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, 2007		Commission file number: 0-12014

IMPERIAL OIL LIMITED

(Exact name of registrant as specified in its charter)

CANADA (State or other jurisdiction of incorporation or organization)		98-0017682 (I.R.S. Employer Identification No.)

237 FOURTH AVENUE S.W., CALGARY, AB, CANADA (Address of principal executive offices)		T2P 3M9 (Postal Code)

Registrant’s telephone number, including area code:
1-800-567-3776

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

		Name of each exchange on
Title of each class None		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 ü    No......

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

Yes ...... No ü

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

Yes ü    No......

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

Yes ü    No......

     Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, or a smaller reporting company (see definition of “large accelerated filer”, “accelerated filer” and “smaller reporting company” in Rule 12b-2 of the Securities Exchange Act of 1934).

Large accelerated filer ü                Accelerated filer......               Non-accelerated filer......               Smaller reporting company......

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

Yes ...... No ü

     As of the last business day of the 2007 second fiscal quarter, the aggregate market value of the voting stock held by non-affiliates of the registrant was Canadian $13,974,075,595 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 14, 2008, was 900,825,903.

				Page
		PART I
Item 1.		Business
		Financial Information by Operating Segments			3
		Natural Resources			4
		Petroleum and Natural Gas Production			4
		Land Holdings			9
		Exploration and Development			9
		Petroleum Products			11
		Supply			11
		Refining			11
		Distribution			11
		Marketing			11
		Chemicals			12
		Research			12
		Environmental Protection			12
		Human Resources			13
		Competition			13
		Government Regulation			13
		The Company Online			14
Item 1A.		Risk Factors			14
Item 1B.		Unresolved Staff Comments			16
Item 2.		Properties			16
Item 3.		Legal Proceedings			16
Item 4.		Submission of Matters to a Vote of Security Holders			16
		PART II
Item 5.		Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities			17
Item 6.		Selected Financial Data			18
Item 7.		Management’s Discussion and Analysis of Financial Condition and Results of Operations			18
Item 7A.		Quantitative and Qualitative Disclosures about Market Risk			29
Item 8.		Financial Statements and Supplementary Data			29
Item 9.		Changes in and Disagreements with Accountants on Accounting and Financial Disclosure			34
Item 9A.		Controls and Procedures			34
		PART III
Item 10.		Directors and Executive Officers of the Registrant			35
Item 11.		Executive Compensation			38
Item 12.		Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters			46
Item 13.		Certain Relationships and Related Transactions			47
Item 14.		Principal Accountant Fees and Services			48
		PART IV
Item 15.		Exhibits and Financial Statement Schedules			49
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.

		2007				2006				2005				2004				2003
		(dollars)
Rate at end of period			1.0120				0.8582				0.8579				0.8310				0.7738
Average rate during period			0.9376				0.8844				0.8276				0.7702				0.7186
High			1.0908				0.9100				0.8690				0.8493				0.7738
Low			0.8437				0.8528				0.7872				0.7158				0.6349

     On February 14, 2008, the noon buying rate in New York City for wire transfers in Canadian dollars as certified for customs purposes by the Federal Reserve Bank of New York was $1.0033 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)

		2007				2006				2005				2004				2003
External sales (1):		(millions of dollars)
Natural resources			4,539				4,619				4,702				3,689				3,390
Petroleum products			19,230				18,527				21,793				17,503				14,710
Chemicals			1,300				1,359				1,302				1,216				994
Corporate and other			–				–				–				–				–
			25,069				24,505				27,797				22,408				19,094
Intersegment sales:
Natural resources			4,146				3,837				3,487				2,891				2,224
Petroleum products			2,305				2,256				2,224				1,666				1,294
Chemicals			335				345				363				293				238
Net income (2):
Natural resources			2,369				2,376				2,008				1,517				1,174
Petroleum products			921				624				694				556				462
Chemicals			97				143				121				109				44
Corporate and other (3)/eliminations			(199)				(99)				(223)				(130)				25
			3,188				3,044				2,600				2,052				1,705
Identifiable assets at December 31 (4):
Natural resources			8,171				7,513				7,289				6,822				6,397
Petroleum products			6,727				6,450				6,257				5,509				5,225
Chemicals			476				504				500				490				433
Corporate and other/eliminations			1,251				1,674				1,536				1,206				282
			16,287				16,141				15,582				14,027				12,337
Capital and exploration expenditures:
Natural resources			744				787				937				1,113				1,007
Petroleum products			187				361				478				283				478
Chemicals			11				13				19				15				41
Corporate and other			36				48				41				34				33
			978				1,209				1,475				1,445				1,559

(1)		Export sales are reported in note 3 to the consolidated financial statements on page F-10. Total external sales include $4,894 million for 2005, $3,584 million for 2004, and $2,851 million for 2003 for purchases/sales contracts with the same counterparty. Associated costs were included in “purchases of crude oil and products”. Effective January 1, 2006, these purchases/sales were recorded on a net basis. See note 1, Summary of significant Accounting Policies.
(2)		These amounts are presented as if each segment were a separate business entity and, accordingly, include the financial effect of transactions between the segments. Intersegment sales are made essentially at prevailing market prices.
(3)		Includes primarily interest charges on the debt obligations of the company, interest income on investments, incentive compensation expenses, and intersegment consolidating adjustments.
(4)		The identifiable assets in each operating segment represent the net book value of the tangible and intangible assets attributed to such segment. Net intangible assets representing unrecognized prior service costs associated with the recognition of the additional minimum pension liability in 2005 and prior years have been reclassified from the operating segments to the corporate and other segment. Amounts reclassified into the corporate and other segment were $92 million for 2005, $97 million in 2004, and $89 million for 2003. This change has no impact on total identifiable assets at December 31 of 2005 and prior years.

