidated financial statements and the supporting and supplemental material are the responsibility of the management of Imperial Oil Limited.
The company’s principal business is energy, involving the exploration, production, transportation and sale of crude oil and natural gas and the manufacture, transportation and sale of petroleum products. The company is also a major manufacturer and marketer of petrochemicals.
The consolidated financial statements have been prepared in accordance with generally accepted accounting principles in the United States of America (GAAP). GAAP requires management to make estimates and judgments that affect the reported amounts of assets, liabilities, revenues and expenses and the disclosure of contingent assets and liabilities. Certain reclassifications to prior years have been made to conform to the 2011 presentation. All amounts are in Canadian dollars unless otherwise indicated.
Principles of consolidation
The consolidated financial statements include the accounts of subsidiaries the company controls. Intercompany accounts and transactions are eliminated. Subsidiaries include those companies in which Imperial has both an equity interest and the continuing ability to unilaterally determine strategic, operating, investing and financing policies. Significant subsidiaries included in the consolidated financial statements include Imperial Oil Resources Limited, Imperial Oil Resources N.W.T. Limited, Imperial Oil Resources Ventures Limited and McColl-Frontenac Petroleum Inc. All of the above companies are wholly owned. A significant portion of the company’s Upstream activities is conducted jointly with other companies. The accounts reflect the company’s share of undivided interest in such activities, including its 25 percent interest in the Syncrude joint venture and its nine percent interest in the Sable offshore energy project as well as its 70.96 percent interest in the Kearl project, which is currently under development.
Inventories
Inventories are recorded at the lower of cost or current market value. The cost of crude oil and products is determined primarily using the last-in, first-out (LIFO) method. LIFO was selected over the alternative first-in, first-out and average cost methods because it provides a better matching of current costs with the revenues generated in the period.
Inventory costs include expenditures and other charges, including depreciation, directly or indirectly incurred in bringing the inventory to its existing condition and final storage prior to delivery to a customer. Selling and general expenses are reported as period costs and excluded from inventory costs.
Investments
The company’s interests in the underlying net assets of affiliates it does not control, but over which it exercises significant influence, are accounted for using the equity method. They are recorded at the original cost of the investment plus Imperial’s share of earnings since the investment was made, less dividends received. Imperial’s share of the after-tax earnings of these companies is included in “investment and other income” in the consolidated statement of income. Other investments are recorded at cost. Dividends from these other investments are included in “investment and other income.”
These investments represent interests in non-publicly traded pipeline companies that facilitate the sale and purchase of crude oil and natural gas in the conduct of company operations. Other parties who also have an equity interest in these companies share in the risks and rewards according to their percentage of ownership. Imperial does not invest in these companies in order to remove liabilities from its balance sheet.
Property, plant and equipment
Property, plant and equipment are recorded at cost. Investment tax credits and other similar grants are treated as a reduction of the capitalized cost of the asset to which they apply.
The company uses the successful-efforts method to account for its exploration and development activities. Under this method, costs are accumulated on a field-by-field basis with certain exploratory expenditures and exploratory dry holes being expensed as incurred. Costs of productive wells and development dry holes are capitalized and amortized using the unit-of-production method. The company carries as an asset exploratory
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Notes to consolidated financial statements (continued)
well costs when the well has found a sufficient quantity of reserves to justify its completion as a producing well and where the company is making sufficient progress assessing the reserves and the economic and operating viability of the project. Other exploratory expenditures, including geophysical costs and annual lease rentals are expenses as incurred.
Maintenance and repair costs, including planned major maintenance, are expensed as incurred. Improvements that increase or prolong the service life or capacity of an asset are capitalized.
Production costs are expensed as incurred. Production involves lifting the oil and gas to the surface and gathering, treating, field processing and field storage of the oil and gas. The production function normally terminates at the outlet valve on the lease or field production storage tank. Production costs are those incurred to operate and maintain the company’s wells and related equipment and facilities. They become part of the cost of oil and gas produced. These costs, sometimes referred to as lifting costs, include such items as labour cost to operate the wells and related equipment; repair and maintenance costs on the wells and equipment; materials, supplies and energy costs required to operate the wells and related equipment; and administrative expenses related to the production activity.
Acquisition costs of proved properties are amortized using a unit-of-production method, computed on the basis of total proved oil and gas reserves. Depreciation and depletion for assets associated with producing properties begin at the time when production commences on a regular basis. Depreciation for other assets begins when the asset is in place and ready for its intended use. Assets under construction are not depreciated or depleted. Unit-of-production depreciation is applied to those wells, plant and equipment assets associated with productive depletable properties, and the unit-of-production rates are based on the amount of proved developed reserves of oil and gas. Depreciation of other plant and equipment is calculated using the straight-line method, based on the estimated service life of the asset. In general, refineries are depreciated over 25 years; other major assets, including chemical plants and service stations, are depreciated over 20 years.
Proved oil and gas properties held and used by the company are reviewed for impairment whenever events or changes in circumstances indicate that the carrying amounts may not be recoverable. Assets are grouped at the lowest level for which there are identifiable cash flows that are largely independent of the cash flows of other groups of assets.
The company estimates the future undiscounted cash flows of the affected properties to judge the recoverability of carrying amounts. Cash flows used in impairment evaluations are developed using annually updated corporate plan investment evaluation assumptions for crude oil and natural gas commodity prices and foreign-currency exchange rates. Annual volumes are based on field production profiles, which are also updated annually.
In general, impairment analyses are based on reserve estimates used for internal planning and capital investment decisions. Where probable reserves exist, an appropriately risk-adjusted amount of these reserves may be included in the impairment evaluation. An asset would be impaired if the undiscounted cash flows were less than its carrying value. Impairments are measured by the amount by which the carrying value exceeds its fair value.
Significant unproved properties are assessed for impairment individually and valuation allowances against the capitalized costs are recorded based on the estimated economic chance of success and the length of time the company expects to hold the properties. Properties that are not individually significant are aggregated by groups and amortized based on development risk and average holding period. The valuation allowances are reviewed at least annually.
Gains or losses on assets sold are included in “investment and other income” in the consolidated statement of income.
Interest capitalization
Interest costs relating to major capital projects under construction are capitalized as part of property, plant and equipment. The project construction phase commences with the development of the detailed engineering design and ends when the constructed assets are ready for their intended use.
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Goodwill and other intangible assets
Goodwill is not subject to amortization. Goodwill is tested for impairment annually or more frequently if events or circumstances indicate it might be impaired. Impairment losses are recognized in current period earnings. The evaluation for impairment of goodwill is based on a comparison of the carrying values of goodwill and associated operating assets with the estimated present value of net cash flows from those operating assets.
Intangible assets with determinable useful lives are amortized over the estimated service lives of the assets. Computer software development costs are amortized over a maximum of 15 years and customer lists are amortized over a maximum of 10 years. The amortization is included in “depreciation and depletion” in the consolidated statement of income.
Legal obligations associated with site restoration on the retirement of assets with determinable useful lives are recognized when they are incurred, which is typically at the time the assets are installed. These obligations primarily relate to soil reclamation and remediation and costs of abandonment and demolition of oil and gas wells and related facilities. The company uses estimates, assumptions and judgments regarding such factors as the existence of a legal obligation for an asset retirement obligation, technical assessments of the assets, estimated amounts and timing of settlements, the credit-adjusted risk-free rate to be used, and inflation rates. The obligations are initially measured at fair value and discounted to present value. A corresponding amount equal to that of the initial obligation is added to the capitalized costs of the related asset. Over time, the discounted asset retirement obligation amount will be accreted for the change in its present value, and the initial capitalized costs will be depreciated over the useful lives of the related assets.
No asset retirement obligations are set up for those manufacturing, distribution and marketing facilities with an indeterminate useful life. Asset retirement obligations for these facilities generally become firm at the time the facilities are permanently shut down and dismantled. These obligations may include the costs of asset disposal and additional soil remediation. However, these sites have indeterminate lives based on plans for continued operations, and as such, the fair value of the conditional legal obligations cannot be measured, since it is impossible to estimate the future settlement dates of such obligations. Provision for environmental liabilities of these assets is made when it is probable that obligations have been incurred and the amount can be reasonably estimated. Provisions for environmental liabilities are determined based on engineering estimated costs, taking into account the anticipated method and extent of remediation consistent with legal requirements, current technology and the possible use of the location. These liabilities are not discounted.
Foreign-currency translation
Monetary assets and liabilities in foreign currencies have been translated at the rates of exchange prevailing on December 31. Any exchange gains or losses are recognized in income.
Fair value
Fair value is the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants. Hierarchy Levels 1, 2 or 3 are terms for the priority of inputs to valuation techniques used to measure fair value. Hierarchy Level 1 inputs are quoted prices in active markets for identical assets or liabilities. Hierarchy Level 2 inputs are inputs other than quoted prices included within Level 1 that are directly or indirectly observable for the asset or liability. Hierarchy Level 3 inputs are inputs that are not observable in the market.
Revenues
Revenues associated with sales of crude oil, natural gas, petroleum and chemical products and other items are recorded when the products are delivered. Delivery occurs when the customer has taken title and has assumed the risks and rewards of ownership, prices are fixed or determinable and collectability is reasonably assured. The company does not enter into ongoing arrangements whereby it is required to repurchase its products, nor does the company provide the customer with a right of return.
Revenues include amounts billed to customers for shipping and handling. Shipping and handling costs incurred up to the point of final storage prior to delivery to a customer are included in “purchases of crude oil and products” in the consolidated statement of income. Delivery costs from final storage to customer are recorded as a marketing expense in “selling and general” expenses.
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Purchases and sales of inventory with the same counterparty that are entered into in contemplation of one another are combined and recorded as exchanges measured at the book value of the item sold.
Share-based compensation
The company awards share-based compensation to certain employees in the form of restricted stock units. Compensation expense is measured each reporting period based on the company’s current stock price and is recorded as “selling and general” expenses in the consolidated statement of income over the requisite service period of each award. See note 7 to the consolidated financial statements on page 69 for further details.
Consumer taxes
Taxes levied on the consumer and collected by the company are excluded from the consolidated statement of income. These are primarily provincial taxes on motor fuels, the federal goods and services tax and the federal/provincial harmonized sales tax.
The company operates its business in Canada. The Upstream, Downstream and Chemical functions best define the operating segments of the business that are reported separately. The factors used to identify these reportable segments are based on the nature of the operations that are undertaken by each segment and the structure of the company’s internal organization. The Upstream segment is organized and operates to explore for and ultimately produce crude oil and its equivalent, and natural gas. The Downstream segment is organized and operates to refine crude oil into petroleum products and the distribution and marketing of these products. The Chemical segment is organized and operates to manufacture and market hydrocarbon-based chemicals and chemical products. The above segmentation has been the long-standing practice of the company and is broadly understood across the petroleum and petrochemical industries.
These functions have been defined as the operating segments of the company because they are the segments (a) that engage in business activities from which revenues are earned and expenses are incurred; (b) whose operating results are regularly reviewed by the company’s chief operating decision maker to make decisions about resources to be allocated to each segment and assess its performance; and (c) for which discrete financial information is available.
Corporate and other includes assets and liabilities that do not specifically relate to business segments – primarily cash, capitalized interest costs, short-term borrowings, long-term debt and liabilities associated with incentive compensation and post-retirement benefits liability adjustment. Net income in this segment primarily includes financing costs, interest income and share-based incentive compensation expenses.
Segment accounting policies are the same as those described in the summary of significant accounting policies. Upstream, Downstream and Chemical expenses include amounts allocated from the Corporate and other segment. The allocation is based on a combination of fee for service, proportional segment expenses and a three-year average of capital expenditures. Transfers of assets between segments are recorded at book amounts. Intersegment sales are made essentially at prevailing market prices. Assets and liabilities that are not identifiable by segment are allocated.
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Operating revenues (a)
Intersegment sales
Investment and other income
Selling and general (b)
Current
Deferred
Total income tax expense
Capital and exploration expenditures (c)
Cost
Accumulated depreciation and depletion
Net property, plant and equipment (d)
Total assets (e)
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Total export sales
Current income tax expense
Deferred income tax expense (a)
Total income tax expense (b)
Statutory corporate tax rate (percent)
Increase/(decrease) resulting from:
Enacted tax rate change
Effective income tax rate
Income taxes (charged)/credited directly to shareholders’ equity were:
Post-retirement benefits liability adjustment:
Net actuarial loss/(gain)
Amortization of net actuarial (loss)/gain
Amortization of prior service cost
Total post-retirement benefits liability adjustment
Deferred income taxes are based on differences between the accounting and tax values of assets and liabilities. These differences in value are re-measured at each year-end using the tax rates and tax laws expected to apply when those differences are realized or settled in the future. Components of deferred income tax liabilities and assets as at December 31 were:
Depreciation and amortization
Successful drilling and land acquisitions
Pension and benefits
Site restoration
Capitalized interest
Deferred income tax liabilities
LIFO inventory valuation
Deferred income tax assets
Valuation allowance
Net deferred income tax liabilities
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Unrecognized tax benefits
Unrecognized tax benefits reflect the difference between positions taken or expected to be taken on tax returns and the amounts recognized in the financial statements. Resolution of the related tax positions will take many years to complete. It is difficult to predict the timing of resolution for tax positions, since such timing is not entirely within the control of the company. The company’s effective tax rate will be reduced if any of these tax benefits are subsequently recognized.
The following table summarizes the movement in unrecognized tax benefits:
January 1 balance
Additions based on current year’s tax position
Additions for prior years’ tax positions
Reductions for prior years’ tax positions
Reductions due to lapse of the statute of limitations
December 31 balance
The 2011, 2010 and 2009 changes in unrecognized tax benefits did not have a material effect on the company’s net income or cash flow. The company’s tax filings from 2007 to 2010 are subject to examination by the tax authorities. The Canada Revenue Agency has proposed certain adjustments to the company’s filings for several years in the period 1994 to 2006. Management is currently evaluating those proposed adjustments. Management believes that a number of outstanding matters before 2007 are expected to be resolved in 2012. The impact on unrecognized tax benefits and the company’s effective income tax rate from these matters is not expected to be material.
The company classifies interest on income tax related balances as interest expense or interest income and classifies tax related penalties as operating expense.
Retirement benefits, which cover almost all retired employees and their surviving spouses, include pension income and certain health care and life insurance benefits. They are met through funded registered retirement plans and through unfunded supplementary benefits that are paid directly to recipients.
Pension income benefits consist mainly of company-paid defined benefit plans that are based on years of service and final average earnings. The company shares in the cost of health care and life insurance benefits. The company’s benefit obligations are based on the projected benefit method of valuation that includes employee service to date and present compensation levels as well as a projection of salaries to retirement.
The expense and obligations for both funded and unfunded benefits are determined in accordance with United States generally accepted accounting principles and actuarial procedures. The process for determining retirement-income expense and related obligations includes making certain long-term assumptions regarding the discount rate, rate of return on plan assets and rate of compensation increases. The obligation and pension expense can vary significantly with changes in the assumptions used to estimate the obligation and the expected return on plan assets.
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The benefit obligations and plan assets associated with the company’s defined benefit plans are measured on December 31.
Other post-retirement
benefits
Assumptions used to determine benefit obligations at December 31 (percent)
Discount rate
Long-term rate of compensation increase
Change in projected benefit obligation
Projected benefit obligation at January 1
Current service cost
Interest cost
Actuarial loss/(gain)
Amendments
Benefits paid (a)
Projected benefit obligation at December 31
Accumulated benefit obligation at December 31
The discount rate for calculating year-end post-retirement liabilities is based on the yield for high quality, long-term Canadian corporate bonds at year-end with an average maturity (or duration) approximately that of the liabilities. The measurement of the accumulated post-retirement benefit obligation assumes a health care cost trend rate of 4.50 percent in 2012 and subsequent years.
Change in plan assets
Fair value at January 1
Actual return/(loss) on plan assets
Company contributions
Benefits paid (b)
Fair value at December 31
Plan assets in excess of/(less than) projected benefit obligation at December 31
Funded plans
Unfunded plans
Total (c)
Funding of registered retirement plans complies with federal and provincial pension regulations, and the company makes contributions to the plans based on an independent actuarial valuation. In accordance with authoritative guidance relating to the accounting for defined pension and other post-retirement benefits plans, the underfunded status of the company’s defined benefit post-retirement plans was recorded as a liability in the balance sheet, and the changes in that funded status in the year in which the changes occurred was recognized through other comprehensive income.
