Item 1. Business.
Imperial Oil Limited was incorporated under the laws of Canada in 1880 and was continued under the Canada Business Corporations Act (the “CBCA”) by certificate of continuance dated April 24, 1978. The head and principal office of the company is located at 237 Fourth Avenue S.W. Calgary, Alberta, Canada T2P 3M9; telephone 1-800-567-3776. Exxon Mobil Corporation owns approximately 69.6 percent of the outstanding shares of the company with the remaining shares being publicly held, with the majority of shareholders having Canadian addresses of record. 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 one of the largest producers of crude oil and natural gas liquids and a major producer of natural gas, and the largest refiner and marketer of petroleum products. It is also a major supplier of petrochemicals.
Financial Information by Operating Segments (under U.S. GAAP)
The company’s operations are conducted in three main segments: natural resources (“upstream”), petroleum products (“downstream”) and chemicals. Natural resources operations include the exploration for, and production of, conventional crude oil, natural gas, upgraded crude oil and heavy oil. Petroleum products operations consist of the transportation, refining and blending of crude oil and refined products and the distribution and marketing thereof. The chemicals operations consist of the manufacturing and marketing of various petrochemicals.
Natural Resources
Petroleum and Natural Gas Production
The company’s average daily production of crude oil and natural gas liquids during the five years ended December 31, 2006, was as follows:
(1)
Gross production of crude oil is the company’s share of production from conventional wells, Syncrude oil sands and Cold Lake heavy oil, and gross production of natural gas liquids is the amount derived from processing the company’s share of production of natural gas (excluding purchased gas), in each case before deduction of the mineral owners’ or governments’ share or both.
(2)
Net production is gross production less the mineral owners’ or governments’ share or both.
(3)
Heavy oil typically is represented by crude oils with a viscosity of greater than 10,000 cP and recovered through enhanced thermal operations. The company’s heavy oil production volumes are from the Cold Lake production operations.
(4)
Oil sands are a semi-solid material composed of bitumen, sand, water and clays which are recovered through surface mining methods. Imperial’s oil sands production volumes are the company’s share of production volumes in the Syncrude joint venture.
In 2003, conventional production declined mainly due to natural decline of the company’s conventional oil fields. In 2004, conventional production increased primarily due to increased natural gas liquids production from the Wizard Lake gas cap. In 2005 and 2006 conventional production declined mainly due to the natural decline of the company’s conventional fields. In 2003, Cold Lake net production increased as a result of a full year of production of phases 11 to 13, which was offset in part by the timing of steaming cycles and higher royalties. Syncrude production decreased in 2003 due to extended maintenance of upgrading facilities. In 2004, Cold Lake production declined due to the timing of steaming cycles and higher royalty, and Syncrude production increased due to fewer disruptions in upgrading operations than in 2003. In 2005, Cold Lake production increased due to the timing of steaming cycles and increased volumes from the ongoing development drilling program, and Syncrude production declined primarily due to greater maintenance downtime for upgrading facilities. In 2006, Cold Lake production increased due to timing of steam cycles and production from the ongoing development drilling program and Syncrude production increased due to lower maintenance activities and the start-up of expanded upgrading facilities.
The company’s average daily production and sales of natural gas during the five years ended December 31, 2006 are set forth below. All gas volumes in this report are calculated at a pressure base of, in the case of cubic metres, 101.325 kilopascals absolute at 15 degrees Celsius and, in the case of cubic feet, 14.73 pounds per square inch absolute at 60 degrees Fahrenheit.
(1)
Sales are sales of the company’s share of production (before deduction of the mineral owners’ and/or governments’ share) and sales of gas purchased, processed and/or resold.
(2)
Gross production of natural gas is the company’s share of production (excluding purchases) before deducting the shares of mineral owners or governments or both. Net production excludes those shares. Production data include amounts used for internal consumption with the exception of amounts reinjected.
In 2003, natural gas production decreased primarily due to the depletion of gas caps in Alberta and increased maintenance activity at gas processing facilities. In 2004 natural gas production increased primarily due to increased production from the Wizard Lake gas cap. In 2005, gross natural gas production increased due to increased production from the Nisku and Wizard Lake gas caps and the Medicine Hat gas field. In 2006, gas production decreased primarily due to natural decline.
Most of the company’s natural gas sales are made under short term contracts.
The company’s average sales price and production costs for crude oil and natural gas liquids and natural gas for the five years ended December 31, 2006, were as follows:
(1)
Average production costs per unit of production do not include depreciation and depletion of capitalized acquisition, exploration and development costs. Administrative expenses are included. Average production (lifting) costs per unit of net production were computed after converting gas production into equivalent units of oil on the basis of relative energy content.
(2)
Unit production costs are sometimes referred to as lifting costs.
Canadian crude oil prices are mainly determined by international crude oil markets which are volatile.
Canadian natural gas prices are determined by North American gas markets and are also volatile. Natural gas prices throughout North America increased in the second half of 2005 due to supply disruptions from hurricane damage to facilities in the U.S. Gulf Coast.
In 2003 and 2005, average unit production costs increased mainly due to higher costs of purchased natural gas at Cold Lake. In 2004, average unit production costs decreased mainly due to higher production from the Wizard Lake gas cap. In 2006, average production costs increased due to lower gas production and higher liquids royalties resulting in lower net liquids production. Liquids royalties were higher in the year due to increased realizations for Cold Lake production.
The company has interests in a large number of facilities related to the production of crude oil and natural gas. Among these facilities are 22 plants that process natural gas to produce marketable gas and recover natural gas liquids or sulphur. The company is the principal owner and operator of 11 of the plants.
The company’s production of conventional crude oil, Cold Lake heavy oil and natural gas is derived from wells located exclusively in Canada. The total number of producing wells in which the company had interests at
December 31, 2006, is set forth in the following table. The statistics in the table are determined in part from information received from other operators.
(1)
Gross wells are wells in which the company owns a working interest.
(2)
Net wells are the sum of the fractional working interests owned by the company in gross wells, rounded to the nearest whole number.
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 approximately 55 percent of the company’s net production of conventional crude oil (approximately 61 percent of gross production). In 2006, net production of crude oil and natural gas liquids was about 2,000 cubic metres (12,700 barrels) per day and gross production was about 3,000 cubic metres (18,900 barrels) per day. 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. Under a shipping agreement, the company pays for the construction, operating and other costs of the 870 kilometre (540 mile) pipeline which transports the crude oil and natural gas liquids from the project. In 2006, those costs were about $33 million.
Most of the 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. In some cases, however, additional oil can be recovered by using various methods of enhanced recovery. The company’s largest enhanced recovery projects are located at the West Pembina oil field.
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.
Cold Lake
The company holds about 78,000 hectares (192,000 acres) of heavy oil leases near Cold Lake, Alberta. To develop the technology necessary to produce this oil commercially, the company has conducted experimental pilot operations since 1964 to recover the heavy oil from wells by means of new drilling and production techniques including steam injection. Research at, and operation of, the Cold Lake pilots is continuing.
In late 1983, the company commenced the development, in phases, of its heavy oil resources at Cold Lake. During 2006, average net production at Cold Lake was about 20,100 cubic metres (126,700 barrels) per day and gross production was about 24,100 cubic metres (151,800 barrels) per day.
To maintain production at Cold Lake, capital expenditures for additional production wells and associated facilities will be required periodically. In 2006, the company spent $213 million and executed a development drilling program of 174 wells on existing phases. In 2007, a development drilling program of more than 100 wells is planned within the currently approved development area to add productive capacity from undeveloped areas of existing Cold Lake phases. In addition, opportunities are also being evaluated to improve utilization of the existing infrastructure.
In 2004, the company received regulatory approval for further expansion of its operations at Cold Lake. Production began in 2006 from part of the approved expansion, the development of which is expected to cost about $400 million and is expected to have gross production of about 4,800 cubic metres (30,000 barrels) per day by the end of the decade. Development plans for the remainder of the approved expansion are being examined to reduce development costs through increased integration with existing infrastructure. Most of the production from Cold Lake is sold to refineries in the northern United States. The remainder of the Cold Lake production is shipped to certain of the company’s refineries and to a heavy oil upgrader in Lloydminster, Saskatchewan.
The Province of Alberta, in its capacity as lessor of the Cold Lake heavy oil leases, is entitled to a royalty on production from the Cold Lake production project. The royalty agreement which applied through the end of 1999, provided for a royalty calculated at the greater of five percent of gross revenue or 30 percent of an amount based on revenue net of operating and capital costs. It also provided for a royalty waiver on equity natural gas produced in Alberta and deemed to be consumed in generating steam at the company’s Cold Lake operations. In late 2000, the company entered into an agreement with the Province of Alberta, effective January 1, 2000, on a transitional royalty arrangement that will apply to all of the company’s current and proposed operations at Cold Lake until the end of 2007, at which time the generic Alberta regulations for heavy oil royalties will apply. The post-transition royalty regulation, which will become effective in 2008, provides for a royalty calculated at the greater of one
percent of gross revenue or 25 percent of an amount based on revenue net of operating and capital costs, but with no gas royalty waiver. The transition agreement, which is effective between 2000 and 2007 inclusive, makes provision for the differences between the two royalty regimes (higher bitumen royalties with gas royalty waiver vs. lower bitumen royalties and no gas royalty waiver). This transition will bring all phases of the company’s Cold Lake operations under one royalty agreement with common terms and conditions. The transition is not expected to materially change the amount of royalties that the company would have otherwise paid under the pre-existing royalty arrangements. The effective royalty on gross production was 17 percent in 2006, 11 percent in 2005 and 2004, 10 percent in 2003 and five percent in 2002.
Other Heavy Oil Activity
The company has interests in other heavy oil leases in the Athabasca and Peace River areas of northern Alberta. Evaluation wells completed on these leased areas established the presence of heavy oil. The company continues to evaluate these leases to determine their potential for future development.
The company holds varying interests in heavy oil lands totalling about 68,000 leased net hectares (168,000 net acres) in the Athabasca area. The company, as part of an industry consortium and several joint ventures, has been involved in recovery research and pilot studies and in evaluating the quality and extent of the heavy oil deposit.
Syncrude Mining 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 (see map), exploits a portion of the Athabasca Oil Sands Deposit. The location is readily accessible by public road. The produced synthetic crude oil is shipped from the Syncrude site to Edmonton, Alberta by Alberta Oil Sands Pipeline Ltd. Since startup in 1978, Syncrude has produced about 1.7 billion barrels of synthetic crude oil.
Syncrude has an operating license issued by the Province of Alberta which is effective until 2035. This license permits Syncrude to mine oil sands and produce synthetic crude oil from approved development areas on oil sands leases. Syncrude holds eight oil sands leases covering about 100,500 hectares (248,300 acres) in the Athabasca Oil Sands Deposit. Issued by the Province of Alberta, the leases are automatically renewable as long as oil sands operations are ongoing or the leases are part of an approved development plan. Syncrude leases 10, 12, 17, 22 and 34 (containing proven reserves) and leases 29, 30 and 31 (containing no proven reserves) are included within
a development plan approved by the Province of Alberta. There were no known previous commercial operations on these leases prior to the start-up of operations in 1978.
As of January 1, 2002, the greater of 25 percent deemed net profit royalty or one percent gross royalty applies to all Syncrude production after the deduction of new capital expenditures.
The Government of Canada had issued an order that expired at the end of 2003 which provided for the remission of any federal income tax otherwise payable by the participants as the result of the non-deductibility from the income of the participants of amounts receivable by the Province of Alberta as a royalty or otherwise with respect to Syncrude. That remission order excluded royalty payable on production for the Aurora project.
Operations at Syncrude involve three main processes: open pit mining, extraction of crude bitumen and upgrading of crude bitumen into synthetic crude oil. The Base mine (lease 17) has now been mined out and only remnants are being removed using trucks and shovels. In the North mine (leases 17 and 22) and in the Aurora mine (leases 10, 12 and 34), truck, shovel and hydrotransport systems are used. The extraction facilities, which separate crude bitumen from sand, are capable of processing approximately 675,000 tonnes (740,000 tons) of oil sands a day, producing about 24 million cubic metres (150 million barrels) of crude bitumen a year. This represents recovery capability of about 93 percent of the crude bitumen contained in the mined oil sands.
Crude bitumen extracted from oil sand is refined to a marketable hydrocarbon product through a combination of carbon removal in three large, high temperature, fluid coking vessels and by hydrogen addition in high temperature, high pressure, hydrocracking vessels. These processes remove carbon and sulphur and reformulate the crude into a low viscosity, low sulphur, high quality synthetic crude oil product. In 2006, the upgrading process yielded 0.849 cubic metres of synthetic crude oil per cubic metre of crude bitumen (0.849 barrels of synthetic crude oil per barrel of crude bitumen). In 2006, about 44 percent of the synthetic crude oil was processed by Edmonton area refineries and the remaining 56 percent was pipelined to refineries in eastern Canada or exported to the United States. Electricity is provided to Syncrude by a 270 megawatt electricity generating plant and a 160 megawatt electricity generating plant, both located at Syncrude. The generating plants are owned by the Syncrude participants. Recycled water is the primary water source, and incremental raw water is drawn, under license, from the Athabasca River. The company’s 25 percent share of net investment in plant, property and equipment, including surface mining facilities, transportation equipment and upgrading facilities is about $3.4 billion.
In 2006, Syncrude’s net production of synthetic crude oil was about 37,100 cubic metres (233,600 barrels) per day and gross production was about 41,000 cubic metres (258,100 barrels) per day. The company’s share of net production in 2006 was about 9,300 cubic metres (58,400 barrels) per day.
In 2000, Syncrude completed development of the first stage of the Aurora mine. The Aurora investment involved extending mining operations to a new location about 35 kilometres (22 miles) from the main Syncrude site and expanding upgrading capacity. In 2001, the Syncrude owners approved another major expansion of upgrading capacity and further development of the Aurora mine. The second Aurora mining and extraction development became fully operational in 2004. The increased upgrading capacity came on stream in 2006. These projects increased total production capacity to about 56,400 cubic metres (355,000 barrels) of synthetic crude oil a day. The company’s share of total project costs was $2.1 billion. Additional mining trains in the North mine and Aurora mine were also completed in 2005. There are no approved plans for major future expansion projects.
On November 1, 2006, the company announced that it plans to enter into a management services agreement with Syncrude to provide operational, technical and business management services to Syncrude. The company has a final checkpoint in the second quarter of 2007 to confirm or cancel the agreement following completion of an opportunity assessment study.
The following table sets forth certain operating statistics for the Syncrude operations:
(1)
Includes pre-stripping of mine areas and reclamation volumes.
