eh1300455_ex9901.htm

Supplementary Oil & Gas Information for

the Fiscal Year Ended December 31, 2012

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, financial information is prepared in accordance with International Financial Reporting Standards (“IFRS”). In addition, comparative financial information for 2010 has been restated from generally accepted accounting principles in the United States to reflect the adoption of IFRS.

For the years ended December 31, 2012, 2011 and 2010, the Company filed its reserves information under National Instrument 51-101 – “Standards of Disclosure of Oil and Gas Activities” (“NI 51-101”), which prescribes the standards for the preparation and disclosure of reserves and related information for companies listed in Canada. For years prior to 2010, the Company was granted an exemption from certain provisions of NI 51-101 allowing the Company to substitute SEC requirements under Regulations S-K and S-X for certain disclosures required under NI 51-101. Such exemption expired on December 31, 2010.

There are significant differences to the type of volumes disclosed and the basis from which the volumes are economically determined under the SEC requirements and NI 51-101. The SEC requires disclosure of net reserves, after royalties, using 12-month average prices and current costs; whereas NI 51-101 requires gross reserves, before royalties, using forecast pricing and costs. Therefore the difference between the reported numbers under the two disclosure standards can be material.

For the purposes of determining proved crude oil and natural gas reserves for SEC requirements as at December 31, 2012, 2011, and 2010 the Company used the 12-month average price, defined by the SEC as the unweighted arithmetic average of the first-day-of-the-month price for each month within the 12-month period prior to the end of the reporting period. The Company has used the following 12-month average benchmark prices to determine its 2012 reserves for SEC requirements.

Crude Oil and NGLs					Natural Gas
WTI Cushing Oklahoma	WCS	Edmonton Par	North Sea Brent	Edmonton C5+	Henry Hub Louisiana	AECO	BC Westcoast Station 2
(US$/bbl)	(C$/bbl)	(C$/bbl)	(US$/bbl)	(C$/bbl)	(US$/MMbtu)	(C$/MMbtu)	(C$/MMbtu)
94.71	73.63	87.07	111.13	101.31	2.77	2.35	2.27

A foreign exchange rate of US$1.00/C$1.00 was used in the 2012 evaluation, determined on the same basis as the 12-month average price.

NET PROVED CRUDE OIL AND NATURAL GAS RESERVES

The Company retains Independent Qualified Reserves Evaluators to evaluate the Company’s proved crude oil, bitumen, synthetic crude oil (“SCO”), natural gas liquids (“NGLs”) and natural gas reserves.

For the years ended December 31, 2012, 2011, 2010, and 2009, the reports by GLJ Petroleum Consultants Ltd. covered 100% of the Company’s SCO reserves. With the inclusion of non-traditional resources within the definition of “oil and gas producing activities” in the SEC’s modernization of oil and gas reporting rules (“Final Rule”), effective January 1, 2010 these reserves volumes are included within the Company’s crude oil and natural gas reserves totals.

For the years ended December 31, 2012, 2011, 2010, and 2009, the reports by Sproule Associates Limited and Sproule International Limited covered 100% of the Company’s bitumen, crude oil and NGLs 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, from 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, 2012, 2011, 2010, and 2009:

