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Exhibit 4.7  

 
 

PENGROWTH ENERGY TRUST    
    

 
 

RECONCILIATION OF INTERIM CONSOLIDATED FINANCIAL STATEMENTS
  OF PENGROWTH ENERGY TRUST FOR THE THREE MONTHS ENDED
  MARCH 31, 2003 TO UNITED STATES GENERALLY ACCEPTED
  ACCOUNTING PRINCIPLES    

       The financial statements included in Pengrowth Energy Trust's 2002 Annual Report have been prepared in accordance with Canadian generally accepted accounting
principles ("Canadian GAAP") which in most respects conforms to generally accepted accounting principles in the United States ("U.S. GAAP"). 

       The
significant differences between those principles as they apply to Pengrowth Energy Trust ("Pengrowth") are as follows: 

	(a)
	As
required annually under U.S. GAAP, the carrying value of petroleum and natural gas properties and related facilities, net of future or deferred income taxes, is limited to
the present value of after tax future net revenue from proven reserves, discounted at 10 percent (based on prices and costs at the balance sheet date), plus the lower of cost and fair value of
unproven properties. Under Canadian GAAP, this "ceiling test" is calculated without application of a discount factor. At December 31, 1998 and 1997 the application of the full cost ceiling test
under U.S. GAAP resulted in a write-down of capitalized costs of $328.6 million and $49.8 million, respectively. At March 31, 2003 and December 31, 2002,
the application of the full cost ceiling test under U.S. GAAP did not result in a write-down of capitalized costs. 

Where
the amount of a ceiling test writedown under Canadian GAAP differs from the amount of the write-down under U.S. GAAP, the charge for depletion, depreciation, and amortization
will differ in subsequent years. 

	(b)
	Under
U.S. GAAP, interest and other income would not be included as a component of Net Revenue.

	(c)
	Under
U.S. GAAP, recognition of compensation cost over the vesting period is required for variable priced stock-based compensation plans such as the Rights Incentive Plan.
Compensation cost is based on the excess of the unit price over the exercise price at the date of the financial statements. Application of this provision results in a compensation cost of $118,000 for
the period ended March 31, 2003. The Rights Incentive Plan was approved on April 23, 2002 and had no effect on the period ended March 31, 2002. 

APB 25
requires recognition of compensation cost with respect to Stock Appreciation Rights granted to employees. Effective October 12, 2002, all outstanding Stock Appreciation Rights
were converted to an equal number of options under the Trust Unit Option Plan. No compensation cost results from application of the above provisions for the period ended March 31, 2002. 

	(d)
	Marketable
securities held by Pengrowth are classified as available-for-sale in accordance with definitions of Statement of Financial Accounting Standards
("SFAS') 115. Under provisions of this Statement, available-for-sale securities are reported at the fair value, with unrealized holding gains and losses included in
comprehensive income and reported as a separate component of unitholders' equity until realized.

	(e)
	SFAS 130
requires the reporting of comprehensive income in addition to net earnings. Comprehensive income includes net income plus other comprehensive income; specifically, all
changes in equity of a company during a period arising from non-owner sources.

	(f)
	SFAS 150
"Accounting for Certain Financial Instruments with Characteristics of both Liabilities and Equity" is effective July 1, 2003. Pengrowth has not determined the
effect of SFAS 150 on the classification of trust units.

	(g)
	Under
U.S. GAAP Pengrowth is required to disclose the estimated fair value of its guarantee under the employee Trust Unit Margin Plan. The maximum amount of the guarantee at
March 31, 2003 was $9,514,780, the fair value of which is estimated to be a nominal amount.

	(h)
	In
2003, Pengrowth adopted SFAS 143, "Accounting for Asset Retirement Obligations", which requires the fair value of a liability for an asset retirement obligation to be
recorded in the period in which it is incurred and a corresponding increase in the carrying amount of the related long term asset. The standard applies to legal obligations associated with the
reclamation and remediation of Pengrowth's property, plant and equipment including abandoning oil and natural gas properties, processing facilities, and site restoration. The change was effective
January 1, 2003, and the related cumulative adjustment to net income was an increase of $19,225,000 or $0.21 per unit ($0.21 per unit — diluted). The
change resulted in an increase in property, plant and equipment of $48,379,000 and an increase in future site restoration liability of $29,154,000 and an increase to trust unitholders' equity of
$19,225,000. There was no impact on Pengrowth's cash flow as a result of adopting SFAS 143. 

1

 

The
following provides a roll forward of the asset retirement obligations for the current period: 

	 
	 	 
	 
	Future site restoration, January 1, 2003	 	$	73,493	 
	Liabilities settled during the period	 	 	(550	)
	Accretion expense	 	 	1,470	 
	 	 	
	 
	Future site restoration liability, March 31, 2003	 	$	74,413	 
	 	 	
	 

The
following table shows the effect of the implementation on the Pengrowth's net income and net income per unit as if SFAS 143 had been effect in prior periods. There was no effect on reported
amounts for the period ended March 31, 2002. 

