Exhibit 1

Supplementary Oil & Gas Information for

the Fiscal Year Ended December 31, 2009

SUPPLEMENTARY OIL & GAS INFORMATION (unaudited)

This supplementary crude oil and natural gas information is provided in accordance with the United States Financial Accounting Standards Board (“FASB”) Topic 932 – “Extractive Activities – Oil and Gas”, and where applicable is reconciled to the financial information prepared in accordance with generally accepted accounting principles in the United States (“US GAAP”).

NET PROVED CRUDE OIL AND NATURAL GAS RESERVES

The Company retains qualified independent reserves evaluators to evaluate the Company’s proved crude oil and natural gas reserves.

● For the year ended December 31, 2009 the reports by GLJ Petroleum Consultants Ltd. (“GLJ”) covered 100% of the Company’s synthetic crude oil reserves.  With the inclusion of the non-traditional resources within the definition of “oil and gas producing activities” within the SEC’s modernization of oil and gas reporting rules (“Final Rule”), effective January 1, 2010 these reserves volumes are now included within the Company’s crude oil and natural gas reserves totals.

● For the years ended December 31, 2009, and 2008, the reports by Sproule Associates Limited (“Sproule”) covered 100% of the Company’s bitumen, coal bed methane, crude oil and natural gas liquids and natural gas reserves.

● For the years ended December 31, 2007, and 2006 the reports by Sproule and Ryder Scott Company covered 100% of the Company’s bitumen, coal bed methane, crude oil and natural gas liquids and natural gas reserves.

Proved crude oil and natural gas reserves, as defined within the SEC’s Regulation S-X, under the Final Rule, are the estimated quantities of oil and gas that geoscience and engineering data demonstrate with reasonable certainty to be  economically producible, from a given date forward, under known reservoirs under existing economic conditions, operating methods and government regulations. Proved developed reserves are reserves that can be expected to be recovered from existing wells with existing equipment and operating methods or in which the cost of the required equipment is relatively minor compared to the cost of drilling a new well; and through installed extraction equipment and infrastructure operational at the time of the reserves estimate if the extraction is by means not involving a well.

Estimates of crude oil and natural gas reserves are subject to uncertainty and will change as additional information regarding producing fields and technology becomes available and as future economic and operating conditions change.

The following table summarizes the Company’s proved and proved developed crude oil and natural gas reserves, net of royalties, as at December 31, 2009, 2008, 2007, and 2006:

Crude Oil and NGLs (mmbbl)	Synthetic Crude Oil(1)	Bitumen(2)	Crude Oil & NGLs	North America Total	North Sea	Offshore West Africa	Total
Net Proved Reserves
Reserves, December 31, 2006				887	299	130	1,316
Extensions and discoveries				30	–	–	30
Improved recovery				13	6	–	19
Purchases of reserves in place				1	–	–	1
Sales of reserves in place				–	(3)	–	(3)
Production				(77)	(20)	(10)	(107)
Revisions of prior estimates (3)				66	28	8	102
Reserves, December 31, 2007				920	310	128	1,358
Extensions and discoveries				51	-	-	51
Improved recovery				17	6	4	27
Purchases of reserves in place				–	–	–	–
Sales of reserves in place				–	–	–	–
Production				(76)	(17)	(8)	(101)
Economic revisions due to prices				28	(81)	8	(45)
Revisions of prior estimates				8	38	10	56
Reserves, December 31, 2008	–	690	258	948	256	142	1,346
Extensions and discoveries	–	24	6	30	–	–	30
Improved recovery	–	8	75	83	–	–	83
SEC reliable technology(4)	–	7	–	7	–	–	7
SEC rule transition(5)	1,650	–	–	1,650	–	–	1,650
Purchases of reserves in place	–	–	1	1	–	–	1
Sales of reserves in place	–	–	–	–	–	–	–
Production	–	(49)	(24)	(73)	(14)	(11)	(98)
Economic revisions due to prices	–	(64)	(8)	(72)	57	(4)	(19)
Revisions of prior estimates	–	79	11	90	(59)	(4)	27
Reserves, December 31, 2009	1,650	695	319	2,664	240	123	3,027
Net proved developed reserves
December 31, 2006				420	214	63	697
December 31, 2007				426	240	70	736
December 31, 2008				428	97	107	632
December 31, 2009	1,589	268	204	2,061	94	106	2,261

(1)   Prior to December 31, 2009 the Company’s Horizon SCO reserves were reported separately in accordance with the SEC’s Industry Guide 7.  With the SEC’s Final Rule in effect January 1, 2010, this synthetic crude oil is now included in the Company’s crude oil and natural gas reserves totals.

