IMPERIAL OIL LTD - Annual Report: 2006 (Form 10-K)

 

 

UNITED STATES SECURITIES AND EXCHANGE COMMISSION

WASHINGTON, D.C. 20549

FORM 10-K

ANNUAL REPORT PURSUANT TO SECTION 13 OR 15 (d) OF THE
SECURITIES EXCHANGE ACT OF 1934

For the fiscal year ended December 31, 2006		Commission file number: 0-12014

IMPERIAL OIL LIMITED

(Exact name of registrant as specified in its charter)

CANADA		98-0017682
(State or other jurisdiction of incorporation or organization)		(I.R.S. Employer Identification No.)
237 FOURTH AVENUE S.W., CALGARY, AB, CANADA (Address of principal executive offices)		T2P 3M9 (Postal Code)

Registrant’s telephone number, including area code:
1-800-567-3776
Securities registered pursuant to Section 12(b) of the Act:

Title of each class None		Name of each exchange on which registered None

Securities registered pursuant to Section 12(g) of the Act:
Common Shares (without par value)

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

Yes þ Noo

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

Yes o No þ

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

Yes þ Noo

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

Yes þ Noo

     Indicate by check mark whether 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 filer þ      Accelerated filero      Non-accelerated filero

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

Yes o No þ

     As of the last business day of the 2006 second fiscal quarter, the aggregate market value of the voting stock held by non-affiliates of the registrant was Canadian $12,075,765,770 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, 2007, was 949,989,788.

 

 

				Page
		PART I
Item 1.		Business
		Financial Information by Operating Segments			3
		Natural Resources			4
		Petroleum and Natural Gas Production			4
		Land Holdings			10
		Exploration and Development			10
		Petroleum Products			12
		Supply			12
		Refining			12
		Distribution			13
		Marketing			13
		Chemicals			14
		Research			14
		Environmental Protection			15
		Human Resources			15
		Competition			15
		Government Regulation			15
		The Company Online			16
Item 1A.		Risk Factors			16
Item 2.		Properties			18
Item 3.		Legal Proceedings			18
Item 4.		Submission of Matters to a Vote of Security Holders			18
		PART II
Item 5.		Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities			19
Item 6.		Selected Financial Data			20
Item 7.		Management’s Discussion and Analysis of Financial Condition and Results of Operation			20
Item 7A.		Quantitative and Qualitative Disclosures about Market Risk			30
Item 8.		Financial Statements and Supplementary Data			31
Item 9.		Changes in and Disagreements with Accountants on Accounting and Financial Disclosure			36
Item 9A.		Controls and Procedures			36
		PART III
Item 10.		Directors and Executive Officers of the Registrant			37
Item 11.		Executive Compensation			39
Item 12.		Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters			48
Item 13.		Certain Relationships and Related Transactions			49
Item 14.		Principal Accountant Fees and Services			50
		PART IV
Item 15.		Exhibits and Financial Statement Schedules			51
Index to Financial Statements					F-1
Management’s Report on Internal Control over Financial Reporting					F-2
Report of Independent Registered Public Accounting Firm					F-2

All dollar amounts set forth in this report are in Canadian dollars, except where otherwise indicated.

Note that numbers may not add due to rounding.

The following table sets forth (i) the rates of exchange for the Canadian dollar, expressed in 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.

		2006				2005				2004				2003				2002
		(dollars)
Rate at end of period			0.8582				0.8579				0.8310				0.7738				0.6329
Average rate during period			0.8844				0.8276				0.7702				0.7186				0.6368
High			0.9100				0.8690				0.8493				0.7738				0.6619
Low			0.8528				0.7872				0.7158				0.6349				0.6200

     On February 15, 2007, 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 $0.8590 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.

PART I

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)