(2)
Crude bitumen production is equal to crude bitumen in mined oil sands multiplied by the average extraction recovery and the appropriate conversion factor.
(3)
Reflects the company’s 25 percent interest in production, less applicable royalties payable to the Province of Alberta.
Other Oil Sands Activity
The company holds a 100 percent interest in approximately 13,500 hectares (33,400 acres) of surface mineable oil sands associated with the Kearl project in the Athabasca region of northern Alberta. The company is assessing a potential phased development of its oil sands in the area as part of the Kearl oil sands mining project. The company would hold about a 70 percent interest and would act as operator in the potential joint project with ExxonMobil Canada. A 400 well delineation drilling program to better define the available resource within the project area began in 2003 and was completed in 2005. The company filed a regulatory application with the Alberta Energy and Utilities Board for the Kearl oil sands project in July 2005. Hearings were held in November 2006 and a regulatory decision is expected in early 2007.
The company is continuing to evaluate other undeveloped oil sands acreage.
Land Holdings
At December 31, 2006 and 2005, the company held the following oil and gas rights, and heavy oil and oil sands leases:
(1)
Gross hectares or acres include the interests of others.
(2)
Net hectares or acres exclude the interests of others.
(3)
Canada Lands include the Arctic Islands, Beaufort Sea/Mackenzie Delta, and Other Northwest Territories, Nunavut and the Yukon.
(4)
Certain land holdings are subject to modification under agreements whereby others may earn interests in the company’s holdings by performing certain exploratory work (farm-out) and whereby the company may earn interests in others’ holdings by performing certain exploratory work (farm-in).
Exploration and Development
The company has been involved in the exploration for and development of petroleum and natural gas in the Western Provinces, in the Canada Lands (which include the Arctic Islands, the Beaufort Sea/Mackenzie Delta, and Other Northwest Territories, Nunavut and the Yukon) and in the Atlantic Offshore.
The company’s exploration strategy in the Western Provinces is to search for hydrocarbons on its existing land holdings and especially near established facilities. Higher risk areas are evaluated through shared ventures with other companies.
The following table sets forth the conventional and heavy oil net exploratory and development wells that were drilled or participated in by the company during the five years ended December 31, 2006.
The 174 heavy oil development wells in 2006 were drilled to add new productive capacity from undeveloped areas of existing phases at Cold Lake. In 2004, there was an increase in gas development wells related to an increase in drilling in shallow gas fields. Weather related delays in 2005 resulted in a reduction in the number of wells drilled in the ongoing shallow gas development program.
At December 31, 2006, the company was participating in the drilling of 221 gross (181 net) exploratory and development wells.
Western Provinces
In 2006, the company had a working interest in three gross (one net) exploratory wells and 520 gross (366 net) development wells. The majority of the exploratory wells were directed toward extending reserves around existing fields.
Beaufort Sea/Mackenzie Delta
Substantial quantities of gas have been found by the company and others in the Beaufort Sea/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 one 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. There are complex issues to be resolved and many interested parties to be consulted, before any development could proceed.
In October 2001, the four companies and the Aboriginal Pipeline Group (“APG”), which represents aboriginal peoples of the Northwest Territories, signed a memorandum of understanding to pursue economic and timely development of a Mackenzie Valley pipeline. In 2002, the four companies completed a preliminary study of the feasibility of developing existing discoveries of Mackenzie Delta gas and based on the results of the study announced, together with the APG, their intention to begin preparing the regulatory applications needed to develop the gas resources, including construction of a Mackenzie Valley pipeline. In 2003, the Preliminary Information Package for the Mackenzie Gas Project was submitted to the regulatory authorities, and funding and participation agreements among the four companies, the APG and TransCanada PipeLines Limited were reached for the proposed Mackenzie Valley pipeline. In late 2004, the four companies and the APG signed agreements covering the development and operations of the Mackenzie Valley pipeline. In October 2004, the main regulatory applications and environmental impact statement for the project were filed with the National Energy Board and other boards, panels and agencies responsible for assessing and regulating energy developments in the Northwest Territories. In November 2005, the National Energy Board was notified of the project proponents’ readiness to proceed to public hearings on the project. The public hearings by the Joint Review Panel and the National Energy Board commenced in early 2006. The National Energy Board concluded their scheduled hearings in December, while the Joint Review Panel, conducting the environmental and socio-economic review, extended hearings into 2007, announcing that it would require several extra months of hearings, and additional time to compile its report. In November 2006, a federal court ruling, relating to traditional land use by a First Nation along the pipeline route in Northern Alberta, added further delay to the process.
Other land holdings include majority interests in 20 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 16 other Significant Discovery Licences and one production licence, managed by others.
Arctic Islands
The company has an interest in 16 Significant Discovery Licences and one production licence granted by the Government of Canada in the Arctic Islands. These licences are managed by another company on behalf of all participants. The company has not participated in wells drilled in this area since 1984.
Atlantic Offshore
The company manages five Significant Discovery Licences granted by the Government of Canada in the Atlantic offshore. The company also has minority interests in 27 Significant Discovery Licences, and six production licences, managed by others.
The company retains a 20 percent interest in two exploration licences for about 45,000 gross hectares (110,000 gross acres) acquired in 1998 and 1999 in the Sable Island area. One exploratory well was completed on each licence, without commercial success.
Also, the company retains a 70 percent interest in one exploration licence for about 113,000 gross hectares (279,000 gross acres) farther offshore in deeper water. In 2003, one exploratory well was drilled on this licence, without commercial success. The company is not planning further exploration in these areas.
In early 2004, the company acquired a 25 percent interest in eight deep water exploration licences offshore Newfoundland in the Orphan Basin for about 2,125,000 gross hectares (5,251,000 gross acres). In February 2005, the company reduced its interest to 15 percent through an agreement with another company. The company’s share of proposed exploration spending is about $100 million with a minimum commitment of about $25 million. In 2004 and 2005, the company participated in 3-D seismic surveys in this area. An exploration well was spud in August 2006 with anticipated completion in early 2007. Two more exploration wells are planned by the end of 2008.
The company retains 100 percent interest in a single exploration licence for about 192,000 gross hectares (474,000 gross acres) in the Laurentian basin area offshore Newfoundland and Labrador.
Petroleum Products
Supply
To supply the requirements of its own refineries and condensate requirements for blending with crude bitumen, the company supplements its own production with substantial purchases from others.
The company purchases domestic crude oil at freely negotiated prices from a number of sources. Domestic purchases of crude oil are generally made under renewable contracts with 30 to 60 day cancellation terms.
Crude oil from foreign sources is purchased by the company at competitive prices mainly through Exxon Mobil Corporation (which has beneficial access to major market sources of crude oil throughout the world).
Refining
The company owns and operates four refineries. Two of these, the Sarnia refinery and the Strathcona refinery, have 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 2006, capital expenditures of about $230 million were made at the company’s refineries. About 40 percent of those expenditures were on new facilities required to meet Government of Canada regulations on motor fuels with the remaining expenditures being primarily on safety and efficiency improvements, and environmental improvement projects.
The approximate average daily volumes of refinery throughput during the five years ended December 31, 2006, and the daily rated capacities of the refineries at December 31, 2001 and 2006, were as follows:
(1)
Refinery throughput is the volume of crude oil and feedstocks that is processed in the refinery atmospheric distillation units.
(2)
Rated capacities are based on definite specifications as to types of crude oil and feedstocks that are processed in the refinery atmospheric distillation units, the products to be obtained and the refinery process, adjusted to include an estimated allowance for normal maintenance shutdowns. Accordingly, actual capacities may be higher or lower than rated capacities due to changes in refinery operation and the type of crude oil available for processing.
Refinery throughput was 88 percent of capacity in 2006, 5 percentage points below the previous year, primarily due to scheduled maintenance and project work.
Distribution
The company maintains a nation-wide distribution system, including 30 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 crude oil, natural gas liquids and products pipelines in Alberta, Manitoba and Ontario and has interests in the capital stock of two products and three crude oil pipeline companies.
At December 31, 2006, the company did not own or operate any marine vessels.
Marketing
The company markets more than 700 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 service stations. On average during the year, there were about 1,960 sites of which about 650 were company owned or leased, but none of which were company operated. The company continues to improve its Esso service station network, providing more customer services such as car washes and convenience stores, primarily at high volume sites in urban centres.
The Canadian farm, residential heating and small commercial markets are served through about 100 sales facilities. Heating oil is provided through authorized dealers as well as through three company operated Home Comfort facilities in urban markets. 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, 2006, are set out in the following table:
The total domestic sales of petroleum products as a percentage of total sales of petroleum products during the five years ended December 31, 2006, were as follows:
The company continues to evaluate and adjust its Esso service station and distribution system to increase productivity and efficiency. During 2006, the company closed or debranded about 110 Esso service stations, about 40 of which were company owned, and added about 70 sites. The company’s average annual throughput in 2006 per Esso service station was 3.6 million litres, the same as in 2005. Average throughput per company owned or leased Esso service station was 6.1 million litres in 2006, an increase of about 0.3 million litres from 2005.
Chemicals
The company’s chemicals 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 average daily sales of petrochemicals during the five years ended December 31, 2006, were as follows:
Research
In 2006, the company’s research expenditures in Canada, before deduction of investment tax credits, were $56 million, as compared with $50 million in 2005, and $40 million in 2004. Those funds were used mainly for developing improved heavy crude oil recovery methods and better lubricants.
A research facility to support the company’s natural resources 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 2006. The company also participated in heavy oil recovery and processing research for oil sands development through its interest in Syncrude, which maintains research facilities in Edmonton, Alberta and through research arrangements with others.
In company laboratories in Sarnia, Ontario, research is mainly conducted on the development and improvement of lubricants and fuels. About 120 people were employed in this type of research at the end of 2006. Also in Sarnia, there are about 15 people engaged in new product development for the company’s and Exxon Mobil Corporation’s polyethylene injection and rotational molding businesses.
The company has scientific research agreements with affiliates of Exxon Mobil Corporation which provide for technical and engineering work to be performed by all parties, the exchange of technical information and the
assignment and licensing of patents and patent rights. These agreements provide mutual access to scientific and operating data related to nearly every phase of the petroleum and petrochemical operations of the parties.
Environmental Protection
The company is concerned with and active in protecting the environment in connection with its various operations. The company works in cooperation with government agencies and industry associations to deal with existing and to anticipate potential environmental protection issues. In the past five years, the company has made capital expenditures of about $1.2 billion on environmental protection and facilities. In 2006, the company’s capital expenditures relating to environmental protection totalled approximately $155 million, and are expected to be about $160 million in 2007.
The increased environmental expenditures over the past four years primarily reflect spending on two major projects. One project completed in 2004, costing about $650 million, reduced sulphur in motor gasolines, meeting a requirement of the Government of Canada. The second project completed in 2006 was to meet a new Government of Canada regulation requiring ultra-low sulphur on-road diesel fuel. In 2006, there were capital expenditures of about $95 million on this second project, which cost about $500 million in total. Capital expenditures on safety related projects in 2006 were approximately $15 million.
Human Resources
At December 31, 2006, the company employed full-time approximately 4,900 persons compared with about 5,100 at the end of 2005 and 6,100 at the end of 2004. During 2005, the company transferred about 700 employees to an affiliated company that provides services to the company and others. About nine percent of the company’s employees are members of unions. The company continues to maintain a broad range of benefits, including illness, disability and survivor benefits, a savings plan and pension plan.
Competition
The Canadian petroleum, natural gas and chemical industries are highly competitive. Competition includes the search for and development of new sources of supply, the construction and operation of crude oil, natural gas and refined products pipelines and facilities and the refining, distribution and marketing of petroleum products and chemicals. The petroleum industry also competes with other industries in supplying energy, fuel and other needs of consumers.
Government Regulation
Petroleum and Natural Gas Rights
Most of the company’s petroleum and natural gas rights were acquired from governments, either federal or provincial. Reservations, permits or licences are acquired from the provinces for cash and entitle the holder to obtain leases upon completing specified work. Leases may also be acquired for cash. A lease entitles the holder to produce petroleum and/or natural gas from the leased lands. The holder of a licence relating to Canada Lands and the Atlantic Offshore is generally required to make cash payments or to undertake specified work or amounts of 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 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 National Energy Board (the “NEB”) and the Government of Canada.
Natural Gas
Production
The maximum allowable gross production of natural gas from wells in Canada is subject to limitations by various regulatory authorities. These limitations are to ensure oil recovery is not adversely impacted by accelerated gas production practices. These limitations do not impact gas reserves, only the timing of production of the reserves, and did not have a significant impact on 2006 gas production rates. As well, these limitations do not apply to gas fields where there are no associated oil reserves.
Exports
The Government of Canada has the authority to regulate the export price for natural gas and has a gas export pricing policy which accommodates export prices for natural gas negotiated between Canadian exporters and U.S. importers.
Exports of natural gas from Canada require approval by the NEB and the Government of Canada. The Government of Canada allows the export of natural gas by NEB order without volume limitation for terms not exceeding 24 months.
Royalties
The Government of Canada and the provinces in which the company produces crude oil and natural gas impose royalties on production from lands where they own the mineral rights. Some producing provinces also receive revenue by imposing taxes on production from lands where they do not own the mineral rights.
Different royalties are imposed by the Government of Canada and each of the producing provinces. Royalties imposed by the producing provinces on crude oil vary depending on well production volumes, selling prices, recovery methods and the date of initial production. Royalties imposed by the producing provinces on natural gas and natural gas liquids vary depending on well production volumes, selling prices and the date of initial production. For information with respect to royalty rates for Norman Wells, Cold Lake and Syncrude, see “Natural Resources - Petroleum and Natural Gas Production”.
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. In certain circumstances, the acquisition of natural resource properties may be considered to be a transaction that constitutes an acquisition of control of a Canadian business requiring Government of Canada approval.
The Act 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. By virtue of the majority stock ownership of the company by Exxon Mobil Corporation, the company is considered to be an entity which is not controlled by Canadians.
The Company Online
The company’s website www.imperialoil.ca contains a variety of corporate and investor information which is available free of charge, including the company’s annual report on Form 10-K, quarterly reports on Form 10-Q and current reports on Form 8-K and amendments to these reports. These reports are made available as soon as reasonably practicable after they are filed or furnished to the U.S. Securities and Exchange Commission.
Item 1A.
Item 1A. Risk Factors.