	 
	 	As at and for the years ended December 31

	 
	 	2001
	 	2002

	As reported:	 	 	 	 	 	 
	Net income under U.S. GAAP	 	$	110,748	 	$	73,246
	Net income per unit under U.S. GAAP	 	 	 	 	 	 
	 	— Basic	 	$	1.56	 	$	0.81
	 	— Diluted	 	$	1.56	 	$	0.81
	
Pro forma amounts assumed SFAS 143 was applied retroactively:	
 	
 	

 	
 	
 	

 
	Net income under U.S. GAAP	 	$	113,783	 	$	81,134
	Net income per unit under U.S. GAAP	 	 	 	 	 	 
	 	— Basic	 	$	1.60	 	$	0.90
	 	— Diluted	 	$	1.60	 	$	0.90
	Future site restoration liability	 	 	 	 	 	 
	 	— Balance beginning of year	 	$	66,634	 	$	69,927
	 	— End of year	 	$	69,927	 	$	73,493

Prior
to January 1, 2003, U.S. GAAP required the provision for abandonment costs to be recorded as a reduction of capital assets. 

	(i)
	SFAS 133,
"Accounting for Derivative instruments and Hedging Activities" establishes accounting and reporting standards for derivative instruments and for hedging
activities. This statement requires an entity to establish, at the inception of a hedge, the method it will use for assessing the effectiveness of the hedging derivative and the measurement approach
for determining the ineffective aspect of the hedge. Those methods must be consistent with the entity's approach to managing risk. 

At
March 31, 2003, $4,031,000 has been recorded as an asset in respect of the fair value of crude oil hedges outstanding at period end of which $25,000 has been included in earnings as the
ineffective portion of the hedge. Of the asset, $2,176,000 has been classified as current and $1,855,000 has been classified as long term. As at March 31, 2003, $14,777,000 has been recorded as
a liability in respect of the fair value of natural gas hedges outstanding at period end with a corresponding decrease in other comprehensive income. Of the liability, $7,403,000 has been classified
as current and $7,374,000 has been classified as long term. As at March 31, 2002, $4,708,000 was recorded as a liability in respect of the fair value of crude oil hedges outstanding at period
end of which $1,121,000 has been included in earnings as the ineffective portion of the hedge. At March 31, 2002, $1,030,000 was recorded as an asset in respect of the fair value of natural gas
hedges outstanding at period end with a corresponding increase in accumulated other comprehensive income. 

At
March 31, 2003, $481,000 has been recorded as a liability in respect of the fair value of interest rate swaps outstanding at period end with a corresponding decrease in accumulated other
comprehensive income. Of this amount, $618,000 has been classified as a current liability and $137,000 has been classified as a long term asset. As at March 31, 2002, $2,517,000 was recorded as
an asset in respect of the fair value of the interest rate swaps outstanding at period end with a corresponding increase in accumulated other comprehensive income. 

At
March 31, 2003, an asset of $791,000 has been recorded in respect of the fair value of a foreign exchange swap outstanding at period end with a corresponding increase in accumulated other
comprehensive income. Of the asset, $459,000 has been classified as current and $332,000 has been classified as long term. There were no foreign exchange swaps outstanding as at March 31, 2002. 

2

 

Consolidated Statements of Income  

       The application of U.S. GAAP would have the following effect on net income as reported: 

       Stated
in thousands of Canadian Dollars, except per unit amounts 

	 
	 	Three months ended March 31,
	 
	 
	 	2002
	 	2003
	 
	 
	 	(unaudited)

	 
	Net income, as reported	 	$	442	 	$	61,050	 
	 	Adjustments net of tax	 	 	 	 	 	 	 
	 	 	Depletion adjustments (a)(h)	 	 	6,311	 	 	5,539	 
	 	 	Compensation cost (c)	 	 	—	 	 	(118	)
	 	 	Unrealized gain (loss) on oil and gas contracts that do not qualify as hedges (i)	 	 	(1,121	)	 	985	 
	 	 	Future site restoration adjustment (h)	 	 	—	 	 	3,099	 
	 	 	
	 	
	 
	Net income before cumulative effect of change in Accounting principle under US GAAP	 	 	5,632	 	 	70,555	 
	Cumulative effect of change in accounting principles (h)	 	 	—	 	 	19,225	 
	 	 	
	 	
	 
	Net income for the period — US GAAP	 	$	5,632	 	$	89,780	 
	

Other comprehensive income:	
 	
 	

 	
 	
 	

 	
 
	 	Unrealized gain (loss) on available-for-sale securities (d)(e)	 	 	236	 	 	(271	)
	 	Unrealized hedging gains (e)(i)	 	 	2,846	 	 	10,364	 
	 	Unrealized hedging losses (e)(i)	 	 	(5,079	)	 	—	 
	 	 	
	 	
	 
	Comprehensive income — U.S. GAAP	 	$	3,635	 	$	99,873	 
	 	 	
	 	
	 
	Net income before cumulative adjustment per unit U.S. GAAP	 	 	 	 	 	 	 
	 	— Basic	 	$	0.07	 	$	0.64	 
	 	— Diluted	 	$	0.07	 	$	0.64	 
	