(2)   Bitumen as defined by the SEC, under the Final Rule, “is petroleum in a solid or semi-solid state in natural deposits with a viscosity greater than 10,000 centipoise measured at original temperature in the deposit and atmospheric pressure, on a gas free basis.”  Under this definition, all the Company’s thermal and primary heavy oil reserves have been classified as bitumen.  Prior to December 31, 2009, these reserves would have been classified within the Company’s conventional crude oil and NGL totals.

(3)   Revisions of prior estimates for the year ended December 31, 2007 include the impact of economic revisions due to prices.

(4)   SEC reliable technology accounts for reserves volumes added due to the reserves rule changes.

(5)   For continuity purposes, with respect to the transition from Industry Guide 7 into the SEC’s Final Rule, the following SCO table has been provided to illustrate the changes in the Company’s Horizon SCO reserves for the 2009 year.

Horizon SCO Reserves	Net proved  (mmbbl)
Reserves, December 31, 2008	1,946
Production	(18	)
Economic revisions due to prices	(307	)
Revisions of prior estimates	29
Reserves, December 31, 2009	1,650

Natural Gas (bcf)	North America	North Sea	Offshore West Africa	Total
Net Proved Reserves
Reserves, December 31, 2006	3,705	37	56	3,798
Extensions and discoveries	134	-	-	134
Improved recovery	132	3	-	135
Purchases of reserves in place	12	-	-	12
Sales of reserves in place	-	-	-	-
Production	(503)	(5)	(4)	(512)
Revisions of prior estimates (1)	41	46	12	99
Reserves, December 31, 2007	3,521	81	64	3,666
Extensions and discoveries	140	-	-	140
Improved recovery	52	(1)	6	57
Purchases of reserves in place	77	-	-	77
Sales of reserves in place	(1)	-	-	(1)
Production	(449)	(4)	(4)	(457)
Economic revisions due to prices	(19)	(56)	6	(69)
Revisions of prior estimates	202	47	22	271
Reserves, December 31, 2008	3,523	67	94	3,684
Extensions and discoveries	92	–	–	92
Improved recovery	11	–	–	11
Purchases of reserves in place	15	–	–	15
Sales of reserves in place	(6)	–	–	(6)
Production	(443)	(4)	(6)	(453)
Economic revisions due to prices	(335)	12	(4)	(327)
Revisions of prior estimates	170	(8)	1	163
Reserves, December 31, 2009	3,027	67	85	3,179
Net proved developed reserves
December 31, 2006	2,934	17	12	2,963
December 31, 2007	2,731	58	53	2,842
December 31, 2008	2,690	45	89	2,824
December 31, 2009	2,333	45	81	2,459

(1)   Revisions of prior estimates for the year ended December 31, 2007include the impact of economic revisions due to prices.

CAPITALIZED COSTS RELATED TO CRUDE OIL AND NATURAL GAS ACTIVITIES

	2009
(millions of Canadian dollars)	North America(1)			North Sea			Offshore West Africa			Other			Total
Proved properties	$	49,052		$	3,875		$	2,195		$	14		$	55,136
Unproved properties		2,854			4			666			28			3,552
		51,906			3,879			2,861			42			58,688
Less: accumulated depletion   and depreciation		(24,216	)		(3,260	)	)	(1,170	)		(14	)		(28,660	)
Net capitalized costs	$	27,690		$	619		$	1,691		$	28		$	30,028

(1) As at December 31, 2009, the Company’s Oil Sands Mining and Upgrading segment has been included in North America capitalized costs in accordance with revisions to the US Securities and Exchange Commission oil and gas disclosures in Regulations S–K and S–X and FASB Topic 932 – “Extractive Activities – Oil and Gas”.

	2008
(millions of Canadian dollars)	North America			North Sea			Offshore West Africa			Other			Total
Proved properties	$	34,386		$	4,155		$	2,076		$	14		$	40,631
Unproved properties		2,271			12			595			26			2,904
		36,657			4,167			2,671			40			43,535
Less: accumulated depletion   and depreciation		(21,857)	)		(3,366	)	)	(777	)		(14	)		(26,014	)
Net capitalized costs	$	14,800		$	801		$	1,894		$	26		$	17,521