Volatility of Oil and Natural Gas Prices
The company’s results of operations and financial condition are dependent on the prices it receives for its oil and natural gas production. Crude oil and natural gas prices are determined by global and North American markets and are subject to changing supply and demand conditions. These can be influenced by a wide range of factors including economic conditions, international political developments and weather. 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 heavy oil. The market prices for heavy oil differ from the established market indices for light and medium grades of oil principally due to the higher transportation and refining costs associated with heavy oil and limited refining capacity capable of processing heavy oil. As a result, the price received for heavy oil is generally lower than the price for medium and light oil, and the production costs associated with heavy oil are often relatively higher than for lighter grades. Future differentials are uncertain and increases in the heavy oil differentials could have a material adverse effect on the company’s business.
The company does not use derivative markets to hedge or sell forward any part of production from any business segment.
Competitive Factors
The oil and gas industry is highly competitive, particularly in the following areas: searching for and developing new sources of supply; constructing and operating crude oil, natural gas and refined products pipelines and facilities; and the refining, distribution and marketing of petroleum products and chemicals. The company’s competitors include major integrated oil and gas companies and numerous other independent oil and gas companies. The petroleum industry also competes with other industries in supplying energy, fuel and related products to customers.
Competitive forces may result in shortages of prospects to drill, services to carry out exploration, development or operating activities and infrastructure to produce and transport production. It may also result in an oversupply of crude oil, natural gas, petroleum products and chemicals. Each of these factors could have a negative impact on costs and prices and, therefore, the company’s financial results.
Environmental Risks
All phases of the upstream, downstream and chemicals 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.
Climate Change
The Government of Canada has published a Notice of Intent to regulate emissions of carbon dioxide, methane, nitrous oxide and other emissions commonly referred to as “greenhouse gases” from various industrial activities, including oil and natural gas exploration and production, petroleum refining, and some chemical manufacturing. The Province of Alberta may also issue regulations under Alberta’s Climate Change and Emissions Management Act limiting greenhouse gas emissions. Other provinces may also issue regulations limiting greenhouse gas emissions. Mandatory emissions limits may result in increased operating costs and capital expenditures for oil and natural gas producers, refiners and chemical manufacturers, and also may reduce demand for the company’s products, possibly adversely affecting the company’s business, financial condition, results of operations and cash flows. However, while the government has outlined broad guidelines of a possible regulatory framework, it has not determined what specific measures it might impose on companies. Consequently attempts to assess the magnitude of any impact on the company can only be speculative.
Other Regulatory Risk
The company is subject to a wide range of legislation and regulation governing its operations over which it has no control. Changes may affect every aspect of the company’s operations and financial performance.
Need to Replace Reserves
The company’s future conventional oil, heavy 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.
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 therefrom 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 engineers or by the same engineers at different times, may vary substantially. Actual production, revenues, taxes and development, abandonment and operating expenditures with respect to its 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.
Market Risk Factors
See Item 7A for a discussion of the impact of market risks and other uncertainties.
Item 2.
Item 2. Properties.
Reference is made to Item 1 above, and for the reserves of the Syncrude mining operations and oil and gas producing activities, reference is made to Item 8 of this report.
Item 3.
Item 3. Legal Proceedings.
Not applicable.
Item 4.
Item 4. Submission of Matters to a Vote of Security Holders.
Not applicable.
PART II
Item 5.
Item 5. Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities.
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 United States that owns at least 10 percent of the voting shares of the company.
Imperial Oil Limited is a qualified foreign corporation for purposes of the reduced U.S. capital gains tax rates (15 percent and 5 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.
Quarterly Financial and Stock Trading Data
(a)
Amounts for purchases/sales with same counterparty are included in both total revenues and other income and total expenses in 2005 quarterly data. Effective January 1, 2006, these purchases/sales were recorded on a net basis. See note 1 (page), Summary of Significant Accounting Policies.
(b)
Adjusted to reflect the May 2006 three-for-one share split.
The company’s shares are listed on the Toronto Stock Exchange and are admitted to unlisted trading on the American Stock Exchange in New York. The symbol on these exchanges for the company’s common shares is IMO. Share prices were obtained from stock exchange records adjusted for the three-for-one share split.
As of February 15, 2007 there were 13,490 holders of record of common shares of the company.
During the period October 1, 2006 to December 31, 2006, the company issued 176,325 common shares for $15.50 per share (following the three-for-one share split) as a result of the exercise of stock options by the holders of the stock options, who are all employees or former employees of the company, in transactions outside the U.S.A. which were not registered under the Securities Act in reliance on Regulation S thereunder.
Issuer purchases of equity securities (1)
Item 6.
Item 6. Selected Financial Data.
Reference is made to the table setting forth exchange rates for the Canadian dollar, expressed in U.S. dollars, on page 2 of this report.
Item 7.
Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations.
Overview
The following discussion and analysis of Imperial’s financial results, as well as the accompanying financial statements and related notes to consolidated financial statements to which they refer, are the responsibility of the management of Imperial Oil Limited.
The company’s accounting and financial reporting fairly reflect its straightforward business model involving the extracting, refining and marketing of hydrocarbons and hydrocarbon-based products. The company’s business involves the production (or purchase), manufacture and sale of physical products, and all commercial activities are directly in support of the underlying physical movement of goods.
Imperial, with its resource base, financial strength, disciplined investment approach and technology portfolio, is well-positioned to participate in substantial investments to develop new Canadian energy supplies. While commodity prices remain volatile on a short-term basis depending upon supply and demand, Imperial’s investment decisions are based on its long-term 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 risk-assessed, 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.
Business environment and outlook
Natural resources
Imperial produces crude oil and natural gas for sale into large North American markets. Economic and population growth are expected to remain the primary drivers of energy demand, globally and in North America. The company expects the global economy to grow at an average rate of slightly less than three percent per year through 2030. The combination of population and economic growth should lead to an increase in demand for primary energy at an average rate slightly less than two percent annually. The vast majority of this increase is expected to occur in developing countries.
Oil, gas and coal are expected to remain the predominant energy sources with approximately 80 percent share of total energy. Oil and gas alone are expected to maintain close to a 60 percent share.
Over the same period, the Canadian economy is expected to grow at an average rate of about two percent per year, and Canadian demand for energy at a rate of about one percent per year. Oil and gas are expected to continue to supply two-thirds of Canadian energy demand. It is expected that Canada will also be a growing supplier of energy to U.S. markets through this period.
Oil products are the transportation fuel of choice for the world’s fleet of cars, trucks, trains, ships and airplanes. Primarily because of increased demand in developing countries, oil consumption will increase by 35 percent or about 30 million barrels a day by 2030. Canada’s resources of heavy oil and oil sands represent an important additional source of supply.
Natural gas is expected to be a major primary energy source globally, capturing about one-third of all incremental energy growth and approaching one-quarter of global energy supplies. Natural gas production from mature established regions in the United States and Canada is not expected to meet increasing demand, strengthening the market opportunities for new gas supply from Canada’s frontier areas.
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. In the past, crude oil and natural gas prices have been volatile, and the company expects that volatility to continue.
Imperial has a large and diverse 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 the established producing areas of Western Canada, Imperial’s production is expected to come increasingly from frontier and unconventional sources, particularly heavy oil, oil sands and natural gas from the Far North, where Imperial has large undeveloped resource opportunities.
Petroleum products
The downstream industry environment remains very competitive. While refining margins in 2006 were strong, long-term real refining margins globally have declined at a rate of about one percent per year over the past 20 years. Intense competition in the retail fuels market similarly has driven down real margins. Refining margins are the difference between what a refinery pays for its raw materials (primarily crude oil) and the wholesale market prices for the range of products produced (primarily gasoline, diesel fuel, heating oil, jet fuel and heavy fuel oil). Crude oil and many products are widely traded with published international prices. Prices for those commodities are determined by the marketplace, often an international marketplace, and are affected by many factors, including global and regional supply/demand balances, inventory levels, refinery operations, import/export balances, transportation logistics, seasonality and weather. Canadian wholesale prices 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.
Imperial’s downstream strategies are to provide customers with quality service at the lowest total cost offer, have the lowest unit costs among our competitors, ensure efficient and effective use of capital and capitalize on integration with the company’s other businesses. Imperial owns and operates four refineries in Canada, with distillation capacity of 502,000 barrels a day and lubricant manufacturing capacity of 9,000 barrels a day.
Imperial’s fuels marketing business includes retail operations across Canada serving customers through about 1,960 Esso-branded service stations, of which about 650 are company-owned or leased, and wholesale and industrial operations through a network of 30 primary distribution terminals, as well as a secondary distribution network.
Chemicals
Although the current business environment is favourable, the North American petrochemical industry is cyclical. The company’s strategy for its chemicals business is to reduce costs and maximize value by continuing to increase the integration of its chemicals plants at Sarnia and Dartmouth with the refineries. The company also
benefits from its integration within ExxonMobil’s North American chemicals businesses, enabling Imperial to maintain a leadership position in its key market segments.
Results of operations
Net income in 2006 was $3,044 million or $3.11 a share - the best year on record - surpassing the previous record of $2,600 million or $2.53 a share in 2005 (2004 - $2,052 million or $1.91 a share). Higher realizations for Cold Lake heavy oil and conventional crude oil contributed about $640 million and stronger refining, marketing and petrochemical margins about $60 million more to earnings when compared with 2005. Also positive to earnings were higher benefits from resolution of tax matters and the impact of tax rate changes of about $340 million and lower share-based compensation expenses of about $105 million. Partially offsetting these positive factors were the impacts of a stronger Canadian dollar of about $275 million, lower natural gas realizations of about $150 million, lower gains on asset divestments of about $130 million, higher planned refinery maintenance and capital project effects of about $100 million and a heavier mix of resources volumes of about $60 million.
Natural resources
Net income from natural resources was a record $2,376 million, exceeding the previous record achieved in 2005 of $2,008 million (2004 - $1,517 million). Cold Lake heavy oil and conventional crude oil realizations were stronger by about $640 million compared with 2005. These positive items were partially offset by lower natural gas realizations of about $150 million and the negative impact of a higher Canadian dollar of about $200 million. The impact of natural resources volumes was unfavourable by about $60 million due to mix effects with lower conventional crude oil volumes being partially offset by higher Syncrude volumes. Higher production at Cold Lake was essentially offset by higher royalties. Tax expense in 2006 was lower by about $290 million, primarily from reductions in federal and Alberta tax rates and higher benefits from resolution of tax matters. Gains from asset divestments were lower by about $130 million compared with 2005.
Financial statistics
World crude oil prices, denominated in U.S. dollars, were higher in 2006 than in the previous year. The annual average price of Brent crude oil, the most actively traded North Sea crude and a common benchmark of world oil markets, was about $65 (U.S.) a barrel in 2006, a more than 19 percent increase over the average price of $55 in 2005 (2004 - $38). However, the company’s Canadian-dollar realizations for conventional crude oil increased to a lesser extent because of a stronger Canadian dollar. Average realizations for conventional crude oil during the year were $68.58 (Cdn) a barrel, an increase of six percent from $64.48 in 2005 (2004 - $48.96).
Average realizations for Cold Lake heavy oil were higher by over 40 percent in 2006, reflecting both increases in light crude oil prices and a narrowing price spread between light crude oil and Cold Lake heavy oil more consistent with historical trend levels.
Prices for Canadian natural gas in 2006 were lower than the previous year. The average of 30-day spot prices for natural gas at the AECO hub in Alberta was about $7.41 a thousand cubic feet in 2006, compared with $9.01 in 2005 (2004 - $6.80). The company’s average realizations on natural gas sales were $7.24 a thousand cubic feet, compared with $9 in 2005 (2004 - $6.78).
Average realizations and prices
Total gross production of crude oil and natural gas liquids (NGLs) averaged 272,000 barrels a day, compared with 261,000 barrels in 2005 (2004 - 262,000).
Gross heavy oil production at the company’s wholly owned facilities at Cold Lake was a record 152,000 barrels a day, surpassing the previous record of 139,000 barrels in 2005 (2004 - 126,000), due to the cyclic nature of production at Cold Lake and increased volumes from the ongoing development drilling program.
Production from the Syncrude oil sands operation, in which the company has a 25 percent interest, was higher during 2006 as a result of lower maintenance activities and new production volume from the new coker unit at the Stage 3 expansion project. Gross production of upgraded crude oil increased to 258,000 barrels a day from
214,000 barrels in 2005 (2004 - 238,000). Imperial’s share of average gross production increased to 65,000 barrels a day from 53,000 barrels in 2005 (2004 - 60,000).
Gross production of conventional oil decreased to 31,000 barrels a day from 38,000 barrels in 2005 (2004 - 43,000) as a result of the impact of divested properties and the natural decline in Western Canadian reservoirs.
Gross production of NGLs available for sale averaged 24,000 barrels a day in 2006, down from 31,000 barrels in 2005 (2004 - 33,000), mainly due to the declining NGL content of Wizard Lake gas production.
Gross production of natural gas decreased to 556 million cubic feet a day from 580 million cubic feet in 2005 (2004 - 569 million). Lower production volumes were primarily due to the natural decline in the Western Canadian Basin.
In 2006, the company realized a gain of $76 million on divestment of assets. In 2005, the gain on divestment of assets was approximately $208 million.
Crude oil and NGLs - production and sales (a)
Natural gas - production and sales (a)
(a)
Daily volumes are calculated by dividing total volumes for the year by the number of days in the year. Gross production is the company’s share of production (excluding purchases) before deducting the share of mineral owners or governments or both. Net production excludes those shares.
(b)
Diluent is natural gas condensate or other light hydrocarbons added to the Cold Lake heavy oil to facilitate transportation to market by pipeline.
(c)
Production of natural gas includes amounts used for internal consumption with the exception of the amounts reinjected.
Operating costs decreased by one percent in 2006. Lower energy and other operating costs more than offset higher Syncrude expenses.
In November, the company announced plans to enter into a management services agreement with Syncrude Canada Ltd., the operating company for the Syncrude joint venture. The company has a final checkpoint in the second quarter of 2007 to confirm or cancel the agreement following completion of an opportunity assessment study.
Petroleum products
Net income from petroleum products was $624 million or 2.4 cents a litre in 2006, compared with $694 million or 2.6 cents a litre in 2005 (2004 - $556 million or 2.1 cents a litre). Earnings were negatively impacted by higher planned refinery maintenance and ultra-low sulphur diesel project activities, which impacted both refinery utilization and expenses by a total of about $100 million versus the prior year. Lower product sales volumes during the year were primarily a result of lower refinery production and had limited impact on earnings, as the reduction was primarily in lower margin refining and marketing sales channels. Earnings were also negatively impacted by a stronger Canadian dollar of about $65 million. These factors were partially offset by the net positive effect of resolution of tax matters and the impact of the tax rate change, totalling about $55 million, and stronger refining and marketing margins.