     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, 2007, was as follows:

				2007				2006				2005				2004				2003
Conventional (including natural gas liquids):				(thousands a day)
Barrels		– Gross (1)			45				55				69				76				74
		– Net (2)			33				42				54				59				57
Heavy Oil (3):
Barrels		– Gross (1)			154				152				139				126				129
		– Net (2)			130				127				124				112				116
Oil Sands (4):
Barrels		– Gross (1)			76				65				53				60				53
		– Net (2)			65				58				53				59				52
Total:
Barrels		– Gross (1)			275				272				261				262				256
		– Net (2)			228				227				231				230				225

(1)		Gross production of crude oil is the company’s share of production from conventional wells, Syncrude oil sands and Cold Lake heavy oil, and gross production of natural gas liquids is the amount derived from processing the company’s share of production of natural gas (excluding purchased gas), in each case before deduction of the mineral owners’ or governments’ share or both.
(2)		Net production is gross production less the mineral owners’ or governments’ share or both.
(3)		Heavy oil typically is represented by crude oils with a viscosity of greater than 10,000 cP and recovered through enhanced thermal operations. The company’s heavy oil production volumes are from the Cold Lake production operations.
(4)		Oil sands are a semi-solid material composed of bitumen, sand, water and clays and are recovered through surface mining methods. Imperial’s oil sands production volumes are the company’s share of production volumes in the Syncrude joint venture.

     In 2004, conventional liquids production increased primarily due to increased natural gas liquids production from the Wizard Lake gas cap. In 2005 and 2006 conventional production fell mainly due to the natural decline of the company’s conventional fields. In 2007, the lower production volume was primarily due to decline in the Wizard Lake field. In 2004, Cold Lake production declined due to the timing of steaming cycles and higher royalty, and Syncrude production increased due to improved reliability 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 increased maintenance 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. In 2007, Cold Lake production increased due to timing of steam cycles and production from the ongoing development drilling program and Syncrude production increased with full year operation of the expanded upgrading facilities.

     The company’s average daily production and sales of natural gas during the five years ended December 31, 2007 are set forth below. All gas volumes in this report are calculated at a pressure base of 14.73 pounds per square inch absolute at 60 degrees Fahrenheit.

		2007				2006				2005				2004				2003
		(millions a day)
Sales (1):
Cubic feet			407				513				536				520				460
Gross Production (2):
Cubic feet			458				556				580				569				513
Net Production (2):
Cubic feet			404				496				514				518				457

(1)		Sales are sales of the company’s share of production (before deduction of the mineral owners’ and/or governments’ share) and sales of gas purchased, processed and/or resold.
(2)		Gross production of natural gas is the company’s share of production (excluding purchases) before deducting the shares of mineral owners or governments or both. Net production excludes those shares. Production data include amounts used for internal consumption with the exception of amounts reinjected.

     In 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. In 2007, the lower production volume was primarily due to decline in production from the gas cap at Wizard Lake.

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

     The company’s average sales price and production costs for conventional crude oil, Cold Lake heavy oil and natural gas liquids and natural gas for the five years ended December 31, 2007, were as follows:

		2007				2006				2005				2004				2003
Average Sales Price:
Crude oil and natural gas liquids:
Dollars per barrel			45.16				45.13				37.21				32.95				28.92
Natural gas:
Dollars per thousand cubic feet			6.95				7.24				9.00				6.78				6.60
Average Production Costs Per
Unit of Net Production (1)(2):
Dollars per barrel			12.75				11.08				10.78				9.25				9.66

(1)		Average production costs per unit of production do not include depreciation and depletion of capitalized acquisition, exploration and development costs. Administrative expenses are included. Average production (lifting) costs per unit of net production were computed after converting gas production into equivalent units of oil on the basis of relative energy content.
(2)		Unit production costs are sometimes referred to as lifting costs.

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

     Canadian natural gas prices are determined by North American gas markets which are also volatile and the impact of foreign exchange rates. 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 2004, average unit production costs decreased mainly due to higher production from the Wizard Lake gas cap. In 2005, average unit production costs increased mainly due to higher costs of purchased natural gas at Cold Lake. 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. In 2007, unit production costs were higher primarily as a result of lower gas and liquids volumes due to decline in production from Wizard 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 21 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 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, 2007, 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			1,139				756				5,090				2,773				6,229				3,529
Heavy Oil wells			4,143				4,143				–				–				4,143				4,143

(1)		Gross wells are wells in which the company owns a working interest.
(2)		Net wells are the sum of the fractional working interests owned by the company in gross wells, rounded to the nearest whole number.

