News release of the Company on November 1, 2010


	Third quarter							Nine months
(millions of dollars, unless noted)	2010		2009		%			2010		2009		%

Net income (U.S. GAAP)		418		547		(24	)		1,411		1,045		35
Net income per common share
- assuming dilution (dollars)		0.49		0.64		(23	)		1.65		1.22		35

Capital and exploration expenditures		1,199		575		109			2,980		1,604		86

(a) Gas converted to oil-equivalent at 6 million cubic feet = 1 thousand barrels


		Bruce March, chairman, president and chief executive officer of Imperial Oil, commented:
		“Imperial Oil achieved solid results with third quarter earnings of $418 million or $0.49 per share. Our earnings were down from $547 million in the third quarter of 2009 due to lower upstream volumes primarily from a planned downtime at Syncrude, unfavourable foreign exchange effects of a stronger Canadian dollar, and third-party pipeline reliability issues that negatively impacted heavy crude oil industry sales and realizations. Strong operating performance in downstream business segments offset continued weak industry margins.
		Earnings for the first nine months of 2010 were $1,411 million or $1.65 per share, up from $1,045 million in the first nine months of 2009, an increase of 35 percent.
		Imperial Oil’s proven approach of taking a long-term view and focusing on disciplined capital investment and financial management will continue to reward our shareholders. Strong cash flow from operating activities continued to substantially fund our record capital investment program. Capital and exploration expenditures were $1,199 million in the third quarter, about double the third quarter of 2009. These expenditures were directed primarily to the development of our Kearl oil sands company growth project.”



Third quarter items of interest

—	Net income was $418 million, compared with $547 million for the third quarter of 2009, a decrease of 24% or $129 million.

—	Net income per common share was $0.49, a decrease of 23% from the third quarter of 2009.

—	Cash generated from operating activities was $965 million, compared with $698 million in the same period last year.

—	Capital and exploration expenditures were $1,199 million, up 109% from the third quarter of 2009, supporting the Kearl oil sands and other growth projects.

—	Gross oil-equivalent barrels of production averaged 281,000 barrels a day, compared with 304,000 barrels a day in the same period last year. Lower production volumes in the third quarter were primarily due to planned maintenance activities at Syncrude and the cyclic nature of production at Cold Lake.

—	Kearl oil sands project update:

	-	The company is currently reconfiguring its Kearl project development plan to include a combination of debottlenecking and expansion to minimize facility requirements and to reduce the plant footprint. The approach will leverage our execution learnings, take advantage of the investments in infrastructure that would not need to be duplicated in the future and will utilize our successful “design one, build many” approach to replicate facilities. The overall production profile and total resource developed at Kearl remain relatively unchanged for the reconfigured project. It is expected that the capital investments’ spending profile of the first phase of the project will be higher based on the adjustments mentioned above.

	-	The Kearl project’s tailings management plan was approved by Alberta’s Energy Resources Conservation Board (ERCB) on August 11, 2010.

—	Nabiye project update – The regulatory approval process for Imperial’s Nabiye expansion project advanced with the recent ERCB Cold Lake scheme amendment and Alberta Utilities Commission approvals. The expansion will add new producing well pads, a processing plant, cogeneration facilities and about 30,000 barrels a day to Cold Lake’s production. Current activities include plant site clearing, grading and road construction.

—	Horn River update – Imperial is planning to drill a horizontal multi-well pad pilot development to evaluate longer-term well productivity this winter season. The company also added an additional 11,000 acres, bringing its joint venture holdings to 321,000 net acres – one of industry’s largest acreage positions in the area.

—	Beaufort Sea – Imperial and ExxonMobil Canada signed a joint operator agreement with BP to share exploration and potential development work on their exploration licenses in the Beaufort Sea. Imperial or ExxonMobil Canada will be the operator and further exploration activities will only proceed with proper regulatory approval.

—	Tim Hortons alliance – Imperial Oil and Tim Hortons signed a 10-year agreement to extend their existing alliance. The agreement includes a commitment to add 175 Tim Hortons locations at Esso sites across Canada over the next 10 years. Tim Hortons began opening kiosks inside Esso gas stations in 1994 and there are now more than 350 of these sites across Canada.