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Other post-
retirement benefits
Amounts recorded in the consolidated balance sheet consist of:
Other long-term obligations
Total recorded
Amounts recorded in accumulated other comprehensive income consist of:
Prior service cost
Total recorded in accumulated other comprehensive income, before tax
The company establishes the long-term expected rate of return on plan assets by developing a forward-looking long-term return assumption for each asset class, taking into account factors such as the expected real return for the specific asset class and inflation. A single long-term rate of return is then calculated as the weighted average of the target asset allocation and the long-term return assumption for each asset class. The 2011 long-term expected return of 7.00 percent used in the calculations of pension expense compares to an actual rate of return of 6.0 percent and 8.3 percent over the last 10- and 20-year periods ending December 31, 2011.
Assumptions used to determine net periodic benefit cost for years ended December 31 (percent)
Long-term rate of return on funded assets
Components of net periodic benefit cost
Expected return on plan assets
Recognized actuarial loss/(gain)
Net periodic benefit cost
Changes in amounts recorded in accumulated other comprehensive income
Amortization of net actuarial (loss)/gain included in net periodic benefit cost
Amortization of prior service cost included in net periodic benefit cost
Total recorded in other comprehensive income
Total recorded in net periodic benefit cost and other comprehensive income, before tax
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Costs for defined contribution plans, primarily the employee savings plan, were $36 million in 2011 (2010 - $37 million, 2009 - $36 million).
A summary of the change in accumulated other comprehensive income is shown in the table below:
Total pension and other
post-retirement benefits
(Charge)/credit to other comprehensive income, before tax
Deferred income tax (charge)/credit (note 3)
(Charge)/credit to other comprehensive income, after tax
The company’s investment strategy for pension plan assets reflects a long-term view, a careful assessment of the risks inherent in various asset classes and broad diversification to reduce the risk of the portfolio. Consistent with the long-term nature of the liability, the plan assets are primarily invested in global, market-cap-weighted indexed equity and domestic indexed bond funds to diversify risk while minimizing costs. The equity funds hold Imperial Oil stock only to the extent necessary to replicate the relevant equity index. The balance of the plan assets is largely invested in high-quality corporate and government debt securities. Studies are periodically conducted to establish the preferred target asset allocation. The target asset allocation for equity securities is 46 percent. The target allocation for debt securities is 49 percent. Plan assets for the remaining 5 percent are invested in venture capital partnerships that pursue a strategy of investment in U.S. and international early stage ventures.
The 2011 fair value of the pension plan assets, including the level within the fair value hierarchy, is shown in the table below:
Quoted prices
in active
markets foridentical assets
(Level 1)
Significant
other
observableinputs
(Level 2)
unobservableinputs
(Level 3)
Asset class
Equity securities
Canadian
Non-Canadian
Debt securities - Canadian
Corporate
Government
Asset backed
Mortgage funds
Equities – Venture capital
Total plan assets at fair value
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The change in the fair value of Level 3 assets, which use significant unobservable inputs to measure fair value, is shown in the table below:
Mortgage
funds
Venture
capital
Fair value at January 1, 2011
Net realized gains/(losses)
Net unrealized gains/(losses)
Net purchases/(sales)
Fair value at December 31, 2011
The 2010 fair value of the pension plan assets, including the level within the fair value hierarchy, is shown in the table below:
Significant other
Fair value at January 1, 2010
Fair value at December 31, 2010
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A summary of pension plans with accumulated benefit obligations in excess of plan assets is shown in the table below:
For funded pension plans with accumulated benefit obligations in excess of plan assets:
Projected benefit obligation
Accumulated benefit obligation
Fair value of plan assets
Accumulated benefit obligation less fair value of plan assets
For unfunded plans covered by book reserves:
Estimated 2012 amortization from accumulated other comprehensive income
Net actuarial loss/(gain) (a)
Prior service cost (b)
Cash flows
Benefit payments expected in:
2012
2014
2015
2016
2017 - 2021
In 2012, the company expects to make cash contributions of about $600 million to its pension plans.
Sensitivities
A one percent change in the assumptions at which retirement liabilities could be effectively settled is as follows:
Increase/(decrease)
millions of dollars
Rate of return on plan assets:
Effect on net benefit cost, before tax
Discount rate:
Effect on benefit obligation
Rate of pay increases:
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A one percent change in the assumed health-care cost trend rate would have the following effects:
Effect on service and interest cost components
Employee retirement benefits (note 4)(a)
Asset retirement obligations and other environmental liabilities (b)
Share-based incentive compensation liabilities (note 7)
Other obligations
Total other long-term obligations
Asset retirement obligations incurred in the current period were Level 3 (unobservable inputs) fair value measurements. The following table summarizes the activity in the liability for asset retirement obligations:
Additions
Accretion
Settlement
The company did not enter into any derivative instruments to offset exposures associated with hydrocarbon prices, foreign currency exchange rates and interest rates that arose from existing assets, liabilities and transactions in the past three years. The company did not engage in speculative derivative activities or derivative trading activities nor did it use derivatives with leveraged features. The company maintains a system of controls that includes a policy covering the authorization, reporting and monitoring of derivative activity.
The fair value of the company’s financial instruments is determined by reference to various market data and other appropriate valuation techniques. There are no material differences between the fair values of the company’s financial instruments and the recorded book value. The fair value hierarchy for long-term debt is primarily Level 2 (observable input).
Share-based incentive compensation programs are designed to retain selected employees, reward them for high performance and promote individual contribution to sustained improvement in the company’s future business performance and shareholder value.
Restricted stock units, deferred share units and incentive share units
Under the restricted stock unit plan, each unit entitles the recipient to the conditional right to receive from the company, upon exercise, an amount equal to the five-day average of the closing price of the company’s common shares on the Toronto Stock Exchange on and immediately prior to the exercise dates. Fifty percent of the units are exercised three years following the grant date, and the remainder is exercised seven years following the grant date. The company may also issue units where 50 percent of the units are exercisable five years following the grant date and the remainder is exercisable on the later of ten years following the grant date or the retirement date of the recipient. For units granted in 2005, the exercise dates have been changed from December 31 to December 4. For units granted in 2005 to be exercised subsequent to the company’s
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May 2006 three-for-one share split, the company has indicated that it will increase the cash payment or number of shares issued per unit, as the case may be, by a factor of three.
The deferred share unit plan is made available to nonemployee directors. The nonemployee directors can elect to receive all or part of their directors’ fees in units. The number of units granted is determined at the end of each calendar quarter by dividing the dollar amount of the nonemployee director’s fees for that calendar quarter elected to be received as deferred share units by the average closing price of the company’s shares for the five consecutive trading days immediately prior to the last day of the calendar quarter. Additional units are granted based on the cash dividend payable on the company’s shares divided by the average closing price immediately prior to the payment date for that dividend and multiplying the resulting number by the number of deferred share units held by the recipient, as adjusted for any share splits. Deferred share units cannot be exercised until after resignation as a director and must be exercised no later than December 31 of the year following resignation. On the exercise date, the cash value to be received for the units is determined based on the average closing price of the company’s shares for the five consecutive trading days immediately prior to the date of exercise, as adjusted for any share splits.
The company’s incentive share units gave the recipient a right to receive cash equal to the amount by which the market price of the company’s common shares at the time of exercise exceeds the issue price of the units. These units were granted prior to 2002. The issue price of the units granted to recipients was the closing price of the company’s shares on the Toronto Stock Exchange on the grant date. The last grant expired in 2011.
All units require settlement by cash payments with the following exceptions. The restricted stock unit program was amended for units granted in 2002 and subsequent years by providing that the recipient may receive one common share of the company per unit or elect to receive the cash payment for the units to be exercised in the seventh year following the grant date. For units where 50 percent are exercisable five years following the grant date and the remainder exercisable on the later of ten years following the grant date or the retirement date of the recipient, the recipient may receive one common share of the company per unit or elect to receive cash payment for all units to be exercised.
The company accounts for all units by using the fair-value-based method. The fair value of awards in the form of restricted stock and deferred share units is the market price of the company’s stock. Under this method, compensation expense related to the units of these programs is measured each reporting period based on the company’s current stock price and is recorded in the consolidated statement of income over the requisite service period of each award.
The following table summarizes information about these units for the year ended December 31, 2011:
share units
Outstanding at January 1, 2011
Granted
Exercised
Forfeited and cancelled
Outstanding at December 31, 2011
The compensation expense charged against income for these programs was $91 million, $57 million and $59 million for the years ended December 31, 2011, 2010 and 2009, respectively. Income tax benefit recognized in income related to compensation expense for the years ended December 31, 2011, 2010 and 2009 was $33 million, $27 million and $24 million, respectively. Cash payments of $173 million, $152 million and $126 million for these programs were made in 2011, 2010 and 2009, respectively.
As of December 31, 2011, there was $216 million of total before-tax unrecognized compensation expense related to non-vested restricted stock units based on the company’s share price at the end of the current reporting period. The weighted average vesting period of nonvested restricted stock units is 3.8 years. All units under the deferred share programs have vested as of December 31, 2011.
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Incentive stock options
In April 2002, incentive stock options were granted for the purchase of the company’s common shares. For units exercised subsequent to the company’s May 2006 three-for-one split, the company has indicated that it will give the option holders the right to purchase three shares for each original stock option granted. The exercise price is $15.50 per share (adjusted to reflect the three-for-one share split). All options have vested as of December 31, 2011. Any unexercised options expire after April 29, 2012. The company has not issued incentive stock options since 2002 and has no plans to issue incentive stock options in the future.
Since incentive stock option awards vested prior to the effective date of current authoritative guidance relating to accounting for stock-based compensation, they continue to be accounted for under the prior prescribed method. Under this method, compensation expense of incentive stock option awards is not recognized, as the exercise price of the option is equal to the market price of the stock on the date of grant.
The aggregate intrinsic value of stock options exercised was $40 million, $5 million and $1 million in the years ended December 31, 2011, 2010 and 2009, respectively, and for the outstanding stock options was $83 million as at December 31, 2011.
The average fair value of each option granted during 2002 was $4.23 (adjusted to reflect the three-for-one share split). The fair value was estimated at the grant date using an option-pricing model with the following weighted average assumptions: risk-free interest rate of 5.7 percent, expected life of five years, volatility of 25 percent and a dividend yield of 1.9 percent.
The company has purchased shares on the market to fully offset the dilutive effects from the exercise of stock options. Purchase may be discontinued at any time without prior notice.
The following table summarizes information about stock options for the year ended December 31, 2011:
Exercise
price
(dollars)
Investment and other income includes gains and losses on asset sales as follows:
Book value of assets sold
Gain/(loss) on asset sales, before tax (a)
Gain/(loss) on asset sales, after tax (a)
A variety of claims have been made against Imperial Oil Limited and its subsidiaries in a number of lawsuits. Management has regular litigation reviews, including updates from corporate and outside counsel, to assess the need for accounting recognition or disclosure of these contingencies. The company accrues an undiscounted liability for those contingencies where the incurrence of a loss is probable and the amount can be reasonably estimated. If a range of amounts can be reasonably estimated and no amount within the range
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is a better estimate than any other amount, then the minimum of the range is accrued. The company does not record liabilities when the likelihood that the liability has been incurred is probable but the amount cannot be reasonably estimated or when the liability is believed to be only reasonably possible or remote. For contingencies where an unfavourable outcome is reasonably possible and which are significant, the company discloses the nature of the contingency and, where feasible, an estimate of the possible loss. For purposes of the company’s contingency disclosures, “significant” includes material matters as well as other matters which management believes should be disclosed. Based on a consideration of all relevant facts and circumstances, the company does not believe the ultimate outcome of any currently pending lawsuits against the company will have a material adverse effect on the company’s operations, financial condition, or financial statements taken as a whole.
Additionally, the company has other commitments arising in the normal course of business for operating and capital needs, all of which are expected to be fulfilled with no adverse consequences material to the company’s operations or financial condition. Unconditional purchase obligations, as defined by accounting standards, are those long-term commitments that are non-cancelable or cancelable only under certain conditions and that third parties have used to secure financing for the facilities that will provide the contracted goods and services.
Unconditional purchase obligations (a)
As at
Dec. 31
Authorized
From 1995 through 2010, the company purchased shares under sixteen 12-month normal course issuer bid share repurchase programs, as well as an auction tender. On June 25, 2011, another 12-month normal course issuer bid program was implemented with an allowable purchase of up to about 42 million shares, including shares purchased from Exxon Mobil Corporation and shares purchased by the employee savings plan and company pension fund. The results of these activities are as shown below.
1995 to 2009
Cumulative purchases to date
Exxon Mobil Corporation’s participation in the above maintained its ownership interest in Imperial at 69.6 percent.
The excess of the purchase cost over the stated value of shares purchased has been recorded as a distribution of earnings reinvested.
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The company’s common share activities are summarized below:
Balance as at January 1, 2009
Issued under employee share-based awards
Purchases at stated value
Balance as at December 31, 2009
Balance as at December 31, 2010
Balance as at December 31, 2011
The following table provides the calculation of basic and diluted earnings per share:
Net income per common share – basic
Net income (millions of dollars)
Weighted average number of common shares outstanding
(millions of shares)
Net income per common share (dollars)
Net income per common share - diluted
Effect of employee share-based awards (millions of shares)
Weighted average number of common shares outstanding, assuming dilution (millions of shares)
In 2011, net income included an after-tax gain of $10 million (2010 – $38 million gain, 2009 – $46 million gain) attributable to the effect of changes in last-in, first-out (LIFO) inventories. The replacement cost of inventories was estimated to exceed their LIFO carrying values at December 31, 2011 by $2,196 million (2010 – $1,859 million). Inventories of crude oil and products at year-end consisted of the following:
Petroleum products
Chemical products
Natural gas and other
Total inventories of crude oil and products
Net research and development costs charged to expenses in 2011 were $120 million (2010 – $97 million, 2009 – $110 million). These costs are included in expenses due to the uncertainty of future benefits.
Cash flow from operating activities included dividends of $3 million received from equity investments in 2011 (2010 – $9 million, 2009 – $14 million).
Accounts payable and accrued liabilities included accrued taxes other than income taxes of $540 million at December 31, 2011 (2010 - $357 million).
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Debt-related interest
Net interest expense
Other interest
Total financing costs (a)
At December 31, 2011, the company held non-cancelable operating leases covering office buildings, rail cars, service stations and other properties with minimum undiscounted lease commitments totalling $430 million as indicated in the following table:
Lease payments under minimum commitments (a)
Capital leases (b)
Total long-term debt
In the second quarter of 2011, the company extended the maturity date of its existing stand-by $200 million long-term bank credit facility to July 2013. The company has not drawn on the facility.
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The company continues capitalization of exploratory well costs beyond one year after the well is completed if (a) the well found a sufficient quantity of reserves to justify its completion as a producing well and (b) sufficient progress is being made in assessing the reserves and the economic and operating viability of the project.
The following two tables provide details of the changes in the balance of suspended exploratory well costs as well as an aging summary of those costs.
Change in capitalized suspended exploratory well costs:
Additions pending the determination of proved reserves
Charged to expense
Reclassification to wells, facilities and equipment based on the determination of proved reserves
Period end capitalized suspended exploratory well costs:
Capitalized for a period of one year or less
Capitalized for a period of between one and five years
Capitalized for a period of greater than one year
Exploration activity often involves drilling multiple wells, over a number of years, to fully evaluate a project. The table below provides a numerical breakdown of the number of projects with suspended exploratory well costs which had their first capitalized well drilled in the preceding 12 months and those that have had exploratory well costs capitalized for a period greater than 12 months.
Number of projects with first capitalized well drilled in the preceding 12 months
Number of projects that have exploratory well costs capitalized for a period of greater than 12 months
The project with exploratory well costs capitalized for a period greater than 12 months as of December 31, 2011 has drilling in the preceding 12 months.
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Revenues and expenses of the company also include the results of transactions with Exxon Mobil Corporation and affiliated companies (ExxonMobil) in the normal course of operations. These were conducted on terms as favourable as they would have been with unrelated parties and primarily consisted of the purchase and sale of crude oil, petroleum and chemical products, as well as technical, engineering and research and development costs. Transactions with ExxonMobil also included amounts paid and received in connection with the company’s participation in a number of upstream activities conducted jointly in Canada.
In addition, the company has existing agreements with ExxonMobil to:
Certain charges from ExxonMobil have been capitalized; they are not material in the aggregate.
As at December 31, 2011, the company had outstanding loans of $820 million (2010 – $500 million) from ExxonMobil (see note 14, long-term debt, on page 74 for further details).