     Conventional Oil and Gas

     The company’s largest conventional oil producing asset is the Norman Wells oil field in the Northwest Territories which currently accounts for approximately 57 percent of the company’s net production of conventional crude oil (approximately 63 percent of gross production). In 2007, net production of crude oil and natural gas liquids was about 12,400 barrels per day and gross production was about 18,200 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 540 mile pipeline which transports the crude oil and natural gas liquids from the project. In 2007, 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 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 2007, average net production at Cold Lake was about 130,000 barrels per day and gross production was about 153,500 barrels per day.

     To maintain production at Cold Lake, capital expenditures for additional production wells and associated facilities will be required periodically. In 2007, the company spent $307 million and executed a development drilling program of 188 wells on existing phases. In 2008, a development drilling program of more than 100 wells is planned within the approved development area to add productive capacity from undeveloped areas of existing Cold Lake phases. In addition, opportunities are being evaluated to improve utilization of the 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 third-party 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 original 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. Effective January 1, 2000, the company entered into an agreement with the Province of Alberta on a transitional royalty arrangement that applied to all of the company’s operations at Cold Lake until the end of 2007 at which time the generic Alberta regulations for heavy oil royalties applied. The transition agreement made 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). The generic regulations which apply effective January 1, 2008, provide 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, and with no gas royalty waiver. The transition did not materially change the amount of royalties that the company would have otherwise paid under the pre-existing royalty arrangements. In 2007, the Alberta government proposed increases to the royalty rates beginning in 2009. The company believes that this proposal could have an adverse effect on future company investments in Alberta and the company’s future financial results. The magnitude of the potential impact will depend on the final form of enacted legislation and the future prices of oil and gas and cannot be reasonably estimated at this time. The effective royalty on gross production was 15 percent in 2007, 17 percent in 2006, 11 percent in 2005 and 2004 and 10 percent in 2003.

     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 totaling about 168,000 leased 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), mines 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 1.8 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 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.

     In 2007, the Alberta government proposed changes to the generic oil sands royalty regime beginning in 2009. The Syncrude Joint Venture owners have a Crown Agreement with the Province of Alberta that codifies the royalty rates through December 31, 2015. The Syncrude Joint Venture owners are in discussions with the Alberta government to determine if an amended agreement can be negotiated that would transition Syncrude to the new generic royalty regime before 2016.

     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 (located on lease 17) was depleted and ceased operation in 2007. 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 830,000 tons of oil sands a day, producing about 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 sands 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 2007, the upgrading process yielded 0.843 barrels of synthetic crude oil per barrel of crude bitumen. In 2007, about 38 percent of the synthetic crude oil was processed by Edmonton area refineries and the remaining 62 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 2007 Syncrude’s net production of synthetic crude oil was about 259,300 barrels per day and gross production was about 305,000 barrels per day. The company’s share of net production in 2007 was about 64,800 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 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 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 May 1, 2007, the company implemented a management services agreement under which Syncrude will be provided with operational, technical and business management services from Imperial and Exxon Mobil Corporation. The agreement has an initial term of 10 years and may be terminated by the company or Syncrude with at least two years prior written notice.

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

		2007				2006				2005				2004				2003
Total mined overburden (1) millions of cubic yards			132.2				128.2				97.1				100.3				109.2
Mined overburden to oil sands ratio (1)			1.06				1.18				1.02				0.94				1.15
Oil sands mined millions of tons			221.0				195.5				168.0				188.0				168.0
Average bitumen grade (weight percent)			11.6				11.4				11.1				11.1				11.0
Crude bitumen in mined oil sands millions of tons			25.6				22.2				18.6				20.9				18.5
Average extraction recovery (percent)			91.8				90.3				89.1				87.3				88.6
Crude bitumen production (2) millions of barrels			132.5				111.6				94.2				103.3				92.3
Average upgrading yield (percent)			84.3				84.9				85.3				85.5				86.0
Gross synthetic crude oil produced millions of barrels			113.0				95.5				79.3				88.4				78.4
Company’s net share (3) millions of barrels			23.7				21.3				19.3				21.6				19.1

(1)		Includes pre-stripping of mine areas and reclamation volumes.
(2)		Crude bitumen production is equal to crude bitumen in mined oil sands multiplied by the average extraction recovery and the appropriate conversion factor.
(3)		Reflects the company’s 25 percent interest in production, less applicable royalties payable to the Province of Alberta.

     Other Oil Sands Activity

     The company holds a 100 percent interest in approximately 33,400 acres of surface mineable oil sands which forms part of the Kearl project in the Athabasca region of northern Alberta. The company, as operator, filed a regulatory application in July 2005 with the Alberta Energy and Utilities Board for the development of the Kearl oil sands as a joint project with ExxonMobil Canada. The Alberta Energy and Utilities Board and the Government of Canada gave conditional regulatory approval in February 2007 to the company’s proposed project, following a joint federal and provincial review. The company, with an approximate 70 percent interest, continues to progress a phased development of the project.

     The company is continuing to evaluate other undeveloped oil sands acreage.

