Imperial Oil - 10-K annual report

 

(Exact name of registrant as specified in its charter)

     The registrant is a well-known seasoned issuer (as defined in Rule 405 of the Securities Exchange Act of 1934).
Yes þ No o

     The registrant is not required to file reports pursuant to Section 13 or Section 15(d) of the Securities Exchange Act of 1934.
Yes o No þ

     The registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days.
Yes þ No o

     Disclosure of delinquent filers pursuant to Item 405 of Regulation S-K is not contained herein, and will not be contained, to the best of registrant’s knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-K or any amendment to this Form 10-K.
Yes þ No o

     The registrant is a large accelerated filer, an accelerated filer, or a non-accelerated filer (see definition of “accelerated filer” and “large accelerated filer” in Rule 12b-2 of the Securities Exchange Act of 1934).

Large accelerated filerþ     Accelerated filer o     Non-accelerated filer o

     The registrant is a shell company (as defined in Rule 12 b-2 of the Securities Exchange Act of 1934).
Yes o No þ

     As of the last business day of the 2005 second fiscal quarter, the aggregate market value of the voting stock held by non-affiliates of the registrant was Canadian $10,570,561,124 based upon the reported last sale price of such stock on the Toronto Stock Exchange on that date.

     The number of common shares outstanding, as of February 15, 2006, was 331,344,044.

 

 

The following table sets forth (i) the rates of exchange for the Canadian dollar, expressed in U.S. dollars, in effect at the end of each of the periods indicated, (ii) the average of exchange rates in effect on the last day of each month during such periods, and (iii) the high and low exchange rates during such periods, in each case based on the noon buying rate in New York City for wire transfers in Canadian dollars as certified for customs purposes by the Federal Reserve Bank of New York.

     On February 15, 2006, the noon buying rate in New York City for wire transfers in Canadian dollars as certified for customs purposes by the Federal Reserve Bank of New York was $0.8665 U.S. = $1.00 Canadian.

     This report contains forward looking information on future production, project start ups and future capital spending. Actual results could differ materially as a result of market conditions or changes in law, government policy, operating conditions, costs, project schedules, operating performance, demand for oil and natural gas, commercial negotiations or other technical and economic factors.

     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” 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.

     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, crude oil and natural gas, including upgraded crude oil and crude bitumen. 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.

     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, 2005, was as follows:

     In 2002 and 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, conventional production declined mainly due to the natural decline of the Company’s conventional fields. In 2002, Cold Lake production decreased mainly due to the timing of steaming cycles and Syncrude net production increased mainly due to lower royalties. In 2003, Cold Lake net production increased as a result of a full year of production of stages 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.

     The Company’s average daily production and sales of natural gas during the five years ended December 31, 2005 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 at 60 degrees Fahrenheit.

     In 2002 and 2003, natural gas production decreased primarily due to the depletion of gas caps in Alberta. In 2003 natural gas production decreased due to 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.

     Most of the Company’s natural gas sales are made under short term contracts.

     The Company’s average sales price and production (lifting) costs for conventional and Cold Lake crude oil and natural gas liquids and natural gas for the five years ended December 31, 2005, were as follows:

     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. Canadian natural gas prices decreased in 2002 primarily due to a weaker U.S. economy and warmer weather. 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 2002, average production (lifting) costs increased mainly due to lower net production at Cold Lake. In 2003, average production (lifting) costs increased mainly due to higher costs of purchased natural gas at Cold Lake. In 2004, average production (lifting) costs decreased mainly due to higher production from the Wizard Lake gas cap.

In 2005, average production (lifting) costs increased mainly due to higher costs of purchased natural gas at Cold Lake.

     The Company has interests in a large number of facilities related to the production of crude oil and natural gas. Among these facilities are 25 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 10 of the plants.

     The Company’s production of conventional and Cold Lake crude 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, 2005, is set forth in the following table. The statistics in the table are determined in part from information received from other operators.

     The Company has major interests in the Norman Wells oil field in the Northwest Territories and the West Pembina oil field in Alberta. Together they currently account for approximately 59 percent of the Company’s net production of conventional crude oil (approximately 64 percent of gross production).

     Norman Wells is the Company’s largest producing conventional oil field. In 2005, net production of crude oil and natural gas liquids was about 2,200 cubic metres (13,700 barrels) per day and gross production was about 3,100 cubic metres (19,400 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 2005, those costs were about $34 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. In December 2005, the Company sold its interest in the Redwater and North Pembina fields. Gross oil production from these two properties averaged approximately 700 cubic metres (4,400 barrels) a day during the third quarter of 2005.

     The Company produces natural gas from a large number of gas fields located in the Western Provinces, primarily in Alberta.