Financial statistics
Sales of petroleum products
Refinery utilization
(a)
Operating revenues in 2005 and prior years included amounts for purchases/sales with the same counterparty. Associated costs were included in “purchases of crude oil and products”. Effective January 1, 2006, these purchases/sales were recorded on a net basis. See note 1, summary of significant Accounting Policies, on page.
(b)
Volumes a day are calculated by dividing total volumes for the year by the number of days in the year.
(c)
Crude oil and feedstocks sent directly to atmospheric distillation units.
One thousand litres is approximately 6.3 barrels.
Margins were stronger in the refining segment of the industry in 2006. However, the effects of stronger industry margins were reduced partially by a higher Canadian dollar. Marketing margins in 2006 were slightly higher than the low levels of 2005.
Impacted by higher planned maintenance and ultra-low sulphur diesel project activities, refinery utilization for 2006 at 88 percent was lower than the record performance level of 93 percent in both 2005 and 2004.
The company’s total sales volumes, excluding those resulting from reciprocal supply agreements with other companies, were 71.9 million litres a day, compared with 73.9 million litres in 2005 (2004 - 73.4 million). Lower refinery production was the main reason for the decline.
Operating costs in 2006 were essentially the same as the previous year.
Chemicals
Net income from chemicals operations was $143 million in 2006, the best on record, compared with $121 million in 2005 (2004 - $109 million). Improved industry margins for polyethylene and intermediate products were the main contributors to higher earnings.
Financial statistics
Sales
(a)
Calculated by dividing total volumes for the year by the number of days in the year.
The average industry price of polyethylene was $1,703 a tonne in 2006, essentially unchanged from $1,708 a tonne in 2005 (2004 - $1,584).
Sales of chemicals were 3,000 tonnes a day, unchanged from 2005 (2004 - 3,300 tonnes).
Operating costs in the chemicals segment for 2006 were about four percent lower than 2005, reflecting lower direct operating expenses.
Corporate and other
Net income from corporate and other was negative $99 million in 2006, compared with negative $223 million in 2005 (2004 - negative $130 million). Favourable earnings effects were due mainly to lower share-based compensation expenses.
Liquidity and capital resources
Sources and uses of cash
Although the company issues long-term debt from time to time and maintains a revolving commercial paper program, internally generated funds cover the majority of its financial requirements. The management of cash that may be temporarily available as surplus to the company’s immediate needs is carefully controlled, both to optimize returns on cash balances and to ensure that it is secure and readily available to meet the company’s cash requirements as they arise.
Cash flows from operating activities are highly dependent on crude oil and natural gas prices and product margins. In addition, the company will need to continually find and develop new resources, and continue to develop and apply new technologies and recovery processes to existing fields, in order to maintain or increase production and resulting cash flows in future periods. Projects are in place 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 large and diverse portfolio of development opportunities and the complementary nature of its business segments help mitigate the overall risks of the company and associated cash flow. Further, due to its financial strength, debt capacity and diverse 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.
Cash flow from operating activities
Cash provided by operating activities was $3,587 million, versus $3,451 million in 2005 (2004 - $3,312 million). Increases in cash flow in 2006 were driven primarily by higher net income and lower overall working capital balances.
Capital and exploration expenditures
Total capital and exploration expenditures were $1,209 million in 2006, compared with $1,475 million in 2005 (2004 - $1,445 million).
The funds were used mainly to invest in Cold Lake and Syncrude to maintain and expand production capacity, improve operating efficiency, reduce the sulphur content of diesel fuel and upgrade the network of Esso retail outlets. About $170 million was spent on projects related to reducing the environmental impact of the company’s operations and improving safety, including about $95 million on the $500-million project to produce ultra-low sulphur diesel.
The following table shows the company’s capital and exploration expenditures for natural resources during the five years ending December 31, 2006:
For the natural resources segment, about 85 percent of the capital and exploration expenditures in 2006 was focused on growth opportunities. Significant expenditures during the year were made to ongoing development
drilling at Cold Lake and to Syncrude for the company’s share of the Stage 3 upgrader expansion project. Sustained operation of the upgrader expansion project began in August 2006, following a prolonged start-up period.
Other 2006 investment included drilling at conventional fields in Western Canada, advancing the Mackenzie gas and Kearl oil sands projects, and exploration off the East Coast of Canada.
The Mackenzie gas project is facing significant cost and schedule pressures brought on by unprecedented global demands for energy infrastructure. There are also uncertainties related to the regulatory and permitting process and the remaining benefits and access agreements. The company’s current work efforts are focused on completing regulatory hearings, advancing approval of permits, finalizing remaining benefits and access agreements, establishing an appropriate fiscal framework with the federal government, advancing potential shipping agreements and continuing paced engineering, technical and cost-reduction efforts.
Regulatory hearings by the joint federal and provincial review panel on the Kearl oil sands project were completed in November 2006 and a decision is expected in early 2007. The company’s current efforts are focused on design optimization to improve project economics and reduce project execution risk. Once this work is completed and a regulatory decision is received, project timing will be determined.
Drilling of a wildcat exploration well began with co-venturers in the Orphan Basin, a frontier basin located off the East Coast of Newfoundland. Two more exploration wells are planned by the end of 2008. Imperial holds a 15-percent interest in eight deepwater exploration licences in the basin.
Planned capital and exploration expenditures in natural resources are expected to be about $700 million in 2007, with over 75 percent of the total focused on growth opportunities. Investments are mainly planned for development drilling at Cold Lake and conventional oil and gas operations in Western Canada, facilities improvement at Syncrude, the Mackenzie gas project, the Kearl oil sands project and exploration off the East Coast.
The following table shows the company’s capital expenditures in the petroleum products segment during the five years ending December 31, 2006:
(a)
Consists primarily of real estate purchases.
For the petroleum products segment, capital expenditures were $361 million in 2006, compared with $478 million in 2005 (2004 - $283 million). The company invested about $95 million in refining operations and other facilities during the year as part of a three-year, $500-million project to reduce sulphur content in diesel. The project was completed in 2006 and the company was able to fully meet all new government regulations on ultra-low sulphur diesel from all of its facilities across Canada by the required schedules. More than $150 million was invested in other refinery projects to improve energy efficiency and increase yield. Major investments were also made to upgrade the network of Esso service stations during the year.
Capital expenditures for the petroleum products segment in 2007 are expected to be about $250 million. Major items include additional investment in the refineries on improving energy efficiencies and increasing yield and continued enhancements to the company’s retail network.
The following table shows the company’s capital expenditures for its chemicals operations during the five years ending December 31, 2006:
Of the capital expenditures for chemicals in 2006, the major investment focused on improving energy efficiency and yields.
Planned capital expenditures for chemicals in 2007 will be about $15 million.
Total capital and exploration expenditures for the company in 2007, which will focus mainly on growth and productivity improvements, are expected to total about $1 billion and will be financed from internally generated funds.
Cash flow from financing activities
In June, the company renewed the normal course issuer bid (share-repurchase program) for another 12 months. During 2006, the company purchased about 45.5 million shares for $1,818 million (2005 - 52.5 million
shares for $1,795 million). Since Imperial initiated its first share-repurchase program in 1995, the company has purchased close to 800 million shares - representing about 46 percent of the total outstanding at the start of the program - with resulting distributions to shareholders of about $10.5 billion.
The company declared dividends totalling 32 cents a share in 2006, up from 31 cents in 2005 (2004 - 29 cents). Regular annual per-share dividends paid have increased in each of the past 12 years and, since 1986, payments per share have grown by 80 percent.
Total debt outstanding at the end of 2006, excluding the company’s share of equity company debt, was $1,437 million, compared with $1,439 million at the end of 2005 (2004 - $1,443 million). Debt represented 17 percent of the company’s capital structure at the end of 2006, compared with 18 percent at the end of 2005 (2004 - 19 percent).
Debt-related interest incurred in 2006, before capitalization of interest, was $63 million, up from $45 million in 2005 (2004 - $37 million). The average effective interest rate on the company’s debt was 4.2 percent in 2006, compared with 3.1 percent in 2005 (2004 - 2.8 percent).
Financial percentages and ratios
(a)
Current and long-term portions of debt (page), divided by debt and shareholders’ equity (page).
(b)
Net income (page), debt-related interest before capitalization (page, note 14) and income taxes (page) divided by debt-related interest before capitalization.
(c)
Cash flow from net income adjusted for other non-cash items (page), current income tax expense (page, note 5) and debt-related interest before capitalization (page, note 14) divided by debt-related interest before capitalization.
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.
Effective May 23, 2006, the issued common shares of the company were split on a three-for-one basis and the number of authorized shares was increased from 450 million to 1,100 million. The prior period number of shares outstanding and shares purchased, as well as net income and dividends per share, have been adjusted to reflect the three-for-one split.
Contractual obligations
The following table shows the company’s contractual obligations outstanding at December 31, 2006. It provides data for easy reference from the consolidated balance sheet and from individual notes to the consolidated financial statements.
(a)
Includes capitalized lease obligations. Long-term debt amounts exclude the company’s share of equity company debt.
(b)
Minimum commitments for operating leases, shown on an undiscounted basis, primarily cover office buildings, rail cars and service stations.
(c)
Unconditional purchase obligations mainly pertain to pipeline throughput agreements.
(d)
Firm capital commitments related to capital projects, shown on an undiscounted basis. The largest commitment outstanding at year-end 2006 was $41 million associated with the company’s share of capital projects at Syncrude.
(e)
The amount by which the projected benefit obligations exceeded the fair value of fund assets for pension and other post-retirement plans at year-end. The payments by period include expected contributions to funded pension plans in 2007 and estimated benefit payments for unfunded plans in all years.
(f)
Asset retirement obligations represent the discounted present value of legal obligations associated with site restoration on the retirement of assets with determinable useful lives.
(g)
Other long-term agreements include primarily raw material supply and transportation services agreements.
The company was contingently liable at December 31, 2006, for a maximum of $87 million relating to guarantees for purchasing operating equipment and other assets from its rural marketing associates upon expiry of the associate agreement or the resignation of the associate. The company expects that the fair value of the operating equipment and other assets so purchased would cover the maximum potential amount of future payments under the guarantees.
Various lawsuits are pending 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 or financial condition. There are no events or uncertainties known to management beyond those already included in reported financial information that would indicate a material change in future operating results or financial condition.
Recently issued Statement of Financial Accounting Standards
Accounting for uncertainty in income taxes
In June 2006, the Financial Accounting Standards Board (FASB) issued Interpretation No. 48 (FIN 48), “Accounting for Uncertainty in Income Taxes”. FIN 48 is an interpretation of FASB Statement No. 109 “Accounting for Income Taxes” and must be adopted by the company no later than January 1, 2007. The interpretation prescribes a comprehensive model for recognizing, measuring, presenting and disclosing in the financial statements uncertain tax positions that the company has taken or expects to take in its tax returns. The new standard requires that a tax benefit be recognized in the books only if it is more likely than not that a tax position will be sustained. Otherwise, a liability will need to be recorded to reflect the difference between the as-filed tax basis and the book tax basis. The new standard does not allow a restatement of the comparative prior periods.
The company expects to recognize a transition gain of approximately $14 million in shareholders’ equity upon adoption of FIN 48 in the first quarter of 2007. This gain reflects the recognition of several refund claims and associated interest, partly offset by increased liability reserves.
Critical accounting policies
The company’s financial statements have been prepared in accordance with United States generally accepted accounting principles (GAAP) and include estimates that reflect management’s best judgment. 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 following summary provides further information about the critical accounting policies and the estimates that are made by the company to apply those policies. It should be read in conjunction with note 1 to the consolidated financial statements on page.
Hydrocarbon reserves
Proved oil, gas and synthetic crude oil reserve quantities are used as the basis of calculating unit-of-production rates for depreciation and evaluating for impairment. Proved oil and gas reserves are the estimated quantities of crude oil, natural gas and natural gas liquids that geological and engineering data demonstrate with reasonable certainty to be recoverable in future years from known reservoirs and deposits under existing economic and operating conditions. Estimates of synthetic crude oil reserves are based on detailed geological and engineering assessments of in-place crude bitumen volume, the mining plan, historical extraction recovery and upgrading yield factors, installed plant operating capacity and operating approval limits.
The estimation of proved reserves is controlled by the company through long-standing approval guidelines. Reserve changes are made with a well-established, disciplined process driven by senior-level geoscience and engineering professionals (assisted by a central reserves group with 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 estimation include rigorous peer-reviewed technical evaluations and analysis of well and field performance information and a requirement that management make significant funding commitment toward the development of the reserves prior to booking.
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 and significant changes in long-term oil and gas price levels.
Beginning in 2004, the year-end reserves volumes as well as the reserves change categories shown in the proved reserves tables are calculated using December 31 prices and costs. These reserves quantities are also used in calculating unit-of-production depreciation rates and in calculating the standardized measure of discounted net cash flow. Regulations preclude the company from showing in this document the reserves that are calculated in a manner which is consistent with the basis that the company uses to make its investment decisions. The use of year-end prices for reserves estimation introduces short-term price volatility into the process
since annual adjustments are required based on prices occurring on a single day. The company believes that this approach is inconsistent with the long-term nature of the natural resources business where production from individual projects often spans multiple decades. The use of prices from a single date is not relevant to the investment decisions made by the company, and annual variations in reserves based on such year-end prices are not of consequence to how the business is actually managed.
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 year-end prices and costs that are used in determination of reserves. This category can also include changes associated with the performance of improved recovery projects and 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 on the unit-of-production method for each field. The company uses this accounting policy instead of the full-cost method because it provides a more timely accounting of the success or failure of the company’s exploration and production activities.
Impact of reserves on depreciation
The calculation of unit-of-production depreciation is a critical accounting estimate that measures the depreciation of natural resources 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 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 proved reserves. 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 asset’s carrying value exceeds its fair value.
The impairment evaluation triggers 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 current operating losses.
In general, the company does not view temporarily low oil and gas 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, industry prices over the long term will continue to be driven by market supply and demand. Accordingly, any impairment tests that the company performs make use of the company’s price assumptions developed in the annual planning and budgeting process for the crude oil and natural gas markets, petroleum products and chemicals. These are the same price assumptions that are used for capital investment decisions. The corporate plan is a fundamental annual management process that is the basis for setting near-term risk assessed operating and capital objectives in addition to providing the longer-term economic assumptions used for investment evaluation purposes. Any impairment tests that the company performs also make use of annual volumes based on individual field production profiles, which are also updated as part of the annual plan process.