     Land Holdings

     At December 31, 2007 and 2006, the company held the following oil and gas rights, and heavy oil and oil sands leases:

		Acres
		Developed								Undeveloped								Total
		2007				2006				2007				2006				2007				2006
Western Provinces										(thousands)
Conventional –
Gross (1)			2,529				2,550				371				382				2,900				2,932
Net (2)			995				1,006				223				235				1,218				1,241
Heavy Oil –
Gross (1)			102				102				429				429				531				531
Net (2)			102				102				258				258				360				360
Oil Sands –
Gross (1)			116				116				293				294				409				410
Net (2)			29				29				134				134				163				163
Canada Lands (3):
Conventional –
Gross (1)			78				78				1,302				794				1,380				872
Net (2)			8				8				496				242				504				250
Atlantic Offshore
Conventional –
Gross (1)			65				42				6,343				6,425				6,408				6,467
Net (2)			6				4				1,513				1,524				1,519				1,528
Total (4):
Gross (1)			2,890				2,888				8,738				8,324				11,628				11,212
Net (2)			1,140				1,149				2,624				2,393				3,764				3,542

(1)		Gross acres include the interests of others.
(2)		Net acres exclude the interests of others.
(3)		Canada Lands include the Arctic Islands, Beaufort Sea/Mackenzie Delta, and other Northwest Territories, Nunavut and Yukon regions.
(4)		Certain land holdings are subject to modification under agreements whereby others may earn interests in the company’s holdings by performing certain exploratory work (farm-out) and whereby the company may earn interests in others’ holdings by performing certain exploratory work (farm-in).

     Exploration and Development

     The company has been involved in the exploration for and development of petroleum and natural gas in the Western Provinces, in the Canada Lands 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, 2007.

		2007				2006				2005				2004				2003
Western and Atlantic Provinces:
Conventional
Exploratory –
Oil			–				–				–				–				–
Gas			–				1				–				2				3
Dry Holes			–				–				–				1				1
Development –
Oil			–				–				2				3				4
Gas			183				192				155				207				89
Dry Holes			–				1				1				1				3
Heavy Oil (Cold Lake and other)
Development –
Oil			188				174				87				218				118
Total			371				368				245				432				218

     In 2007, 188 heavy oil development wells were drilled to add new productive capacity from undeveloped areas of existing phases at Cold Lake. In addition, 183 gas development wells were drilled in 2007 adding productivity primarily in the shallow gas area. Increased shallow gas development drilling accounted for the increase in gas

well count in 2004. 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, 2007, the company was participating in the drilling of 183 gross (123 net) exploratory and development wells.

     Western Provinces

     In 2007, the company had a working interest in 489 gross (371 net) development wells.

     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 the largest of these fields.

     The commercial viability of these natural gas resources, and the pipeline required to transport this natural gas to markets, is dependent on a number of factors. These factors include natural gas markets, support from northern parties, regulatory approvals, environmental considerations, pipeline participation, fiscal framework, and the cost of constructing, operating and abandoning the field production and pipeline facilities.

     In October 2004, the company and its co-venturers filed regulatory applications and environmental impact statements for the project with the National Energy Board (“NEB”) and other boards, panels and agencies responsible for assessing and regulating energy developments in the Northwest Territories. All the scheduled public hearings by the Joint Review Panel (“JRP”) and the NEB were concluded in late 2007. The regulatory process continues with a JRP report expected in 2008 followed by an NEB decision in early 2009.

     In 2007, the company acquired a 50 percent interest in an exploration licence for about 507,000 gross acres in the Beaufort Sea. As part of the evaluation, a 3-D seismic program is being planned.

     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 one exploration licence for about 52,000 gross acres acquired in 1999 in the Sable Island area. One exploratory well was completed on this licence without commercial success. In 2007, one exploration licence in which the company had a 20 percent interest for about 58,000 gross acres in the Sable Island area was allowed to expire.

     Also, the company retains a 70 percent interest in one exploration licence for about 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 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. Drilling of an exploration well was concluded in early 2007. Additional drilling is planned.

     The company retains 100 percent interest in a single exploration licence for about 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 market prices mainly through Exxon Mobil Corporation (which has beneficial access to major market sources of crude oil throughout the world).

     Refining

     The company owns and operates four refineries. 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 2007, capital expenditures of about $110 million were made at the company’s refineries. About 50 percent of those expenditures were on environmental and safety initiatives with the remaining expenditures being primarily on capacity and efficiency improvements.

     The approximate average daily volumes of refinery throughput during the five years ended December 31, 2007, and the daily rated capacities of the refineries at December 31, 2002 and 2007, were as follows:

		Average Daily Volumes of																				Daily Rated
		Refinery Throughput (1)																				Capacities at
		Year Ended December 31																				December 31 (2)
		2007				2006				2005				2004				2003				2007				2002
		(thousands of barrels)
Strathcona, Alberta			170				160				174				170				174				187				184
Sarnia, Ontario			103				111				106				108				92				121				121
Dartmouth, Nova Scotia			69				77				79				80				82				82				82
Nanticoke, Ontario			100				94				108				109				102				112				112
Total			442				442				466				467				450				502				499

(1)		Refinery throughput is the volume of crude oil and feedstocks that is processed in the refinery atmospheric distillation units.
(2)		Rated capacities are based on definite specifications as to types of crude oil and feedstocks that are processed in the refinery atmospheric distillation units, the products to be obtained and the refinery process, adjusted to include an estimated allowance for normal maintenance shutdowns. Accordingly, actual capacities may be higher or lower than rated capacities due to changes in refinery operation and the type of crude oil available for processing.