As at December 31, 2011, the company had outstanding loans of $18 million (2010 - $30 million) to Montreal Pipe Line Limited, in which the company has an equity interest, for financing of the equity company’s capital expenditure programs and working capital requirements.
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Supplemental information on oil and gas exploration and production activities(unaudited)
The information on pages 77 to 78 excludes items not related to oil and natural gas extraction, such as administrative and general expenses, pipeline operations, gas plant processing fees and gains or losses on asset sales. The company’s 25 percent interest in proved synthetic oil reserves in the Syncrude joint-venture and 70.96 percent interest in proved bitumen reserves in the Kearl project are included as part of the company’s total proved oil and gas reserves in accordance with U.S. Securities and Exchange Commission (SEC) and U.S. Financial Accounting Standards Board (FASB) rules. Similarly, the company’s share of proved synthetic oil reserves from Syncrude and proved bitumen reserves from Kearl are included in the calculation of the standardized measure of discounted future cash flows. Results of operations, costs incurred in property acquisitions, exploration and development activities, and capitalized costs include the company’s share of Syncrude, Kearl and other unproved mineable acreages in the following tables.
Sales to customers (a)
Intersegment sales (a)(b)
Production expenses
Exploration expenses
Income taxes
Costs incurred in property acquisitions, exploration and development activities
Property costs (c)
Proved
Unproved
Exploration costs
Development costs
Total costs incurred in property acquisitions, exploration and development activities
The amounts reported as costs incurred in property acquisitions, exploration and development activities include both capitalized costs and costs charged to expense during the year. Costs incurred also include new asset retirement obligations established in the current year, as well as increases or decreases to the asset retirement obligation resulting from changes in cost estimates or abandonment.
Capitalized costs
Producing assets
Support facilities
Incomplete construction
Total capitalized cost
Net capitalized costs
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(unaudited) (continued)
Standardized measure of discounted future cash flows
As required by the U.S. Financial Accounting Standards Board (FASB), the standardized measure of discounted future net cash flows is computed by applying first-day-of-the-month average prices, year-end costs and legislated tax rates and a discount factor of 10 percent to net proved reserves. The standardized measure includes costs for future dismantlement, abandonment and remediation obligations. The company believes the standardized measure does not provide a reliable estimate of the company’s expected future cash flows to be obtained from the development and production of its oil and gas properties or of the value of its proved oil and gas reserves. The standardized measure is prepared on the basis of certain prescribed assumptions, including first-day-of-the-month average prices, which represent discrete points in time and therefore may cause significant variability in cash flows from year to year as prices change.
Standardized measure of discounted future net cash flows related to proved oil and gas reserves
Future cash flows
Future production costs
Future development costs
Future income taxes
Future net cash flows
Annual discount of 10 percent for estimated timing of cash flows
Discounted future cash flows
Changes in standardized measure of discounted future net cash flows related to proved oil and gas reserves
Balance at beginning of year
Changes resulting from:
Sales and transfers of oil and gas produced, net of production costs
Net changes in prices, development costs and production costs
Extensions, discoveries, additions and improved recovery, less related costs
Development costs incurred during the year
Revisions of previous quantity estimates
Accretion of discount
Net change in income taxes
Net change
Balance at end of year
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Net Proved Reserves (a)
oil-equivalent
basis (c)
millions of
barrels
billions of
cubic feet
Beginning of year 2009
Revisions
Improved recovery
(Sale)/purchase of reserves in place
Discoveries and extensions
End of year 2009
End of year 2010
End of year 2011
Net Proved Developed Reserves included above, as of
January 1, 2009
December 31, 2009
December 31, 2010
December 31, 2011
Net Proved Undeveloped Reserves included above, as of
The information above describes changes during the years and balances of proved oil and gas reserves at year-end 2009, 2010 and 2011. The 2009, 2010 and 2011 year-end oil and gas reserves are reported in accordance with the definitions under the U.S. Securities and Exchange Commission’s (SEC) Rule 4-10 (a) of Regulation S-X.
Proved oil and gas reserves are those quantities of oil and gas, which, by analysis of geoscience and engineering data, can be estimated with reasonable certainty to be economically producible – from a given date forward, from known reservoirs, and under existing economic conditions, operating methods and government regulations – prior to the time at which contracts providing the right to operate expire. In some
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cases, substantial new investments in additional wells and other facilities will be required to recover these proved reserves.
In accordance with SEC rules, the year-end reserves volumes as well as the reserves change categories for 2009, 2010 and 2011 shown in the proved reserves tables were calculated using average prices during the 12-month period prior to the ending date of the period covered by the report, determined as an unweighted arithmetic average of the first-day-of-the-month price for each month within such period. The beginning-of-year oil and gas reserves volumes for 2009 were calculated using December 31 prices and costs. These reserves quantities were also used in calculating unit-of-production depreciation rates and in calculating the standardized measure of discounted net cash flow.
Revisions can include upward or downward changes in previously estimated volumes of proved reserves for existing fields due to the evaluation or revaluation of already available geologic, reservoir or production data; new geologic, reservoir or production data; or changes in prices and costs that are used in the determination of reserves. This category can also include significant changes in either development strategy or production equipment/facility capacity.
In 2011, the quantities shown in the discoveries and extensions category under proved reserves were due primarily to the initial booking of the approved Kearl expansion.
Net proved reserves are determined by deducting the estimated future share of mineral owners or governments or both. For liquids and natural gas, net proved reserves are based on estimated future royalty rates as of the date the estimate is made incorporating the applicable governments’ oil and gas royalty regimes. For bitumen, net proved reserves are based on the company’s best estimate of average royalty rates over the life of each of the Cold Lake and Kearl projects, and they incorporate the Alberta government’s revised oil sands royalty regime. For synthetic oil, net proved reserves are based on the company’s best estimate of average royalty rates over the life of the project, and they incorporate amendments to the Syncrude Crown Agreement. In all cases, actual future royalty rates may vary with production, price and costs.
Net proved developed reserves are those volumes that are expected to be recovered through existing wells and facilities with existing equipment and operating methods or in which the cost of the required equipment is relatively minor compared to the cost of a new well or facility. Net proved undeveloped reserves are those volumes that are expected to be recovered as a result of future investments to drill new wells, to recomplete existing wells and/or to install facilities to collect and deliver the production from existing and future wells and facilities.
In accordance with SEC rules, beginning with 2009 year-end, bitumen extracted through mining activities and hydrocarbons from other non-traditional resources are reported as oil and gas reserves.
The rules in 2009 adopted a reliable technology definition that permits reserves to be added based on technologies that have been field tested and have been demonstrated to provide reasonably certain results with consistency and repeatability in the formation being evaluated.
No independent qualified reserves evaluator or auditor was involved in the preparation of the reserves data.
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Quarterly financial and stock trading data (a)
Financial data (millions of dollars)
Segmented net income (millions of dollars)
Net earnings – basic
Net earnings – diluted
Dividends (declared quarterly)
Share prices (dollars) (b)
Toronto Stock Exchange
Close
NYSE Amex (U.S. dollars) (b)
Shares traded (thousands) (c)
81
III. Board of directors
Director information
Director qualification and selection process
Director orientation, education, development, tenure and performance assessment
Independence of the directors
Board and committee structure
Committee memberships of the directors
Number of meetings and director attendance in 2011
Share ownership guidelines for directors
Other public company directorships
Interlocking directorships
Director compensation
Compensation discussion and analysis
Director compensation details and tables
IV. Company executives and executive compensation
Named executive officers of the company
Other executive officers of the company
Report of executive resources committee on executive compensation
Compensation program
Compensation decision making process and considerations for named executive officers
Executive compensation tables and narratives
V. Other important information
Effective date
Largest shareholder
Transactions with Exxon Mobil Corporation
Auditor Information
Auditor fees
Auditor independence
Ethical business conduct
Appendix B - Board of Director and Committee Charters
Board of Directors Charter
Audit Committee Charter
Environment, Health and Safety Committee Charter
Executive Resources Committee Charter
Nominations and Corporate Governance Committee Charter
Contributions Committee Charter
82
The tables on the following pages provide information on the seven nominees proposed for election to the board of directors of the company. All of the nominees are now directors and have been since the dates indicated.
Included in these tables is information relating to the directors’ biographies, independence status, expertise, committee memberships, attendance, public board memberships and shareholdings in the company, as well as any shareholdings in Exxon Mobil Corporation. The information is as of February 15, 2012, the effective date of this circular unless otherwise indicated.
Krystyna T. Hoeg
Toronto, Ontario, Canada
Age: 62
Current Position:
Nonemployee director
Independent
Director since May 1, 2008
Skills and experience:
— Leadership of large organizations
— Project management
— Global experience
— Strategy development
— Audit committee financial expert
— Financial expertise
— Executive compensation
Ms. Hoeg was the president and chief executive officer of Corby Distilleries Limited from 1996 until her retirement in February 2007. She previously held several positions in the finance and controllers functions of Allied Domecq PLC and Hiram Walker & Sons Limited. Prior to that, she spent five years in public practice as a chartered accountant with the accounting firm of Touche Ross. She is currently a director of Sun Life Financial Inc., Shoppers Drug Mart Corporation, Canadian Pacific Railway Limited and Canadian Pacific Railway Company, and is also a director of Ganong Brothers Limited and Samuel, Son & Co. Limited, both of which are privately owned corporations. Ms. Hoeg sits on the board of the Toronto East General Hospital.
Board and Committee Membership
Imperial Oil Limited board
Audit committee
Executive resources committee(Chair)
Environment, health and safety committee
Nominations and corporate governance committee
Contributions committee
Annual meeting of shareholders
9 of 9
5 of 5
7 of 7
3 of 3
4 of 4
1 of 1
100%
Overall Attendance – 100%
Common
Shares
(% of class)
Deferred Share
Units (DSU)
Restricted Stock
Units (RSU)
Total Common
Shares, DSU and
RSU
Total Market Value of
Common Shares, DSU
and RSU ($)
Date
Number
Total Number of
Unexercised
Options
Total Value of
Unexercised Options ($)
Common Shares
Restricted
Stock
Total Common Shares
and Restricted Stock
Common Shares and
Restricted Stock ($)
— Sun Life Financial Inc. (2002 – Present)
— Shoppers Drug Mart Corporation (2006 – Present)
— Canadian Pacific Railway Limited (2007 – Present)
— Canadian Pacific Railway Company (2007 – Present)
— Cineplex Galaxy Income Fund (2006 – 2010)
— Corby Distilleries (1996 – 2007)
Other Positions in the Past Five Years (position, date office held and status of employer)
— President and chief executive officer, Corby Distilleries (1996 – 2007)
83
Bruce H. March
Age: 55
Current Position: Chairman, president and chief executive officer, Imperial Oil Limited
Not independent
Director since January 1, 2008
— Operations/technical
Mr. March is currently chairman, president and chief executive officer of Imperial Oil Limited. Mr. March has worked for Mobil Oil Corporation and ExxonMobil in refining, supply and upstream project development assignments in the United States and Europe. In his previous position, he was the director of refining Europe/Africa/Middle East with ExxonMobil Petroleum and Chemicals BVBA in Brussels, Belgium.
Imperial Oil Limited board (Chair)
Share Units
(DSU)
8,500
(<0.01%)
--
35,752
18,350
— President, Imperial Oil Limited (January to April 2008)
— Director, refining Europe/Africa/Middle East, ExxonMobil Petroleum and Chemicals BVBA
(2007 – 2008) (Affiliate)
— Project executive, Qatar Gas to Liquids project, ExxonMobil Development Company
(2006 – 2007) (Affiliate)
84
Jack M. Mintz
Age: 60
Director since April 21, 2005
— Government relations
— Academic/research
Dr. Mintz is currently the Palmer Chair in Public Policy for the University of Calgary. Prior to that he was a professor at the Joseph L. Rotman School of Management at the University of Toronto from 1989. Dr. Mintz is a director of Brookfield Asset Management and Morneau Shepell Inc. Dr. Mintz has published widely in the fields of public economics and fiscal federalism and has frequently published articles in national newspapers and magazines.
Executive resources committee
Environment, health and safety committee (Chair)
4 of 5
3 of 4
80%
75%
Overall Attendance – 93.75%
1,000
0
— Brookfield Asset Management Inc. (formerly Brascan Corporation) (2002 – Present)
— Morneau Shepell Inc. (2010 - Present)
— CHC Helicopter Corporation (2004 – 2008)
— Palmer Chair in Public Policy, University of Calgary (2008 – Present)
— Professor, Joseph L. Rotman School of Management, University of Toronto (1989 – 2007)
85
Robert C. Olsen
Houston, Texas, United
States of America
Age: 61
Current Position: Executivevice-president, ExxonMobil
Production Company
Mr. Olsen is the executive vice-president of ExxonMobil Production Company, a division of Exxon Mobil Corporation, with responsibility for ExxonMobil’s global oil and gas producing operations. He is located in Houston, Texas. Mr. Olsen has worked for ExxonMobil in a range of upstream management assignments in the United States, Asia, Russia, Australia, and Europe. In his previous position, he was located in London as chairman and production director of ExxonMobil International Limited with responsibility for the company’s producing businesses in Europe, the Caspian and Russia.
20,000
950,200
Options ($)
111,933
210,000
321,933
26,986,220
Public Company Directorships in the Past Five Years
— Executive vice-president, Exxon Mobil Production Company, a division of Exxon Mobil Corporation
(2008 – Present)
— Chairman and production director, ExxonMobil International Limited (2004 – 2008)
86
David S. Sutherland
Waterloo, Ontario Canada
Director since April 29, 2010
In July 2007, Mr. Sutherland retired as president and chief executive officer of the former IPSCO, Inc. after spending 30 years with the company and more than five years as president and chief executive officer. Mr. Sutherland is a director of GATX Corporation and United States Steel Corporation and is a member of the Board of Governors of the University of Saskatchewan. Mr. Sutherland is a former chairman of the American Iron and Steel Institute and served as a member of the board of directors of the Steel Manufacturers Association, the International Iron and Steel Institute, the Canadian Steel Producers Association and the National Association of Manufacturers.
Contributions committee (Chair)
45,000
5,232
54,232
2,576,562
5,450
— IPSCO Inc. (2002 – 2007)
— GATX Corporation (2007 - Present)
— United States Steel Corporation (2008 – Present)
— ZCL Composites Inc. (2008 – 2010)
— President and chief executive officer, IPSCO Inc. (2002 – 2007)
87
Sheelagh D. Whittaker
London, England
Age: 64
Director since April 19, 1996
— Information technology
Ms. Whittaker spent much of her early business career as director and partner with The Canada Consulting Group, now Boston Consulting Group. From 1989 she was president and chief executive officer of Canadian Satellite Communications (Cancom). In 1993, Ms. Whittaker joined Electronic Data Systems of Plano, Texas, then one of the world’s foremost providers of information technology services. Initially spending several years as president and chief executive officer of EDS Canada, Ms. Whittaker then undertook other key leadership roles globally, ultimately serving the company as managing director, United Kingdom, Middle East and Africa, until her retirement from EDS in November 2005. Ms. Whittaker is also a non-executive director of Standard Life plc.
Nominations and corporate governance committee (Chair)
Common Shares, DSU and RSU ($)
9,350
Unexercised Options
($)
— Standard Life plc (2009 – Present)
— CanWest Mediaworks Income Fund (2005 – 2007)
No other positions held in the last five years.
88
Victor L. Young, O.C.
St. John’s, Newfoundland and
Labrador, Canada
Age: 66
Director since April 23, 2002
From November 1984 until May 2001, Mr. Young served as chairman and chief executive officer of Fishery Products International Limited, a frozen seafood products company. He is a director of Royal Bank of Canada and McCain Foods Limited. Mr. Young was appointed an Officer of the Order of Canada in 1996, and is currently vice chair of the capital campaign for Memorial University.