The standardized measure of discounted future cash flows on page 35 is based on the year-end 2006 price applied for all future years, as required under Statement of Financial Accounting Standards No. 69 (SFAS 69). Future prices used for any impairment tests will vary from the one used in the SFAS 69 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 8.25 percent used in 2006 compares to actual returns of 9.82 percent and 9.99 percent achieved over the last 10- and 20- year periods ending December 31, 2006. If different assumptions are used, the expense and obligations could increase or decrease as a result. The company’s potential exposure to changes in assumptions is summarized in note 6 to the consolidated financial statements on page. At Imperial, differences between actual returns on plan assets versus long-term expected returns are not recorded in pension expense in the year the differences occur, but rather are amortized in pension expense as permitted by GAAP, along with other actuarial gains and losses, over the expected remaining service life of employees. Pension expense represented less than one percent of total expenses in 2006.
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 operating expense. 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 2006, the obligations were discounted at six percent and the accretion expense was $22 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.
Item 7A.
Item 7A. Quantitative and Qualitative Disclosures about Market Risk.
The company is exposed to a variety of financial, operating and market risks in the course of its business. Some of these risks are within the company’s control, while others are not. For those risks that can be controlled, specific risk-management strategies are employed to reduce the likelihood of loss.
In October 2006, the Government of Canada indicated its intent to introduce regulations to control greenhouse-gas emissions from major industrial facilities, although details of what measures will be imposed on companies have not been determined. Consequently, attempts to assess the impact on Imperial can only be speculative. The company will continue to monitor the development of legal requirements in this area.
Other risks, such as changes in international commodity prices and currency-exchange rates, are beyond the company’s control. The company’s size, strong financial position and the complementary nature of its natural resources, petroleum products and chemicals segments help mitigate the company’s exposure to changes in these other risks. The company’s potential exposure to these types of risks is summarized in the earnings sensitivity table below.
The company does not use derivative markets to speculate on the future direction of currency or commodity prices and does not sell forward any part of production from any business segment.
The following table shows the estimated annual effect, under current conditions, of certain sensitivities of the company’s after-tax net income.
Earnings sensitivities (a)
(a)
The amount quoted to illustrate the impact of each sensitivity represents a change of about 10 percent in the value of the commodity or rate in question at the end of 2006. Each sensitivity calculation shows the impact on net income that results from a change in one factor, after tax and royalties and holding all other factors constant. While these sensitivities are applicable under current conditions, they may not apply proportionately to larger fluctuations.
The sensitivity of net income to changes in the Canadian dollar versus the U.S. dollar decreased from year-end 2005 by about $8 million (after tax) a year for each one-cent change, primarily due to the decrease in industry refining margins.
The sensitivity to changes in natural gas prices decreased from 2005 year-end by about $3 million (after tax) for each 10-cent change, primarily due to the company’s lower natural gas production.
Item 8.
Item 8. Financial Statements and Supplementary Data.
Reference is made to the Index to Financial Statements on page of this report.
Syncrude Mining Operations
Syncrude’s crude bitumen is contained within the unconsolidated sands of the McMurray Formation. Ore bodies are buried beneath 15 to 45 metres (50 to 150 feet) of overburden, have bitumen grades ranging from 4 to 14 weight percent and ore thickness of 35 to 50 metres (115 to 160 feet). Estimates of synthetic crude oil reserves are based on detailed geological and engineering assessments of in-place crude bitumen volumes, the mining plan, historical extraction recovery and upgrading yield factors, installed plant operating capacity and operating approval limits. The in-place volume, depth and grade are established through extensive and closely spaced core drilling. In active mining areas, the approximate well spacing is 125 metres (150 wells per section) and in future mining areas, the well spacing is approximately 350 metres (20 wells per section). Proven reserves include the operating Base and North mines and the Aurora mine. In accordance with the long range mine plan approved by the Syncrude owners, there are an estimated 1,675 million tonnes (1,845 million tons) of extractable oil sands in the Base and North mines, with an average bitumen grade of 10.6 weight percent. In addition, at the Aurora mine, there are an estimated 4,155 million tonnes (4,580 million tons) of extractable oil sands at an average bitumen grade of 11.2 weight percent. After deducting royalties payable to the Province of Alberta, the company estimates its 25 percent net share of proven reserves at year end 2006 was equivalent to 114 million cubic metres (718 million barrels) of synthetic crude oil. Imperial’s reserve assessment uses a 6 percent and 7 percent bitumen grade cut-off for the North mine and Aurora mine respectively, a 90 percent overall extraction recovery, a 97 percent mining dilution factor and an 88 percent upgrading yield.
The following table sets forth the company’s share of net proven reserves of Syncrude after deducting royalties payable to the Province of Alberta:
Oil and Gas Producing Activities
The following information is provided in accordance with the United States’ Statement of Financial Accounting Standards No. 69, “Disclosures about Oil and Gas Producing Activities”.
Results of operations
Capital and exploration expenditures
Property, plant and equipment
(1)
Sales to customers or intersegment sales do not include the sale of natural gas and natural gas liquids purchased for resale, as well as royalty payments. These items are reported gross in note 3 (page) in “external sales”, “intersegment sales” and in “purchases of crude oil and products”.
(2)
Sales of crude oil to consolidated affiliates are at market value, using posted field prices. Sales of natural gas liquids to consolidated affiliates are at prices estimated to be obtainable in a competitive, arm’s-length transaction.
(3)
“Property costs” are payments for rights to explore for petroleum and natural gas and for purchased reserves (acquired tangible and intangible assets such as gas plants, production facilities and producing-well costs are included under “producing assets”). “Proved” represents areas where successful drilling has delineated a field capable of production. “Unproved” represents all other areas.
Oil and Gas Reserves
(1)
Proved developed and undeveloped reserves reported on this table represent net reserves. Net reserves are the company’s share of reserves after deducting the shares of mineral owners or governments or both. All reported reserves are located in Canada. Reserves of natural gas are calculated at a pressure of 101.325 kilopascals absolute at 15 degrees Celsius.
(2)
Heavy oil reserves typically are represented by crude oils with a viscosity of greater than 10,000 cP and recovered through enhanced thermal operations. Currently, the company’s heavy oil reserves are from the Cold Lake production operations.
(1)
Proved developed and undeveloped reserves reported on this table represent net reserves. Net reserves are the company’s share of reserves after deducting the shares of mineral owners or governments or both. All reported reserves are located in Canada. Reserves of natural gas are calculated at a pressure of 14.73 pounds per square inch at 60°F.
(2)
Heavy oil reserves typically are represented by crude oils with a viscosity of greater than 10,000 cP and recovered through enhanced thermal operations. Currently, the company’s heavy oil reserves are from the Cold Lake production operations.
The information on the previous page describes changes during the years and balances of proved oil and gas and reserves at year-end 2004, 2005 and 2006. The definitions used for oil and gas reserves are in accordance with the U.S. Securities and Exchange Commission’s (SEC) Rule 4-10 (a) of Regulation S-X, paragraphs (2), (3) and (4).
Crude oil and natural gas reserve estimates, are based on geological and engineering data, which have demonstrated with reasonable certainty that these reserves are recoverable in future years from known reservoirs under existing economic and operating conditions, i.e., prices and costs as of the date the estimate is made. Beginning in 2004, the year-end reserves volumes as well as the reserves change categories shown in the proved reserves tables are calculated using December 31 prices and costs. These reserves quantities are also used in calculating unit-of-production depreciation rates and in calculating the standardized measure of discounted net cash flow. Regulations preclude the company from showing in this document the reserves that are calculated in a manner which is consistent with the basis that the company uses to make its investment decisions. The use of year-end prices for reserves estimation introduces short-term price volatility into the process since annual adjustments are required based on prices occurring on a single day. The company believes that this approach is inconsistent with the long-term nature of the natural resources business where production from individual projects often spans multiple decades. The use of prices from a single date is not relevant to the investment decisions made by the company and annual variations in reserves based on such year-end prices are not of consequence to how the business is actually managed.
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 year-end prices and costs that are used in the determination of reserves. This category can also include changes associated with the performance of improved recovery projects and significant changes in either development strategy or production equipment/facility capacity.
Net proved reserves are determined by deducting the estimated future share of mineral owners or governments or both. For conventional crude oil (excluding enhanced oil-recovery projects) and natural gas, net proved reserves are based on estimated future royalty rates representative of those existing as of the date the estimate is made. Actual future royalty rates may vary with production and price. For enhanced oil-recovery projects and Cold Lake, net proved reserves are based on the company’s best estimate of average royalty rates over the life of each project. Actual future royalty rates may vary with production, price and costs.
Reserves data do not include crude oil and natural gas, such as those discovered in the Beaufort Sea-Mackenzie Delta and the Arctic islands, or the heavy oil and oil sands, other than reserves attributable to commercial phases of Cold Lake production operations.
Oil-equivalent barrels (OEB) may be misleading, particularly if used in isolation. An OEB conversion ratio of 6,000 cubic feet to one barrel on an energy-equivalent conversion method is primarily applicable at the burner tip and does not represent a value equivalency at the well head. No independent qualified reserves evaluator or auditor was involved in the preparation of the reserves data.
Net proved developed and undeveloped reserves of crude oil and natural gas as of December 31 (1)
(1)
Net reserves are the company’s share of reserves after deducting the shares of mineral owners or governments or both.
Net proved developed reserves of crude oil and natural gas as of December 31(1)
(1)
Net reserves are the company’s share of reserves after deducting the shares of mineral owners or governments or both.
Standardized measure of discounted future net cash flows related to proved oil and gas reserves
As required by the Financial Accounting Standards Board, the standardized measure of discounted future net cash flows is computed by applying year end prices, 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 year end prices, which represent a single point in time and therefore may cause significant variability in cash flows from year to year as prices change. The table below excludes the company’s interest in Syncrude.
Changes in standardized measure of discounted future net cash flows related to proved oil and gas reserves
Within the past 12 months, the company has not filed oil and gas reserve estimates with any authority or agency of the United States.
Item 9.
Item 9. Changes in and Disagreements with Accountants on Accounting and Financial Disclosure.
None.
Item 9A.
Item 9A. Controls and Procedures.
As indicated in the certifications in Exhibit 31.1 and 31.2 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, 2006. Based on that evaluation, these officers have concluded that the company’s disclosure controls and procedures are appropriate and effective for the purpose of ensuring that material information relating to the company, including its consolidated subsidiaries, is made known to them by others within those entities, particularly during the period in which this annual report is being prepared.
Reference is made to page of this report for management’s report on internal control over financial reporting.
Reference is made to page of this report for the report of the independent registered public accounting firm on management’s assessment on internal control over financial reporting.
There has not been any change in the company’s internal control over financial reporting that occurred during the company’s fourth fiscal quarter of 2006 that has materially affected, or is reasonably likely to materially affect, the company’s internal control over financial reporting.
PART III
Item 10.
Item 10. Directors and Executive Officers of the Registrant.
The company currently has eight directors. Each director is elected to hold office until the close of the next annual meeting.
Each of the eight directors listed below has been nominated for re-election at the annual meeting of shareholders to be held May 1, 2007. All of the nominees are now directors and have been since the dates indicated.
The following table provides information on the nominees for election as directors.
(Table continued on following page)
(1)
Member of audit committee; member of environment, health and safety committee; member of executive resources committee; and member of nominations and corporate governance committee.
(2)
Member of Imperial Oil Foundation board of directors
(3)
The information includes the beneficial ownership of common shares of Imperial Oil Limited and shares of Exxon Mobil Corporation, which information not being within the knowledge of the company, has been provided by the nominees individually.
(4)
The company’s plans for deferred share units and restricted stock units for selected employees and nonemployee directors are described on page 45 and pages 46 and 47, respectively.
(5)
The numbers for restricted stock units and deferred share units represent the total of the restricted stock units and deferred share units received in 2006 after the three-for-one share split in May 2006, plus three times the number of restricted stock units and deferred share units granted before the share split and still held by the director.
(6)
R.L. Broiles holds 16,641 common shares and 43,000 restricted shares of Exxon Mobil Corporation.
The ages of the directors, nominees for election as directors, and the five senior executives of the company are: Randy L. Broiles 49, Timothy J. Hearn 62, Jack M. Mintz 55, Roger Phillips 67, James F. Shepard 68, Paul A. Smith 53, Sheelagh D. Whittaker 59, Victor L. Young 61, Rob F. Lipsett 60, and John F. Kyle 64.
Certain of the directors hold positions as directors of other Canadian and U.S. reporting issuers as follows: Timothy J. Hearn - Royal Bank of Canada; Jack M. Mintz - Brookfield Asset Management Inc. and CHC Helicopter Corporation; Roger Phillips - Canadian Pacific Railway Company, Canadian Pacific Railway Limited, Cleveland-
Cliffs Inc. and The Toronto-Dominion Bank; Sheelagh D. Whittaker - CanWest Media Works Income Fund; and Victor L. Young - Bell Aliant Regional Communications Income Fund, BCE Inc. and Royal Bank of Canada.
All of the directors and nominees for election as directors, except for Jack M. Mintz and Sheelagh D. Whittaker have been engaged for more than five years in their present principal occupations or in other executive capacities with the same firm or affiliated firms. During the five preceding years, Jack M. Mintz was president and chief executive officer of The C.D. Howe Institute until he retired in July 2006 and Sheelagh D. Whittaker was managing director of Electronic Data Systems until she retired in November 2005.
The following table provides information on the senior executives of the company.
All of the above senior executives have been engaged for more than five years at their current occupations or in other executive capacities with the company or its affiliates. All senior executives hold office until their appointment is rescinded by the directors, or by the chief executive officer.
Audit committee
The company has an audit committee of the board of directors. The following directors are the members of the audit committee: R. Phillips, J.F. Shepard, S.D. Whittaker, V.L. Young, and J.M. Mintz.
Audit committee financial expert
The company’s board of directors has determined that R. Phillips, S.D. Whittaker and V.L. Young meet the definition of “audit committee financial expert” and that they, J.F. Shepard and J.M. Mintz are independent, as that term is defined in Multilateral Instrument 52-110, the Securities and Exchange Commission rules and the listing standards of the American Stock Exchange and the New York Stock Exchange. The Securities and Exchange Commission has indicated that the designation of an audit committee financial expert does not make that person an expert for any purpose, or impose any duties, obligations or liability on that person that are greater than those imposed on members of the audit committee and board of directors in the absence of such designation or identification.