		Third quarter 2010 vs. third quarter 2009
		The company’s net income for the third quarter of 2010 was $418 million or $0.49 a share on a diluted basis, compared with $547 million or $0.64 a share for the same period last year.
		Although third quarter earnings were lower, underlying business operations remained strong across all segments of the company. The lower third quarter earnings were primarily attributable to planned maintenance activities at Syncrude, impacting earnings by about $90 million, and the unfavourable foreign exchange effects of a stronger Canadian dollar of about $70 million. These factors were partially offset by the combined impacts of upstream commodity prices and downstream margins totaling about $75 million. The company estimates that third-party pipeline reliability issues negatively impacted third quarter earnings by about $60 million; this effect, which will carry-over in fourth quarter results, has been reflected in the overall commodity price and margins factor above.
		Upstream net income in the third quarter was $348 million versus $439 million in the same period of 2009. Earnings decreased primarily due to higher costs and lower volumes at Syncrude, mainly a result of planned maintenance activities, totaling about $90 million. Earnings were also negatively impacted by the unfavourable foreign exchange effects of a stronger Canadian dollar of about $65 million and lower Cold Lake bitumen production and lower conventional volumes totaling about $25 million. These factors were partially offset by higher crude oil and natural gas commodity prices in the third quarter of 2010 which contributed to higher earnings of about $95 million. Third-party pipeline reliability issues in the third quarter negatively impacted the transportation of western crude oil. The company estimates the negative impact on earnings of about $45 million from lower realizations, the effect of which has been reflected in the commodity price factor above.
		The average price of Brent crude oil in U.S. dollars, a common benchmark for world oil markets, was $76.85 a barrel in the third quarter, up about 13 percent from the corresponding period last year. The company’s average realizations on sales of Canadian conventional crude oil and synthetic crude oil from Syncrude production also increased. The company’s average bitumen realizations were also higher in the third quarter, but by less than the relative increase in light crude oil prices, reflecting a widened price spread between the lighter crude oils and Cold Lake bitumen, attributable to third-party pipeline outages.
		Gross production of Cold Lake bitumen averaged 139 thousand barrels a day during the third quarter, versus 145 thousand barrels in the same quarter last year. Lower volumes were due to the cyclic nature of production at Cold Lake.
		The company’s share of Syncrude’s gross production in the third quarter was 66 thousand barrels a day, versus 78 thousand barrels in the third quarter of 2009. Lower volumes were the result of planned maintenance activities, which began in September 2010 and will complete in late October 2010.
		Gross production of conventional crude oil averaged 22 thousand barrels a day in the third quarter, down from 25 thousand barrels in the third quarter of 2009. Planned maintenance activities at the Norman Wells field and natural reservoir decline were the main contributors to the lower production.
		Gross production of natural gas during the third quarter of 2010 was 284 million cubic feet a day, down slightly from 291 million cubic feet in the same period last year. The lower production volume was primarily a result of maintenance activities and natural reservoir decline.
		Downstream net income was $69 million in the third quarter of 2010, compared with $62 million in the same period a year ago. Improved refinery operations as well as improved sales volumes when compared to the low levels in the third quarter of 2009 contributed about $25 million to the earnings increase. These factors were partially offset by lower overall margins of about $20 million, which included the negative impact of the third-party pipeline outages.


		Chemical net income was $23 million in the third quarter, $4 million higher than the same quarter last year. Improved industry margins for polyethylene and intermediate products were partially offset by lower sales volumes for polyethylene products.
		Net income effects from Corporate and other were negative $22 million in the third quarter, compared with $27 million in the same period of 2009. The change in earnings effects was primarily due to changes in share-based compensation charges in the third quarter of 2010.
		Cash flow generated from operating activities was $965 million during the third quarter of 2010, compared with $698 million in the same period last year. Higher cash flow was primarily driven by working capital effects partially offset by lower earnings.
		Investing activities used net cash of $1,113 million in the third quarter, an increase of $568 million from the corresponding period in 2009. Capital and exploration expenditures were $1,199 million in the third quarter, compared with $575 million during the same quarter 2009. Expenditures during the quarter were primarily directed towards the advancement of the Kearl oil sands project. Other investments included development drilling at Cold Lake, exploration drilling at Horn River as well as environmental and other projects at Syncrude.
		In the third quarter, the company increased its debt level by $228 million by drawing on existing facilities.
		The company’s balance of cash was $51 million at September 30, 2010, compared with $513 million at the end of 2009.


		Nine months highlights
		—		Net income was $1,411 million, up from $1,045 million in the nine months of 2009.
		—		Net income per common share increased to $1.65 compared to $1.22 in the same period of 2009.
		—		Cash generated from operations was $2,203 million, versus $664 million in the nine months of 2009.
		—		Capital and exploration expenditures were $2,980 million, up 86 percent, supporting the Kearl oil sands and other growth projects.
		—		Gross oil-equivalent barrels of production averaged 291 thousands of barrels per day, compared to 292 thousands of barrels per day in the nine months of 2009.
		—		Per-share dividends declared in the first three quarters of 2010 totaled $0.32, up from $0.30 in the same period of 2009.


