Proved Oil and Gas Reserves Quantities

	Gross				Net
	Crude Oil and Natural Gas Liquids (millions of barrels)		Natural Gas (billions of cubic feet)		Crude Oil and Natural Gas Liquids (millions of barrels)		Natural Gas (billions of cubic feet)
Proved

December 31, 1998	69		1 197		56		915
December 31, 1999	51		1 013		41		764
Revisions of previous estimates	(3	)	(52	)	(6	)	(81	)
Purchases of minerals in place	—		9		—		7
Extensions and discoveries	1		39		1		28
Production	(3	)	(73	)	(2	)	(52	)
Sales of minerals in place	(30	)	(139	)	(23	)	(99	)
December 31, 2000	16		797		11		567
Revisions of previous estimates	(1	)	(3	)	—		4
Extensions and discoveries	—		27		—		20
Production	(1	)	(65	)	(1	)	(45	)
Sales of minerals in place	—		(1	)	—		(1	)
December 31, 2001	14		755		10		545
Revisions of previous estimates	—		(35	)	—		(18	)
Extensions and discoveries	145		53		125		39
Production	(1	)	(65	)	(1	)	(48	)
Sales of minerals in place	—		(2	)	—		(2	)
December 31, 2002	158		706		134		516
Proved developed
December 31, 1998	53		730		43		557
December 31, 1999	38		627		30		471
December 31, 2000	13		573		10		414
December 31, 2001	11		573		8		416
December 31, 2002	11		584		8		426

Proved reserves are considered recoverable under current technology and existing economic conditions, from reservoirs that are evaluated on known drilling, geological, geophysical and engineering data.

Proved developed reserves are on production, or reserves that could be recovered from existing wells or facilities, if the company placed them on production.

Gross reserves are presented before deducting royalties. Net reserves are after deducting royalties. Royalties can vary depending upon factors such as prices, production volumes, timing of initial production and changes in legislation.

All reserves are located in Canada. There has been no major discovery or other favourable or adverse event that caused a significant change in estimated proved reserves since December 31, 2002. The company has no long-term supply agreements or contracts with governments or authorities in which it acts as producer nor does it have any interest in oil and gas operations accounted for by the equity method.

Capitalized Costs Relating to Oil and Gas Producing Activities

	Capitalized costs relating to oil and gas activities for the years ended December 31,
	2002		2001
	($ millions)
Proved properties	1,723		931
Unproved properties	128		409
Other support facilities and equipment	16		14
Total cost	1,867		1,354
Accumulated depreciation and depletion	(532	)	(488	)
Net capitalized costs	1,335		866

Costs Incurred in Oil and Gas Acquisition, Exploration and Developmental Activities

	Costs incurred for the years ended December 31
	2002	2001	2000
	($ millions)
Property acquisition costs
Proved properties	2	—	5
Unproved properties	12	5	7
Exploration costs	17	27	39
Development costs	510	256	144
Total capital and exploration expenditures	541	288	195

Results of Operations for Oil and Gas Production

	Results of Operations for Oil and Gas Production For the years ended December 31
	2002		2001		2000
	($ millions)
Revenues
Sales to unaffiliated customers	200		286		139
Transfers to other operations	16		58		183
	216		344		322
Expenses
Production costs	39		36		47
Depreciation, depletion and amortization	66		61		68
Exploration	27		31		63
Gain on disposal of assets	(4	)	(8	)	(147	)
Restructuring costs	—		(2	)	65
Other related costs	10		30		25
	138		148		121
Operating profit before income taxes	78		196		201
Related income taxes	(43	)	(79	)	(103	)
Results of operations	35		117		98

Standardized Measure of Discounted Future Net Cash Flows from Estimated Production of Proved Oil and Gas Reserves after Income Taxes

In computing the standardized measure of discounted future net cash flows from estimated production of proved oil and gas reserves after income taxes, assumptions other than those mandated by Statement 69 could produce substantially different results. The Company cautions against viewing this information as a forecast of future economic conditions or revenues, and does not consider it to represent the fair market value of gas properties. Figures are based on year-end commodity prices, and are as follows:

	2002	2001	2000
Year end natural gas price assumptions (AECO— CDN$/GJ)	5.21	3.55	7.81
Year end crude oil price assumption (WTI US$/bbl)	29.40	19.40	28.40

Actual future net cash flows may differ from those estimated due to, but not limited to, the following:

·		Production rates could differ from those estimated both in terms of timing and amount;
·		Future prices and economic conditions will likely differ from those at year-end;
·		Future production and development costs will be determined by future events and may differ from those at year-end; and
·		Estimated income taxes may differ in terms of amounts and timing due to the above factors as well as changes in enacted rates and the impact of future expenditures on unproved properties.

The standardized measure of discounted future net cash flows is determined by using estimated quantities of proved reserves and taking into account the future periods in which they are expected to be developed and produced based on year-end economic conditions. The estimated future production is priced at year-end prices, except that future gas prices are increased, where applicable, for fixed and determinable price escalations provided by contract. At December 31, 2002, no such contractual arrangements existed. The resulting estimated future cash inflows are reduced by estimated future costs to develop and produce the proved reserves based on year-end cost levels. In addition, the Company has also deducted certain other estimated costs deemed necessary to derive the estimated pretax future net cash flows from the proved reserves including direct general and administrative costs of exploration and production operations and reclamation and environmental remediation costs. Deducting future income tax expenses then reduces the estimated pretax future net cash flows further. Such income taxes are determined by applying the appropriate year-end statutory tax rates, with consideration of future tax rates already legislated, to the future pretax cash flows relating to the Company’s proved oil and gas reserves less the tax basis of the properties involved. At December 31, 2002, there were no legislated future tax rate changes. The resultant future net cash flows are reduced to present value amounts by applying the Statement 69 mandated 10% discount factor. The result is referred to as “Standardized Measure of Discounted Future Net Cash Flows from Estimated Production of Proved Oil and Gas Reserves after Income Taxes”.

	2002		2001		2000
	($ millions)
Future cash inflows	8,964		2,266		8,176
Future production and development costs	(3,007	)	(652	)	(633	)
Other related future costs	(314	)	(283	)	(175	)
Future income tax expenses	(2,094	)	(521	)	(3,426	)
Future net cash flows	3,549		810		3,942
Discount at 10%	(1,822	)	(370	)	(2,009	)
Standardized measure of discounted future net cash flows from estimated production of proved oil and gas reserves after income taxes	1,727		440		1,933

Summary of Changes in the Standardized Measure of Discounted Future Net Cash Flows from Estimated Production of Proved Oil and Gas Reserves after Income Taxes

	2002		2001		2000
	($ millions)
Balance, beginning of year	440		1,933		749
Increase (decrease) in discounted future net cash flows:
Sales and transfers of oil and gas net of related costs	(192	)	(297	)	(275	)
Revisions to estimates of proved reserves:
Prices	713		(3,055	)	3,886
Development costs	(38	)	(50	)	(3	)
Production costs	(49	)	(9	)	55
Quantities	(45	)	(2	)	(363	)
Extensions, discoveries, and improved recovery less related costs	1,387		23		177
Development costs incurred during the period	112		81		69

Purchases of reserves in place	—		—		41
Sales of reserves in place	(7	)	(1	)	(989	)
Accretion of discount	68		361		115
Income taxes	(697	)	1,472		(1,292	)
Other	35		(16	)	(237	)
Balance, end of year	1,727		440		1,933