	North America
Crude Oil and NGLs (MMbbl)	Synthetic Crude Oil(1)			Bitumen(2)			Crude Oil & NGLs			North America Total			North Sea			Offshore Africa			Total
Net Proved Reserves
Reserves, December 31, 2009		1,650			695			319			2,664			240			123			3,027
Extensions and discoveries		–			55			9			64			–			–			64
Improved recovery		–			22			6			28			–			–			28
Purchases of reserves in place		–			92			15			107			–			–			107
Sales of reserves in place		–			–			–			–			–			–			–
Production		(32	)		(54	)		(26	)		(112	)		(12	)		(10	)		(134	)
Economic revisions due to prices		(41	)		(25	)		–			(66	)		28			–			(38	)
Revisions of prior estimates		86			93			5			184			1			(11	)		174
Reserves, December 31, 2010		1,663			878			328			2,869			257			102			3,228
Extensions and discoveries		–			78			28			106			–			–			106
Improved recovery		–			10			8			18			–			2			20
Purchases of reserves in place		–			–			6			6			–			–			6
Sales of reserves in place		–			–			–			–			–			–			–
Production		(14	)		(60	)		(28	)		(102	)		(11	)		(8	)		(121	)
Economic revisions due to prices		18			(32	)		1			(13	)		26			–			13
Revisions of prior estimates		169			(5	)		23			187			(28	)		(8	)		151
Reserves, December 31, 2011		1,836			869			366			3,071			244			88			3,403
Extensions and discoveries		–			90			5			95			–			–			95
Improved recovery		–			25			9			34			–			1			35
Purchases of reserves in place		–			–			2			2			–			–			2
Sales of reserves in place		–			–			–			–			–			–			–
Production		(30	)		(70	)		(31	)		(131	)		(7	)		(5	)		(143	)
Economic revisions due to prices		34			6			(20	)		20			4			–			24
Revisions of prior estimates		134			79			39			252			(6	)		1			247
Reserves, December 31, 2012		1,974			999			370			3,343			235			85			3,663
Net proved developed reserves
December 31, 2009		1,589			268			204			2,061			94			106			2,261
December 31, 2010		1,546			262			240			2,048			94			83			2,225
December 31, 2011		1,588			269			269			2,126			78			61			2,265
December 31, 2012		1,612			348			295			2,255			66			55			2,376

(1)	Pursuant to the SEC’s Final Rule in effect January 1, 2010, SCO 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 crude oil reserves have been classified as bitumen.

Natural Gas (Bcf)	North America			North Sea			Offshore Africa			Total
Net Proved Reserves
Reserves, December 31, 2009		3,027			67			85			3,179
Extensions and discoveries		249			–			–			249
Improved recovery		19			–			–			19
Purchases of reserves in place		364			–			–			364
Sales of reserves in place		–			–			–			–
Production		(426	)		(4	)		(5	)		(435	)
Economic revisions due to prices		105			6			–			111
Revisions of prior estimates		83			9			(4	)		88
Reserves, December 31, 2010		3,421			78			76			3,575
Extensions and discoveries		154			–			–			154
Improved recovery		48			–			–			48
Purchases of reserves in place		375			–			–			375
Sales of reserves in place		(1	)		–			–			(1	)
Production		(433	)		(2	)		(6	)		(441	)
Economic revisions due to prices		(104	)		3			–			(101	)
Revisions of prior estimates		39			18			(16	)		41
Reserves, December 31, 2011		3,499			97			54			3,650
Extensions and discoveries		50			–			–			50
Improved recovery		11			–			–			11
Purchases of reserves in place		34			–			–			34
Sales of reserves in place		(1	)		–			–			(1	)
Production		(429	)		(1	)		(6	)		(436	)
Economic revisions due to prices		(596	)		1			–			(595	)
Revisions of prior estimates		79			(14	)		–			65
Reserves, December 31, 2012		2,647			83			48			2,778
Net proved developed reserves
December 31, 2009		2,333			45			81			2,459
December 31, 2010		2,557			49			72			2,678
December 31, 2011		2,637			60			47			2,744
December 31, 2012		2,060			58			39			2,157

CAPITALIZED COSTS RELATED TO CRUDE OIL AND NATURAL GAS ACTIVITIES

	2012
(millions of Canadian dollars)	North America			North Sea			Offshore Africa			Total
Proved properties	$	67,287		$	4,574		$	3,045		$	74,906
Unproved properties		2,564			–			47			2,611
		69,851			4,574			3,092			77,517
Less: accumulated depletion and depreciation		(26,193	)		(2,709	)		(2,273	)		(31,175	)
Net capitalized costs	$	43,658		$	1,865		$	819		$	46,342

