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Exhibit 4.8    
    


SUPPLEMENTAL INFORMATION — OIL AND GAS PRODUCING ACTIVITIES

(unaudited)  


       The following disclosures have been prepared in accordance with SFAS No. 69 — "disclosures about Oil and Gas
Producing Activities.": 


OIL AND GAS RESERVES  


       Users of this information should be aware that the process of estimating quantities of "proved" and "proved developed" crude oil and natural gas reserves is very
complex, requiring significant subjective decisions in the evaluation of all available geological, engineering and economic data for each reservoir. The data for a given reservoir may also change
substantially over time as a result of numerous factors including, but not limited to, additional development activity, evolving production history, and continual reassessment of the viability of
production under varying economic conditions. Consequently, material revisions to existing reserve estimates occur from time to time. Although every reasonable effort is made to ensure that reserve
estimates reported represent the most accurate assessments possible, the significance of the subjective decisions required and variances in available data for various reservoirs make these estimates
generally less precise than other estimates presented in connection with financial statement disclosures. 



       Proved
oil and gas reserves are the estimated quantities of crude oil, natural gas and natural gas liquids which geological and engineering data demonstrate with reasonable certainty to
be recoverable in future years from known reservoirs under existing economic and operating conditions. 


       Proved
developed oil and gas reserves are reserves that can be expected to be recovered through existing wells with existing equipment and operating methods. 


       Canadian
provincial royalties are determined based on a graduated percentage scale which varies with prices and production volumes. Canadian reserves, as presented on a net basis, assume
prices and royalty rates in existence at the time the estimates were made, and the Trust's estimate of future production volumes. Future fluctuations in prices, production rates, or changes in
political or regulatory environments could cause the Trust's share of future production from Canadian reserves to be materially different from that presented. 


       Subsequent
to December 31, 2002 no major discovery or other favorable or adverse event is believed to have caused a material change in the estimates of proved or proved developed
reserves as of that date. 



RESULTS OF OPERATIONS FOR PRODUCING ACTIVITIES  


       The following table sets forth revenue and direct cost information relating to the Trust's oil and gas producing activities for the years ended December 31. 



	 
	 	2002
	 	2001

	 
	 	(thousands of dollars)



	Revenue	 	 	 	 	 	 
	 	Sales	 	$	408,630	 	$	405,040
	Deduct	 	 	 	 	 	 
	 	Production costs	 	 	125,558	 	 	101,953
	 	Amortization of injectant costs	 	 	44,330	 	 	47,448
	 	Technical support and other	 	 	4,244	 	 	2,990
	 	Depletion, depreciation and amortization and valuation provision	 	 	112,511	 	 	98,610
	 	 	
	 	

	Results of operations from producing activities	 	$	121,987	 	$	154,039
	 	 	
	 	








Note: 


	1.
	The
costs in this schedule exclude corporate overhead, interest expense and other operating costs which are not directly related to producing activities. 







COSTS INCURRED IN OIL AND GAS PROPERTY ACQUISITION, EXPLORATION AND DEVELOPMENT ACTIVITIES  


       Costs incurred in oil and gas producing activities for the years ended December 31 are as follows: 



	 
	 	2002
	 	2001

	 
	 	(thousands of dollars)



	Property Acquisition Costs	 	 	 	 	 	 
	 	Proved	 	$	391,761	 	$	280,058
	Development Costs	 	 	55,631	 	 	74,026
	Injectant Costs	 	 	15,107	 	 	56,352
	 	 	
	 	

	 	 	$	462,499	 	$	410,436
	 	 	
	 	






       Acquisition costs include costs incurred to purchase, lease, or otherwise acquire oil and gas properties. 


       Development
costs include the costs of drilling and equipping development wells and facilities to extract, treat and gather and store oil and gas. 