	2007
(millions of Canadian dollars)	North America			North Sea			Offshore West Africa			Other			Total
Proved properties	$	32,061		$	3,164		$	1,695		$	14		$	36,934
Unproved properties		2,259			10			138			25			2,432
		34,320			3,174			1,833			39			39,366
Less: accumulated depletion   and depreciation		(12,213	)		(1,446	)	)	(645	)		(14	)		(14,318	)
Net capitalized costs	$	22,107		$	1,728		$	1,188		$	25		$	25,048

COSTS INCURRED IN CRUDE OIL AND NATURAL GAS ACTIVITIES

	2009
(millions of Canadian dollars)	North America(1)		North Sea		Offshore West Africa		Other		Total
Property acquisitions
Proved	$	6	$	-	$	-	$	-	$	6
Unproved		69		-		-		-		69
Exploration		173		36		1		-		210
Development		1,480		277		654		2		2,413
Costs incurred	$	1,728	$	313	$	655	$	2	$	2,698

(1) Excludes additions related to the Company’s Oil Sands Mining and Upgrading Segment.

	2008
(millions of Canadian dollars)	North America		North Sea		Offshore West Africa		Other		Total
Property acquisitions
Proved	$	299	$	(7)	$	44	$	-	$	336
Unproved		84		1		1		-		86
Exploration		144		3		-		1		148
Development		1,810		195		772		-		2,777
Costs incurred	$	2,337	$	192	$	817	$	1	$	3,347

	2007
(millions of Canadian dollars)	North America		North Sea		Offshore West Africa		Other		Total
Property acquisitions
Proved	$	55	$	(38)	$	-	$	-	$	17
Unproved		13		1		-		-		14
Exploration		239		19		-		1		259
Development		2,173		380		148		-		2,701
Costs incurred	$	2,480	$	362	$	148	$	1	$	2,991

RESULTS OF OPERATIONS FROM CRUDE OIL AND NATURAL GAS PRODUCING ACTIVITIES

The Company’s results of operations from crude oil and natural gas producing activities for the years ended December 31, 2009, 2008, and 2007 are summarized in the following tables:

	2009
(millions of Canadian dollars)	North America(1)			North Sea			Offshore West Africa			Total
Crude oil and natural gas revenue, net of    royalties and blending costs	$	7,121		$	1,334		$	832		$	9,287
Production		(1,748	)		(376	)		(179	)		(2,303	)
Transportation		(284	)		(8	)		(1	)		(293	)
Depletion, depreciation and amortization(2)		(2,186	)		(207	)		(527	)		(2,920	)
Asset retirement obligation accretion		(41	)		(24	)		(4	)		(69	)
Petroleum revenue tax		-			(85	)		-			(85	)
Income tax		(833	)		(317	)		(30	)		(1,180	)
Results of operations	$	2,029		$	317		$	91		$	2,437

(1) Excludes results of operations from the Company’s Oil Sands Mining and Upgrading segment.

(2) Includes the impact of a ceiling test impairment at December 31, 2009 of $993 million, pre-tax.

	2008
(millions of Canadian dollars)	North America			North Sea			Offshore West Africa			Total
Crude oil and natural gas revenue, net of    royalties and blending costs	$	8,126		$	1,731		$	801		$	10,658
Production		(1,881	)		(457	)		(102	)		(2,440	)
Transportation		(327	)		(10	)		(1	)		(338	)
Depletion, depreciation and amortization(1)		(9,661	)		(1,564	)		(132	)		(11,357	)
Asset retirement obligation accretion		(42	)		(27	)		(2	)		(71	)
Petroleum revenue tax		-			(143	)		-			(143	)
Income tax		1,128			235			(141	)		1,222
Results of operations	$	(2,657	)	$	(235	)	$	423		$	(2,469	)

(1) Includes the impact of a ceiling test impairment at December 31, 2008 of $8,665 million, pre-tax.

	2007
(millions of Canadian dollars)	North America			North Sea			Offshore West Africa			Total
Crude oil and natural gas revenue, net of    royalties and blending costs	$	7,441		$	1,522		$	709		$	9,672
Production		(1,642	)		(432	)		(94	)		(2,168	)
Transportation		(335	)		(16	)		(1	)		(352	)
Depletion, depreciation and amortization		(2,359	)		(340	)		(165	)		(2,864	)
Asset retirement obligation accretion		(38	)		(30	)		(2	)		(70	)
Petroleum revenue tax		-			(141	)		-			(141	)
Income tax		(997	)		(282	)		(121	)		(1,400	)
Results of operations	$	2,070		$	1,522		$	326		$	2,677

STANDARDIZED MEASURE OF DISCOUNTED FUTURE NET CASH FLOWS FROM PROVED CRUDE OIL AND NATURAL GAS RESERVES AND CHANGES THEREIN