Audit committee (Chair)
17,750
1,774,213
— Bell Aliant Regional Communications Income Fund (2002 – 2010)
— BCE Inc. (1995 – 2010)
— Royal Bank of Canada (1991 – Present)
No other positions held in the last five years
Footnotes to Directors Tables on pages 83 through 89:
89
In considering the qualifications of potential nominees for election as directors, the nominations and corporate governance committee considers the work experience and other areas of expertise of the potential nominees. The following key criteria are considered to be relevant to the work of the board of directors and its committees:
Work Experience
Experience in leadership of businesses or other large organizations (Leadership of large organizations)
Operations/technical experience (Operations/technical)
Project management experience (Project management)
Experience in working in a global work environment (Global experience)
Experience in development of business strategy (Strategy development)
Other Expertise
Audit committee financial expert (also see the financial expert section in the audit committee chart on page 95)
Expertise in financial matters (Financial expertise)
Expertise in managing relations with government (Government relations)
Experience in academia or in research (Academic/research)
Expertise in information technology (Information technology)
Expertise in executive compensation policies and practices (Executive compensation)
Succession Planning
The nominations and corporate governance committee is responsible for identifying and recommending new candidates for board nomination. The process for selection is described in paragraph 9(a) of the Board of Directors Charter attached as Appendix B. When the committee is recommending candidates for re-nomination, it assesses such candidates against the criteria for re-nomination as set out in paragraph 9(b) of the Board of Directors Charter. The committee maintains a list of potential director candidates for future consideration and reviews such list annually.
Skills and Experience of the Director Nominees
The current nominees for election as director collectively have experience and expertise required to ensure effective stewardship and governance of the company. The key areas of work experience and skills and experience for each of the nominees for election as directors can also be found in each of the directors tables on pages 83 through 89 of this circular.
K.T. Hoeg
J.M. Mintz
R.C. Olsen
D.S. Sutherland
S.D. Whittaker
V.L. Young
Leadership of Large Organization
ü
Operations/ Technical
Project Management
Global Experience
Strategy Development
Audit Committee Financial Expert
Financial Expertise
Government Relations
Academic/ Research
Information Technology
Executive Compensation
90
Orientation, education and development
The vice-president, general counsel and corporate secretary organizes an orientation program for all new directors that includes a detailed briefing by members of management on all significant areas of the company’s operations. They also receive a comprehensive board manual which contains a record of historical information about the company, the charters of the board and its committees and other relevant company business information.
Continuing education is provided to board members by regular presentations by senior management on the main areas of company business. In August or September of each year, the board has an extended meeting that focuses on a particular area of the company’s operations and includes a visit to one or more of the company’s operating sites or a site of relevance to the company’s operations. In September 2011, the board visited the Kearl site in northern Alberta, Canada. Other continuing education events in 2011, presented to all directors, included two reviews of best practices in corporate governance, various Kearl presentations, reviews of various aspects of risk management including tax, credit and information technology and a review of major environmental and public policy issues.
Members of the board also receive an extensive package of materials prior to each board meeting that provides a comprehensive summary on each agenda item to be discussed. Similarly, the committee members also receive a comprehensive summary on each agenda item to be discussed by that particular committee.
As part of its annual assessment process, the board members are canvassed as to whether there are any additional topics that they would like to see addressed. In addition, the directors meet prior to most regularly scheduled board meetings and this provides an opportunity for informal discussion. In some cases, where senior management is present, these gatherings provide an opportunity for a review of selected topics of interest.
Tenure
Collectively, the seven nominees for election as directors have 47 years of experience on this company’s board and individually, the years of service range from two to 16 years. The board charter provides that incumbent directors will not be renominated if they have attained the age of 72 (revised in 2011 from the previous age of 70), except under exceptional circumstances at the request of the chief executive officer. The following chart shows the current years of service of the members of the board of directors and the year they would be normally be expected to retire from the board.
Director
Years of service on
the board
Year of mandatory
retirement from the
board
4 years
2022
2028
7 years
2023
2 years
2021
16 years
2019
10 years
2017
Total of 47 years of experience on the board.
The average tenure is 6.7 years.
91
Board performance assessment
The board and its committees, as well as the performance of the directors, are assessed on an annual basis. In 2011, the directors provided their written response to a series of questions to evaluate the responsibility and effectiveness of the board and its committees. This response formed the basis for a discussion with the nominations and corporate governance committee at its February 2, 2012 meeting to review the effectiveness of the board and its committees. Given the small board size, the directors are able to provide continuous peer performance feedback as required. The committee also assesses the company’s response to issues raised in the previous year’s survey.
The current board is composed of seven directors, the majority of whom (five out of seven) are independent. The five independent directors are not employees of the company. Based on the directors’ response to an annual questionnaire, the board determined that none of the independent directors has any interest, business or other relationship that could or could reasonably be perceived to constitute a material relationship with the company. As chairman, president and chief executive officer, B.H. March is not considered to be independent and R.C. Olsen is also a non-independent director as he is an employee of Exxon Mobil Corporation and holds the position of executive vice-president of ExxonMobil Production Company, a division of Exxon Mobil Corporation. The board believes that B.H. March’s extensive knowledge of the company’s business is beneficial to the other directors and his participation as a director enhances the effectiveness of the board. The company believes that R.C. Olsen, although deemed non-independent under the relevant standards by virtue of his employment, can be viewed as independent of the company’s management and that his ability to reflect the perspective of the company’s shareholders enhances the effectiveness of the board.
Name of director
Management
Reason for non-independent status
B.H. March is chairman, president and chief executive officer of Imperial Oil Limited.
R.C. Olsen is executive vice-president of ExxonMobil Production Company, a division of Exxon Mobil Corporation.
Leadership structure
The company has chosen to combine the positions of chairman, president and chief executive officer. B.H. March currently holds these positions. The company does not have a lead director. While the chairman of the board is not an independent director, S.D. Whittaker, chair of the executive sessions, provides leadership for the independent directors. The duties of the chair of the executive sessions include presiding at executive sessions of the board, and reviewing and modifying, if necessary, the agenda of the meetings of the board in advance to ensure that the board may successfully carry out its duties. The position description of the chair of the executive sessions is described in paragraph 8(3) of the Board of Directors Charter attached as Appendix B.
92
Independent director executive sessions
The executive sessions of the board are meetings of the independent directors and are held in conjunction with every board meeting. These meetings are held in the absence of management. The independent directors held eight executive sessions in 2011. The purposes of the executive sessions of the board include the following:
Raising substantive issues that are more appropriately discussed in the absence of management;
Discussing the need to communicate to the chairman of the board any matter of concern raised by any committee or director;
Addressing issues raised but not resolved at meetings of the board and assessing any follow-up needs with the chairman of the board;
Discussing the quality, quantity, and timeliness of the flow of information from management that is necessary for the independent directors to effectively and responsibly perform their duties, and advising the chairman of the board of any changes required; and
Seeking feedback about board processes.
In camera sessions of the board committees
Various committees also regularly hold in camera sessions without management present. The audit committee regularly holds private sessions of the committee members as well as private meetings of the committee with each of the external auditor, the internal auditor and senior management following every regularly scheduled committee meeting. Similarly, the nominations and corporate governance committee has also held in camera sessions without management present.
Committee structure
The board has created five committees to help carry out its duties. Each committee is chaired by a different independent director and all of the five independent directors are members of each committee. R.C. Olsen is also a member of each committee, with the exception of the audit committee which is composed entirely of independent directors. B.H. March is also a member of the contributions committee. Board committees work on key issues in greater detail than would be possible at full board meetings allowing directors to more effectively discharge their stewardship responsibilities. The five independent chairs of the five committees are able to take a leadership role in executing the board’s responsibility with respect to a specific area of the company’s operations falling within the responsibility of the committee he or she chairs. The board and each committee have a written charter that can be found at Appendix B of this circular. The charters are reviewed and approved by the board annually. The charters set out the structure, position description for the chair and the process and responsibilities of that committee. The five committees of the board are:
audit committee,
executive resources committee,
environment, health and safety committee,
nominations and corporate governance committee, and
contributions committee.
93
The following tables provide additional information about the board and its five committees:
Board of Directors
Mandate
The board of directors is responsible for the stewardship of the corporation. The stewardship process is carried out by the board directly or through one or more of the committees of the board. The formal mandate of the board can be found within the Board of Directors Charter in Appendix B of this circular.
Directors
— B.H. March (chair)
— K.T. Hoeg
— J.M. Mintz
— R.C. Olsen
— D.S. Sutherland
— S.D. Whittaker
— V.L. Young
Highlights
— Significant role in progressing Kearl project.
— Monitored and reviewed other long-term growth projects (Horn River, Nabiye).
— Review of investor relations program.
— Credit review.
— Risk management review, tax update.
— Review of research activities.
— Kearl site visit.
Role in Risk
The chairman, president and chief executive officer is charged with identifying, for review with the board of directors, the principal risks of the corporation’s business, and ensuring appropriate systems are in place to manage such risks. The company’s financial, execution and operational risk rests with corporate and business management and the company is governed by well-established risk management systems. The board of directors carefully considers these risks in evaluating the company’s strategic plans and specific proposals for capital expenditures and budget additions.
Disclosure Policy
The company is committed to full, true and plain public disclosure of all material information in a timely manner, in order to keep security holders and the investing public informed about the company’s operations. The full details of the corporate disclosure policy can be found on the company’s internet site at www.imperialoil.ca.
Independence
The current board of directors is composed of seven directors, the majority of whom (five out of seven) are independent. The five independent directors are not employees of the company.
94
Audit Committee
The role of the audit committee includes assisting the board in overseeing the integrity of the company’s financial statements, the company’s compliance with legal and regulatory requirements and the quality and effectiveness of internal controls; reviewing the adequacy of the company’s insurance program; approving any changes in accounting principles and practices; reviewing the results of monitoring activity under the company’s business ethics compliance program and reviewing senior management’s expense accounts. The formal mandate of the audit committee can be found within the Audit Committee Charter in Appendix B of this circular.
Members
— V.L. Young (chair)
— S.D. Whittaker (vice-chair)
— Reviewed the interim and annual financial statements and MD&A.
— Reviewed and assessed the results of the internal auditor’s audit program.
— Reviewed and assessed the external auditor plan and fees.
— Reviewed the committee’s mandate and committee self-assessment.
— Received a presentation on Exxon Mobil Corporation’s global audit program.
— Met in camera without management present at every meeting and also separately with the internal auditor and the external auditor at all meetings.
Expert
The company’s board of directors has determined that K.T. Hoeg, D.S. Sutherland, S.D. Whittaker and V.L. Young meet the definition of “audit committee financial expert”. The SEC has indicated that the designation of an audit committee financial expert does not make that person an expert for any purpose, or impose any duties, obligations or liability on that person that are greater than those imposed on members of the audit committee and board of directors in the absence of such designation or identification. All members of the audit committee are financially literate within the meaning of Multilateral Instrument 52-110 Audit Committees and the listing standards of the NYSE Amex LLC.
The audit committee also has an important role in risk management. It annually receives updates from management on the company’s risk management systems, including credit risk. It reviews financial statements and results of internal and external audit results.
The audit committee is composed entirely of independent directors. All members met board approved independence standards, as that term is defined in Multilateral Instrument 52-110 Audit Committees, the Securities and Exchange Commission (SEC) rules and the listing standards of the NYSE Amex LLC, a subsidiary of NYSE Euronext and the New York Stock Exchange.
95
Executive Resources Committee
The executive resources committee is responsible for corporate policy on compensation and for specific decisions on the compensation of the chief executive officer and key senior executives and officers reporting directly to that position. In addition to compensation matters, the committee is also responsible for succession plans and appointments to senior executive and officer positions, including the chief executive officer. The formal mandate of the executive resources committee can be found within the Executive Resources Committee Charter in Appendix B of this circular.
— K.T. Hoeg (chair)
— V.L. Young (vice-chair)
None of the members of the executive resources committee currently serves as a chief executive officer of another company.
— Improved focus on succession planning for senior executive positions.
— Reviewed and approved compensation for senior executive positions.
— Appointed two vice-president positions.
Committee
members
relevant skills
and
experience
Ms. Hoeg, Ms. Whittaker, Mr. Olsen, Mr. Sutherland and Mr. Young have extensive and lengthy experience in managing and implementing their respective companies’ compensation policies and practices in their role as chief executive officers or members of senior management. Ms. Hoeg, Mr. Mintz, Mr. Sutherland and Ms. Whittaker sit on compensation committees of one or more public companies. Accordingly, committee members are able to use this experience and knowledge derived from their roles with other companies in judging the suitability of the company’s compensation policies and practices.
The members of the executive resources committee are independent, with the exception of R.C. Olsen, who is not considered to be independent under the rules of the U.S. Securities and Exchange Commission, Canadian securities rules and the rules of the Toronto Stock Exchange and the NYSE Amex due to his employment with Exxon Mobil Corporation. However, the Canadian Coalition for Good Governance’s policy, “Governance Differences of Equity Controlled Corporations” – October, 2011, would view Mr. Olsen as a related director and independent of management and who may participate as a member of the company’s executive resources committee. Mr. Olsen’s participation helps to ensure an objective process for determining compensation of the company’s officers and directors and assists the deliberations of this committee by bringing the views and perspectives of the majority shareholder.
96
Environment, Health and Safety Committee
The role of the environment, health and safety committee is to review and monitor the company’s policies and practices in matters of the environment, health and safety and to monitor the company’s compliance with legislative, regulatory and corporate standards in these areas. The committee monitors trends and reviews current and emerging public policy in this area. The formal mandate of the environment, health and safety committee can be found within the Environment, Health and Safety Committee Charter in Appendix B of this circular.
— J.M. Mintz (chair)
— D.S. Sutherland (vice-chair)
— Incident performance review.
— Annual emissions and managing systems performance review.
— Occupational health review.
— Environmental public policy issues review.
The environment, health and safety committee reviews and monitors the company’s policies and practices in matters of environment, health and safety, which policies and practices are intended to mitigate and manage risk in these areas. The committee receives regular reports from management on these matters.
The members of the environment, health and safety committee are independent, with the exception of R.C. Olsen.
97
Nominations and Corporate Governance Committee
The role of the nominations and corporate governance committee is to oversee issues of corporate governance as they apply to the company, including the overall performance of the board, review potential nominees for directorship and review the charters of the board and any of its committees. The formal mandate of the nominations and corporate governance committee can be found within the Nominations and Corporate Governance Committee Charter in Appendix B of this circular.
— S.D. Whittaker (chair)
— J.M. Mintz (vice-chair)
— Two corporate governance reviews.
— Review of director compensation.
— Review of director retirement policy.
— Director search update.
— Approved statement of corporate governance practice.
The members of the nominations and corporate governance committee are independent, with the exception of R.C. Olsen, who is not considered to be independent under the rules of the U.S. Securities and Exchange Commission, Canadian securities rules and the rules of the Toronto Stock Exchange and the NYSE Amex due to his employment with Exxon Mobil Corporation. However, the Canadian Coalition for Good Governance’s policy, “Governance Differences of Equity Controlled Corporations” – October, 2011, would view Mr. Olsen as a related director and independent of management and who may participate as a member of the company’s nominations and corporate governance committee. Mr. Olsen’s participation helps to ensure an objective nominations process and assists the deliberations of this committee by bringing the views and perspectives of the majority shareholder.
98
Contributions Committee
The role of the contributions committee is to oversee all of the company’s community investment activities, including charitable donations which are presently made through the Imperial Oil Foundation. The formal mandate of the contributions committee can be found within the Contributions Committee Charter in Appendix B of this circular.
— D.S. Sutherland (chair)
— K.T. Hoeg (vice-chair)
— B.H. March
— Contribution of $15 million to communities across Canada in 2011, with a focus on education in math and sciences, environmental and energy literacy initiatives and community opportunities with an emphasis on aboriginal communities.
— Presentation by grant recipients on effectiveness of program funding.
— Graduation of first class from newly launched aboriginal women’s community leadership program.
The majority of the members of the contributions committee are independent (five out of seven) with the exception of B.H. March and R.C. Olsen.
99
The chart below shows the company’s current committee memberships and the chair of each committee.
Board committees
Nominations
and corporate
governance
committee
Audit
(b)
Environment
health and
safety
Executive
resources
Contributions
K.T. Hoeg (c)
Chair
B.H. March (a)
-
R.C. Olsen (a)
D.S. Sutherland (c)
S.D. Whittaker (c)
V.L. Young (c)
The chart below shows the number of board, committee and annual meetings held in 2011.
Number of meetings
Board or committee
Number of meetings held in 2011
Imperial Oil Limited board (a)
Executive resources committee (b)
1
100
Director attendance
The following chart provides a summary of the attendance record of each of the directors in 2011. The attendance record of each director nominee is also set out in his or her biographical information on pages 83 through 89. The attendance charts also provide an overall view of the attendance per committee. Senior management directors and other members of management periodically attend committee meetings at the request of the committee chair.
corporate
Annual
meeting
Percentage
by director
K.T.
Hoeg
B.H.
March
J.M.