		2006				2005				2004				2003				2002
		(millions of dollars)
External sales (1) :
Natural resources		$	4,619			$	4,702			$	3,689			$	3,390			$	2,573
Petroleum products			18,527				21,793				17,503				14,710				13,362
Chemicals			1,359				1,302				1,216				994				955
Corporate and other			—				—				—				—				—
		$	24,505			$	27,797			$	22,408			$	19,094			$	16,890
Intersegment sales:
Natural resources		$	3,837			$	3,487			$	2,891			$	2,224			$	2,217
Petroleum products			2,256				2,224				1,666				1,294				1,038
Chemicals			345				363				293				238				209
Net income (2) :
Natural resources		$	2,376			$	2,008			$	1,517			$	1,174			$	1,052
Petroleum products			624				694				556				462				147
Chemicals			143				121				109				44				54
Corporate and other (3) /eliminations			(99	)			(223	)			(130	)			25				(39	)
		$	3,044			$	2,600			$	2,052			$	1,705			$	1,214
Identifiable assets at December 31 (4) :
Natural resources		$	7,513			$	7,289			$	6,822			$	6,397			$	5,982
Petroleum products			6,450				6,257				5,509				5,225				5,034
Chemicals			504				500				490				433				417
Corporate and other/eliminations			1,674				1,536				1,206				282				570
		$	16,141			$	15,582			$	14,027			$	12,337			$	12,003
Capital and exploration expenditures:
Natural resources		$	787			$	937			$	1,113			$	1,007			$	986
Petroleum products			361				478				283				478				589
Chemicals			13				19				15				41				25
Corporate and other			48				41				34				33				12
		$	1,209			$	1,475			$	1,445			$	1,559			$	1,612

     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:

			2006				2005				2004				2003				2002
			(thousands a day)
Conventional (including natural gas liquids):
Cubic metres	— Gross (1)			8.7				11.0				12.1				11.8				12.4
	— Net (2)			6.7				8.6				9.4				9.1				9.5
Barrels	— Gross (1)			55				69				76				74				78
	— Net (2)			42				54				59				57				60
Heavy Oil (3):
Cubic metres	— Gross (1)			24.1				22.1				20.0				20.5				17.8
	— Net (2)			20.1				19.7				17.7				18.4				16.9
Barrels	— Gross (1)			152				139				126				129				112
	— Net (2)			127				124				112				116				106
Oil Sands (4):
Cubic metres	— Gross (1)			10.3				8.4				9.5				8.4				9.1
	— Net (2)			9.3				8.4				9.4				8.3				9.1
Barrels	— Gross (1)			65				53				60				53				57
	— Net (2)			58				53				59				52				57
Total:
Cubic metres	— Gross (1)			43.1				41.5				41.6				40.7				39.3
	— Net (2)			36.1				36.7				36.5				35.8				35.5
Barrels	— Gross (1)			272				261				262				256				247
	— Net (2)			227				231				230				225				223

     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.

		2006				2005				2004				2003				2002
		(millions a day)
Sales (1) :
Cubic metres			14.5				15.2				14.7				13.0				14.1
Cubic feet			513				536				520				460				499
Gross Production (2):
Cubic metres			15.8				16.4				16.1				14.5				15.0
Cubic feet			556				580				569				513				530
Net Production (2):
Cubic metres			14.1				14.6				14.7				12.9				13.1
Cubic feet			496				514				518				457				463

     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:

		2006				2005				2004				2003				2002
Average Sales Price:
Crude oil and natural gas liquids:
Per cubic metre		$	283.84			$	234.04			$	207.26			$	181.92			$	174.72
Per barrel			45.13				37.21				32.95				28.92				27.78
Natural gas:
Per thousand cubic metres		$	255.58			$	317.71			$	239.34			$	232.99			$	141.91
Per thousand cubic feet			7.24				9.00				6.78				6.60				4.02
Average Production Costs Per Unit of Net Production (1),(2):
Per cubic metre		$	69.69			$	67.82			$	58.16			$	60.78			$	53.09
Per barrel			11.08				10.78				9.25				9.66				8.44

     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.

		Crude Oil								Natural Gas								Total
		Gross (1)				Net (2)				Gross (1)				Net (2)				Gross (1)				Net (2)
Conventional wells			1,241				794				4,791				2,612				6,032				3,406
Heavy Oil wells			3,983				3,983				—				—				3,983				3,983

     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:

		2006				2005				2004				2003				2002
Total mined overburden (1)
millions of cubic metres			98.0				74.2				76.6				83.5				77.9
millions of cubic yards			128.2				97.1				100.3				109.2				102.0
Mined overburden to oil sands ratio (1)			1.18				1.02				0.94				1.15				1.05
Oil sands mined
millions of tonnes			175.0				152.7				170.9				152.4				156.5
millions of tons			195.5				168.0				188.0				168.0				172.1
Average bitumen grade (weight percent)			11.4				11.1				11.1				11.0				11.2
Crude bitumen in mined oil sands
millions of tonnes			19.9				16.9				19.0				16.8				17.5
millions of tons			22.2				18.6				20.9				18.5				19.2
Average extraction recovery (percent)			90.3				89.1				87.3				88.6				89.9
Crude bitumen production (2)
millions of cubic metres			17.7				15.1				16.4				14.7				15.5
millions of barrels			111.6				94.2				103.3				92.3				97.8
Average upgrading yield (percent)			84.9				85.3				85.5				86.0				86.3
Gross synthetic crude oil produced
millions of cubic metres			15.2				12.6				14.1				12.5				13.5
millions of barrels			95.5				79.3				88.4				78.4				84.8
Company’s net share (3)
millions of cubic metres			3.4				3.1				3.4				3.0				3.3
millions of barrels			21.3				19.3				21.6				19.1				20.7