     Refinery throughput was 88 percent of capacity in 2007, the same as the previous year but lower than 2005 due to planned and unplanned downtime of crude processing facilities.

     Distribution

     The company maintains a nation-wide distribution system, including 27 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.

     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 1,930 sites of which about 600 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 two 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, 2007, are set out in the following table:

		2007				2006				2005				2004				2003
		(thousands of cubic metres a day)
Gasolines			33.1				32.7				33.4				33.2				33.0
Heating, Diesel and Jet Fuels			26.0				26.4				26.9				27.3				26.2
Heavy Fuel Oils			5.2				5.1				6.0				5.9				5.4
Lube Oils and Other Products			6.9				7.7				7.6				7.0				5.8
Net petroleum product sales			71.2				71.9				73.9				73.4				70.4

     The total domestic sales of petroleum products as a percentage of total sales of petroleum products during the five years ended December 31, 2007, were as follows:

		2007				2006				2005				2004				2003
			94.8	%			95.1	%			95.3	%			93.0	%			93.3	%

     The company continues to evaluate and adjust its Esso service station and distribution system to increase productivity and efficiency. During 2007, the company closed or debranded about 80 Esso service stations, about 30 of which were company owned, and added about 50 sites. The company’s average annual throughput in 2007 per Esso service station was 3.8 million litres, an increase of about 0.2 million litres from 2006. Average throughput per company owned or leased Esso service station was 6.5 million litres in 2007, an increase of about 0.4 million litres from 2006.

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, 2007, were as follows:

		2007				2006				2005				2004				2003
		(thousands of tonnes a day)
Petrochemicals			3.1				3.0				3.0				3.3				3.3

Research

     In 2007, the company’s research expenditures in Canada, before deduction of investment tax credits, were $83 million, as compared with $56 million in 2006, and $50 million in 2005. Those funds were used mainly for developing improved heavy oil and oil sands 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 2007. 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 115 people were employed in this type of research and advanced technical support at the end of 2007. Also in Sarnia, there are about 10 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 $1.0 billion on environmental protection and facilities. The environmental expenditures over the past five 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 which cost about $500 million in total. In 2007, the company’s capital expenditures relating to environmental protection totaled approximately $135 million which was spent primarily on emissions reductions at Syncrude and company owned facilities as well as on ultra-low sulphur off-road diesel fuel. Capital expenditures relating to environmental protection are expected to be about $200 million in 2008.

Human Resources

     At December 31, 2007, the company employed full-time approximately 4,800 persons compared with about 4,900 at the end of 2006 and 5,100 at the end of 2005. About 10 percent of the company’s employees are members of unions. The company continues to maintain a broad range of benefits, including health, dental, disability and survivor benefits, vacation, savings plan and pension plan.

Competition

     The Canadian petroleum, natural gas and chemical industries are highly competitive. Competition exists in the search for and development of new sources of supply, the construction and operation of crude oil, natural gas and refined products pipelines and facilities and the refining, distribution and marketing of petroleum products and chemicals. The petroleum industry also competes with other industries in supplying energy, fuel and other needs of consumers.

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 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 2007 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. The acquisition of natural resource properties may, in certain circumstances, be considered to be a transaction that constitutes an acquisition of control of a Canadian business requiring Government of Canada approval.

     The Act also requires notification of the establishment of new unrelated businesses in Canada by entities not controlled by Canadians, but does not require Government of Canada approval except when the new business is related to Canada’s cultural heritage or national identity. 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. 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

     In April 2007, the Government of Canada announced its intent to introduce a set of regulations to limit emissions of greenhouse gas and air pollutants from major industrial facilities in Canada beginning in 2010, although the details of the regulations have not been finalized. Consequently, attempts to assess the impact on the company are premature. The company will continue to monitor the development of legal requirements in this area.

     In the Province of Alberta, regulations governing greenhouse gas emissions from large industrial facilities came into effect July 1, 2007. The company does not expect ongoing compliance costs to have a material adverse effect on the company’s operations or financial condition.

     The recently enacted U.S. Energy Independence and Security Act of 2007 precludes agencies of the U.S. federal government from procuring motive fuels from non-conventional petroleum sources that have lifecycle greenhouse gas emissions greater than equivalent conventional fuel. This may have implications for the company’s marketing in the United States of some heavy oil and oil sands production, but the impact cannot be determined at this time.

     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 1B Unresolved Staff Comments.

     Not applicable.