Mintz
(chair)
R.C.
Olsen
D.S.
Sutherland
S.D.
Whittaker
V.L.
Young
by committee
Overall
attendance
percentage
99.00%
101
Directors are required to hold the equivalent of at least 15,000 shares of Imperial Oil Limited, including common shares, deferred share units and restricted stock units. Directors are expected to reach this level within five years from the date of appointment to the board. The board of directors believes that the share ownership guideline will result in an alignment of the interest of board members with the interests of all other shareholders.
since
Amount
acquired
since last
report
(February 12,
2011 to
February 15,
2012)
holdings
(includes
common
shares,
deferred share
units and
restricted stock
units)
Total at-risk
value of
total
(b) ($)
Minimum
shareholding
requirement
met or date
required to
achieve
minimum
May 1,
2008
met
B.H. March(a)
January 1,
April 21,
2005
April 29,
April 19,
1996
April 23,
2002
102
The following table shows which current directors serve on the boards of other reporting issuers and the committee membership in those companies.
Other reporting issuers of whichdirector is also a director
Risk review committee
Shoppers Drug Mart Corporation
Pension committee
Canadian Pacific Railway Company
Brookfield Asset Management Inc.
Compensation committee
United States Steel Corporation
Standard Life plc
Risk and capital committee
Remuneration committee
Risk committee
There are currently no interlocking directorships among the director nominees listed in this circular.
103
Philosophy and objectives
Director compensation elements are designed to:
ensure alignment with long-term shareholder interests;
provide motivation to promote sustained improvement in the company’s business performance and shareholder value;
ensure the company can attract and retain outstanding director candidates who meet the selection criteria outlined in section 9 of the Board of Directors Charter;
recognize the substantial time commitments necessary to oversee the affairs of the company; and
support the independence of thought and action expected of directors.
Nonemployee director compensation levels are reviewed by the nominations and corporate governance committee each year, and resulting recommendations are presented to the full board for approval.
Employees of the company or Exxon Mobil Corporation receive no extra pay for serving as directors. Nonemployee directors receive compensation consisting of cash and restricted stock units. Since 1999, the nonemployee directors have been able to receive all or part of their cash directors’ fees in the form of deferred share units. The purpose of the deferred share unit plan for nonemployee directors is to provide them with additional motivation to promote sustained improvement in the company’s business performance and shareholder value by allowing them to have all or part of their directors’ fees tied to the future growth in value of the company’s common shares. The deferred share unit plan is described in more detail on page 105.
Compensation decision making process and considerations
The nominations and corporate governance committee relies on market comparisons with a group of 23 major Canadian companies with national and international scope and complexity. The company draws its nonemployee directors from a wide variety of industrial sectors, so a broad sample is appropriate for this purpose. The nominations and corporate governance committee does not target any specific percentile among comparator companies at which to align compensation for this group. The 23 comparator companies included in the benchmark sample are as follows:
Directors’ compensation has not been changed since 2008 and will be maintained at current levels until at least July 1, 2012.
Independent consultants
Following the nominations and corporate governance committee decision to use an external research firm to assemble the comparator data for the prior year in the second quarter of each year, so as to determine compensation for the upcoming July 1st – June 30th twelve month period, the committee retained Patrick O’Callaghan and Associates, an independent consultant, to provide information on competitive practices for director compensation, which assisted the committee in making a compensation recommendation for the company’s directors. The professional fees and expenses for this service in 2011 totalled $48,612.
The nominations and corporate governance committee also retained Meridian Compensation Partners, an independent consultant, to provide an assessment of competitive compensation and market data for directors’ compensation. The professional fees and expenses for this service totalled $35,702.
104
Hedging policy
Company policy prohibits all employees, including executives, and directors, from purchasing or selling puts, calls, other options or futures contracts on the company or Exxon Mobil Corporation stock.
Compensation Details
Annual retainer
In 2011, the base cash retainer for nonemployee directors was $100,000 per year. Nonemployee directors were paid $20,000 for membership on all board committees. Additionally, each board committee chair received a retainer of $10,000 for each committee chaired (the ‘annual retainer’). Nonemployee directors were not paid a fee for attending board and committee meetings for each of the eight regularly-scheduled meetings. However, they were eligible to receive a fee of $2,000 per board or committee meeting occurring on any other day. One board meeting occurred outside of the eight regularly-scheduled meeting days.
Deferred share units
In 1998, an additional form of long-term incentive compensation (“deferred share units”) was made available to nonemployee directors. Nonemployee directors may elect to receive all or a portion of their annual retainer for board membership, annual retainer for committee membership and annual retainer for committee chair, in the form of deferred share units.
The following table shows the portion of the annual retainer for board membership, annual retainer for committee membership and annual retainer for committee chair which each nonemployee director elected to receive in cash and deferred share units in 2011.
Election for 2011 director
fees in cash
(%)
Election for 2011 director fees indeferred share units
The number of deferred share units granted to a nonemployee director is determined at the end of each calendar quarter for that year by dividing (i) the dollar amount of the nonemployee director’s fees for that calendar quarter that the director elected to receive as deferred share units by (ii) the average of the closing price of the company’s shares on the Toronto Stock Exchange for the five consecutive trading days (“average closing price”) immediately prior to the last day of that calendar quarter. Those deferred share units are granted effective the last day of that calendar quarter.
A nonemployee director is granted additional deferred share units in respect of the unexercised deferred share units on the dividend payment dates for the common shares of the company. The number of such additional deferred share units is determined for each cash dividend payment date by (i) dividing the cash dividend payable for a common share of the company by the average closing price immediately prior to the payment date for that dividend and then (ii) multiplying that resultant number by the number of unexercised deferred share units held by the nonemployee directors on the record date for the determination of shareholders entitled to receive payment of such cash dividend.
A nonemployee director may only exercise these deferred share units after termination of service as a director of the company, including termination of service due to death. No deferred share units granted to a nonemployee director may be exercised unless all of the deferred share units are exercised on the same date.
Restricted stock units
In addition to the cash fees described above, the company pays a significant portion of director compensation in restricted stock units to align director compensation with the long-term interests of shareholders. Restricted
105
stock units are awarded annually with 50 percent vesting in cash three years from the date of grant and the remaining 50 percent vesting on the seventh anniversary of the grant date. Directors can elect to receive one common share for each unit or a cash payment for the units to be exercised on the seventh anniversary of the date of grant of the restricted stock units. The vesting periods are not accelerated upon separation or retirement from the board, except in the event of death. The restricted stock unit plan is described in more detail on page 116. In 2011, each nonemployee director received a grant of 2,000 restricted stock units.
In contrast to the forfeiture provisions for restricted stock units held by employees of the company, the restricted stock units awarded to nonemployee directors are not subject to risk of forfeiture at the time a director leaves the company’s board. This provision is designed to reinforce the independence of these board members. However, while on the board and for a 24-month period after leaving the company’s board, restricted stock units may be forfeited if the nonemployee director engages in direct competition with the company or otherwise engages in any activity detrimental to the company. The board agreed that the word “detrimental” shall not include any actions taken by a nonemployee director or former nonemployee director who acted in good faith and in the best interest of the company.
Other reimbursement
Nonemployee directors are also reimbursed for travel and other expenses incurred for attendance at board and committee meetings.
Components of director compensation
The following table sets out the details of compensation paid to the nonemployee directors for 2011.
retainer for board
membership
retainer for
chair
stock units
(RSU)
(#)
Fee for board and committee
meetings not regularly
scheduled
fees
paid in
cash
(a)
deferred
share
units
restricted
stock
(c)
All other
compensation
(d)
Number of
non-
regularly
meetings
attended
Fee
($2,000 x
number of
non-regularly
attended)
(ERC)
(EH&S)
(CC)
(N&CG)
(AC)
106
Compensation tables
The following table summarizes the compensation paid, payable, awarded or granted for 2011 to each of the nonemployee directors of the company.
Name
Fees
earned
($) (c)
Share-
based
awards
($) (d)
Option-
Non-equity
incentive plan
Pension
value
($) (e)
K.T. Hoeg (b)
2,000
218,400
6,591
226,991
J.M. Mintz (b)
67,000
153,400
8,716
229,116
D.S. Sutherland (b)
2,113
222,513
S.D. Whittaker (b)
132,000
88,400
21,542
241,942
V.L. Young (b)
99,500
120,900
8,663
229,063
$1,044,721
2009
$1,110,500
$1,089,012
$ 1,149,625
107
Outstanding share-based awards and option-based awards for directors
The following table sets forth all outstanding awards held by nonemployee directors of the company as at December 31, 2011 and does not include common shares owned by the director.
securities
underlying
unexercised
options
Option
exercise
expiration
date
Value of
in-the-
money
shares or units
of shares that
have not
vested
(#) (b)
Market or
payout value
of share-
awards that
18,450
837,446
20,447
928,089
9,232
419,040
48,575
2,204,819
19,594
889,372
Incentive plan awards for directors – Value vested or earned during the year
The following table sets forth the value of the awards that vested or were earned by each nonemployee director of the company in 2011.
Option-based awards –
Value vested during
the year
Share-based awards –
Value vested during the
year
Non-equity incentive plan
compensation – Value earned
during the year
42,760
106,900
108
The named executive officers of the company at the end of 2011 were:
Age
(as ofFebruary 15,2012)
Current Position
(date office held)
Other Positions in the Past Five Years
(position, date office held and status of employer)
Calgary, Alberta,
Canada
Chairman, president and chief executive officer
— President,
(January 2008 to April 2008)
— Director, refining Europe/Africa/Middle East, ExxonMobil Petroleum & Chemicals BVBA
(2007 - 2008)
(Affiliate)
— Project executive, Qatar Gas to Liquids project
ExxonMobil Development Company
(2006 - 2007)
Paul J. Masschelin
Senior vice-president, finance and administration, and treasurer
(May 1, 2010 – Present)
— Controller, refining & supply and research & engineering,
ExxonMobil Fuels Marketing Company
(2007 - 2010)
— Manager, global product movement and inventory
(2003 - 2007)
T. Glenn Scott
Senior vice-president, resources
(July 1, 2010 – Present)
— President, ExxonMobil Canada Limited and Production manager, ExxonMobil Canada East,
(2006 - 2010)
R. Gilles Courtemanche
Vice-president and general manager, refining and supply
(May 1, 2011 – Present)
— Manager, Downstream & Chemicals, Safety, Health & Environment
ExxonMobil Refining and Supply Company
(2007 – 2011)
Brian W. Livingston
Vice-president, general counsel and corporate secretary
(2004 – Present)
109
Sean R. Carleton
Controller
— Controller and treasurer,
Syncrude Canada Ltd.
— Special project executive for the Syncrude joint venture
(2005 - 2007)
Phil Dranse
Assistant treasurer
(2002 – Present)
Marvin A. Lamb
Director, corporate tax
(2001 – Present)
Compensation governance
The executive resources committee is responsible for corporate policy on compensation and for specific decisions on the compensation of the chief executive officer and key senior executives and officers of the company as stated on page 96 of this circular. The committee members, their experience in compensation, committee responsibilities and details on the use of any compensation consultants are further outlined on page 96 and page 104.
As part of its ongoing governance, the committee’s role ensures that the management of risk and a long term orientation are integral elements of the compensation policies and practices of the company. These policies and practices are designed to keep management, including named executive officers focused on the strategic objectives of the company over the long term and to effectively assess and mitigate risk in the execution of these objectives. The individual committee members, through their participation on all board committees, are able to understand the company’s overall objectives, operating risks and financial risks. This understanding of the company’s range of business risks allows an appropriate calibration to the company’s compensation policies and practices.
110
The executive resources committee of the board of directors has reviewed and discussed the “Compensation discussion and analysis” for 2011 with management of the company. Based on that review and discussion, the committee recommended to the board that the “Compensation discussion and analysis” be included in the company’s management proxy circular for the 2012 annual meeting of shareholders.
Submitted on behalf of the executive resources committee:
Index
— Business environment
— Key business strategies
— Key elements of the compensation program
— Management of risk
— Other supporting compensation and staffing practices
— Hedging policy
— Business performance and basis for compensation
— Succession planning
112
114
Compensation
program
— Career orientation
— Base salary
— Annual bonus
— Long term incentive compensation - Restricted stock units
- Exercise of restricted stock units and plan amendments
- Forfeiture risk
— Retirement benefits
- Pension plan benefits
- Savings plan benefits
115
116
117
118
119
120
considerations
— Benchmarking
— Comparator companies
— Analytical tools – Compensation summary sheets
— 2011 named executive officer compensation assessment
— 2011 chief executive officer compensation assessment
— Pay awarded to other named executive officers
— Independent consultant
— Performance graph
121
122
123
124
tables and
narratives
— Summary compensation table
— Outstanding share-based awards and option-based awards table
— Incentive plan awards table for named executive officers – Value vested during the year
— Proceeds realized in 2011 from compensation awards granted in prior years
— Equity compensation plan information
— Pension plan benefits table
— Details of former long-term incentive compensation plans
- Incentive share units
- Stock option plan
125
127
128
129
130
132
111
Providing energy to meet Canada’s demands is a complex business. The company meets this challenge by taking a long-term view to managing its business rather than reacting to short-term business cycles. As such, the compensation program of the company aligns with this long-term business approach and supports key business strategies as outlined below.
Business environment
Long investment horizons;
Large capital investments;
Complex operating and financial risks;
National scope of company operations; and
Commodity-based cyclical product prices.
Key business strategies
Grow profitable sales volumes;
Disciplined, selective and long-term focus on improving the productivity of the company’s asset mix;
Operational excellence; and
Best-in-class cost structure to ensure industry-leading returns on capital and superior cash flow.
Focus on these key business strategies is a company priority and ensures long-term growth in shareholder value.
Key elements of the compensation program
The key elements of the company’s compensation program that align with the business environment and support key business strategies are:
long-term career orientation with high individual performance standards (see page 115);
base salary that rewards individual performance and experience (see page 115);
annual bonus grants to select executives based on company performance, as well as individual performance and experience (see page 115);
payment of a large portion of executive compensation in the form of restricted stock units with lengthy vesting periods and risk of forfeiture (see page 116); and
retirement benefits (pension and savings plans) that provide for financial security after employment (see pages 119 through 120).
The company’s executive compensation program is designed to ensure that executives place a priority on:
aligning with long-term shareholder interests;
reinforcing the company’s orientation toward career employment and individual performance;
reinforcing its philosophy that the experience, skill and motivation of the company’s executives are significant determinants of future business success; and
managing risk and taking a long-term view when making investments and managing the assets of the business.
Management of risk
The company operates in an industry environment in which excellence in risk management is critical. For this reason, the company places a high premium on effective risk management, including safety, security, health, environmental, financial and reputational risks. The long-term orientation the company takes and risk of forfeiture in the compensation program reinforce this priority.
The company’s success in managing risk over multiple year periods is achieved through emphasis on flawless execution through a disciplined management framework called the Operation Integrity Management System (OIMS). The OIMS framework establishes common expectations for addressing risks inherent in our business and takes priority over other business and financial objectives. The compensation program ensures that senior executives have a strong financial incentive to protect the safety and security of our employees and the communities and environment in which we operate, to effectively manage risk and operate the business with effective business controls, as well as to create value for company shareholders through their
actions to increase shareholder return, net income, return on capital employed, and advance the long-term strategic direction of the company.
The company also has strong controls and compliance programs to manage other types of risk, including fraud, regulatory compliance and litigation risks. These controls and compliance programs are reinforced by the same features of the compensation program. The influence of commodity prices on company compensation is indirect because it is limited to only one element of compensation via its effect on earnings per share or share price. The compensation program is composed of competitive salaries and performance-based incentives as the primary instruments to attract, develop and retain key personnel.
There is no material adverse risk resulting from how the company pays its executives; to the contrary, the compensation programs and practices are designed to encourage appropriate risk assessment and risk management. The underlying design and principles inherent in the company’s compensation program, which are primarily long-term focused, discourage taking adverse risks.
The design of the compensation program helps reinforce these priorities and ensures that the compensation granted over multiple years and the shareholding net worth of senior executives is linked to the performance of the company’s stock and resulting shareholder value.
The key design features of our compensation program that discourage inappropriate risk taking are summarized below and are also described in more detail under various sections of this proxy statement.
Pay mix
The largest percentage of total compensation (excluding compensatory pension value) to senior executives is in the form of restricted stock units and an annual bonus. In the judgment of the committee, this mix of short and long term incentives strikes an appropriate balance in aligning the interests of the senior executives with the business priorities of the company and sustainable growth in long-term shareholder value.