Code of ethics
The company has a code of ethics that applies to all employees, including its principal executive officer, principal financial officer and principal accounting officer. The code of ethics consists of the company’s ethics policy, conflicts of interest policy, corporate assets policy, directorships policy, and procedures and open door communication. Those documents are available at the company’s web site www.imperialoil.ca.
Item 11.
Item 11. Executive Compensation.
Composition of the company’s compensation committee
The executive resources committee of the board of directors, composed of the independent directors, 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. During 2006, the membership of the executive resources committee was as follows:
R. Phillips - Chair
V.L. Young - Vice-chair
J.F. Shepard
S.D. Whittaker
J.M. Mintz
T.J. Hearn periodically attends meetings at the request of the committee.
Executive Resources Committee Report on Executive Compensation
Compensation Discussion and Analysis
The company’s executive compensation program is designed to reinforce the company’s orientation toward career employment and individual performance. It acknowledges the long-term nature of the company’s business and its philosophy that the experience, skill and motivation of the company’s executives are significant determinants of future business success. The compensation program emphasizes competitive salaries and performance-based incentives as the primary instruments to develop and retain key personnel.
The assessment of individual performance is conducted through the company’s employee appraisal program. The appraisal program is a disciplined annual program that assesses business performance measures relevant to each employee, including the means by which performance is achieved, and involves comparative ranking of employee performance using a standard process throughout the organization and at all levels. The appraisal program is integrated with the compensation program and also with the executive development process which has been in place for more than 50 years and is the basis for planning individual development and succession planning for management positions.
In establishing compensation for the company’s senior executives, the executive resources committee relies on market comparisons to a group of 25 major Canadian companies with revenues in excess of $1 billion a year. These market comparisons are prepared by independent external compensation consultants. On a case-by-case basis, depending on the scope of market coverage represented by a particular comparison, compensation is targeted to a range between the mid-point and the upper quartile of comparable employers, reflecting the company’s emphasis on quality management.
The company’s executive compensation program is composed of base salaries, cash bonuses and medium/long-term incentive compensation.
Base Salary
The company’s salary ranges for executives were increased by 1.5 percent in 2005, 2.5 percent in 2006 and eight percent in 2007. The larger increase in 2007 was required to maintain 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.
Cash Bonus
Cash bonuses are typically granted to about 80 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.
In 2006, the overall bonus pool was increased by 7.5 percent over the previous year to reflect improved financial results and operating performance. In relation to this, the company’s net income for 2006 was a record $3.044 billion (up 17 percent ), return on shareholders’ equity was 44 percent, return on capital employed was 36 percent and total annual shareholders’ return was 13 percent. Changes in individual cash bonus awards vary depending on each executive’s performance assessment.
Medium/Long-Term Incentive Compensation
A medium-term incentive compensation plan, called the earnings bonus unit plan, was introduced in 2001 and continues in use today. This plan is 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 to approximately 80 executives annually. In 2006, each earnings bonus unit entitles the recipient to receive an amount equal to the company’s cumulative net earnings per common share as announced each quarter beginning after the grant. Payout occurs after the fifth anniversary of the grant, or when the maximum settlement value per unit is reached, if earlier. If after five years the maximum payout has not been reached, payout will be prorated. In 2006, similar to the cash bonus pool, the earnings bonus units pool was increased by 7.5 percent over the previous year.
In December 2002, the company introduced a restricted stock unit plan, which is the company’s long-term incentive compensation plan. The purpose of the plan is to align the interests of selected employees and non employee directors directly with the interests of shareholders. The restricted stock unit plan is a straightforward, primarily cash-based approach to long-term incentive compensation.
Grant level guidelines for the restricted stock unit program are generally held constant for long periods of time. 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 past 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 compared to earlier years.
Each unit granted in 2006 entitles the recipient to receive from the company, upon exercise, an amount equal to the five day average of the closing price of the company’s shares preceding the exercise dates. Fifty percent of the units will be exercised by the company on the third anniversary of the grant date, and the remainder will be exercised on the seventh anniversary of the grant date. Recipients may receive the proceeds of the seventh year exercise as either one common share per unit or elect a cash payment. The company also pays 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.
In 2006, 964 employees were granted restricted stock units, including 92 executives.
CEO compensation
T.J. Hearn’s salary is currently assessed to be within the range of the competitive target for the company’s chairman, president and chief executive officer, namely, between the median and upper quartile of the competitive market. The target is consistent with the executive resources committee’s view that the chairman, president and chief executive officer’s salary should be above the average of salaries for chief executive officers of major Canadian companies, reflecting the company’s executive development philosophy and the significance placed on experience and judgment in leading a large, complex operation.
In the case of T.J. Hearn, the committee’s approach to cash bonuses is based on the company’s financial and operating performance and on the committee’s assessment of T.J. Hearn’s effectiveness in leading the organization. The continuing progress being made in focusing the organization on advancing key strategic interests, safety, environmental performance, productivity, cost effectiveness and asset management were primary considerations in determining a cash bonus for the chairman, president and chief executive officer. T.J. Hearn’s cash bonus was increased by 11 percent in 2006 to reflect his effectiveness in the position, the company’s record financial performance and comparisons to other leading Canadian employers.
With respect to the company’s medium term incentive program, the committee similarly awarded Mr. Hearn an 11 percent increase in his earnings bonus unit award compared to 2005 for the same reasons noted above for Mr. Hearn’s cash bonus award.
For 2006, the committee adjusted the restricted stock unit grant for T.J. Hearn on an approximately two-for-one basis, as compared to the share split of three-for-one. This was consistent with the treatment for all other high performing executives and had the effect of reducing the award value on the grant date for T.J. Hearn.
Directors’ compensation
Directors’ fees are paid only to non-employee directors. For 2006, non-employee directors were paid an annual retainer of $35,000 and 3,000 restricted stock units for their services as directors, plus an annual retainer of $4,500 for each committee on which they served, an additional $5,000 for serving as chair of a committee and $2,000 for each board and board committee meeting attended. The restricted stock units issued to non-employee directors have the same features as the restricted stock units for selected key employees described on pages 46 and 47.
Starting in 1999, the non-employee directors have been able to receive all or part of their directors’ fees in the form of deferred share units for non-employee directors. The purpose of the deferred share unit plan for non-employee 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. This plan is described on page 45.
While serving as directors in 2006, the aggregate cash remuneration paid to non-employee directors, as a group, was $418,125, and they received an additional 4,953 deferred share units, based on an aggregate of $234,375 of cash remuneration elected to be received as deferred share units. The non-employee directors, as a group, received an additional 444 deferred share units granted as the equivalent to the cash dividend paid on company shares during 2006 for previously granted deferred share units. In addition, the non-employee directors received 15,000 restricted stock units.
Senior executive compensation
Summary Compensation Table
The following table shows the compensation for the chairman, president and chief executive officer and the four other senior executives of the company who were serving as senior executives at the end of 2006. This information includes the dollar value of base salaries, cash bonus awards, and units of other long term incentive compensation and certain other compensation.
(7)
Payouts were from 2005 earnings bonus unit that reached maximum value of $4.50 per unit in 2006. That plan is described on page 46. R.L. Broiles participates in Exxon Mobil Corporation’s earnings bonus unit plan, which is similar to the company’s earnings bonus unit plan.
(8)
Amounts under “All Other Compensation”, except for R.L. Broiles, are the company’s contributions to the savings plan, which is a plan available to all employees. Under one of the options of that plan to which the senior executives subscribe, except for R.L. Broiles, the company matched employee contributions up to six percent of base salary per year; however, an employee may elect to receive an enhanced pension under the company’s pension plan by foregoing three percent of the company’s matching contributions. The plan is intended to be primarily for retirement savings, although employees may withdraw their contributions prior to retirement. For R.L. Broiles, the amount is Exxon Mobil Corporation’s contributions to its employee savings plan.
(9)
“Total Compensation” for each of 2004, 2005 and 2006 consists of the total dollar value of Salary, Bonus, Other Annual Compensation, Shares or Units Subject to Resale Restrictions, LTIP Payouts and All Other Compensation for each such year.
Earnings Bonus Unit Plan - awards in most recently completed financial year
The following table provides information on earnings bonus units granted in 2006 to the named senior executives. The earnings bonus unit plan is described in more detail on page 46.
(1)
Payment will be made earlier when the cumulative net earnings per outstanding common share reach the maximum settlement value per unit prior to the fifth anniversary of the grant date.
(2)
This is the maximum settlement value payable per earnings bonus unit granted in 2006.
(3)
R.L. Broiles participates in Exxon Mobil Corporation’s earnings bonus unit plan which is similar to the company’s earnings bonus unit plan. In 2006, R.L Broiles was granted 37,474 units under that plan for which the maximum settlement value payable per earnings bonus unit is $4.25 U.S.
Aggregated option/SAR exercises during the most recently completed financial year and financial year end option/SAR values
The following table provides information on the exercise in 2006 and the aggregate holdings at the end of 2006 of incentive share units (referred to in the table as “SARs”) by the named senior executives. The incentive share unit plan is described in more detail on page 45. The number of incentive share units in the table below is equal to three times the number of incentive share units held before the three-for-one share split in May 2006.
(1)
Unexercisable units are units for which the conditions for exercise have not been met.
The following table provides information on the exercise in 2006 and the aggregate holdings at the end of 2006 of stock options by the named senior executives. The stock option plan is described in more detail on page 46.
Details of long-term and medium-term incentive compensation
Consistent with the company’s compensation philosophy of being performance driven, long-term incentive compensation is granted to retain selected employees and reward them for high performance.
The assessment of employee performance is conducted through the company’s appraisal program. The appraisal program is a disciplined annual program that assesses business performance measures relevant to eligible employees and involves ranking of employee performance using a consistent process throughout the organization at all levels. The number of units received by each employee is tied to the performance of the employee in achieving these business performance measures. The scope of the company program is determined by the overall performance of the company each year.
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.
In 1998, an additional form of long-term incentive compensation (“deferred share units”) was made available to selected executives whose decisions are considered to have a direct effect on the long term financial performance of the company. They can elect to receive all or part of their cash bonus compensation in the form of such units. The number of units granted to an executive is determined by dividing the amount of the executive’s bonus elected to be received as deferred share units by the average of the closing prices of the company’s shares on the Toronto Stock Exchange for the five consecutive trading days (“average closing price”) immediately prior to the date that the bonus would have been paid to the executive. Additional units will be granted to recipients of these units, in respect of unexercised units, based on the cash dividend payable on the company 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. An executive may not exercise these units until after termination of employment with the company and must exercise the units no later than December 31 of the year following termination of employment with the company. The units held must all be exercised on the same date. On the date of exercise, the cash value to be received for the units will be determined by multiplying the number of units exercised by the average closing price immediately prior to the date of exercise. In 2006, no executive elected to receive deferred share units.
Starting in 1999, a form of long-term incentive compensation, similar to the deferred share units for executives, was made available to nonemployee directors in lieu of their receiving all or part of their directors’ fees. The main differences between the two plans are that all nonemployee directors are allowed to participate in the plan for nonemployee directors and that the number of units granted to a nonemployee director is determined at the end of each calendar quarter by dividing the amount of the directors’ fees for that calendar quarter that the nonemployee
director elected to receive as deferred share units by the average closing price immediately prior to the last day of the calendar quarter.
Starting in 2001, a medium-term incentive compensation plan was introduced, called the earnings bonus unit plan. This plan was made available to selected executives to promote individual contribution to sustained improvement in the company’s business performance and shareholder value. Each earnings bonus unit entitles the recipient to receive an amount equal to the company’s cumulative net earnings per common share as announced each quarter beginning after the grant. Payout occurs on the fifth anniversary of the grant or when the maximum settlement value per unit is reached, if earlier. If after five years the maximum settlement has not been reached, payout will be prorated.
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 selected 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 after April 29, 2012. As of February 15, 2007, there have been 4,139,439 common shares issued upon exercise of stock options and 5,426,811 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 1.0 percent of the company’s currently outstanding common shares. The company’s directors, officers and vice-presidents as a group hold 9.7 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 165,000 common shares, which is about 0.02 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.
In December 2002, the company introduced a restricted stock unit plan, which will be the primary long-term incentive compensation plan in future years. The purpose of the plan is to align the interests of the selected key employees and nonemployee directors directly with the interests of shareholders. Each unit entitles the recipient the right to receive from the company, upon exercise, an amount equal to the closing price of the company’s shares on the exercise dates. 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 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 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. A total of 1,935,658 units were granted on December 4, 2006.
There are 6,230,974 common shares issuable upon future exercise of restricted stock units, which represent about 0.66 percent of the company’s currently outstanding common shares. The company’s directors, officers and vice-presidents have available, as a group, 19 percent of the common shares issuable under outstanding restricted stock units. The maximum number of common shares that any one person may receive from the exercise of outstanding restricted stock units is 423,200 common shares, which is about 0.04 percent of the currently outstanding common shares.
Restricted stock units will be exercised only during employment except in the event of death, disability or retirement. Also, restricted stock units 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 restricted stock units will not be forfeited after the cessation of employment. 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. Effective December 31, 2004, the restricted stock unit plan was amended by the company to provide that on retirement the company shall determine whether the employee’s restricted stock units will not be forfeited. Effective August 2, 2006, the restricted stock unit plan was amended by the company to change the exercise price under the plan from a single day’s closing price to a five-day average and to change exercise dates under the plan from December 31 to December 4 with respect to restricted stock units granted in prior years. Shareholder approval for these changes was not required by the Toronto Stock Exchange.
Payments to Employees Who Retire
Pension Plan Table
The company’s pension plan applies to almost all employees. The plan provides an annual pension of a specific percentage of an employee’s “final three year average earnings”, multiplied by the employee’s years of service, subject to certain requirements concerning age and length of service. An employee may elect to forego three of the six percent of the company’s contributions to the savings plan under one of the options of that plan (except for R.L. Broiles), to receive an enhanced pension 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. In addition to the pension payable under the plan, the company has paid and may continue to pay a supplemental retirement income to employees who have earned a pension in excess of the maximum pension under the Income Tax Act. The pension plan table on this page shows estimated undiscounted annual payments, consisting of pension and supplemental retirement income, payable on retirement to the senior executives in specified classifications of remuneration and years of service currently applicable to that group.
The remuneration used to determine the payments on retirement to the individuals named in the summary compensation table on page 42 corresponds generally to the salary, bonus compensation and bonus compensation amount elected to be received as deferred share units in that table. The aggregate maximum settlement value that could be paid for earnings bonus units granted shown in the table on page 44 is also included in the employee’s “final three year average earnings” for the year of grant of such units. As of February 15, 2007, the number of completed years of service with Imperial Oil Limited used to determine payments on retirement was 40 for T.J. Hearn, 26 for P.A. Smith, 37 for R.F. Lipsett and 30 for J.F. Kyle.