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

		2007																	2006
		three months ended																	three months ended
		Mar. 31				Jun. 30				Sep. 30				Dec. 31				Mar. 31			Jun. 30			Sep. 30				Dec. 31
Financial data		(millions of dollars)																(millions of dollars)
Total revenues and other income			5,934				6,339				6,430				6,740				5,818				6,688				6,651				5,631
Total expenses			4,819				5,319				5,240				5,686				4,928				5,604				5,421				4,735
Income before income taxes			1,115				1,020				1,190				1,054				890				1,084				1,230				896
Income taxes			(341	)			(308	)			(374	)			(168	)			(299)				(247)				(408)				(102)
Net income			774				712				816				886				591				837				822				794
Per-share information (a)		(dollars)																(dollars)
Net earnings – basic			0.82				0.76				0.88				0.97				0.60				0.85				0.84				0.83
Net earnings – diluted			0.81				0.76				0.88				0.96				0.59				0.85				0.84				0.83
Dividends (declared quarterly)			0.08				0.09				0.09				0.09				0.08				0.08				0.08				0.08
Share prices (a)		(dollars)																(dollars)
Toronto Stock Exchange
High			43.75				54.70				51.90				56.26				42.28				43.33				45.20				44.80
Low			37.40				41.77				40.86				45.57				35.36				36.18				35.33				34.31
Close			42.80				49.59				49.29				54.26				41.91				40.78				37.47				42.93
American Stock Exchange		($U.S.)																($U.S.)
High			38.29				50.35				50.95				61.48				36.67				39.64				40.38				38.93
Low			31.87				36.90				37.99				46.43				30.54				32.50				31.64				29.99
Close			37.12				46.34				49.56				54.78				35.85				36.50				33.55				36.83

(a)		Adjusted to reflect the May 2006 three-for-one share split.

     The company’s shares are listed on the Toronto Stock Exchange and are admitted to unlisted trading on the American Stock Exchange in New York. The symbol on these exchanges for the company’s common shares is IMO. Share prices were obtained from stock exchange records adjusted for the three-for-one share split.

     As of February 14, 2008 there were 13,175 holders of record of common shares of the company.

     During the period October 1, 2007 to December 31, 2007, the company issued 164,805 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)

	Period			(a) Total number					(b) Average price					(c) Total number of					(d) Maximum number
				of shares					paid per share					shares purchased as					(or approximate dollar value)
				(or units)					(or unit)					part of publicly					of shares that may yet be
				purchased										announced plans or					purchased under the plans or
														programs					programs
	October 2007 (October 1 - October 31)				1,498,890				$	48.00					1,498,890					30,445,586
	November 2007 (November 1 - November 30)				6,656,699				$	51.45					6,656,699					23,737,240
	December 2007 (December 1 - December 31)				2,971,920				$	51.70					2,971,920					20,714,852

(1)		The purchases were pursuant to a 12 month normal course share purchase program that was renewed on June 25, 2007 under which the company may purchase up to 46,459,967 of its outstanding common shares less any shares purchased by the employee savings plan and the company pension fund. If not previously terminated, the program will terminate on June 24, 2008.

Item 6. Selected Financial Data.

		2007				2006				2005				2004				2003
		(millions of dollars)
Total operating revenues (a)			25,069				24,505				27,797				22,408				19,094
Net income			3,188				3,044				2,600				2,052				1,705
Total assets			16,287				16,141				15,582				14,027				12,337
Long term debt			38				359				863				367				859
Other long term obligations			1,914				1,683				1,728				1,525				1,314
		(dollars)
Net income/share – basic (b)			3.43				3.12				2.54				1.92				1.53
Net income/share – diluted (b)			3.41				3.11				2.53				1.91				1.53
Cash dividends/share (b)			0.35				0.32				0.31				0.29				0.29

(a)		Total operating revenues include $4,894 million for 2005, $3,584 million for 2004, and $2,851 million for 2003 for purchases/sales contracts with the same counterparty. Associated costs were included in “purchases of crude oil and products”. Effective January 1, 2006, these purchases/sales were recorded on a net basis. See note 1 (page F-7), Summary of Significant Accounting Policies.
(b)		Adjusted to reflect the three-for-one share split.

     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 business outlook, using a disciplined approach in selecting and pursuing the most attractive investment opportunities. The corporate plan is a fundamental annual management process that is the basis for setting near-term operating and capital objectives, in addition to providing the longer-term economic assumptions used for investment evaluation purposes. Potential investment opportunities are tested over a wide range of economic scenarios to establish the resiliency of each opportunity. Once investments are made, a reappraisal process is completed to ensure relevant lessons are learned and improvements are incorporated into future projects.

Business environment and risk assessment

Long-term business outlook

     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 about 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 of 1.3 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 an 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 less than one percent per year. Oil and gas are expected to continue to supply about 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 about 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 30 percent 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.

Natural resources

     Imperial produces crude oil and natural gas for sale into large North American markets. Crude oil and natural gas prices are determined by global and North American markets and are subject to changing supply and demand conditions. These can be influenced by a wide range of factors, including economic conditions, international political developments and weather. 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 Canada’s North, where Imperial has large undeveloped resource opportunities.

Petroleum products

     The downstream industry environment remains very competitive. 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). While refining margins have been strong over the last few years, real inflation adjusted refining margins 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. 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 more than 1,900 Esso-branded service stations, of which about 600 are company-owned or leased, and wholesale and industrial operations through a network of 27 primary distribution terminals, as well as a secondary distribution network.

Chemicals

     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 2007 of $3,188 million or $3.41 a share on a diluted basis was the best on record, exceeding the previous record achieved in 2006 of $3,044 million or $3.11 a share. Earnings increased primarily due to higher crude oil commodity prices, stronger industry refining and marketing margins, favourable refinery operations and higher Syncrude volumes. Gains from asset divestments were also higher in 2007. These factors were partially offset by lower expected conventional resources volumes, the negative impact of a stronger Canadian dollar, higher exploration and share-based compensation expenses and higher tax expense.