Long holding periods - As noted above, to further reinforce the importance of risk management and a long-term investment orientation, senior executives are required to hold a substantial portion of their equity incentive award for a long period of time and in some cases beyond retirement based on the vesting provisions described on page 117. These lengthy holding periods are tailored to the company’s business model.
Risk of forfeiture – During these long holding periods, the restricted stock units are at risk of forfeiture for resignation or detrimental activity. The long vesting periods on restricted stock units and the risk of forfeiture together support an appropriate risk/reward profile that reinforces the long-term orientation expected of senior executives.
Annual bonus
Delayed payout – Payout of 50 percent of the annual bonus is delayed and is subject to risk of forfeiture. The timing of the delayed payout is determined by earnings performance. This is a unique feature of the company’s program relative to many comparator companies and further discourages inappropriate risk taking.
Risk of forfeiture – Similar to restricted stock units, the entire annual bonus is subject to risk of forfeiture for resignation or detrimental activity.
Recoupment – The entire annual bonus is subject to recoupment (‘clawback’) in the event of material negative restatement of the company’s reported financial or operating results. The clawback provision reinforces the importance of the company’s financial controls and compliance programs.
113
Common programs
All executives, including the named executive officers, participate in common programs (the same salary, incentive and retirement programs), which are reviewed by the committee; therefore, inappropriate risk taking is discouraged at all levels of the company through similar compensation design features and allocation of awards. Within these programs, the compensation of executives is differentiated based on individual performance assessment, level of responsibility and individual experience. All senior executives on loan assignment from Exxon Mobil Corporation participate in common programs, as well, which are administered by Exxon Mobil Corporation.
The company’s defined benefit pension plan and supplemental pension arrangements are highly dependent on executives remaining with the company for a career and performing at the highest levels until retirement. This dimension of total compensation encourages executives to take a long-term view when making business decisions and to focus on achieving sustainable growth for shareholders.
Other supporting compensation and staffing practices
A long established program of management development and succession planning is in place to reinforce a career orientation and ensure continuity of leadership.
The use of perquisites at the company is very limited, and mainly composed of only two elements: financial planning for senior executives and the use of club memberships for select executives which are largely tied to building business relationships.
No tax assistance is provided by the company on any elements of executive officer compensation or perquisites other than relocation. The relocation program is broad-based and applies to all management, professional, technical and executive transferred employees.
Business performance and basis for compensation
The assessment of individual performance is conducted through the company’s employee appraisal program. Conducted annually, the appraisal process assesses performance against business performance measures and objectives relevant to each employee, including the means by which performance is achieved. These business performance measures include:
safety, health and environmental performance;
risk management;
total shareholder return;
net income;
return on capital employed;
cash distribution to shareholders;
operating performance of the upstream, downstream and chemical segments; and
effectiveness of actions that support the long-term strategic direction of the company.
The appraisal process involves comparative assessment of employee performance using a standard process throughout the organization and at all levels. This process is integrated with the compensation program which results in significant pay differentiation between high and low performers. The appraisal process is also integrated with the executive development process. Both have been in place for many years and are the basis for planning individual development and succession for management positions. The decision-making process with respect to compensation requires judgment, taking into account business and individual performance and responsibility. Quantitative targets or formulae are not used to assess individual performance or determine the amount of compensation.
Succession planning
The employee appraisal process is an important aspect of succession planning for the position of chairman, president and chief executive officer, as well as other key senior executive positions. The succession planning process fosters the company’s approach to a career orientation and promotion from within, which strengthens continuity of leadership at all levels, including that of the most senior positions. This process helps to assess the competence and readiness of individuals for senior executive positions. The executive
resources committee is responsible for approving specific succession plans for the position of chairman, president and chief executive officer and key senior executive positions reporting to him, including all officers of the company.
The executive resources committee regularly reviews the company’s succession plans for the position of chairman, president and chief executive officer and other key senior executive positions. It considers candidates for these positions, from within the company and certain candidates from ExxonMobil. The executive resources committee makes recommendations to the board of directors for selection of all officers of the company, as well as other key senior executive positions reporting to the chairman, president and chief executive officer.
Career orientation
The company’s objective is to attract, develop and retain over a career the best talent available. It takes a long period of time and significant investment to develop the experienced executive talent necessary to succeed in the company’s business; senior executives must have experience with all phases of the business cycle to be effective leaders. The company’s compensation program elements are designed to encourage a career orientation among employees at all levels of the company. Career orientation among a dedicated and highly skilled workforce, combined with the highest performance standards, contributes to the company’s leadership in the industry and serves the interests of shareholders in the long term. The company service of the named executive officers reflects this strategy. Their career service ranges from approximately 26 to 36 years.
Consistent with the company’s long-term career orientation, high-performing executives typically earn substantially higher levels of compensation in the final years of their careers than in the earlier years. This pay practice reinforces the importance of a long-term focus in making decisions that are key to business success.
The compensation program emphasizes individual experience and sustained performance; executives holding similar positions may receive substantially different levels of compensation.
The company’s executive compensation program is composed of base salaries, cash bonuses and medium and long-term incentive compensation. The company does not have written employment contracts or any other agreement with its named executive officers providing for payments on change of control or termination of employment.
Base salary
Salaries provide executives with a base level of income. The level of annual salary is based on the executive’s responsibility, performance assessment and career experience. The salary program in 2011 maintained the company’s competitive position on salaries in the marketplace. Individual salary increases vary depending on each executive’s performance assessment and other factors such as time in position and potential for advancement. Salary decisions also directly affect the level of retirement benefits since salary is included in the retirement benefit calculation. Thus, the level of retirement benefits is also performance-based like other elements of compensation.
Annual bonuses were granted to approximately 90 executives to reward their contributions to the business during the past year. Bonuses are drawn from an aggregate bonus pool established annually by the executive resources committee based on the company’s financial and operating performance, and can be highly variable depending on these results. This bonus reflects the combined value at grant of annual cash bonus and earnings bonus units.
In setting the size of the annual bonus pool and individual executive awards, the executive resources committee:
considers input from the chairman, president and chief executive officer on the performance of the company and from the company’s internal compensation advisors regarding compensation trends as obtained from external consultants;
considers total shareholder return, annual net income of the company and the other key business performance indicators as described on page 114; and
uses judgment to manage the overall size of the annual bonus pool taking into consideration the cyclical nature and long-term orientation of the business.
The cost of the 2011 annual bonus program was $12.3 million versus $10.0 million in 2010. The company’s operating and financial performance was achieved in an improving but still uncertain economic environment. The 2011 annual bonus pool was approved to increase by up to 30 percent from the previous year. This change reflects an increase in corporate earnings of 53 percent and strong operating performance in 2011, including management of controllable factors. The company’s net income for 2011 was approximately $3.4 billion, return on capital employed was approximately 25 percent. Changes in individual cash bonus awards vary depending on each executive’s performance assessment.
The annual bonus program incorporates unique elements to further reinforce retention and recognize performance. Awards under this program are generally delivered as:
50 percent cash paid in the year of grant; and
50 percent earnings bonus units with a delayed payout based on cumulative earnings performance.
The cash component is intended to be a short-term incentive, while the earnings bonus unit plan is intended to be a medium-term incentive. Earnings bonus units are made available to selected executives to promote individual contribution to sustained improvement in the company’s business performance and shareholder value. Earnings bonus units are generally equal to and granted in tandem with cash bonuses.
Specifically, earnings bonus units are cash awards that are tied to future cumulative earnings per share. Earnings bonus units pay out when a specified level of cumulative earnings per share is achieved or within three years, whichever is earlier. For earnings bonus units granted in 2011, the maximum settlement value (trigger) or cumulative earnings per share required for payout was increased to $3.00, reinforcing the company’s principle of continuous improvement in business performance. The trigger of $3.00 is intentionally set at a level that is expected to be achieved within the three-year period.
If cumulative earnings per share did not reach $3.00 within three years, the payment with respect to the earnings bonus unit would be reduced to an amount equal to the number of units times the actual cumulative earnings per share over the period.
The annual bonus includes the combined value of the cash bonus and delayed earnings bonus unit portion and is intended to be competitive with the annual bonus awards of other major comparator companies adjusted to reflect the company’s performance relative to its comparators. The earnings bonus units are designed such that the timing and the amount of the payout is tied to the rate of the company’s future earnings. The amount of the award, once vested, will never exceed the original grant value. In so doing, the delayed portion of the annual bonus, that is the earnings bonus unit, puts part of the annual bonus at risk of forfeiture and thus reinforces the performance basis of the annual bonus grant.
Prior to payment, the earnings bonus units may be forfeited if the executive leaves the company before age 65, or engages in activity that is detrimental to the company.
Starting in November 2011, for executives, the entire annual bonus will be subject to a forfeiture and clawback feature if there is a material negative restatement in the financial results of the company. This clawback feature may require the executives to forfeit some or all of the cash and earnings bonus units granted in the three years prior to the restatement. Executives may be required to repay to the company any cash amounts received from bonus or earnings bonus units that were paid out five years prior to the restatement. In addition, the forfeiture and clawback provisions also apply to the annual bonus in the event an executive engages in detrimental behavior during employment or up to 24 months after leaving the company, including working for a competitor.
Long-term incentive compensation – Restricted stock units
In December 2002, the company introduced a restricted stock unit plan, which is the company’s primary long-term incentive compensation plan. Given the long-term nature of the company’s business, granting compensation in the form of restricted stock units with long vesting periods keeps executives focused on the key premise that decisions made today affect the performance of the organization and company stock for many years to come. This practice supports a risk/reward model that reinforces a long-term view, which is critical to the company’s business success, and discourages inappropriate risk taking. The amount granted is intended to provide an incentive to promote individual contribution to the company’s performance and
motivation to remain with the company. The amount is computed by reference to the most recent ranking of performance as an indication of future potential, but may also be considered for an adjustment at time of grant, if near-term performance is deemed to have changed significantly at time of grant. This type of compensation removes employee discretion in the exercise of restricted stock units, ensures alignment with the long-term interests of shareholders and reinforces retention objectives. As a matter of principle, the company does not re-price any equity awards. The utilization of restricted stock units and the determination of annual grants on a share-denominated versus price-denominated basis help reinforce this practice. Restricted stock units are not included in pension calculations.
The restricted stock unit plan is a straightforward approach to long-term incentive compensation. Grant level guidelines for the restricted stock unit program are generally held constant for long periods of time. The intent of the plan is not to frequently change the number of shares awarded for the same level of individual performance and classification or level of responsibility. A change may be required as a result of periodic checks against the market every three to five years or as a result of any subdivision, consolidation, or reclassification of the shares of the company or other relevant change in the capitalization of the company. The company does not offset losses on prior grants with higher share awards in subsequent grants, nor does the company re-price restricted stock units.
In 2006, the guidelines were reviewed in light of the company’s three-for-one share split. Given the significant appreciation in the company’s share price over the previous several years, restricted stock unit guidelines were adjusted on a two-for-one basis rather than the three-for-one share split. This had the effect of reducing grant values since 2006 compared to 2005 and earlier years. In 2011, after an analysis of the competitive positioning of the company’s restricted stock unit program, the executive resources committee determined that current levels of restricted stock units appropriately position the plan. In 2011, 685 recipients, including 92 executives, were granted 1,782,340 restricted stock units.
Exercise of restricted stock units and amendments to the restricted stock unit plan
Restricted stock units will be exercised only during employment, except in the event of death, disability or retirement. Restricted stock units cannot be assigned. In the case of any subdivision, consolidation, or reclassification of the shares of the company or other relevant change in the capitalization of the company, the company, in its discretion, may make appropriate adjustments in the number of common shares to be issued and the calculation of the cash amount payable per restricted stock unit.
Each restricted stock unit entitles the recipient the right to receive from the company, upon vesting, an amount equal to the five day average closing price of the company’s shares on the vesting date and the four preceding trading days. Fifty percent of the units will be exercised on the third anniversary of the grant date, and the remainder will be exercised on the seventh anniversary of the grant date. The chairman, president and chief executive officer’s restricted stock units are subject to longer vesting periods as described on page 123. The company will pay the recipients cash with respect to each unexercised unit granted to the recipient corresponding in time and amount to the cash dividend that is paid by the company on a common share of the company. The restricted stock unit plan was amended for units granted in 2002 and future years to Canadian residents by providing that the recipient may receive one common share of the company per unit or elect to receive the cash payment for the units to be exercised on the seventh anniversary of the grant date.
There are 4,772,763 common shares that may be issued in the future with respect to outstanding restricted stock units that represent about 0.56 percent of the company’s currently outstanding common shares. The company’s directors, officers and vice-presidents as a group hold approximately 13 percent of the unexercised restricted stock units that give the recipient the right to receive common shares that represent about 0.07 percent of the company’s currently outstanding common shares. The maximum number of common shares that any one person may receive from the exercise of restricted stock units is 226,600 common shares, which is about 0.03 percent of the currently outstanding common shares.
Exxon Mobil Corporation has a plan similar to the company’s restricted stock unit plan, under which grantees may receive restricted stock or restricted stock units, both of which are referred to herein as Exxon Mobil Corporation restricted stock. T.G. Scott and P.J. Masschelin hold Exxon Mobil Corporation restricted stock granted in 2009 and previous years, as well as the company’s restricted stock units granted in 2010 and 2011. B.H. March also holds Exxon Mobil Corporation restricted stock granted in 2007 and previous years, as well as the company’s restricted stock units granted from 2008 to 2011.
In 2008, the company’s restricted stock unit plan was amended to provide that the number of common shares of the company issuable under the plan to any insiders (as defined by the Toronto Stock Exchange) cannot
exceed 10 percent of the issued and outstanding common shares, whether at any time or as issued in any one year. The Toronto Stock Exchange advised that this amendment did not require shareholder approval.
In 2008, shareholders approved the following changes to the restricted stock unit plan:
Include an additional vesting period option for 50 percent of restricted stock units to vest on the fifth anniversary of the date of grant, with the remaining 50 percent of the grant to vest on the later of the tenth anniversary of the date of grant or the date of retirement of the grantee. The recipient of such restricted stock units may receive one common share of the company per unit or elect to receive the cash payment for all units to be exercised. The choice of which vesting period to use will be at the discretion of the company.
Set out which amendments in the future will require shareholder approval, and which amendments will only require director approval and to set an exercise price based on the weighted average price of the company’s shares on the exercise date and the four consecutive trading days immediately prior to the exercise date.
In respect of restricted stock units granted in 2011:
to the chairman, president and chief executive officer:
50 percent of each grant is exercisable on the fifth anniversary of the date of grant; and
the balance is exercisable on the tenth anniversary of the date of grant or the date of retirement, whichever is later; and
to all other senior executives:
50 percent of each grant is exercisable on the third anniversary of the date of grant; and
the balance is exercisable on the seventh anniversary of the date of grant.
As of November 2011, the restricted stock unit plan was amended to include language confirming the long standing practice of not forfeiting any restricted stock units in the event that grantee’s continued employment terminates on or after the date grantee reaches the age of 65 in circumstances where grantee becomes entitled to an annuity under the company’s retirement plan.
The long vesting periods, which are longer than those in use by most other companies, reinforce the company’s focus on growing shareholder value over the long term by subjecting a large percentage of executive compensation and the shareholding net worth of senior executives to the long-term return on the company’s stock realized by shareholders. The vesting period for restricted stock unit awards is not subject to acceleration, except in the case of death. The long vesting periods ensure that a substantial portion of the compensation received by the chairman, president and chief executive officer, as well as other key senior executives, will be received subsequent to their retirement. The value of this compensation is at risk in the event that their decisions as senior executives prior to retirement negatively impact share market value after retirement. The objective of these long vesting periods is to hold senior executives accountable for many years into the future, and even into retirement, for investment and operating decisions made today.
Forfeiture risk
Restricted stock units are subject to forfeiture if:
A recipient retires or terminates employment with the company. The company has indicated its intention not to forfeit restricted stock units of employees who retire at age 65. In other circumstances, where a recipient retires or terminates employment, the company may determine that restricted stock units shall not be forfeited.
During employment or during the period of 24 months after the termination of employment, the recipient, without the consent of the company, engaged in any business that was in competition with the company or otherwise engaged in any activity that was detrimental to the company.
Retirement benefits
Named executive officers participate in the same pension plan, including supplemental pension arrangements outside the registered plan, as other employees, except that B.H. March, P.J. Masschelin and T.G. Scott, participate in the Exxon Mobil Corporation pension plans (both tax-qualified and non-qualified).