     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:

		Hectares																								Acres
		Developed								Undeveloped								Total								Developed								Undeveloped								Total
		2006				2005				2006				2005				2006				2005				2006				2005				2006				2005				2006				2005
		(thousands)
Western Provinces
Conventional —
Gross (1)			1,032				1,055				154				181				1,186				1,236				2,550				2,607				381				447				2,931				3,054
Net (2)			407				430				95				109				502				539				1,006				1,063				235				269				1,241				1,332
Heavy Oil —
Gross (1)			41				41				174				193				215				234				101				101				430				477				531				578
Net (2)			41				41				105				105				146				146				101				101				260				260				361				361
Oil Sands —
Gross (1)			47				47				119				72				166				119				116				116				294				178				410				294
Net (2)			12				11				54				31				66				42				30				27				133				77				163				104
Canada Lands (3):
Conventional —
Gross (1)			31				31				322				322				353				353				77				77				795				795				872				872
Net (2)			3				3				98				98				101				101				7				7				242				242				249				249
Atlantic Offshore
Conventional —
Gross (1)			17				17				2,600				2,600				2,617				2,617				42				42				6,425				6,425				6,467				6,467
Net (2)			2				2				616				616				618				618				5				5				1,522				1,522				1,527				1,527
Total (4) :
Gross (1)			1,168				1,191				3,369				3,368				4,537				4,559				2,886				2,943				8,325				8,322				11,211				11,265
Net (2)			465				487				968				959				1,433				1,446				1,149				1,203				2,392				2,370				3,541				3,573

     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.

		2006				2005				2004				2003				2002
Western and Atlantic Provinces:
Conventional
Exploratory —
Oil			—				—				—				—				—
Gas			1				—				2				3				1
Dry Holes			—				—				1				1				2
Development —
Oil			—				2				3				4				1
Gas			192				155				207				89				42
Dry Holes			1				1				1				3				3
Heavy Oil (Cold Lake and other)
Development —
Oil			174				87				218				118				332
Total			368				245				432				218				381

     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:

		Average Daily Volumes of																				Daily Rated
		Refinery Throughput (1)																				Capacities at
		Year Ended December 31																				December 31 (2)
		2006				2005				2004				2003				2002				2006				2001
		(thousands of cubic metres)
Strathcona, Alberta			25.5				27.6				27.1				27.6				26.0				29.8				29.0
Sarnia, Ontario			17.6				16.9				17.2				14.7				16.5				19.2				19.2
Dartmouth, Nova Scotia			12.3				12.5				12.7				13.0				12.5				13.1				13.1
Nanticoke, Ontario			14.9				17.2				17.3				16.3				16.2				17.8				17.8
Total			70.3				74.1				74.3				71.6				71.2				79.9				79.1

		Average Daily Volumes of																				Daily Rated
		Refinery Throughput (1)																				Capacities at
		Year Ended December 31																				December 31 (2)
		2006				2005				2004				2003				2002				2006				2001
		(thousands of barrels)
Strathcona, Alberta			160				174				170				174				163				187				182
Sarnia, Ontario			111				106				108				92				104				121				121
Dartmouth, Nova Scotia			77				79				80				82				78				82				82
Nanticoke, Ontario			94				108				109				102				102				112				112
Total			442				466				467				450				447				502				497

     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:

		2006				2005				2004				2003				2002
		(thousands a day)
Gasolines:
Cubic metres			32.7				33.4				33.2				33.0				32.9
Barrels			206				210				209				208				207
Heating, Diesel and Jet Fuels:
Cubic metres			26.4				26.9				27.3				26.2				25.0
Barrels			166				169				172				165				157
Heavy Fuel Oils:
Cubic metres			5.1				6.0				5.9				5.4				4.9
Barrels			32				38				37				34				31
Lube Oils and Other Products
Cubic metres			7.7				7.6				7.0				5.8				6.4
Barrels			49				48				44				36				41
Net petroleum product sales:
Cubic metres			71.9				73.9				73.4				70.4				69.2
Barrels			453				465				462				443				436

     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:

		2006				2005				2004				2003				2002
			96.1	%			95.3	%			93.0	%			93.3	%			91.5	%

     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:

		2006				2005				2004				2003				2002
		(thousands a day)
Petrochemicals:
Tonnes			3.0				3.0				3.3				3.3				3.5
Tons			3.3				3.3				3.6				3.6				3.9

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. 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. 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. Legal Proceedings.