       Injectants
(mostly ethane and methane) are used in miscible flood programs to stimulate incremental oil recovery. The cost of injectants purchased from third parties for miscible flood
projects is deferred and amortized over the period of expected future economic benefit which is estimated as 30 months. 



       General
and administrative costs are not capitalized other than to the extent they are directly related to a successful acquisition, or to the extent of the Trust's working interest in
exploration or development projects to which overhead fees can be recovered from partners. Overhead fees are not charged on 100% owned projects. 


       There
were no oil and gas property costs not being amortized in any of the years presented. 


CAPITALIZED COSTS RELATING TO OIL AND GAS PRODUCING ACTIVITIES  



       The capitalized costs and related accumulated depreciation, depletion and amortization, including impairments, relating to the Trust's oil and gas exploration,
development and producing activities at December 31 consist of: 



	 
	 	2002
	 	2001
	 
	 
	 	(thousands of dollars)


	 
	Proved oil and gas properties	 	$	2,021,141	 	$	1,646,125	 
	Less accumulated depletion, depreciation and amortization	 	 	(890,753	)	 	(766,494	)
	 	 	
	 	
	 
	Net capitalized costs	 	$	1,130,388	 	$	879,631	 
	 	 	
	 	
	 








OIL AND GAS RESERVE INFORMATION  


       All of the Trust's proved oil, natural gas liquids, and natural gas reserves are located in Canada, primarily in the provinces of Alberta, British Columbia,
Saskatchewan and Nova Scotia. The Trust's proved developed and undeveloped reserves after deductions of royalties are summarized below: 



	 
	 	Crude Oil and Natural Gas Liquids
	 	Natural Gas
	 
	 
	 	MMbbls


	 	Bcf


	 
	NET PROVED DEVELOPED AND UNDEVELOPED RESERVES AFTER ROYALTIES	 	 	 	 	 
	End of year 2000	 	93.1	 	178.3	 
	Revision of previous estimates	 	(0.8	)	22.2	 
	Purchase of reserves in place	 	6.4	 	159.6	 
	Sales of reserves in place	 	(1.9	)	(8.3	)
	Discoveries and extensions	 	1.7	 	5.8	 
	Production	 	(7.6	)	(27.3	)
	End of year 2001	 	90.9	 	330.3	 
	Revision of previous estimates	 	(3.0	)	(22.1	)
	Purchase of reserves in place	 	13.4	 	73.2	 
	Sales of reserves in place	 	(4.2	)	(16.5	)
	Discoveries and extensions	 	0.1	 	3.2	 
	Production	 	(7.4	)	(32.1	)
	End of year 2002	 	89.8	 	336.0	 
	NET PROVED DEVELOPED

RESERVES AFTER ROYALTIES	 	 	 	 	 
	End of year 2000	 	68.1	 	160.7	 
	End of year 2001	 	65.9	 	231.6	 
	End of year 2002	 	66.6	 	233.2	 







Notes: 


	1.
	Net
after royalty reserves are the Trust's lessor royalty, overriding royalty, and working interest share of the gross remaining reserves, after deduction of any crown, freehold and
overriding royalties. Such royalties are subject to change by legislation or regulation and can also vary depending on production rates, selling prices and timing of initial production.



	2.
	Reserves
are the estimated quantities of crude oil, natural gas and related substances anticipated from geological and engineering data to be recoverable from known accumulations, from
a given date forward, by known technology, under existing operating conditions and prices in effect at year end.



	3.
	Proved
oil and gas reserves are the estimated quantities of crude oil, natural gas and natural gas liquids which geological and engineering data demonstrate with reasonable certainty
to be recoverable in future years from known reservoirs under existing economic and operating conditions.



	4.
	Proved
developed oil and gas reserves are reserves that can be expected to be recovered through existing wells with existing equipment and operating methods. Proved undeveloped
reserves are reserves that are expected to be recovered from known accumulations where a significant expenditure is required. 