Pension plan benefits
The estimated annual benefits that would be payable to each named executive officer of the company upon retirement under the company’s pension plan and the supplemental pension arrangements, or under Exxon Mobil Corporation’s tax-qualified and non-qualified pension plans, and the change in the accrued obligation for each named executive officer of the company in 2011 can be found in the table on page 130.
The current version of the company’s historic 1.6 percent defined benefit plan has been in place since 1976; predecessor plans have been in place since 1919. This version of the plan was available to all employees including executives, with pre-1998 service.
The registered pension plan and supplemental pension arrangements can provide an annual benefit of 1.6 percent of final three year average earnings per each year of service with respect to the named executive officers, with a partial offset for applicable government pension benefits, plus an annual benefit of 1.6 percent of final average bonus earnings times years of service. The supplemental pension arrangements address any portions that cannot be paid from the registered plan due to tax regulations. Any amounts paid to an eligible employee, in this regard, are subject to the employee meeting the terms of the registered pension plan and the criteria of the supplemental pension arrangements, as applicable. Earnings, for the purpose of the registered pension plan, include average base salary during the last 36 consecutive months of service prior to retirement or the highest consecutive three calendar years of earnings in the last 10 years of service prior to retirement. Earnings, for the purpose of the supplemental pension arrangement related to cash bonus and earnings bonus units, include the average annual bonus for the highest three of the last five years prior to retirement for eligible executives, but do not include long-term compensation, including restricted stock units. By limiting inclusion of bonuses only to those granted in the five years prior to retirement, there is a strong motivation for executives to continue to perform at a high level. Annual bonus includes the cash amounts that are paid at grant and the value of any earnings bonus units received, as described starting on page 115. The aggregate maximum settlement value that could be paid for earnings bonus units is included in the employee’s final three year average earnings for the year of grant of such units. The value of the earnings bonus units are expected to pay out subject to forfeiture provisions, and are included for supplemental pension arrangement purposes in the year of grant rather than the year of payment.
An employee may also elect to forego three of the six percent of the company’s matching contributions to the savings plan under one of the options of that plan (except for B.H. March, P.J. Masschelin and T.G. Scott), to receive additional pension value equal to 0.4 percent of the employee’s “final three year average earnings”, multiplied by the employee’s years of service, while foregoing such company contributions.
The remuneration used to determine the payments on retirement to the individuals named in the summary compensation table on page 125 corresponds generally to the salary, bonus and earnings bonus units received in the current year, as described in the previous paragraph. As of February 15, 2012, the number of completed years of service with the company used to determine payments on retirement was 35.8 for R.G. Courtemanche and 27.5 for B.W. Livingston.
B.H. March, P.J. Masschelin and T.G. Scott are not members of the company’s pension plan, but are members of Exxon Mobil Corporation’s pension plans. Under those plans, B.H. March has 31.6 years of credited service, P.J. Masschelin has 34.2 years of credited service and T.G. Scott has 25.7 years of credited service. Their respective pensions are payable in U.S. dollars. Pay for the purpose of the pension calculation is based on final average base salary over the highest 36 consecutive months in the 10 years of service prior to retirement, and the average annual bonus for the three highest grants out of the last five grants prior to retirement.
Savings plan benefits
The company maintains a savings plan into which career employees with more than one year of service may contribute between one and 30 percent of normal earnings. The company provides contributions which vary depending on the amount of employee contributions and on which defined-benefit pension arrangement the employee participates in. All named executive officers are members of the historic 1.6 percent defined-benefit pension plan, and are receiving a six percent company matching contribution, except for B.H. March, P.J. Masschelin and T.G. Scott, who participate in the Exxon Mobil Corporation savings plan and tax-qualified and non-qualified pension plans, which have provisions different from the company plan.
Employee and company contributions can be allocated in any combination to a non-registered (tax-paid) account or a registered (tax-deferred) group retirement savings plan (RRSP) account, subject in the latter case to contribution limits under the Income Tax Act.
Available investment options include cash savings, a money market mutual fund, a suite of four index-based equity or bond mutual funds and company shares. Company matching contributions must be allocated to company shares initially, and remain in that investment for a minimum of 24 months, after which they can be redeemed for other investment options. As of February 15, 2012, employees hold 10,698,804 shares through the company savings plan and the employees are allowed to vote these shares.
During employment, withdrawals are only permitted from employee contributions and investment earnings within the tax-paid account, to a maximum of three withdrawals per year. Assets in the RRSP account, and company contributions to the tax-paid account, may only be withdrawn upon retirement or termination of employment, reinforcing the company’s long-term approach to total compensation. Income tax regulations require RRSPs to be closed by the end of the year in which the individual reaches age 71.
Benchmarking
In addition to the assessment of business performance, individual performance and level of responsibility, the executive resources committee relies on market comparisons to a group of 24 major Canadian companies with revenues in excess of $1 billion a year.
Comparator Companies
The following criteria are used to select comparator companies:
Canadian companies;
Large scope and complexity;
Capital intensive; and
Proven sustainability.
The 24 companies benchmarked are as follows:
Comparator companies for named executive officers
Agrium Inc.
BCE Inc.
BP Canada Energy Company
Canadian Tire Corporation Limited
Chevron Canada Limited
Canadian Natural Resources Limited
Canadian Pacific Railway Limited
Cenovus Energy Inc.
The company is a national employer drawing from a wide range of disciplines. It is important to understand its competitive position relative to a variety of oil and non-oil employers. Compensation trends across industries, based on survey data, are prepared annually by independent external consultant, Towers Watson, with additional analysis and recommendation provided by the company’s internal compensation advisors. Consistent with the executive resources committee’s practice of using well-informed judgment rather than formulae to determine executive compensation, the committee does not target any specific percentile among comparator companies to align compensation. Rather, on a case-by-case basis, depending on the scope of market coverage represented by a particular comparison, total compensation (excluding perquisites) is focused on a range between the mid-point and the upper quartile of comparable employers, reflecting the company’s emphasis on quality management. This approach applies to salaries and the annual incentive program that includes bonus and restricted stock units.
As a secondary source of data, the company also considers a comparison with Exxon Mobil Corporation, when it determines the annual bonus program. For the restricted stock unit program, the executive resources committee also reviews a summary of data of the comparator companies provided by the same external consultant above in order to assist in assessing total value of long-term compensation grants.
This overall approach provides the company with the ability to:
better respond to changing business conditions;
manage salaries based on a career orientation;
minimize potential for automatic increasing of salaries, which could occur with an inflexible and narrow target among benchmarked companies; and
differentiate salaries based on performance and experience levels among executives.
Analytical tools – Compensation summary sheets
A compensation summary sheet is a matrix used by the executive resources committee that shows the individual elements and total compensation for each senior executive. The sheets are used to understand how decisions on each individual element of compensation affect total compensation for each senior executive. The committee considers both current compensation recommendations and prior compensation results in its final determination.
The elements of the Exxon Mobil Corporation compensation program, including salary and annual bonus and equity (long-term) compensation considerations for B.H. March, P.J. Masschelin and T.G. Scott, are similar to those of the company. The data used for long-term compensation determination for B.H. March, P.J. Masschelin and T.G. Scott is as described above, as they received company restricted stock units in 2011. The executive resources committee reviews and approves recommendations for each named executive officer prior to implementation. B.H. March’s compensation determination is described in more detail on page 123.
2011 named executive officer compensation assessment
When determining the annual compensation for the named executive officers, the executive resources committee has reflected on the following business performance result indicators in its determination of 2011 salary and incentive compensation.
Business performance results for consideration
The operating and financial performance measurements listed below and the company’s continued maintenance of sound business controls and a strong corporate governance environment formed the basis for the salary and incentive award decisions made by the executive resources committee in 2011. The executive resources committee considered the results over multiple years, in recognition of the long-term nature of the company’s business.
Strong results in the areas of safety, health and environment.
Satisfactory management of risk through effective business controls, as confirmed by independent audit.
Net income of approximately $3.4 billion, up by 53 percent.
Total shareholder return of approximately 13 percent. Ten-year annual average of approximately 13 percent.
Industry-leading return on average capital employed of approximately 25 percent, with an average of approximately 28 percent since the beginning of 2000.
Over 80 percent of capital investment on advancement of long term strategic initiatives, including the Kearl and Nabiye projects.
$373 million distributed to shareholders as dividends in 2011.
Approximately $59 million distributed to shareholders through the share purchase program in 2011 and approximately $15,580 million since 1995.
Performance assessment considerations
The above results form the context in which the committee assesses the individual performance of each senior executive, taking into account experience and level of responsibility.
Annually, the chairman, president and chief executive officer reviews the performance of the senior executives in achieving business results and individual development needs.
The same long-term key business strategies noted on page 112 and results noted above are key elements in the assessment of the chairman, president and chief executive officer’s performance by the executive resources committee.
The performance of all named executive officers is also assessed by the board of directors throughout the year during specific business reviews and board committee meetings that provide reports on strategy development; operating and financial results; safety, health, and environmental results; business controls; and other areas pertinent to the general performance of the company.
The executive resources committee does not use quantitative targets or formulae to assess executive performance or determine compensation. The executive resources committee does not assign weights to the factors considered. Formula-based performance assessments and compensation typically require emphasis on two or three business metrics. For the company to be an industry leader and effectively manage the technical complexity and integrated scope of its operations, most senior executives must advance multiple strategies and objectives in parallel, versus emphasizing one or two at the expense of others that require equal attention.
Senior executives and officers are expected to perform at the highest level or they are replaced. If it is determined that another executive is ready and would make a stronger contribution than one of the current incumbents, a replacement plan is implemented.
2011 chief executive officer compensation assessment
B.H. March was appointed chairman, president and chief executive officer of the company on April 1, 2008. Mr. March is a 32-year veteran of ExxonMobil, including service with heritage Mobil Corporation before the merger with Exxon Corporation on November 30, 1999. Mr. March has extensive operating and management experience in the oil and gas business, including assignments in multiple locations in the United States, as well as experience working in London and Brussels. His level of salary was determined by the executive resources committee based on his individual performance and to align with that of his peers in ExxonMobil. It was also the objective of the executive resources committee to ensure appropriate internal alignment with senior management in the company. The committee also approved a salary increase of $40,000 U.S. to $570,000 U.S., effective January 1, 2012.
Mr. March’s 2011 annual bonus was based on his performance as assessed by the executive resources committee since his appointment to the position of chairman, president and chief executive officer. His long-term incentive award was paid in the form of company restricted stock units, not Exxon Mobil Corporation restricted stock, to reinforce alignment of his interests with that of the company’s shareholders. His company restricted stock units are subject to vesting periods longer than those applied by most companies conducting business in Canada. Fifty percent of the restricted stock units awarded vest in five years and the other 50 percent vest on the later of 10 years from the date of grant or the date of retirement. The purpose of these long vesting periods is to reinforce the long investment lead times in the business and to link a substantial portion of Mr. March’s shareholding net worth to the performance of the company. During these vesting periods, the awards are subject to risk of forfeiture based on detrimental activity, or if Mr. March should leave the company before normal retirement.
The executive resources committee has determined that the overall compensation of Mr. March is appropriate based on the company’s financial and operating performance and its assessment of his effectiveness in leading the organization.
Key factors considered by the committee in determining his overall compensation level include:
safety metrics and environmental performance;
continuing progress on advancing long term strategic interests such as the Kearl and Nabiye projects;
financial results;
government relations;
productivity;
leadership;
cost effectiveness; and
asset management.
Taking all factors into consideration, the committee’s decisions on compensation of the chief executive officer reflect judgment, rather than the application of formulae or targets. The higher level of pay for Mr. March, compared to the other named executive officers, reflects his greater level of responsibility, including his ultimate responsibility for the performance of the company, and oversight of the other senior executives.
Pay awarded to other named executive officers
Within the context of the compensation program structure and performance assessment processes described above, the value of 2011 incentive awards and salary adjustments align with:
performance of the company;
individual performance;
long-term strategic plan of the business; and
annual compensation of comparator companies.
Taking all factors into consideration, the executive resources committee’s decisions on pay awarded to other named executive officers reflect judgment, rather than the application of formulae or targets. The executive resources committee approved the individual elements of compensation and the total compensation as shown in the summary compensation table on page 125.
Independent consultant
In fulfilling its responsibilities during 2011, the executive resources committee did not retain an independent consultant or advisor in determining compensation for any of the company’s officers or any other senior executives. The company’s management retained Towers Watson, an independent consultant, to provide an assessment of competitive compensation and market data for all salaried levels of employees of the company. While providing this data, Towers Watson was not retained to provide individual compensation recommendations or advice for the company or committee in determining the compensation of the chief executive officer or long-term incentive compensation levels for senior executives.
Performance graph
The following graph shows changes over the past 10 years in the value of $100 invested in (i) Imperial Oil Limited common shares, (ii) the S&P/TSX Composite Index, and (iii) the S&P/TSX Equity Energy Index. The S&P/TSX Equity Energy Index is made up of share performance data for 64 oil and gas companies including integrated oil companies, oil and gas producers and oil and gas service companies.
The year-end values in the graph represent appreciation in share price and the value of dividends paid and reinvested. The calculations exclude trading commissions and taxes. Total shareholder returns from each investment, whether measured in dollars or percent, can be calculated from the year-end investment values shown beneath the graph.
During the past 10 years, the company’s cumulative total shareholder return was approximately 344 percent, for an average annual return of approximately 13 percent. During that same 10-year period, while the average annual return was approximately 13 percent, the company’s compensation (which compensation excluded the compensatory change in pension value) of its named executive officers, by comparison, decreased by approximately two percent on an average annual basis.
Summary compensation table
The following table shows the compensation for the chairman, president and chief executive officer; the senior vice-president, finance and administration, and treasurer and the three other most highly compensated executive officers of the company who were serving as at the end of 2011. This information includes the Canadian dollar value of base salaries, cash bonus awards and units of other long-term incentive compensation and certain other compensation.
Name and principal
position at the end
of 2011
Salary
Non-equity incentive
plan compensation
(f)
(g)
(h)
incentive
plans
Long-
term
(e)
524,223
2,192,320
362,604
438,447
1,308,434
830,876
5,656,904
525,249
1,731,648
290,638
276,430
1,050,438
(18,091)
3,856,312
553,870
1,706,020
183,862
649,756
881,422
3,974,930
P.J. Masschelin (a)
(since May 1, 2010)
414,763
994,500
181,401
262,248
672,897
578,196
3,104,005
280,133
768,792
166,947
165,826
593,858
(112,537)
1,863,019
T. Glenn Scott (a)
(since August 1, 2010)
420,862
185,357
225,480
381,730
441,323
2,649,252
175,727
729,606
148,821
143,257
258,001
177,284
1,632,696
R.G. Courtemanche
(since May 1, 2011)
B.W. Livingston
421,167
189,600
249,150
567,700
73,724
2,495,841
411,417
839,700
146,439
171,875
317,800
72,042
1,959,273
402,500
886,500
103,278
(259,300)
78,685
1,211,663
Footnotes to the Summary compensation table for named executive officers on the preceding page
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Outstanding share-based awards and option-based awards for named executive officers
The following table sets forth all share-based and option-based awards outstanding as at December 31, 2011 for each of the named executive officers of the company.
in-the-money
shares or
units of
shares that
of share-based awards
that have not
payout value of
vested share-based awards
not paid out or
distributed
P.J. Masschelin (b)
T.G. Scott(c)
(from May 1, 2011)
Incentive plan awards for named executive officers – Value vested or earned during the year
The following table sets forth the value of the incentive plan awards that vested for each named executive officer of the company for the year.
Share-based awards – Value
vested during the year
Non-equity incentive plancompensation – Value
earned during the year
Proceeds realized in 2011 from compensation awards granted in prior years - restricted stock units, stock options, incentive share units and earnings bonus units
Proceeds from
exercise of
exercise of stockoptions
incentive share
Receipt of proceeds
of earnings bonus
Equity compensation plan information
The following table provides information on the common shares of the company that may be issued as of the end of 2011 pursuant to compensation plans of the company.