     Not applicable.

Item 4. Submission of Matters to a Vote of Security Holders.

     Not applicable.

PART II

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

		2006																2005
		three months ended																three months ended
		Mar. 31				June 30				Sept. 30				Dec. 31				Mar. 31				June 30				Sept. 30				Dec. 31
		(millions of dollars)																(millions of dollars)
Financial data
Total revenues and other income (a)			5,818				6,688				6,651				5,631				5,958				6,802				7,711				7,743
Total expenses (a)			4,928				5,604				5,421				4,735				5,370				5,989				6,753				6,184
Income before income taxes			890				1,084				1,230				896				588				813				958				1,559
Income taxes			(299	)			(247	)			(408	)			(102	)			(195	)			(274	)			(306	)			(543	)
Net income			591				837				822				794				393				539				652				1,016
Per-share information (b)		(dollars)																(dollars)
Net earnings — basic			0.60				0.85				0.84				0.83				0.38				0.52				0.64				1.00
Net earnings — diluted			0.59				0.85				0.84				0.83				0.37				0.52				0.64				1.00
Dividends (declared quarterly)			0.08				0.08				0.08				0.08				0.07				0.08				0.08				0.08
Share prices (b)		(dollars)																(dollars)
Toronto Stock Exchange
High			42.28				43.33				45.20				44.80				31.44				34.99				45.79				45.39
Low			35.36				36.18				35.33				34.31				22.50				27.37				33.33				32.28
Close			41.91				40.78				37.47				42.93				30.67				34.01				44.67				38.47
American Stock Exchange		($U.S.)																($U.S.)
High			36.67				39.64				40.38				38.93				25.73				28.38				39.14				38.93
Low			30.54				32.50				31.64				29.99				18.27				21.57				27.46				27.47
Close			35.85				36.50				33.55				36.83				25.38				27.75				38.35				33.20

     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)

										(c) Total number of shares				(d) Maximum number
		(a) Total number								purchased as part				(or approximate dollar value)
		of shares				(b) Average price				of publicly				of shares that may yet be
		(or units)				paid per share				announced plans				purchased under the plans or
Period		purchased				(or unit)				or programs				programs
October 2006 (October 1 - October 31)			1,315,785			$	36.14				1,315,785				34,336,470
November 2006 (November 1 - November 30)			5,554,679			$	41.65				5,554,679				28,721,476
December 2006 (December 1 - December 31)			3,031,537			$	43.99				3,031,537				25,632,528

Item 6. Selected Financial Data.

		2006				2005				2004				2003				2002
		(millions of dollars)
Total operating revenues (a)		$	24,505			$	27,797			$	22,408			$	19,094			$	16,890
Net income			3,044				2,600				2,052				1,705				1,214
Total assets			16,141				15,582				14,027				12,337				12,003
Long term debt			359				863				367				859				1,466
Other long term obligations			1,683				1,728				1,525				1,314				1,822
										(dollars)
Net income/share – basic (b)			3.12				2.54				1.92				1.53				1.07
Net income/share – diluted (b)			3.11				2.53				1.91				1.53				1.07
Cash dividends/share (b)			0.32				0.31				0.29				0.29				0.28

     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. 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

		2006				2005				2004				2003				2002
		(millions of dollars)
Net income		$	2,376			$	2,008			$	1,517			$	1,174			$	1,052
Operating revenues			8,456				8,189				6,580				5,584				4,790

     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

		2006				2005				2004				2003				2002
		(Canadian dollars)
Conventional crude oil realizations (a barrel)		$	68.58			$	64.48			$	48.96			$	40.10			$	36.81
Natural gas liquids realizations (a barrel)			40.75				40.00				33.78				32.09				23.38
Natural gas realizations (a thousand cubic feet)			7.24				9.00				6.78				6.60				4.02
Par crude oil price at Edmonton (a barrel)			73.75				69.86				53.26				43.93				40.44
Heavy oil price at Hardisty (Bow River, a barrel)			51.90				45.62				37.98				33.00				31.85