     The Company has a nine percent interest in a project to develop natural gas reserves in the Sable Island area off the coast of the Province of Nova Scotia. About $5 billion has been spent by the participants to the end of 2005 on the project. Production from the Sable Offshore Energy Project began at the end of 1999 and is expected to average about 12 million cubic metres (420 million cubic feet) per day of natural gas and 3,200 cubic metres (20,000 barrels) per day of natural gas liquids through the end of the decade.

     The Company holds about 78,000 leased hectares (192,000 acres) of oil sands near Cold Lake, Alberta. This oil sands deposit contains a very heavy crude oil (crude bitumen). To develop the technology necessary to produce this oil commercially, the Company has conducted experimental pilot operations since 1964 to recover the crude bitumen 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 stages, of its oil sands resources at Cold Lake. During 2005, average net production at Cold Lake was about 19,700 cubic metres (123,500 barrels) per day and gross production was about 22,100 cubic metres (138,700 barrels) per day.

     To maintain production at Cold Lake, capital expenditures for additional production wells and associated facilities will be required periodically. In 2005, the Company spent $117 million and executed a development drilling program of 87 wells on existing stages. In 2006, 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 stages. 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 is expected to begin in 2006 from part of the approved expansion, the development of which is expected to cost about $300 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 oil sands leases, is entitled to a royalty on production from the Cold Lake production project. 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 royalties that apply to all other oil sands development in the Province will take effect. 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 11 percent in 2005 and 2004, 10 percent in 2003 and five percent in 2002 and 2001. The Company expects that after 2007 the royalty will be the greater of one percent of gross revenue or 25 percent of an amount based on revenue net of operating and capital costs for the Cold Lake production project and the pilot operations.

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

     The Company holds varying interests in lands totalling about 68,000 leased net hectares (168,000 net acres) in the Athabasca area where the oil sands are buried too deeply to permit recovery by surface mining methods. 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 oil sands.

     The Company holds a 25 percent participating interest in Syncrude, a joint venture established to recover shallow deposits of tar 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, 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 1.6 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 tar sands and produce synthetic crude oil from approved development areas on tar sands leases. Syncrude holds eight tar sands leases covering about 102,000 hectares (252,000 acres) in the Athabasca Oil Sands Deposit. Issued by the Province of Alberta, the leases are automatically renewable as long as tar 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.

     As of January 1, 2002, a 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. In the Base mine (lease 17), the mining and transportation system uses draglines, bucketwheel reclaimers and belt conveyors. 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 495,000 tonnes (545,000 tons) of tar sands a day, producing about 18 million cubic metres (110 million barrels) of crude bitumen a year. This represents recovery capability of about 92 percent of the crude bitumen contained in the mined tar sands.

     Crude bitumen extracted from tar sands is refined to a marketable hydrocarbon product through a combination of carbon removal in two 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 2005, the upgrading process yielded 0.853 cubic metres of synthetic crude oil per cubic metre of crude bitumen (0.853 barrels of synthetic crude oil per barrel of crude bitumen). In 2005, about 49 percent of the synthetic crude oil was processed by Edmonton area refineries and the remaining 51 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 80 megawatt electricity generating plant, both located at Syncrude. The generating plants are owned by the Syncrude participants. 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 $3.2 billion.

     In 2005, Syncrude’s net production of synthetic crude oil was about 33,700 cubic metres (211,800 barrels) per day and gross production was about 34,000 cubic metres (213,900 barrels) per day. The Company’s share of net production in 2005 was about 8,400 cubic metres (52,900 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 is scheduled to come on stream in 2006. These projects are expected to lead to a total production capacity of about 56,500 cubic metres (355,000 barrels) of synthetic crude oil a day when completed. The Company’s share of project costs is expected to be about $2.1 billion of which about $2.0 billion has been incurred to the end of 2005.

     The following table sets forth certain operating statistics for the Syncrude operations:

     The Company holds a 100 percent interest in approximately 16,600 hectares (41,000 acres) of surface mineable tar sands in the Kearl area in the Athabasca area of northern Alberta. The Company is assessing a potential phased development of its tar sands in the area as part of the Kearl oil sands mining project. The Company would hold 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.

     At December 31, 2005 and 2004, the Company held the following oil and gas rights, and tar sands leases:

     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 oil sands net exploratory and development wells that were drilled or participated in by the Company during the five years ended December 31, 2005.

     The 87 oil sands development wells in 2005 were drilled to add new productive capacity from undeveloped areas of existing stages 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, 2005, the Company was participating in the drilling of 138 gross (86 net) exploratory and development wells.

     In 2005, the Company had a working interest in three gross (zero net) exploratory wells and 351 gross (158 net) development wells, while retaining an overriding royalty in an additional 19 gross exploratory wells drilled by others. The majority of the exploratory wells were directed toward extending reserves around existing fields.