Net income per unit U.S. GAAP	
 	
 	

 	
 	
 	

 	
 
	 	— Basic	 	$	0.07	 	$	0.81	 
	 	— Diluted	 	$	0.07	 	$	0.81	 
	 	 	
	 	
	 

Consolidated Balance Sheets  

       The application of U.S. GAAP would have the following effect on the Balance Sheets as reported: 

Stated
in thousands of Canadian Dollars 

	December 31, 2002
 
	 	As Reported
	 	Increase

(Decrease)
	 	U.S. GAAP
	 
	Assets:	 	 	 	 	 	 	 	 	 	 
	 	Marketable securities (d)	 	$	1,906	 	$	271	 	$	2,177	 
	 	Capital assets (a)(h)	 	 	1,444,668	 	 	(314,280	)	 	1,130,388	 
	 	 	
	 	
	 	
	 
	 	 	 	 	 	 	$	(314,009	)	 	 	 
	 	 	
	 	
	 	
	 
	Liabilities:	 	 	 	 	 	 	 	 	 	 
	 	Accounts payable and accrued liabilities (c)(i)	 	$	43,092	 	$	960	 	$	44,052	 
	 	Current portion of unrealized hedging loss (i)	 	 	—	 	 	14,462	 	 	14,462	 
	 	Long term portion of unrealized hedging loss (i)	 	 	—	 	 	6,363	 	 	6,363	 
	 	Provision for abandonment costs (h)	 	 	44,339	 	 	(44,339	)	 	—	 
	

Unitholders' equity:	
 	
 	

 	
 	
 	

 	
 	
 	

 	
 
	 	Other comprehensive income (e)(i)	 	 	—	 	 	(20,554	)	 	(20,554	)
	 	Trust Unitholders' Equity (a)	 	 	1,053,939	 	 	(270,901	)	 	783,038	 
	 	 	
	 	
	 	
	 
	 	 	 	 	 	$	(314,009	)	 	 	 
	 	 	
	 	
	 	
	 

3

 

	March 31, 2003 (unaudited) 

	 
	Assets:	 	 	 	 	 	 	 	 	 	 
	 	Accounts receivable (i)	 	$	61,231	 	$	25	 	$	61,256	 
	 	Current portion of unrealized hedging gain (i)	 	 	—	 	 	2,610	 	 	2,610	 
	 	Long term portion of unrealized hedging gain (i)	 	 	—	 	 	2,324	 	 	2,324	 
	 	Capital assets (a)(h)	 	 	1,421,605	 	 	(216,023	)	 	1,205,582	 
	 	 	
	 	
	 	
	 
	 	 	 	 	 	$	(211,064	)	 	 	 
	 	 	
	 	
	 	
	 
	Liabilities:	 	 	 	 	 	 	 	 	 	 
	 	Current portion of unrealized hedging loss (i)	 	$	—	 	$	8,021	 	$	8,021	 
	 	Long term portion of unrealized hedging loss (i)	 	 	—	 	 	7,374	 	 	7,374	 
	 	Provision for abandonment costs (h)	 	 	48,358	 	 	26,055	 	 	74,413	 
	

Unitholders' equity:	
 	
 	

 	
 	
 	

 	
 	
 	

 	
 
	 	Other comprehensive income (e)(i)	 	 	—	 	 	(10,461	)	 	(10,461	)
	 	Trust Unitholders' Equity (a)	 	 	1,024,162	 	 	(242,053	)	 	782,109	 
	 	 	
	 	
	 	
	 
	 	 	 	 	 	$	(211,064	)	 	 	 
	 	 	
	 	
	 	
	 

Additional disclosures required under U.S. GAAP  

       The components of accounts receivable are as follows: 

Stated
in thousands of Canadian Dollars 

	 
	 	December 31,

2002
	 	March 31,

2003

	 
	 	 
	 	(unaudited)

	Trade	 	$	35,148	 	$	54,314
	Prepaids	 	 	5,084	 	 	5,495
	Other	 	 	1,194	 	 	1,422
	 	 	
	 	

	 	 	$	41,426	 	$	61,231
	 	 	
	 	

       The components of accounts payable and accrued liabilities are as follows: 

Stated
in thousands of Canadian Dollars 

	 
	 	December 31,

2002
	 	March 31,

2003

	 
	 	 
	 	(unaudited)

	Accounts payable	 	$	29,806	 	$	30,811
	Accrued liabilities	 	 	13,286	 	 	13,350
	 	 	
	 	

	 	 	$	43,092	 	$	44,161
	 	 	
	 	

4

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PENGROWTH ENERGY TRUST

RECONCILIATION OF INTERIM CONSOLIDATED FINANCIAL STATEMENTS OF PENGROWTH ENERGY TRUST FOR THE THREE MONTHS ENDED MARCH 31, 2003 TO UNITED STATES GENERALLY ACCEPTED ACCOUNTING PRINCIPLESQuickLinks
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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

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