	2011
(millions of Canadian dollars)	North America			North Sea			Offshore Africa			Total
Proved properties	$	61,331		$	4,147		$	3,044		$	68,522
Unproved properties		2,442			–			33			2,475
		63,773			4,147			3,077			70,997
Less: accumulated depletion and depreciation		(22,497	)		(2,512	)		(2,152	)		(27,161	)
Net capitalized costs	$	41,276		$	1,635		$	925		$	43,836

	2010(1)
(millions of Canadian dollars)	North America			North Sea			Offshore Africa			Total
Proved properties	$	55,030		$	3,813		$	2,928		$	61,771
Unproved properties		2,366			5			31			2,402
		57,396			3,818			2,959			64,173
Less: accumulated depletion and depreciation		(19,502	)		(2,205	)		(1,904	)		(23,611	)
Net capitalized costs	$	37,894		$	1,613		$	1,055		$	40,562

(1)	Comparative amounts for 2010 have been restated to reflect the adoption of IFRS.

COSTS INCURRED IN CRUDE OIL AND NATURAL GAS ACTIVITIES

	2012
(millions of Canadian dollars)	North America		North Sea		Offshore Africa		Total
Property acquisitions
Proved	$	144	$	–	$	–	$	144
Unproved		44		–		3		47
Exploration		251		–		11		262
Development		5,773		556		75		6,404
Costs incurred	$	6,212	$	556	$	89	$	6,857

	2011
(millions of Canadian dollars)	North America		North Sea		Offshore Africa		Total
Property acquisitions
Proved	$	1,012	$	–	$	–	$	1,012
Unproved		59		–		–		59
Exploration		250		1		2		253
Development		5,559		235		76		5,870
Costs incurred	$	6,880	$	236	$	78	$	7,194

	2010(1)
(millions of Canadian dollars)	North America		North Sea		Offshore Africa		Total
Property acquisitions
Proved	$	1,482	$	–	$	–	$	1,482
Unproved		522		–		–		522
Exploration		41		6		3		50
Development		3,332		190		254		3,776
Costs incurred	$	5,377	$	196	$	257	$	5,830

(1) Comparative amounts for 2010 have been restated to reflect the adoption of IFRS.

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, 2012, 2011 and 2010 are summarized in the following tables:

	2012
(millions of Canadian dollars)	North America			North Sea			Offshore Africa			Total
Crude oil and natural gas revenue, net of royalties and blending costs	$	10,609		$	837		$	574		$	12,020
Production		(3,669	)		(402	)		(163	)		(4,234	)
Transportation		(479	)		(10	)		(1	)		(490	)
Depletion, depreciation and amortization		(3,860	)		(296	)		(165	)		(4,321	)
Asset retirement obligation accretion		(117	)		(27	)		(7	)		(151	)
Petroleum revenue tax		–			(14	)		–			(14	)
Income tax		(623	)		(55	)		(55	)		(733	)
Results of operations	$	1,861		$	33		$	183		$	2,077

	2011
(millions of Canadian dollars)	North America			North Sea			Offshore Africa			Total
Crude oil and natural gas revenue, net of royalties and blending costs	$	9,600		$	1,206		$	828		$	11,634
Production		(3,060	)		(412	)		(186	)		(3,658	)
Transportation		(374	)		(13	)		(1	)		(388	)
Depletion, depreciation and amortization		(3,488	)		(248	)		(242	)		(3,978	)
Asset retirement obligation accretion		(90	)		(33	)		(7	)		(130	)
Petroleum revenue tax		–			(130	)		–			(130	)
Income tax		(688	)		(218	)		(89	)		(995	)
Results of operations	$	1,900		$	152		$	303		$	2,355