Number of securities to
be issued upon exercise
of outstanding options,
warrants and rights
Weighted average
exercise price of
outstanding
options, warrants
and rights
Number of securities
remaining available for future
issuance under equity
compensation plans
(excluding securities
reflected in the first column)
Equity compensation plans approved by security holders (a)
Equity compensation plans not approved by security holders (b)
7,548,471
5,717,949
Pension plan benefits table
of years
credited
service
(as ofDecember 31,2011)
Annual benefits
payable
Opening
present
defined
benefit
obligation
Compensatory
change
Non-
compensatory
Closing
benefitobligation
At year
end
At age
T.G. Scott(a)
R.G. Courtemanche (b)
B.W. Livingston (b)
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Details of former long-term incentive compensation plans
The following describes forms of long-term incentive compensation formerly used by the company. While incentive share units and stock options are no longer granted, incentive share units and stock options formerly granted continue to remain outstanding and are referenced in the foregoing tables.
Incentive share units
The company’s incentive share units give the recipient a right to receive cash equal to the amount by which the market price of the company’s common shares at the time of exercise exceeds the issue price of the units. These units were granted prior to 2002. The issue price of the units granted to executives was the closing price of the company’s shares on the Toronto Stock Exchange on the grant date. Incentive share units are eligible for exercise up to 10 years from issuance. The last grant expired in 2011. No executive officer or director held incentive share units as at December 31, 2011.
Stock option plan
Under the stock option plan adopted by the company in April 2002, a total of 9,630,600 options, on a post share split basis, were granted to select key employees on April 30, 2002 for the purchase of the company’s common shares at an exercise price of $15.50 per share on a post share split basis. All of the options are exercisable. Any unexercised options expire on April 29, 2012. As of February 15, 2012, there have been 5,169,690 common shares issued upon exercise of stock options and 1,944,834 common shares are issuable upon future exercise of stock options. The common shares that were issued and those that may be issued in the future represent about 0.84 percent of the company’s currently outstanding common shares. The company’s directors, officers and vice-presidents as a group hold 0.31 percent of the unexercised stock options.
The maximum number of common shares that any one person may receive from the exercise of stock options is 51,000 common shares, which is about 0.01 percent of the currently outstanding common shares. Stock options may be exercised only during employment with the company except in the event of death, disability or retirement. Also, stock options may be forfeited if the company believes that the employee intends to terminate employment or if during employment or during the period of 24 months after the termination of employment the employee, without the consent of the company, engaged in any business that was in competition with the company or otherwise engaged in any activity that was detrimental to the company. The company may determine that stock options will not be forfeited after the cessation of employment. Stock options cannot be assigned except in the case of death.
The company may amend or terminate the incentive stock option plan as it, in its sole discretion, determines appropriate. No such amendment or termination can be made to impair any rights of stock option holders under the incentive stock option plan unless the stock option holder consents, except in the event of (a) any adjustments to the share capital of the company or (b) a take-over bid, amalgamation, combination, merger or other reorganization, sale or lease of assets, or any liquidation, dissolution, or winding-up, involving the company. Appropriate adjustments may be made by the company to: (i) the number of common shares that may be acquired on the exercise of outstanding stock options; (ii) the exercise price of outstanding stock options; or (iii) the class of shares that may be acquired in place of common shares on the exercise of outstanding stock options in order to preserve proportionately the rights of the stock option holders and give proper effect to the event.
The effective date of this management proxy circular is February 15, 2012.
To the knowledge of the directors and executive officers of the company, the only shareholder who, as of February 15, 2012, owned beneficially, or exercised control or direction over, directly or indirectly, more than 10 percent of the outstanding common shares of the company is Exxon Mobil Corporation, 5959 Las Colinas Boulevard, Irving, Texas 75039-2298, which owns beneficially 589,928,303 common shares, representing 69.6 percent of the outstanding voting shares of the company. As a consequence, the company is a “controlled company” for purposes of the listing standards of the NYSE Amex LLC.
On June 25, 2010, the company implemented a 12-month “normal course” share purchase program under which it purchased 1,028,244 of its outstanding shares between June 25, 2010 and June 24, 2011. On June 25, 2011, a 12-month share purchase program was implemented under which the company may purchase up to 42,385,463 of its outstanding shares, less any shares purchased by the employee savings plan and company pension fund. Exxon Mobil Corporation maintained its ownership at 69.6 percent. In 2011, such share purchases cost $59.5 million, none of which was received by Exxon Mobil Corporation.
The amounts of purchases and sales by the company and its subsidiaries for other transactions in 2011 with Exxon Mobil Corporation and affiliates of Exxon Mobil Corporation were $3,853 million and $2,818 million, respectively. These transactions were conducted on terms as favourable as they would have been with unrelated parties, and primarily consisted of the purchase and sale of crude oil, natural gas, petroleum and chemical products, as well as technical, engineering and research and development services. Transactions with Exxon Mobil Corporation also included amounts paid and received in connection with the company’s participation in a number of upstream activities conducted jointly in Canada. In addition, the company has existing agreements with affiliates of Exxon Mobil Corporation to provide computer and customer support services to the company and to share common business and operational support services to allow the companies to consolidate duplicate work and systems. The company has a contractual agreement with an affiliate of Exxon Mobil Corporation in Canada to operate the Western Canada production properties owned by ExxonMobil. There are no asset ownership changes. The company and that affiliate also have a contractual agreement to provide for equal participation in new upstream opportunities. During 2007, the company entered into agreements with Exxon Mobil Corporation and one of its affiliated companies that provide for the delivery of management, business and technical services to Syncrude Canada Ltd. by ExxonMobil.
As at December 31, 2011, the company had an outstanding loan of $820 million under an existing agreement with Exxon Mobil Corporation that provides for a long term, variable rate loan from ExxonMobil to the company of $5 billion (Canadian) at market interest rates. The agreement is effective until July 31, 2020, cancellable if ExxonMobil provides at least 370 days advance written notice.
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PricewaterhouseCoopers LLP (‘PwC’) have been the auditors of the company for more than five years and are located in Calgary, Alberta. PwC is a participating audit firm with the Canadian Public Accountability Board.
The aggregate fees of PwC for professional services rendered for the audit of the company’s financial statements and other services for the fiscal years ended December 31, 2011 and December 31, 2010 were as follows:
Audit fees
Audit-related fees
Tax fees
All other fees
Total fees
Audit fees included the audit of the company’s annual financial statements, internal control over financial reporting, and a review of the first three quarterly financial statements in 2011. In 2011, fees also included a review of the implementation of a new information system.
Audit-related fees included other assurance services including the audit of the company’s retirement plan and royalty statement audits for oil and gas producing entities.
The company did not engage the auditor for any other services.
The board, on the recommendation of the audit committee, recommends the external auditor be appointed by the shareholders, fixes its remuneration and oversees its work. The audit committee also approves the proposed current year audit program of the external auditor, assesses the results of the program after the end of the program period and approves in advance any non-audit services to be performed by the external auditor after considering the effect of such services on their independence.
All of the services rendered by the auditor to the company were approved by the audit committee.
The audit committee continually discusses with PwC their independence from the company and from management. PwC has confirmed that they are independent with respect to the company within the meaning of the Rules of Professional Conduct of the Institute of Chartered Accountants of Alberta and the rules of the U.S. Securities and Exchange Commission. The company has concluded that the auditors’ independence has been maintained.
The board has adopted a written code of ethics and business conduct (“Code”) which can be found on the company’s website at www.imperialoil.ca.
The Code is applicable to each of the company’s directors, officers and employees, and consists of the ethics policy, the conflicts of interest policy, the corporate assets policy, the directorships policy and the procedures and open door communication. Under the company’s procedures and open door communication, employees are encouraged and expected to refer suspected violations of the law, company policy or internal controls procedures to their supervisors. Suspected violations involving a director or executive officer, as well as any concern regarding questionable accounting or auditing matters are to be referred directly to the general auditor. The audit committee initially reviews all issues involving directors or executive officers, and then refers all issues to the board of directors. In the alternative, employees may also address concerns to individual nonemployee directors or to nonemployee directors as a group. In addition, the directors of the
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company must comply with the conflict of interest provisions of the Canada Business Corporations Act, as well as the relevant securities regulatory instruments, in order to ensure that the directors exercise independent judgment in considering transactions and agreements in respect of which such director has a material interest.
Management provides the board of directors with a review of corporate ethics and conflicts of interest on an annual basis. Directors, officers and employees review the company’s standards of business conduct (which includes the Code) on an annual basis, with employees in positions where there is a higher risk of exposure to ethical or conflict of interest situations being required to sign a declaration card confirming that they have read and are familiar with the standards of business conduct. In addition, every four years a business practices review is conducted in which managers review the standards of business conduct with employees in their respective work units.
The board, through its audit committee, examines the effectiveness of the company’s internal control processes and management information systems. The board consults with the external auditor, the internal auditor and the management of the company to ensure the integrity of the systems.
There are a number of structures and processes in place to facilitate the functioning of the board independently of management. The board has a majority of independent directors. Each committee is chaired by a different independent director and all of the five independent directors are members of each committee. The audit committee is composed entirely of independent directors. Each other committee (except the contributions committee) is composed entirely of the independent directors and R.C. Olsen, who is an employee of ExxonMobil Production Company, a division of Exxon Mobil Corporation, and is, therefore, independent of the company’s management. The agendas of each of the board and its committees are not set by management alone, but by the board as a whole and by each committee. A significant number of agenda items are mandatory and recurring. Board meetings are scheduled at least one full year in advance. Any director may call a meeting of the board or a meeting of a committee of which the director is a member. There is a board-prescribed flow of financial, operating and other corporate information to all directors.
The independent directors conduct executive sessions in the absence of members of management. These meetings are chaired by S.D. Whittaker, the independent director designated by the independent directors to chair and lead these discussions. Eight executive sessions were held in 2011. There has been no material change reports filed in the past 12 months pertaining to conduct of a director or executive officer that constitutes a departure from the Code.
The company’s delegation of authority guide provides that certain matters of the company are reviewed by functional contacts within ExxonMobil. The company’s employees are regularly reminded that they are expected to act in the best interests of the company, and are reminded of their obligation to identify any instances where the company’s general interest may not be consistent with ExxonMobil’s priorities. If such situations ever occurred, employees are expected to escalate such issues with successive levels of the company’s management. Final resolution of any such issues is made by the company’s chairman, president and chief executive officer.
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The structure, process and responsibilities of the board of directors of the corporation shall include the following items and matters:
1. Responsibility
The directors shall be responsible for the stewardship of the corporation.
2. Duty of care
The directors, in exercising their powers and discharging their duties, shall:
3. Stewardship process
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4. Range of items to be considered by the board
Organization/legal
fixing of the number of directors
director appointments to fill interim vacancies
director slate for election by the shareholders
officer appointments
board governance processes
by-laws and administrative resolutions
changes in fundamental structure of the corporation
shareholder meeting notice and materials
nonemployee director compensation
policies adopted by the board
investigations and litigation of a material nature
equity or debt financing
dividend declarations
financial statements and the related management discussion and analysis, annual and quarterly
status of the corporation’s retirement plan and employee savings plan
Strategic/investment/operating plans/performance
near-term and long-range outlooks
capital, lease, loan and contributions budgets annually
budget additions over $100 million individually
quarterly updates of actual and projected capital expenditures
capital expenditures or dispositions in excess of $100 million individually
entering into any venture that is outside of the corporation’s existing businesses
financial and operating results quarterly
Canadian and world economic outlooks
regional socio-economic reviews
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5. Information to be received by the board
Information manual (Directors’ Digest)
articles of incorporation, by-laws and administrative resolutions
corporate policies
corporate data
board and management processes
financial and operating report
organization outline
Social/political/economic environment
public issues updates
economic outlook
external communications packages
Major announcements
press releases
speeches by management
organization changes
Communications to shareholders
Other significant submissions, studies and reports
6. Unrelated and independent directors
(i) accept any consulting, advisory, or other compensatory fee from the issuer; or
(ii) be an affiliated person of the issuer or any subsidiary thereof.
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7. Independent legal or other advice
The board and, with the approval of the board, any director, may engage independent counsel and other advisors at the expense of the corporation.
8. Meetings of the unrelated and independent directors in the absence of members of management
9. Selection and tenure of directors
The guidelines for selection and tenure of directors shall be as follows:
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Audit committee financial expert
In addition, the nominations and corporate governance committee may consider the following additional factors:
possessing expertise in any of the following areas: finance, law, science, marketing, administration, government affairs, social/political environment or community and civic affairs; and
providing diversity of viewpoint, individual competencies in business, other areas of endeavour in contributing to the collective experience of the directors, age, gender or regional association.
The nominations and corporate governance committee shall then assess what work experience and other expertise each existing director possesses. The nominations and corporate governance committee shall identify individuals qualified to become new board members and recommend to the board the new director nominees. In making its recommendations, the nominations and corporate governance committee shall consider the work experience and other expertise that the board considers each existing director to possess and which each new nominee will bring. The nominations and corporate governance committee may also consider the additional factors noted above and any other factors which it believes to be relevant.
A candidate may be nominated for directorship after consideration has been given as to his or her degree of compatibility with the following criteria, i.e., as to whether he or she:
will not adversely affect the requirements with respect to citizenship and residency for the directors imposed by the Canada Business Corporations Act;
possesses the ability to contribute to the broad range of issues with which the directors and any one or all of the committees of directors must deal;
is able to devote the necessary amount of time to prepare for and attend all meetings of the directors and committees of directors, and to keep abreast of significant corporate developments;
is free of any present or apparent potential legal impediment or conflict of interest, such as:
serving as an employee or principal of any organization presently providing a significant level of service to the corporation or which might so provide to the corporation, for example, institutions engaged in commercial banking, underwriting, law, management consulting, insurance, or trust companies; or of any substantial customer or supplier of the corporation;
serving as an employee or director of a competitor of the corporation, such as petroleum or chemical businesses, or of a significant competitor of corporations represented by a director of this corporation;
serving as the chief executive officer or a top administrator of an organization that has the chief executive officer or a top administrator of this corporation serving as director;
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is expected to remain qualified to serve for a minimum of five years;
will not, at the time that he or she stands for election or appointment, have attained the age of 72;
is, or will become within a period of five years of becoming a director, the beneficial owner, directly or indirectly, of not less than 15000 common shares, deferred share units or restricted stock units of the corporation.
An incumbent director shall be supported for re-nomination as long as he or she:
does not suffer from any disability that would prevent the effective discharge of his or her responsibilities as a director;
makes a positive contribution to the effective performance of the directors;
regularly attends directors’ and committee meetings;
has not made a change with respect to principal position or thrust of involvement or regional association that would significantly detract from his or her value as a director of the corporation;
is not otherwise, to a significant degree, incompatible with the criteria established for use in the selection process;
in a situation where it is known that a director will become incompatible with the criteria established for use in the selection process within a three-month period of election, such as retirement from principal position at age 65, this information would be included in the management proxy circular, and where possible, information regarding the proposed replacement would also be included;
will not, at the time that he or she stands for re-election, have attained the age of 72; however, under exceptional circumstances, at the request of the chief executive officer, the nominations and corporate governance committee may continue to support the nomination.
An incumbent director will resign in the event that he or she:
experiences a change in circumstances such as a change in his or her principal occupation, but not merely a change in geographic location;
displays a change in the exercise of his or her powers and in the discharge of duties that, in the opinion of at least 75 percent of the directors, is incompatible with the duty of care of a director as defined in the Canada Business Corporations Act;
has made a change in citizenship or residency that will adversely affect the requirements for directors with respect to those areas imposed by the Canada Business Corporations Act;
develops a conflict of interest, such as
assuming a position as an employee or principal with any organization providing a significant level of service to the corporation, for example, institutions engaged in commercial banking, underwriting, law, management consulting, insurance, or trust companies; or with any substantial customer or supplier of the corporation;
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assuming a position as an employee or director of any competitor of the corporation, such as petroleum or chemical businesses, or of a competitor of corporations represented by a director of this corporation;
assuming the position of chief executive officer or a top administrator of an organization that has the chief executive officer or a top administrator of this corporation serving as a director;
becomes unable to devote the necessary amount of time to prepare for and regularly attend meetings of the directors and committees of directors, and to keep abreast of significant corporate developments,
and the nominations and corporate governance committee will make a recommendation to the board as to whether to accept or reject such resignation.
10. Chairman and chief executive officer
The chairman and chief executive officer shall
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The structure, process and responsibilities of the audit committee shall include the following items and matters:
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The structure, process and responsibilities of the environment, health and safety committee shall include the following items and matters:
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The structure, process and responsibilities of the executive resources committee shall include the following items and matters:
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The structure, process and responsibilities of the nominations and corporate governance committee shall include the following items and matters:
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The structure, process and responsibilities of the contributions and community investment committee shall include the following items and matters:
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