R.L. Broiles is not a member of the company’s pension plan, but is a member of Exxon Mobil Corporation’s pension plan. Under that plan, R.L. Broiles has 27 years of service and he will receive a pension payable in U.S. dollars. The remuneration used to determine the payment on retirement to him also corresponds generally to his salary extended on a full year basis and bonus compensation in the summary compensation table on page 42, which total may be applied to the pension plan table above but with the dollars in that table representing U.S. rather than Canadian dollars.
Executive Pension Value Disclosure (1) (2)
Item 12.
Item 12. Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters.
To the knowledge of the management of the company, the only shareholder who, as of February 15, 2007, owned beneficially, or exercised control or direction over, more than five percent of the outstanding common shares of the company is Exxon Mobil Corporation, 5959 Las Colinas Boulevard, Irving, Texas 75039-2298, which owns beneficially 661,175,328 common shares, representing 69.6 percent of the outstanding voting shares of the company.
Reference is made to the security ownership information under the preceding Items 10 and 11. As of February 15, 2007, R.F. Lipsett was the owner of 4,163 common shares of the company, held options to acquire 75,000 common shares of the company and held 154,650 restricted share units of the company. As of February 15, 2006, J.F. Kyle was the owner of 12,215 common shares of the company, held options to acquire 57,000 common shares of the company and held 127,300 restricted share units of the company.
The directors and the senior executives of the company consist of 10 persons, who, as a group, own beneficially 155,346 common shares of the company, being approximately 0.02 percent of the total number of outstanding shares of the company, and 72,937 shares of Exxon Mobil Corporation. This information not being within the knowledge of the company has been provided by the directors and the senior executives individually. As a group, the directors and senior executives of the company held options to acquire 372,000 common shares of the company and held restricted stock units to acquire 1,196,225 common shares of the company, as of February 15, 2007.
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 2006 pursuant to compensation plans of the company.
(1)
This is a stock option plan, which is described on page 46.
(2)
This is a restricted stock unit plan, which is described on page 46 and 47.
(3)
The number of securities reserved for the stock option plan represents three times the number of stock options granted before the three-for-one share split in May 2006 and still outstanding. The number of securities reserved for the restricted stock unit plan represent the securities reserved for restricted stock units issued in 2006 after the three-for-one share split in May 2006, plus three times the number of securities reserved for restricted stock units issued before the share split and still outstanding. The weighted average exercise price of the outstanding stock options of $15.50 was determined on a post share split basis.
Item 13.
Item 13. Certain Relationships and Related Transactions.
On June 23, 2005, the company implemented another 12-month “normal course” share-purchase program under which it purchased 50,251,542 of its outstanding shares between June 23, 2005 and June 22, 2006. On June 23, 2006, another 12-month “normal course” program was implemented under which the company may purchase up to 48,772,466 of its outstanding shares, less any shares purchased by the employee savings plan and company pension fund. Exxon Mobil Corporation participated by selling shares to maintain its ownership at 69.6 percent. In 2006, such purchases cost $1,817 million, of which $1,247 million was received by Exxon Mobil Corporation.
During 2003, the company borrowed $818 million from an affiliated company of Exxon Mobil Corporation under two long term loan agreements at interest equivalent to Canadian market rates. Interest on the loans in 2006 was $34 million. The average effective interest rate for the loans was 4.2 percent for 2006.
The amounts of purchases and sales by the company and its subsidiaries for other transactions in 2006 with Exxon Mobil Corporation and affiliates of Exxon Mobil Corporation were $4,292 million and $1,948 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, petroleum and chemical products, as well as transportation, technical and engineering services. Transactions with Exxon Mobil Corporation also included amounts paid and received in connection with the company’s participation in a number of natural resources activities conducted jointly in Canada. The company has 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. During 2005, the company and an affiliate of Exxon Mobil Corporation in Canada agreed to operate their respective Western Canada production organizations as one single organization. Under the consolidation, the company will operate all Western Canada properties. There are no asset ownership changes.
Item 14.
Item 14. Principal Accountant Fees and Services.
Auditor Fees
The aggregate fees of the company’s auditors for professional services rendered for the audit of the company’s financial statements and other services for the fiscal years ended December 31, 2006 and December 31, 2005 were as follows:
Audit fees include the audit of the company’s annual financial statements, audit of management’s report on internal control over financial reporting, and a review of the first three quarterly financial statements in 2006.
Audit-related fees include other assurance services including the audit of the company’s retirement plan and royalty statement audits for oil and gas producing entities.
Tax fees are mainly tax services for employees on foreign loan assignments.
The company did not engage the auditors for any other services.
The audit committee recommends the external auditors to be appointed by the shareholders, fixes their remuneration and oversees their work. The audit committee also approves the proposed current year audit program of the external auditors, 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 auditors after considering the effect of such services on their independence.
All of the services rendered by the auditors to the company were approved by the audit committee.
PART IV
Item 15.
Item 15. Exhibits and Financial Statement Schedules.
Reference is made to the Index to Financial Statements on page of this report.
The following exhibits numbered in accordance with Item 601 of Regulation S-K are filed as part of this report:
(21)
Imperial Oil Resources Limited, McColl-Frontenac Petroleum Inc., Imperial Oil Resources N.W.T. Limited and Imperial Oil Resources Ventures Limited, all incorporated in Canada, are wholly-owned subsidiaries of the company. The names of all other subsidiaries of the company are omitted because, considered in the aggregate as a single subsidiary, they would not constitute a significant subsidiary as of December 31, 2006.
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.
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 27, 2007 by the undersigned, thereunto duly authorized.
Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below on February 27, 2007 by the following persons on behalf of the registrant and in the capacities indicated.
Signature
Title
/s/ T.J. Hearn
(Timothy J. Hearn)
Chairman of the Board, President, Chief Executive Officer and Director (Principal Executive Officer)
/s/ Paul A. Smith
(Paul A. Smith)
Controller and Senior Vice-President, Finance and Administration and Director (Principal Accounting Officer and Principal Financial Officer)
/s/ R.L. Broiles
(Randy L. Broiles)
Director
/s/ J.M. Mintz
(Jack M. Mintz)
Director
/s/ Roger Phillips
(Roger Phillips)
Director
/s/ J.F. Shepard
(James F. Shepard)
Director
/s/ Sheelagh D. Whittaker
(Sheelagh D. Whittaker)
Director
/s/ V.L. Young
Director
(Victor L. Young)
MANAGEMENT’S REPORT ON INTERNAL CONTROL OVER FINANCIAL REPORTING
Management, including the company’s chief executive officer, and principal accounting officer and principal financial officer, is responsible for establishing and maintaining adequate internal control over the company’s financial reporting. Management conducted an evaluation of the effectiveness of internal control over financial reporting based on the 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, 2006.
Management’s assessment of the effectiveness of internal control over financial reporting as of December 31, 2006, was audited by PricewaterhouseCoopers LLP, an independent registered public accounting firm, as stated in their report which is included herein.
REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
To the Shareholders of Imperial Oil Limited
We have completed integrated audits of Imperial Oil Limited’s consolidated financial statements and of its internal control over financial reporting as of December 31, 2006, in accordance with the standards of the Public Company Accounting Oversight Board (United States). Our opinions, based on our audits, are presented below.
Consolidated financial statements
In our opinion, the accompanying consolidated financial statements in the Form 10-K present fairly, in all material respects, the financial position of Imperial Oil Limited and its subsidiaries at December 31, 2006, and 2005, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 2006 in conformity with accounting principles generally accepted in the United States of America. These financial statements are the responsibility of the company’s management. Our responsibility is to express an opinion on these financial statements based on our audits. We conducted our audits of these statements in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit of financial statements includes 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. We believe that our audits provide a reasonable basis for our opinion.
Internal control over financial reporting
Also, in our opinion, management’s assessment, included in the accompanying Management’s Report on Internal Control Over Financial Reporting, that the company maintained effective internal control over financial reporting as of December 31, 2006, based on criteria established in Internal Control - Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO), is fairly stated, in all material respects, based on those criteria. Furthermore, in our opinion, the company maintained, in all material respects, effective internal control over financial reporting as of December 31, 2006, based on criteria established in Internal Control - Integrated Framework issued by the COSO. The company’s management is responsible for maintaining effective internal control over financial reporting and for its assessment of the effectiveness of internal control over financial reporting. Our responsibility is to express opinions on management’s assessment and on the effectiveness of the company’s internal control over financial reporting based on our audit. We conducted our audit of internal control over financial reporting in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether effective internal control over financial reporting was maintained in all material respects. An audit of internal control over financial reporting includes obtaining an understanding of internal control over financial reporting, evaluating management’s assessment, testing and evaluating the design and operating effectiveness of internal control, and performing such other procedures as we consider necessary in the circumstances. We believe that our audit provides 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.
/s/ PricewaterhouseCoopers LLP
Chartered Accountants
Calgary, Alberta, Canada
February 27, 2007
Consolidated statement of income
The information on pages through is an integral part of these consolidated financial statements.
Consolidated statement of cash flows
The information on pages through is an integral part of these consolidated financial statements.
Consolidated balance sheet
The information on pages through is an integral part of these consolidated financial statements.
Approved by the directors
/s/ T.J. Hearn
/s/ Paul A. Smith
Chairman, president and
Controller and senior vice-president,
chief executive officer
finance and administration
Consolidated statement of shareholders’ equity
The information on pages through is an integral part of these consolidated financial statements.
Notes to consolidated financial statements
1.
Summary of significant accounting policies
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 (GAAP) in the United States of America. The financial statements include certain estimates that reflect management’s best judgment. Certain reclassifications to prior years have been made to conform to the 2006 presentation. All amounts are in Canadian dollars unless otherwise indicated.
Principles of consolidation
The consolidated financial statements include the accounts of Imperial Oil Limited and its subsidiaries. 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 activities in natural resources 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.
Inventories
Inventories are recorded at the lower of cost or net realizable 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 principal investments in companies other than subsidiaries 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. The company carries as an asset exploratory well costs if (a) the well found a sufficient quantity of reserves to justify its completion as a producing well and (b) 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 were charged to expense. Costs of productive wells and development dry holes are capitalized and amortized on the unit-of-production method for each field. The company uses this accounting policy instead of the full-cost method because it provides a more timely accounting of the success or failure of the company’s exploration and production activities.
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.
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. Acquisition costs of proved properties are amortized using a unit-of-production method, computed on the basis of total proved oil and gas reserves. 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 commodity prices and foreign-
currency exchange rates. Annual volumes are based on individual field production profiles, which are also updated annually. Prices for natural gas and other products sold under contract are based on corporate plan assumptions developed annually by major contracts and also for investment evaluation purposes.
In general, impairment analyses are based on proved reserves. 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.
Acquisition costs for the company’s oil sands (a) operation are capitalized as incurred. Oil sands exploration costs are expensed as incurred. The capitalization of project development costs begins when there are no major uncertainties that exist which would preclude management from making a significant funding commitment within a reasonable time period. The company expenses stripping costs during the production phase as incurred.
Depreciation of oil sands assets begins at the time when production commences on a regular basis. Assets under construction are not depreciated. Investments in extraction facilities, which separate the crude from sand, as well as the upgrading facilities, are depreciated on a unit-of-production method based on proven developed reserves. Investments in mining and transportation systems are generally depreciated on a straight-line basis over a 15-year life.
Oil sands assets held and used by the company are reviewed for impairment whenever events or changes in circumstances indicate that the carrying amounts are not recoverable. The impairment evaluation for oil sands assets is based on a comparison of undiscounted cash flows to book carrying value.
Gains or losses on assets sold are included in “investment and other income” in the consolidated statement of income.
(a) Oil sands are a semi-solid material composed of bitumen, sand, water and clays, which are recovered through surface mining methods. Currently, the company’s oil sands production volumes and reserves include the company’s share of production volumes and reserves in the Syncrude joint venture.
Interest capitalization
Interest costs relating to major capital projects under construction are capitalized as part of property, plant and equipment. The project construction phase commences with the development of the detailed engineering design and ends when the constructed assets are ready for their intended use.
Goodwill and other intangible assets
Goodwill is not subject to amortization. Goodwill is tested for impairment annually or more frequently if events or circumstances indicate it might be impaired. Impairment losses are recognized in current period earnings. The evaluation for impairment of goodwill is based on a comparison of the carrying values of goodwill and associated operating assets with the estimated present value of net cash flows from those operating assets.
Intangible assets with determinable useful lives are amortized over the estimated service lives of the assets. Computer software development costs are amortized over a maximum of 15 years and customer lists are amortized over a maximum of 10 years. The amortization is included in “depreciation and depletion” in the consolidated statement of income.
Asset retirement obligations and other environmental liabilities
Legal obligations associated with site restoration on the retirement of assets with determinable useful lives are recognized when they are incurred, which is typically at the time the assets are installed. These obligations primarily relate to soil remediation and decommissioning and removal costs of oil and gas wells and related facilities. 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. These liabilities are not discounted. Asset retirement obligations and other 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.
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.
Financial instruments
The fair values of cash, accounts receivable and current liabilities approximate recorded amounts because of the short period to receipt or payment of cash. The fair value of the company’s long-term debt is estimated based on quoted market prices for the same or similar issues or on the current rates offered to the company for debt of the same duration to maturity. The fair values of the company’s other financial instruments, which are mainly long-term receivables, are estimated primarily by discounting future cash flows, using current rates for similar financial instruments under similar credit risk and maturity conditions.
The company does not use financing structures for the purpose of altering accounting outcomes or removing debt from the balance sheet. The company does not use derivative instruments to speculate on the future direction of currency or commodity prices and does not sell forward any part of production from any business segment.
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 collectibility 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.
Notes to consolidated financial statements (continued)
Effective January 1, 2006, the company adopted the Emerging Issues Task Force (EITF) consensus on Issue No. 04-13, “Accounting for Purchases and Sales of Inventory with the Same Counterparty”. The EITF concluded that purchases and sales of inventory with the same counterparty that are entered into in contemplation of one another should be combined and recorded as exchanges measured at the book value of the item sold. In prior periods, the company recorded certain crude oil, natural gas, petroleum product and chemical sales and purchases contemporaneously negotiated with the same counterparty as revenues and purchases. As a result of the EITF consensus, beginning in 2006, the company’s accounts “operating revenue” and “purchases of crude oil and products” on the consolidated statement of income have been reduced by associated amounts with no impact on net income. All operating segments are affected by this change, with the largest impact in the petroleum products segment.