		Nine months 2010 vs. nine months 2009
		Net income for the first nine months of 2010 was $1,411 million or $1.65 a share on a diluted basis, versus $1,045 million or $1.22 a share for the nine months of 2009.
		For the nine months, earnings increased primarily due to the impacts of higher upstream commodity prices of about $800 million, higher Syncrude volumes of about $90 million and improved refinery operations and lower refinery maintenance activities totaling about $75 million. These factors were partially offset by the unfavourable effects of a stronger Canadian dollar of about $330 million, higher royalty costs due to higher commodity prices of about $240 million, and lower overall downstream margins of about $110 million. Earnings in the nine months of 2010 also included higher gain of about $25 million from sale of non-operating assets.
		Upstream net income for the nine months was $1,238 million versus $833 million during the same period last year. Higher crude oil and natural gas commodity prices in 2010 increased revenues, contributing to higher earnings of about $800 million. Earnings were also positively impacted by higher Syncrude volumes, reflecting improved reliability, of about $90 million. These factors were partially offset by the impact of a stronger Canadian dollar of about $265 million and higher royalty costs due to higher commodity prices of about $240 million.
		The average price of Brent crude oil in U.S. dollars, a common benchmark for world oil markets, was $77.15 a barrel in the nine months of 2010, up about 35 percent from the corresponding period last year. The company’s average realizations on sales of Canadian conventional crude oil and synthetic crude oil from Syncrude production also increased. The company’s average bitumen realizations were also higher in the first nine months of 2010, but by less than the relative increase in light crude oil prices, reflecting widened price spread between the lighter crude oils and Cold Lake bitumen, attributable to third-party pipeline outages.
		For the nine months, gross production of Cold Lake bitumen was 143 thousand barrels a day this year, compared with 144 thousand barrels in the same period of 2009.
		During the nine months of the year, the company’s share of gross production from Syncrude averaged 71 thousand barrels a day, up from 66 thousand barrels in 2009. Increased production in the nine months of 2010 was due to improved operational reliability.


		Gross production of conventional crude oil in the first nine months of the year was 23 thousand barrels a day, compared with 25 thousand barrels in 2009. Planned maintenance activities at the Norman Wells field and natural reservoir decline were the main contributors to the lower production.

		In the nine months of the year, gross production of natural gas was 282 million cubic feet a day, down from 294 million cubic feet in the nine months of 2009. The lower production volume was primarily a result of maintenance activities and natural reservoir decline.

		Nine-month net income from Downstream was $176 million, compared with $226 million in 2009. Lower earnings were primarily due to lower overall margins of about $110 million and the unfavourable effects of a stronger Canadian dollar of about $60 million. These factors were partially offset by the favourable impacts of about $75 million associated with improved refinery operations and lower refinery maintenance activities and $35 million gain from sale of non-operating assets.

		Chemical net income for the first nine months was $44 million, up $14 million from the same period in 2009. Improved industry margins were partially offset by lower sales volumes for polyethylene products and higher costs due to planned maintenance activities.

		For the nine months of 2010, net income from Corporate and other was negative $47 million, in line with negative $44 million reported last year.

		Key financial and operating data follow.

		Forward-Looking Statements

		Statements in this report relating to future plans, projections, events or conditions are forward-looking statements. Actual future results, including project plans, costs, timing and capacities; financing sources; the resolution of contingencies and uncertain tax positions; the effect of changes in prices and other market conditions; and environmental and capital expenditures could differ materially depending on a number of factors, such as the outcome of commercial negotiations; changes in the supply of and demand for crude oil, natural gas, and petroleum and petrochemical products; political or regulatory events; and other factors discussed in Item 1A of the company’s 2010 Form 10K.


	Third Quarter							Nine Months
millions of Canadian dollars	2010				2009			2010				2009

Total cash and cash equivalents at period end		51				458			51				458

Net income		418				547			1,411				1,045
Adjustment for non-cash items:
Depreciation and depletion		187				194			561				584
(Gain)/loss on asset sales		(12	)			-			(58	)			(32	)
Deferred income taxes and other		(17	)			(6	)		55				(49	)
Changes in operating assets and liabilities		389		(a)		(37	)		234		(a)		(884	)
Cash from (used in) operating activities		965				698			2,203				664

Cash from (used in) investing activities		(1,113	)			(545	)		(2,717	)			(1,431	)
Proceeds from asset sales		35				8			95				45

Cash from (used in) financing activities		135				(85	)		52				(749	)