STANDARDIZED MEASURE OF DISCOUNTED FUTURE NET CASH FLOWS RELATING TO PROVED OIL AND GAS RESERVES  


       The following information has been developed utilizing procedures described by SFAS No. 69 and based on crude oil and natural gas reserve and
production volumes estimated by the independent engineering consultants of the Trust. It may be useful for certain comparison purposes, but should not be
solely relied upon in evaluating the Trust or its performance. Further, information contained in the following table should not be considered as representative of realistic assessments of future cash
flows, nor should the Standardized Measure of Discounted Future Net Cash Flows be viewed as representative of the current value of the Trust's reserves. 


       The
future cash flows presented below are based on sales prices, cost rates, and statutory income tax rates in existence as of the date of the projections. It is expected that material
revisions to some estimates of crude oil and natural gas reserves may occur in the future, development and production of the reserves may occur in periods other than those assumed, and actual prices
realized and costs incurred may vary significantly from those used. 








       Management
does not rely upon the following information in making investment and operating decisions. Such decisions are based upon a wide range of factors, including estimates of
probable as well as proved reserves, and varying price and cost assumptions considered more representative of a range of possible economic conditions that may be anticipated. 


       The
computation of the standardized measure of discounted future net cash flows relating to proved oil and gas reserves at December 31, 2002 was based on a crude price of $42.58
/bbl and natural gas price of $5.58 /mcf. The computation of the standardized measure of discounted future net cash flows relating to proved oil and gas reserves at December 31, 2001 was based
on the Trust's crude oil price of $30.06 /bbl and natural gas price of $3.14 /mcf. 


STANDARDIZED MEASURE OF DISCOUNTED FUTURE CASH FLOW RELATING TO PROVED OIL AND GAS RESERVES  


       The following table sets forth the standardized measure of discounted future net cash flows from projected production of the Trust's crude oil and natural gas
reserves at December 31, for the years presented. 



	 
	 	2002
	 	2001
	 
	 
	 	(millions of dollars)


	 
	Future cash inflows	 	$	5,621	 	$	3,633	 
	Future costs	 	 	 	 	 	 	 
	 	Future production and development costs	 	 	(2,108	)	 	(1,968	)
	 	 	
	 	
	 
	Future net cash flows	 	 	3,513	 	 	1,665	 
	Deduct: 10% annual discount factor	 	 	(1,571	)	 	(768	)
	 	 	
	 	
	 
	Standardized measure of discounted future net cash flows	 	$	1,942	 	$	897	 
	 	 	
	 	
	 





CHANGES IN STANDARDIZED MEASURE OF DISCOUNTED FUTURE CASH FLOW RELATING TO PROVED OIL AND GAS RESERVES  


       The following table sets forth the changes in the standardized measure of discounted future net cash flows at December 31, for the years presented. 



	 
	 	2002
	 	2001
	 
	 
	 	(millions of dollars)


	 
	Future discounted net cash flows at beginning of year	 	$	897	 	$	2,152	 
	Sales and transfer, net of production costs	 	 	(262	)	 	(251	)
	Net change in sales and transfer prices, net of development and production costs	 	 	733	 	 	(1,372	)
	Extensions, discoveries and improved recovery, net of related costs	 	 	9	 	 	16	 
	Revisions of quantity estimates	 	 	(89	)	 	14	 
	Accretion of discount	 	 	90	 	 	215	 
	Sales of reserves in place	 	 	(92	)	 	(20	)
	Purchase of reserves in place	 	 	432	 	 	198	 
	Changes in timing of future net cash flows and other	 	 	224	 	 	(66	)
	Net change in income taxes	 	 	0	 	 	11	 
	End of Year	 	$	1,942	 	$	897	 







Note: 


	1.
	The
schedules above are calculated using year-end prices, costs, statutory tax rates and existing proved oil and gas reserves. The value of exploration properties and
probable reserves, future exploration costs, future changes in oil and gas prices and in production and development costs are excluded. 









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Exhibit 4.8