Share-based compensation
Effective January 1, 2006, the company adopted the Financial Accounting Standards Board’s (FASB) revised Statement of Financial Accounting Standards No. 123 (SFAS 123R), “Share-based Payment”. SFAS 123R requires compensation costs related to share-based payments to be recognized in the income statement over the requisite service period. The amount of the compensation costs is to be measured based on the grant-date fair value of the instrument issued. In addition, liability awards are to be remeasured each reporting period through settlement. SFAS 123R is effective for awards granted or modified after the date of adoption and for awards granted prior to that date that have not vested. In 2003, the company adopted a policy of expensing all share-based payments that is consistent with the provisions of SFAS 123R, and all prior years outstanding stock option awards have vested. SFAS 123R does not materially change the company’s existing accounting practices or the amount of share-based compensation recognized in earnings. Compensation expense related to share-based programs is recorded as “selling and general” expenses in the consolidated statement of income.
The company has recognized restricted stock awards made prior to 2006 in compensation expense using the “nominal vesting period approach”. Under this method, the fair value of the awards has been amortized into compensation expense over the full vesting period of each award. The fair value is remeasured each reporting period through settlement. For awards granted after the company’s adoption of SFAS 123R, compensation expense is recognized using the “non-substantive vesting period approach”. Under this method, the value of the grants is amortized to compensation expense over the shorter of (a) the vesting period of each award or (b) the remaining time period until the employee becomes retiree eligible. Under both methods, the full unamortized value of awards for employees who retire before the end of the applicable amortization period is expensed. The impact of switching to the non-substantive vesting period approach is not material for the company.
As permitted by Statement of Financial Accounting Standard (SFAS) No. 123, the company continues to apply the intrinsic-value-based method of accounting for the incentive stock options granted in April 2002. Under this method, compensation expense is not recognized on the issuance of stock options, as the exercise price is equal to the market value at the date of grant. If the provisions of SFAS 123 had been adopted for all prior years, net income for 2004 would have been reduced by $2 million. The impact on net income per share on both a basic and diluted basis for 2004 was negligible. All incentive stock options have vested as of January 1, 2005.
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 and the federal goods and services tax.
2.
Accounting change for defined benefit post-retirement plans
In September 2006, the FASB issued Statement of Financial Accounting Standards No. 158 (SFAS 158), “Employers’ Accounting for Defined Benefit Pension and Other Post-retirement Plans, an amendment to FASB Statements No. 87, 88, 106 and 132(R)”. SFAS 158 requires an employer to recognize the overfunded or underfunded status of a defined benefit post-retirement plan as an asset or liability in its balance sheet and to recognize changes in that funded status in the year in which the changes occur through other nonowner changes in equity. The standard also requires disclosure in the notes to the financial statements of additional information, including certain effects on net periodic benefit costs of the next fiscal year that arise from delayed recognition of gains or losses and prior service costs. SFAS 158 was adopted by the company in the financial statements for the year ending December 31, 2006. See note 6, Employee retirement benefits, for further details.
The company operates its business in Canada. The natural resources, petroleum products and chemicals 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 natural resources segment is organized and operates to explore for and ultimately produce crude oil and its equivalent, and natural gas. The petroleum products segment is organized and operates to refine crude oil into petroleum products and the distribution and marketing of these products. The chemicals 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, long-term debt and liabilities associated with incentive compensation and post-retirement benefit liability adjustment. Net income in this segment primarily includes financing costs, interest income and incentive compensation expenses.
Segment accounting policies are the same as those described in this summary of significant accounting policies. Natural resources, petroleum products and chemicals 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.
Notes to consolidated financial statements (continued)
(a)
A significant portion of activities in the natural resources segment is conducted jointly with other companies. The segment includes the company’s share of undivided interest in such activities as follows:
(b)
Includes export sales to the United States, as follows:
(e)
All goodwill has been assigned to the petroleum products segment. There have been no goodwill acquisitions, impairment losses or write-offs due to sales in the past three years.
Deferred income taxes are based on differences between the accounting and tax values of assets and liabilities. These differences in value are remeasured 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:
The operations of the company are complex, and related tax interpretations, regulations and legislation are continually changing. As a result, there are usually some tax matters in question. The company believes the provision made for income taxes is adequate.
6.
Employee retirement benefits
Retirement benefits, which cover almost all retired employees and their surviving spouses, include pension-income and certain health-care and life-insurance benefits. They are met through funded registered retirement plans and through unfunded supplementary benefits that are paid directly to recipients. 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.
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 and service 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.
The benefit obligations and plan assets associated with the company’s defined benefit plans are measured on December 31.
Notes to consolidated financial statements (continued)
(a)
Benefit payments for funded and unfunded plans.
(b)
Benefit payments for funded plan only.
(c)
Fair value of assets less projected benefit obligation shown above.
Effective December 31, 2006, the company adopted SFAS 158, which requires an employer to recognize the overfunded or underfunded status of a defined benefit post-retirement plan as an asset or liability in its balance sheet and to recognize changes in that funded status in the year in which the changes occur through other nonowner changes in equity. In 2006, the amounts recorded in other nonowner changes in equity for net actuarial losses and prior service cost are required by SFAS 158. For 2005, SFAS 87 required an employer to recognize a liability in its balance sheet that was at least equal to the unfunded accumulated benefit obligation for defined benefit pension plans.
Costs for defined contribution plans, primarily the employee savings plan, were $30 million in 2006 (2005 - $30 million; 2004 - $32 million).
A summary of the change in other nonowner changes in equity is shown in the table below:
The impact of adopting SFAS 158 is shown in the table below:
Preceding data on this note conform with current accounting standards that specify use of a discount rate at which post-retirement liabilities could be effectively settled. 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 8.50 percent in 2007 that declines to 4.50 percent by 2012.
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 2006 long-term expected return of 8.25 percent used in the calculations of pension expense compares to an actual rate of return over the past decade of 9.82 percent.
The company’s pension plan asset allocation at December 31, 2005 and 2006, and target allocation for 2007 are as follows:
The company’s investment strategy for benefit 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 total portfolio. The company primarily invests in funds that follow an index-based strategy to achieve its objectives of diversifying risk while minimizing costs. The fund holds Imperial Oil Limited common shares primarily only to the extent necessary to replicate the relevant equity index. Asset-liability studies, or simulations of the interaction of cash flows associated with both assets and liabilities, are periodically used to establish the preferred target asset allocation. The target asset allocation for equity securities reflects the long-term nature of the liability. The balance of the fund is targeted to debt securities.
A summary of pension plans with accumulated benefit obligations in excess of plan assets is shown in the table below:
Notes to consolidated financial statements (continued)
(a)
The company amortizes the net balance of actuarial loss/(gain) over the average remaining service period of active plan participants.
(b)
The company amortizes prior service cost on a straight-line basis as permitted under SFAS 87.
Cash flows
Benefit payments expected in:
In 2007, the company expects to make cash contributions of about $183 million to its pension plan.
Sensitivities
A one percent change in the assumptions at which retirement liabilities could be effectively settled is as follows:
A one percent change in the assumed health-care cost trend rate would have the following effects:
7.
Other long-term obligations
The change in asset retirement obligations liability is as follows:
8.
Derivatives and financial instruments
No energy derivatives, foreign-exchange forward contracts or currency and interest-rate swaps were transacted in the past three years. 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 from the recorded book value.
9.
Share-based incentive compensation programs
Share-based incentive compensation programs are designed to retain selected employees, reward them for high performance and promote individual contribution to sustained improvement in the company’s future business performance and shareholder value.
Incentive share units, deferred share units and restricted stock units
Incentive share units have value if the market price of the company’s common shares when the unit is exercised exceeds the market value when the unit was issued, as adjusted for any share splits. The issue price of incentive share units is the closing price of the company’s shares on the Toronto Stock Exchange on the grant date. Up to 50 percent of the units may be exercised after one year from issuance; an additional 25 percent may be exercised after two years; and the remaining 25 percent may be exercised after three years. Incentive share units are eligible for exercise up to 10 years from issuance. The units may expire earlier if employment is terminated other than by retirement, death or disability.
The deferred share unit plan is made available to selected executives and nonemployee directors. The selected executives can elect to receive all or part of their performance bonus compensation in units and the nonemployee directors can elect to receive all or part of their directors’ fees in units. The number of units granted to executives is determined by dividing the amount of the bonus elected to be received as deferred share units by the average of the closing prices of the company’s shares on the Toronto Stock Exchange for the five consecutive trading days immediately prior to the date that the bonus would have been paid. The number of units granted to a nonemployee director is determined at the end of each calendar quarter by dividing the amount of director’s fees for the calendar quarter that the nonemployee director elected to receive 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 termination of employment with the company or resignation as a director and must be exercised no later than December 31 of the year following termination or 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.
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 are exercised seven years following the grant date. For units granted in 2002 to 2005, the exercise date has been changed from December 31 to December 4 for units exercised in 2006 and subsequent years. For units granted in 2002, 2003, 2004 and 2005 to be exercised subsequent to the company’s 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 the factor of three.
All units require settlement by cash payments with one exception. The restricted stock unit program was amended for units granted in 2002 and future 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.
In accordance with SFAS 123R, the company accounts for these units by using the fair-value-based method. The fair value of awards in the form of incentive share, deferred share and restricted stock units is the market price of the company’s stock, which is the same method of accounting as under SFAS 123. 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 vesting period.
The following table summarizes information about these units for the year ended December 31, 2006:
The compensation expense charged against income for these programs was $133 million, $238 million and $95 million in 2006, 2005, and 2004, respectively. Total income tax benefit recognized in income related to this compensation expense was $45 million, $127 million and $46 million in 2006, 2005 and 2004, respectively. Cash payments of $162 million, $169 million and $64 million for these programs were made in 2006, 2005 and 2004, respectively.
As of December 31, 2006, there was $265 million of total before-tax unrecognized compensation expenses related to nonvested 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 3.9 years. All units under the incentive share and deferred share programs have vested as of December 31, 2006.
Notes to consolidated financial statements (continued)
Incentive stock options
In April 2002, incentive stock options were granted for the purchase of the company’s common shares at an exercise price of $15.50 per share (adjusted to reflect the three-for-one share split). Up to 50 percent of the options may be exercised on or after January 1, 2003; a further 25 percent may be exercised on or after January 1, 2004; and the remaining 25 percent may be exercised on or after January 1, 2005. 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.
As permitted by SFAS 123, the company continues to apply the intrinsic-value-based method of accounting for the incentive stock options granted in April 2002. Under this method, compensation expense is not recognized on the issuance of stock options, as the exercise price is equal to the market value at the date of grant. All incentive stock options have vested as of January 1, 2005.
No compensation expense and no income tax benefit related to stock options were recognized for stock options in 2006, 2005 and 2004. Cash received from stock option exercised in 2006 was $10 million. The aggregate intrinsic value of stock options exercised was $18 million, $43 million and $5 million in 2006, 2005 and 2004, respectively, and for the balance of outstanding stock options is $152 million.
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. The practice is expected to continue.
The following table summarizes information about stock options for the year ended December 31, 2006 :
(a)
Reflects number of units granted, as adjusted for any share splits.
(b)
Adjusted to reflect the three-for-one share split.
Investment and other income includes gains and losses on asset sales as follows:
At December 31, 2006, the company had commitments for non-cancellable operating leases and other long-term agreements that require the following minimum future payments:
Other commitments arising in the normal course of business for operating and capital needs do not materially affect the company’s consolidated financial position.
The company was contingently liable at December 31, 2006, for a maximum of $87 million relating to guarantees for purchasing operating equipment and other assets from its rural marketing associates upon expiry of the associate agreement or the resignation of the associate. The company expects that the fair value of the operating equipment and other assets so purchased would cover the maximum potential amount of future payment under the guarantees.
Various lawsuits are pending against Imperial Oil Limited and its subsidiaries. The company accrues an undiscounted liability for those contingencies where the incurrence of a loss is determined to be probable and the amount can be reasonably estimated. 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 or financial condition. There are no events or uncertainties known to management beyond those already included in reported financial information that would indicate a material change in future operating results or financial condition.
Effective May 23, 2006, the issued common shares of the company were split on a three-for-one basis and the number of authorized shares was increased from 450 million to 1,100 million. The prior period number of shares outstanding and shares purchased, as well as net income and dividends per share, have been adjusted to reflect the three-for one split.
From 1995 to 2005, the company purchased shares under eleven 12-month normal course share purchase programs, as well as an auction tender. On June 23, 2006, another 12-month normal course share purchase program was implemented with an allowable purchase of 48.8 million shares (five percent of the total at June 21, 2006), less any shares purchased by the employee savings plan and company pension fund. The results of these activities are shown below.
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 retained earnings.
The company’s common share activities are summarized below:
The following table provides the calculation of basic and diluted earnings per share:
Notes to consolidated financial statements (continued)
In 2006, net income included an after-tax gain of $14 million (2005 - $5 million gain; 2004 - $23 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, 2006 by $1,509 million (2005 - $1,429 million). Inventories of crude oil and products at year-end consisted of the following:
Research and development costs in 2006 were $73 million (2005 - $68 million; 2004 - $70 million) before investment tax credits earned on these expenditures of $7 million (2005 - $10 million; 2004 - $7 million). Research and development costs are included in expenses due to the uncertainty of future benefits.
Cash flow from operating activities included dividends of $18 million received from equity investments in 2006 (2005 - $21 million; 2004 - $18 million).
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 and petroleum and chemical products, as well as transportation, technical and engineering services. Transactions with ExxonMobil also included amounts paid and received in connection with the company’s participation in a number of natural resources activities conducted jointly in Canada. 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 that 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. This contractual agreement is designed to provide organizational efficiencies and to reduce costs. No separate legal entities were created from this arrangement. Separate books of account continue to be maintained for Imperial and ExxonMobil. Imperial and ExxonMobil retain ownership of their respective assets and there is no impact on operations or reserves.
Certain charges from ExxonMobil have been capitalized; they are not material in the aggregate.
The company borrowed $818 million (Cdn) from an affiliated company of Exxon Mobil Corporation under two long-term loan agreements as presented in note 4.
As at December 31, 2006, the company had outstanding loans of $33 million (2005 - $32 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.
16. Net payments/payables to governments
(a)
The abbreviations refer to the federal goods and services tax, the Quebec sales tax and the federal/provincial harmonized sales tax, respectively. The HST is applicable in the provinces of Nova Scotia, New Brunswick and Newfoundland and Labrador.