The following standardized measure of discounted future net cash flows from proved crude oil and natural gas reserves has been computed using the average first-day-of-the-month price during the previous 12-month period, costs as at the balance sheet date and year-end statutory income tax rates. A discount factor of 10% has been applied in determining the standardized measure of discounted future net cash flows. The Company does not believe that the standardized measure of discounted future net cash flows will be representative of actual future net cash flows and should not be considered to represent the fair value of the crude oil and natural gas properties. Actual net cash flows will differ from the presented estimated future net cash flows due to several factors including:

● Future production will include production not only from proved properties, but may also include production from probable and possible reserves;

● Future production of crude oil and natural gas from proved properties will differ from reserves estimated;

● Future production rates will vary from those estimated;

●  Future rather than average first-day-of-the-month prices during the previous 12-month period and costs as at the balance sheet date will apply;

● Economic factors such as interest rates, income tax rates, regulatory and fiscal environments and operating conditions will change;

● Future estimated income taxes do not take into account the effects of future exploration expenditures; and

● Future development and asset retirement obligations will differ from those estimated.

Future net revenues, development, production and restoration costs have been based upon the estimates referred to above. The following tables summarize the Company’s future net cash flows relating to proved crude oil and natural gas reserves based on the standardized measure as prescribed in FASB Topic 932 – “Extractive Activities – Oil and Gas”:

	2009
(millions of Canadian dollars)	North America(1)			North Sea			Offshore West Africa			Total
Future cash inflows	$	176,866		$	16,304		$	8,305		$	201,475
Future production costs		(88,134	)		(6,929	)		(3,255	)		(98,318	)
Future development and asset retirement    obligations		(22,767	)		(5,271	)		(975	)		(29,013	)
Future income taxes		(11,237	)		(3,487	)		(1,229	)		(15,953	)
Future net cash flows		54,728			617			2,846			58,191
10% annual discount for timing of future    cash flows		(35,526	)		(275	)		(1,345	)		(37,146	)
Standardized measure of future net cash flows	$	19,202		$	342		$	1,501		$	21,045

	2008
(millions of Canadian dollars)	North America			North Sea			Offshore West Africa			Total
Future cash inflows	$	51,913		$	13,681		$	6,789		$	72,383
Future production costs		(23,747	)		(6,845	)		(3,000	)		(33,592	)
Future development and asset retirement    obligations		(9,238	)		(4,674	)		(364	)		(14,276	)
Future income taxes		(3,097	)		(2,011	)		(1,061	)		(6,169	)
Future net cash flows		15,831			151			2,364			18,346
10% annual discount for timing of future    cash flows		(6,872	)		(76	)		(1,011	)		(7,959	)
Standardized measure of future net cash flows	$	8,959		$	75		$	1,353		$	10,387

	2008
(millions of Canadian dollars)	North America			North Sea			Offshore West Africa			Total
Future cash inflows	$	71,069		$	30,269		$	9,921		$	111,259
Future production costs		(23,729	)		(9,316	)		(2,419	)		(35,464	)
Future development and asset retirement    obligations		(7,938	)		(4,021	)		(621	)		(12,580	)
Future income taxes		(9,508	)		(11,376	)		(1,978	)		(22,862	)
Future net cash flows		29,894			5,556			4,903			40,353
10% annual discount for timing of future    cash flows		(13,952	)		(2,176	)		(2,505	)		(18,633	)
Standardized measure of future net cash flows	$	15,942		$	3,380		$	2,398		$	21,720

The principal sources of change in the standardized measure of discounted future net cash flows are summarized in the following table:

(millions of Canadian dollars)	2009			2008			2007
Sales of crude oil and natural gas produced, net of    production costs	$	(5,437	)	$	0		$	(7,150	)
Net changes in sales prices and production costs		16,808			(14,680	)		7,412
Extensions, discoveries and improved recovery		4,222			820			1,429
Changes in estimated future development costs		(2,752	)		(715	)		(169	)
Purchases of proved reserves in place		53			113			39
Sales of proved reserves in place		(7	)		(1	)		(103	)
Revisions of previous reserve estimates		220			112			2,380
Accretion of discount		1,375			3,468			2,760
SEC reliable technology		254			-			-
SEC rule transition		7,332			-			-
Changes in production timing and other		(2,788	)		767			508
Net change in income taxes		(8,622	)		8,462			(3,378	)
Net change		10,658			(11,333	)		3,728
Balance – beginning of year		10,387			21,720			17,992
Balance – end of year	$	21,045		$	10,387		$	21,720