	2010(2)
(millions of Canadian dollars)	North America			North Sea			Offshore Africa			Total
Crude oil and natural gas revenue, net of royalties and blending costs	$	9,687		$	1,059		$	821		$	11,567
Production		(2,883	)		(387	)		(167	)		(3,437	)
Transportation		(365	)		(8	)		(1	)		(374	)
Depletion, depreciation and amortization(1)		(2,869	)		(295	)		(935	)		(4,099	)
Asset retirement obligation accretion		(80	)		(36	)		(7	)		(123	)
Petroleum revenue tax		–			(59	)		–			(59	)
Income tax		(980	)		(137	)		146			(971	)
Results of operations	$	2,510		$	137		$	(143	)	$	2,504
(1) Includes the impact of an impairment relating to Gabon, Offshore Africa at December 31, 2010 of $637 million. (2) Comparative amounts for 2010 have been restated to reflect the adoption of IFRS.

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 12-month average price, defined by the SEC as the unweighted arithmetic average of the first-day-of-the-month price for each month within the 12-month period prior to the end of the reporting 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 prices and costs rather than 12-month average prices 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 and evaluation expenditures; and

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

Future net revenues, development, production and asset retirement obligation 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”:

	2012
(millions of Canadian dollars)	North America			North Sea			Offshore Africa			Total
Future cash inflows	$	273,167		$	26,922		$	7,985		$	308,074
Future production costs		(114,825	)		(9,369	)		(2,428	)		(126,622	)
Future development costs and asset retirement obligations		(49,226	)		(7,032	)		(1,640	)		(57,898	)
Future income taxes		(16,688	)		(7,662	)		(949	)		(25,299	)
Future net cash flows		92,428			2,859			2,968			98,255
10% annual discount for timing of future cash flows		(61,878	)		(1,330	)		(1,313	)		(64,521	)
Standardized measure of future net cash flows	$	30,550		$	1,529		$	1,655		$	33,734

	2011
(millions of Canadian dollars)	North America			North Sea			Offshore Africa			Total
Future cash inflows	$	280,809		$	26,887		$	8,257		$	315,953
Future production costs		(109,586	)		(8,908	)		(2,058	)		(120,552	)
Future development costs and asset retirement obligations		(37,486	)		(6,821	)		(1,669	)		(45,976	)
Future income taxes		(23,100	)		(8,095	)		(1,070	)		(32,265	)
Future net cash flows		110,637			3,063			3,460			117,160
10% annual discount for timing of future cash flows		(75,438	)		(1,376	)		(1,623	)		(78,437	)
Standardized measure of future net cash flows	$	35,199		$	1,687		$	1,837		$	38,723

	2010
(millions of Canadian dollars)	North America			North Sea			Offshore Africa			Total
Future cash inflows	$	221,337		$	21,117		$	8,268		$	250,722
Future production costs		(96,899	)		(8,596	)		(1,884	)		(107,379	)
Future development costs and asset retirement obligations		(35,424	)		(5,448	)		(688	)		(41,560	)
Future income taxes		(17,249	)		(5,572	)		(1,760	)		(24,581	)
Future net cash flows		71,765			1,501			3,936			77,202
10% annual discount for timing of future cash flows		(47,687	)		(722	)		(1,906	)		(50,315	)
Standardized measure of future net cash flows	$	24,078		$	779		$	2,030		$	26,887

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)	2012			2011			2010
Sales of crude oil and natural gas produced, net of production costs	$	(7,895	)	$	(7,727	)	$	(7,641	)
Net changes in sales prices and production costs		(7,994	)		15,802			14,748
Extensions, discoveries and improved recovery		1,834			1,328			1,636
Changes in estimated future development costs		(3,492	)		(2,022	)		(5,208	)
Purchases of proved reserves in place		83			803			1,894
Sales of proved reserves in place		(1	)		–			–
Revisions of previous reserve estimates		4,266			4,154			2,567
Accretion of discount		5,110			3,648			2,757
Changes in production timing and other		946			(1,141	)		(895	)
Net change in income taxes		2,154			(3,009	)		(4,016	)
Net change		(4,989	)		11,836			5,842
Balance – beginning of year		38,723			26,887			21,045
Balance – end of year	$	33,734		$	38,723		$	26,887