Operating statistics	Third Quarter				Nine Months
	2010		2009		2010		2009

Gross crude oil and Natural Gas Liquids (NGL) production (thousands of barrels a day)
Cold Lake		139		145		143		144
Syncrude		66		78		71		66
Conventional		22		25		23		25
Total crude oil production		227		248		237		235
NGLs available for sale		7		7		7		8
Total crude oil and NGL production		234		255		244		243

Gross natural gas production (millions of cubic feet a day)		284		291		282		294

Gross oil-equivalent production (a) (thousands of oil-equivalent barrels a day)		281		304		291		292

Net crude oil and NGL production (thousands of barrels a day)
Cold Lake		112		116		114		124
Syncrude		61		67		65		62
Conventional		17		19		17		21
Total crude oil production		190		202		196		207
NGLs available for sale		5		6		5		6
Total crude oil and NGL production		195		208		201		213

Net natural gas production (millions of cubic feet a day)		263		295		255		278

Net oil-equivalent production (a) (thousands of oil-equivalent barrels a day)		239		257		244		259

Cold Lake blend sales (thousands of barrels a day)		176		185		187		187
NGL Sales (thousands of barrels a day)		13		9		11		9
Natural gas sales (millions of cubic feet a day)		259		269		262		270

Average realizations (Canadian dollars)
Conventional crude oil realizations (a barrel)		67.93		65.29		70.76		57.30
NGL realizations (a barrel)		44.22		36.24		48.15		38.14
Natural gas realizations (a thousand cubic feet)		3.58		2.90		4.19		4.07
Synthetic oil realizations (a barrel)		77.83		73.27		79.26		65.95
Bitumen realizations (a barrel)		57.04		55.97		58.17		49.31

Refinery throughput (thousands of barrels a day)		453		417		437		414
Refinery capacity utilization (percent)		90		83		87		82

Petroleum product sales (thousands of barrels a day)
Gasolines		227		204		215		200
Heating, diesel and jet fuels		151		138		145		143
Heavy fuel oils		20		22		28		26
Lube oils and other products		46		43		44		39
Net petroleum products sales		444		407		432		408

Petrochemical Sales (thousands of tonnes a day)		2.7		2.8		2.7		2.8


	Net income (U.S. GAAP)		Net income per common share
	(millions of Canadian dollars)		(dollars)

2006
First Quarter		591		0.60
Second Quarter		837		0.85
Third Quarter		822		0.84
Fourth Quarter		794		0.83
Year		3,044		3.12

2007
First Quarter		774		0.82
Second Quarter		712		0.76
Third Quarter		816		0.88
Fourth Quarter		886		0.97
Year		3,188		3.43

2008
First Quarter		681		0.76
Second Quarter		1,148		1.29
Third Quarter		1,389		1.57
Fourth Quarter		660		0.77
Year		3,878		4.39

2009
First Quarter		289		0.34
Second Quarter		209		0.25
Third Quarter		547		0.64
Fourth Quarter		534		0.63
Year		1,579		1.86

2010
First Quarter		476		0.56
Second Quarter		517		0.61
Third Quarter		418		0.49


	Third Quarter						Nine Months
millions of Canadian dollars	2010			2009			2010			2009

Net income (U.S. GAAP)
Upstream		348			439			1,238			833
Downstream		69			62			176			226
Chemical		23			19			44			30
Corporate and other		(22	)		27			(47	)		(44	)
Net income		418			547			1,411			1,045

Total revenues
Upstream		1,792			1,878			5,985			4,894
Downstream		5,088			4,749			15,592			13,362
Chemical		344			315			1,028			900
Eliminations/Other		(1,373	)		(1,381	)		(4,449	)		(3,622	)
Revenues		5,851			5,561			18,156			15,534

Purchases of crude oil and products
Upstream		545			568			1,985			1,400
Downstream		4,047			3,729			12,471			10,162
Chemical		244			218			754			650
Eliminations		(1,374	)		(1,389	)		(4,451	)		(3,635	)
Purchases of crude oil and products		3,462			3,126			10,759			8,577

Production and manufacturing expenses
Upstream		592			549			1,767			1,825
Downstream		320			313			1,079			1,049
Chemical		49			47			157			142
Production and manufacturing expenses		961			909			3,003			3,016

Capital and exploration expenditures
Upstream		1,151			504			2,838			1,422
Downstream		45			64			129			167
Chemical		1			6			9			12
Corporate and other		2			1			4			3
Capital and exploration expenditures		1,199			575			2,980			1,604

Exploration expenses charged to income included above		54			21			171			126