Natural resources

     Net income from natural resources was $2,369 million versus $2,376 million in 2006. Earnings benefited from higher crude oil commodity prices totaling about $325 million and higher Syncrude volumes of about $125 million. Higher gains from asset divestments of about $65 million also contributed to higher earnings. Offsetting these positive factors were lower natural gas, conventional crude oil, and natural gas liquids (NGLs) volumes totaling about $285 million, the negative impact of a stronger Canadian dollar of about $175 million and higher exploration and other operating expenses of about $75 million.

Financial statistics

		2007				2006				2005				2004				2003
		(millions of dollars)
Net income			2,369				2,376				2,008				1,517				1,174
Operating revenues			8,685				8,456				8,189				6,580				5,584

     World crude oil prices, denominated in U.S. dollars, were higher in 2007 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 $72 (U.S.) a barrel in 2007, about 11 percent higher than the average price of $65 in 2006 (2005 – $55). 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 $71.70 (Cdn) a barrel, an increase of less than five percent from $68.58 in 2006 (2005 – $64.48).

     Average realizations for Cold Lake heavy oil in U.S. dollars were about five percent higher for the year. Also mainly because of a stronger Canadian dollar, the company’s average realizations for Cold Lake heavy oil were lower by about two percent in 2007.

     Prices for Canadian natural gas in 2007 were lower than in the previous year. The average of 30-day spot prices for natural gas in Alberta was about $7.01 a thousand cubic feet in 2007, compared with $7.41 in 2006 (2005 – $9.01). The company’s average realizations on natural gas sales were $6.95 a thousand cubic feet, compared with $7.24 in 2006 (2005 – $9.00).

Average realizations and prices

		2007				2006				2005				2004				2003
		(Canadian dollars)
Conventional crude oil realizations (a barrel)			71.70				68.58				64.48				48.96				40.10
Natural gas liquids realizations (a barrel)			47.92				40.75				40.00				33.78				32.09
Natural gas realizations (a thousand cubic feet)			6.95				7.24				9.00				6.78				6.60
Par crude oil price at Edmonton (a barrel)			77.67				73.75				69.86				53.26				43.93
Heavy oil price at Hardisty (Bow River, a barrel)			53.87				51.90				45.62				37.98				33.00

     Total gross production of crude oil and NGLs averaged 275,000 barrels a day, compared with 272,000 barrels in 2006 (2005 – 261,000).

     Gross production of heavy oil at the company’s wholly owned facilities at Cold Lake was a record 154,000 barrels a day, surpassing the previous record of 152,000 barrels in 2006 (2005 – 139,000). Increased production was due to the cyclic nature of production at Cold Lake and increased volumes from the ongoing development drilling program.

     Production from the Syncrude oil sands operation, in which the company has a 25 percent interest, was higher during 2007 with increased volumes from the Stage 3 upgrader expansion. Gross production of synthetic crude oil increased to 305,000 barrels a day from 258,000 barrels in 2006 (2005 – 214,000). Imperial’s share of average gross production increased to 76,000 barrels a day from 65,000 barrels in 2006 (2005 – 53,000).

     Gross production of conventional oil decreased to 29,000 barrels a day from 31,000 barrels in 2006 (2005 – 38,000) as a result of natural decline in Western Canadian reservoirs and the impact of divested properties.

     Gross production of NGLs available for sale averaged 16,000 barrels a day in 2007, down from 24,000 barrels in 2006 (2005 – 31,000), mainly due to the declining NGL content of Wizard Lake gas production.

     Gross production of natural gas decreased to 458 million cubic feet a day from 556 million in 2006 (2005 — 580 million). Lower production volumes were primarily due to decline, as expected, in production from the gas cap at Wizard Lake.

     In 2007, the company realized a gain of $142 million primarily from the sale of the company’s interests in several producing properties. Production of the company’s share of these properties averaged about 2,000 oil-equivalent barrels a day in 2006. In 2006, the gain on divestment of assets was approximately $76 million (2005 — $208 million).

Crude oil and NGLs — production and sales (a)

		2007								2006								2005								2004								2003
		gross				net				gross				net				gross				net				gross				net				gross				net
		(thousands of barrels a day)
Cold Lake			154				130				152				127				139				124				126				112				129				116
Syncrude			76				65				65				58				53				53				60				59				53				52
Conventional crude oil			29				21				31				23				38				29				43				33				46				35
Total crude oil production			259				216				248				208				230				206				229				204				228				203
NGLs available for sale			16				12				24				19				31				25				33				26				28				22
Total crude oil and NGL production			275				228				272				227				261				231				262				230				256				225
Cold Lake sales, including diluent (b)			200								198								183								167								170
NGL sales			20								29								39								42								39

Natural gas – production and sales (a)

		2007								2006								2005								2004								2003
		gross				net				gross				net				gross				net				gross				net				gross				net
		(millions of cubic feet a day)
Production (c)			458				404				556				496				580				514				569				518				513				457
Sales			407								513								536								520								460

	(a)		Daily volumes are calculated by dividing total volumes for the year by the number of days in the year. Gross production is the company’s share of production (excluding purchases) before deducting the share of mineral owners or governments or both. Net production excludes those shares.
	(b)		Diluent is natural gas condensate or other light hydrocarbons added to the Cold Lake heavy oil to facilitate transportation to market by pipeline.
	(c)		Production of natural gas includes amounts used for internal consumption with the exception of the amounts reinjected.