     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 terms, 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. Public hearings by the Joint Review Panel and National Energy Board, the next phase of the remaining two-year regulatory review process commenced in early 2006. The initial cost for the project is estimated to be about $7 billion with the Company’s share of the cost estimated to be about $3 billion.

     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.

     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.

     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 five 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 a 3-D seismic survey in this area. A contract agreement for a drilling vessel has been signed and exploration drilling is expected in 2006.

     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.

     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).

     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 2005, capital expenditures of about $340 million were made at the Company’s refineries. About 65 percent of those expenditures were on new facilities required to meet Government of Canada regulations on the sulphur level in motor fuels with the remaining expenditures being on safety and efficiency improvements, and environmental improvement projects.

     The approximate average daily volumes of refinery throughput during the five years ended December 31, 2005, and the daily rated capacities of the refineries at December 31, 2000 and 2005, were as follows:

     Refinery throughput was 93 percent of capacity in 2005, the same as the previous year.

     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, 2005, the Company did not own and operate any vessels other than one barge used primarily for domestic transportation of refined petroleum products.

     The Company markets more than 700 petroleum products throughout Canada under well known brand names, notably Esso, to all types of customers.

     The Company sells to the motoring public through approximately 2,000 Esso service stations, of which about 700 are Company owned or leased, but none of which are 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. In 2005, the Company divested its Western Canada fertilizer distribution assets to Agrium Inc. The transaction did not have a material impact on the financial results of the petroleum products segment.

     The approximate daily volumes of petroleum products sold during the five years ended December 31, 2005, 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, 2005, were as follows:

     The Company continues to evaluate and adjust its Esso service station and distribution system to increase productivity and efficiency. During 2005, the Company closed or debranded about 70 Esso service stations, about 20 of which were Company owned, and added about 70 sites. The Company’s average annual throughput in 2005 per Esso service station was 3.6 million litres, 0.2 million litres higher than 2004. Average throughput per Company owned or leased Esso service station was 5.8 million litres in 2005, an increase of about 0.3 million litres from 2004.

     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, 2005, were as follows:

     In 2005, the Company’s research expenditures in Canada, before deduction of investment tax credits, were $50 million, as compared with $40 million in 2004 and $36 million in 2003. 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 2005. The Company also participated in bitumen recovery and processing research for tar 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 2005. 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.

     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 $1.1 billion on environmental protection and facilities. In 2005, the Company’s capital expenditures relating to environmental protection totalled approximately $270 million, and are expected to be about $200 million in 2006.

     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 a year in advance. The second project underway in 2004 is to meet a new Government of Canada regulation requiring ultra-low sulphur on-road diesel fuel commencing in 2006. In 2005, there were capital expenditures of about $240 million on this second project, which is expected to cost about $600 million when completed. Capital expenditures on safety related projects in 2005 were approximately $15 million.

     At December 31, 2005, the Company employed full-time approximately 5,100 persons compared with about 6,100 at the end of 2004 and 6,300 at the end of 2003. During 2005, the Company transferred about 700 employees to an affiliated company that provides services to the Company and others. About 9 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.

     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.

     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 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.

     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.

     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.

     Production

     The maximum allowable gross production of natural gas from wells in Canada is subject to limitation by various regulatory authorities on the basis of engineering and conservation principles. A permit is required from the Alberta Energy and Utilities Board, subject to the approval of the Province of Alberta, for the removal from Alberta of natural gas produced in that province.

     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.

     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”.

     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’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.

     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.

     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.

     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.

     Canada is a signatory to the United Nations Framework Convention on Climate Change and has ratified the Kyoto Protocol established thereunder to set legally-binding targets to reduce nation-wide emissions of carbon dioxide, methane, nitrous oxide and other so-called “greenhouse gases”. The Government of Canada has indicated an intent to issue regulations limiting greenhouse gas emissions 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, as might other provinces. 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.

     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 Company operations and financial performance.

     The Company’s future oil, tar sands 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.

     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 overcome. 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.

     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.

     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.

     See Item 7A for a discussion of the impact of market risks and other uncertainties.

     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.

     Not applicable.

     Not applicable.

     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.

     The Company is a qualified foreign corporation for purposes of the new 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.

     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.

     As of February 15, 2006, there were 14,011 holders of record of common shares of the Company.

     During the period October 1, 2005 to December 31, 2005, the Company issued 185,800 common shares for $46.50 per share 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 sales of those common shares outside the U.S.A. which were not registered under the Securities Act in reliance on Regulation S thereunder.

     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.

     The following discussion and analysis of the Company’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 Company’s management.

     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.