     Operating costs increased by less than three percent in 2007. Higher exploration and other operating costs were partially offset by lower depreciation expenses.

     On May 1, 2007, the company confirmed and implemented a management services agreement with Syncrude Canada Ltd., under which Syncrude will be provided operational, technical and business management services from Imperial and Exxon Mobil Corporation.

Petroleum products

     Net income from petroleum products was a record $921 million, $297 million higher than 2006. Increased earnings were primarily due to improved refinery operations including lower refinery maintenance and project activities which contributed about $205 million, and stronger industry refining and marketing margins totaling about $190 million. These positive factors were partially offset by the negative impact of a stronger Canadian dollar of about $60 million and the absence of favourable tax effects of about $40 million.

Financial statistics

		2007				2006				2005				2004				2003
		(millions of dollars)
Net income			921				624				694				556				462
Operating revenues (a)			21,535				20,783				24,017				19,169				16,004

Sale of petroleum products

		2007				2006				2005				2004				2003
		(millions of litres a day (b))
Gasolines			33.1				32.7				33.4				33.2				33.0
Heating, diesel and jet fuels			26.0				26.4				26.9				27.3				26.2
Heavy fuel oils			5.2				5.1				6.0				5.9				5.4
Lube oils and other products			6.9				7.7				7.6				7.0				5.8
Net petroleum product sales			71.2				71.9				73.9				73.4				70.4
Total domestic sales of petroleum products (percent)			94.8				95.1				95.3				93.0				93.3

Refinery utilization

		2007				2006				2005				2004				2003
		(thousands of barrels a day (b))
Total refinery throughput (c)			442				442				466				467				450
Refinery capacity at December 31			502				502				502				502				502
Utilization of total refinery capacity (percent)			88				88				93				93				90

	(a)		Operating revenues in 2005 and prior years included amounts for purchases/sales with the same counterparty. Associated costs were included in “purchases of crude oil and products”. Effective January 1, 2006, these purchases/sales were recorded on a net basis. See note 1, Summary of Significant Accounting Policies, on page F-7.
	(b)		Volumes a day are calculated by dividing total volumes for the year by the number of days in the year.
	(c)		Crude oil and feedstocks sent directly to atmospheric distillation units.

     One thousand litres are approximately 6.3 barrels.

     Margins were stronger in the refining segment of the industry in 2007 compared with those in 2006, pushed up by increased demand for refined petroleum products that stemmed from generally stronger global economic conditions. However, the effects of stronger industry margins were reduced partially by a higher Canadian dollar. Marketing margins in 2007 were slightly higher than those in 2006.

     Refinery throughput was 88 percent of capacity in 2007, unchanged from the previous year (2005 - 93 percent). Refinery throughput in 2007 and 2006 was lower than in 2005 due to planned and unplanned downtime of crude processing facilities.

     The company’s total sales volumes, excluding those resulting from reciprocal supply agreements with other companies, were 71.2 million litres a day, compared with 71.9 million litres in 2006 (2005 — 73.9 million). Lower refinery production was the main reason for the decline.

     Operating costs in 2007 were lower than the previous year by about two percent, reflecting lower maintenance and project related expenses.

Chemicals

     Net income from chemicals operations was $97 million, compared with $143 million in 2006. Lower earnings were primarily due to lower industry margins for polyethylene products partially offset by the positive impact of lower tax rates. A stronger Canadian dollar also negatively impacted earnings in 2007.

Financial statistics

		2007				2006				2005				2004				2003
		(millions of dollars)
Net income			97				143				121				109				44
Operating revenues			1,635				1,704				1,665				1,509				1,232

Sales

		2007				2006				2005				2004				2003
		(thousands of tonnes a day (a))
Polymers and basic chemicals			2.2				2.2				2.1				2.4				2.4
Intermediate and others			0.9				0.8				0.9				0.9				0.9
Total chemicals			3.1				3.0				3.0				3.3				3.3

(a)

Calculated by dividing total volumes for the year by the number of days in the year.

     The average industry price of polyethylene was $1,666 a tonne in 2007, slightly lower than $1,703 a tonne in 2006 (2005 — $1,708).

     Sales of chemicals were 3,100 tonnes a day, compared with 3,000 tonnes a day in 2006 (2005 - 3,000 tonnes) primarily due to higher volumes in intermediate chemical products.

     Operating costs in the chemicals segment for 2007 were about three percent lower than in 2006, reflecting lower direct operating expenses.

Corporate and other

     Net income from corporate and other was negative $199 million, versus negative $99 million last year. Unfavourable earnings effects were primarily due to higher share-based compensation charges and the impact of tax rate changes.

Liquidity and capital resources

Sources and uses of cash

		2007				2006
		(millions of dollars)
Cash provided by/(used in)
Operating activities			3,626				3,587
Investing activities			(620)				(965)
Financing activities			(3,956)				(2,125)
Increase/(decrease) in cash and cash equivalents			(950)				497
Cash and cash equivalents at end of year			1,208				2,158