     With its extensive resource base in Canada, financial strength, disciplined investment approach and technology portfolio, the Company is well positioned to participate in substantial investments to develop new energy supplies. While commodity prices remain volatile on a short-term basis depending upon supply and demand, the Company’s investment decisions are based on long-term outlooks, using a disciplined approach in selecting and pursuing the most attractive investment opportunities. The corporate plan is a fundamental annual management process that is the basis for setting near-term operating and capital objectives in addition to providing the longer-term economic assumptions used for investment evaluation purposes. Annual plan volumes are based on individual field production profiles that are updated annually. Prices for crude oil, natural gas and refined products used for investment evaluation purposes are based on corporate plan assumptions that are developed annually. Potential investment opportunities are tested over a wide range of economic scenarios to establish the resiliency of each opportunity. Once investments are made, a reappraisal process is completed to ensure relevant lessons are learned and improvements are incorporated into future projects.

     The Company 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. The Company expects the global economy to grow at an average rate of almost three percent per year through 2030. World energy demand should grow by about two percent per year, and oil and gas are expected to consistently account for about 60 percent of world energy supply through 2030. 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 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.

     The Company 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, the Company’s production is expected to come increasingly from frontier and unconventional sources, particularly oil sands and natural gas from the Far North, where the Company has large undeveloped resource opportunities.

     The downstream continues to experience ongoing volatility in industry margins. Refining margins are the difference between what a refinery pays for its raw materials (primarily crude oil) and the wholesale prices it receives for the range of products produced (primarily gasoline, diesel fuel, heating oil, jet fuel and 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.

     The Company’s downstream strategies are to provide customers with quality service at the lowest total cost offer, have the lowest net unit costs among our competitors, ensure efficient and effective use of capital and capitalize on integration with the Company’s other businesses. The Company 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.

     The Company’s fuels marketing business includes retail operations across Canada serving customers through about 2,000 Esso-branded service stations, of which about 700 are Company-owned or leased, and wholesale and industrial operations through a network of 30 primary distribution terminals.

     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 it to maintain a leadership position in its key market segments.

     Net income in 2005 was $2,600 million or $7.59 a share — the best year on record — surpassing the previous record of $2,052 million or $5.74 a share in 2004 (2003 — $1,705 million or $4.58 a share). Strong operational performance in 2005 allowed the Company to capture opportunities in an environment of higher commodity prices and industry margins. Higher realizations for crude oil, natural gas and Cold Lake bitumen and stronger refining margins contributed about $1,300 million to earnings when compared to 2004. Also positive to earnings was

increased natural gas and Cold Lake bitumen volumes of about $125 million. These factors were partly offset by a stronger Canadian dollar, lower volumes at Syncrude, the natural decline of conventional crude oil volumes and higher planned maintenance impacting refinery operations. These factors had a combined negative impact of about $590 million on earnings. Operating costs increased and impacted earnings by about $325 million, primarily driven by higher energy costs and higher Syncrude maintenance expenses. In addition, stock-related compensation expenses were $143 million higher than a year earlier and costs associated with the head office relocation of about $45 million were incurred in 2005. Included in net income in 2005 was a $233 million gain on sale of assets, mainly from the Redwater and North Pembina fields. Included in net income in 2004 was a $32 million gain on sale of assets and a write down of $42 million on a north Toronto property.

     Total operating revenues were $27.8 billion, up 24 percent from 2004.

     Beginning in the third quarter of 2005, incentive compensation expenses previously included in the operating segments are now reported in the “corporate and other” segment. This change has the effect of isolating in one segment all incentive compensation expenses and improving the transparency of operating events in the operating segments. This change has no impact on consolidated total expenses, net income or the cash-flow profile of the Company. Segmented results in previous years have been reclassified for comparative purposes.

     Net income from natural resources was a record $2,008 million, exceeding the previous record achieved in 2004 of $1,517 million (2003 — $1,174 million). Improved realizations for crude oil, natural gas and Cold Lake bitumen of about $910 million, and higher natural gas and Cold Lake bitumen volumes of about $125 million were the main reasons for the increase. Their positive impact on earnings was partially offset by the unfavourable impact of a higher Canadian dollar of about $260 million, lower volumes due to higher maintenance activities at Syncrude of about $100 million and the natural decline of conventional crude oil and NGL volumes of about $90 million. Operating costs were also higher than 2004 by about $275 million, primarily driven by higher energy costs of about $140 million and higher Syncrude maintenance and other expenses of about $75 million. Included in net income in 2005 was a $208 million gain on sale of assets, mainly from the Redwater and North Pembina fields. Included in net income in 2004 was a $25 million gain on sale of assets.

     Resource operating revenues were $8.2 billion, up from $6.6 billion in 2004 (2003 — $5.6 billion). The main reasons for the increase were higher realizations primarily for crude oil, natural gas and Cold Lake bitumen and higher natural gas and Cold Lake bitumen volumes.