EXHIBIT 2

Managements Report

These financial statements are the responsibility of the management of NCE Petrofund, NCE Petrofund Management Corp. (Management). They have been prepared in accordance with generally accepted accounting principles using Managements best estimates and judgments, where appropriate.

Management is responsible for the reliability and integrity of the financial statements, notes to the financial statements and other financial information contained in this report. Estimates are sometimes necessary in the preparation of these statements because a precise determination of some assets and liabilities depends on future events. Management has based these estimates on careful judgments and believes they are properly reflected in the accompanying financial statements. Management is also responsible for maintaining a system of internal controls designed to provide reasonable assurance that assets are safeguarded and that accounting systems provide timely, accurate and reliable financial information.

The Board of Directors of NCE Petrofund is responsible for ensuring that Management fulfills its responsibilities for financial reporting and internal controls. The Board meets with Management to ensure that managements responsibilities are fulfilled, to review financial statements and to recommend approval of the financial statements. An independent auditor appointed by Management, Deloitte & Touche LLP, has audited the financial statements of NCE Petrofund in accordance with generally accepted auditing standards and has provided an independent professional opinion.

By:  /s/ John F. Driscoll                                             By:  /s/ John Vooglaid

Title:  Chief Executive Officer                                    Title:  Chief Financial Officer

Toronto, Canada

March 10, 2003





Auditors Report

TO THE UNITHOLDERS OF NCE PETROFUND:

We have audited the consolidated balance sheet of NCE Petrofund (an Ontario open-ended investment trust) as at December 31, 2002 and the consolidated statements of operations, unitholders equity and cash flows for the year then ended. These financial statements are the responsibility of the management of NCE Petrofund Management Corp. Our responsibility is to express an opinion on these financial statements based on our audit.

We conducted our audit in accordance with Canadian generally accepted auditing standards. Those standards require that we plan and perform an audit to obtain reasonable assurance whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation.

In our opinion, these consolidated financial statements present fairly, in all material respects, the financial position of NCE Petrofund as at December 31, 2002 and the results of its operations and its cash flows for the year then ended in accordance with Canadian generally accepted accounting principles.

The consolidated financial statements of NCE Petrofund as at December 31, 2001, and for each of the years in the two-year period then ended were audited by other auditors who have ceased operations. Those auditors expressed an opinion without reservation on those financial statements in their report dated February 15, 2002.

Calgary, Alberta                                     By: /s/ Deloitte & Touche LLP

March 10, 2003                                      Chartered Accountants





Consolidated Balance Sheet

(thousands of dollars)



|                                                       |  |   |         |         |   |         |        
|------------------------------------------------------ |  | - | ------- | ------- | - | ------- | -------
|As at December 31                                      |  |   |         | 2002    |   |         | 2001   
|                                                       |  |   |         |         |   |         |        
|Assets                                                 |  |   |         |         |   |         |        
|                                                       |  |   |         |         |   |         |        
|Current assets                                         |  |   |         |         |   |         |        
|Cash                                                   |  |   | $       | -       | $ |         | 1,917  
|Accounts receivable                                    |  |   |         | 41,953  |   |         | 12,965 
|Due from affiliates                                    |  |   |         | 164     |   |         | -      
|Prepaid expenses                                       |  |   |         | 10,090  |   |         | 4,584  
|                                                       |  |   |         |         |   |         |        
|Total current assets                                   |  |   |         | 52,207  |   |         | 19,466 
|                                                       |  |   |         |         |   |         |        
|Reclamation and abandonment reserve ( Note 7)          |  |   | 3,001   |         |   | 2,073  
|                                                       |  |   |         |         |   |         |        
|Oil and gas royalty and property interests, at cost    |  |   |         |         |   |        
|less accumulated depletion and depreciation of         |  |   |         |         |   |        
|$354,309 (2001 - $255,532) (Notes 2, 3 and 4)          |  |   | 835,366 |         |   | 677,776
|                                                       |  |   |         |         |   |         |        
|                                                       |  | $ |         | 890,574 | $ |         | 699,315
|                                                       |  |   |         |         |   |         |        
|                                                       |  |   |         |         |   |         |        
|Liabilities and unitholders' equity                    |  |   |         |         |   |        
|                                                       |  |   |         |         |   |         |        
|Current liabilities                                    |  |   |         |         |   |         |        
|Bank overdraft                                         |  | $ |         | 1,572   |   | $       | -      
|Accounts payable and accrued liabilities               |  |   | 22,007  |         |   | 21,319 
|Payable to affiliates (Note 4)                         |  |   | 2,168   |         |   | 1,056  
|Current portion of capital lease obligations  (Note 6) |  |   | 3,304   |         |   | 5,467  
|Distributions payable to unitholders                   |  |   | 30,065  |         |   | 12,188 
|                                                       |  |   |         |         |   |         |        
|Total current liabilities                              |  |   |         | 59,116  |   |         | 40,030 
|                                                       |  |   |         |         |   |         |        
|Long-term debt (Note 5)                                |  |   |         | 212,253 |   |         | 128,783
|Capital lease obligations (Note 6)                     |  |   | 6,965   |         |   | 16,168 
|Future income taxes (Notes 2, 3 and 13 )               |  |   | 116,845 |         |   | 104,000
|Accrued reclamation and abandonment costs              |  |   | 15,298  |         |   | 11,632 
|                                                       |  |   |         |         |   |         |        
|Total liabilities                                      |  |   |         | 410,477 |   |         | 300,613
|                                                       |  |   |         |         |   |         |        
|Unitholders' equity (Note 8)                           |  |   |         | 480,097 |   |         | 398,702
|                                                       |  |   |         |         |   |         |        
|                                                       |  | $ |         | 890,574 | $ |         | 699,315
|                                                       |  |   |         |         |   |         |        



Signed on behalf of NCE Petrofund by NCE Petrofund Management Corp., Manager of the Trust:

By: /s/ John Driscoll, Director                                          By: /s/Richard Zarzeczny, Director

The accompanying notes to consolidated financial statements are an integral part of these consolidated financial statements.





Consolidated Statement of Operations

(thousands of dollars except per unit amounts)



|                                                  |   |          |   |          |   |         
|------------------------------------------------- | - | -------- | - | -------- | - | --------
|For the years ended December 31                   |   | 2002     |   | 2001     |   | 2000    
|                                                  |   |          |   |          |   |         
|Revenues                                          |   |          |   |          |   |         
|Oil and gas sales                                 | $ | 270,669  | $ | 244,512  | $ | 184,764 
|Royalties, net of incentives                      |   | (50,427) |   | (54,746) |   | (39,155)
|                                                  |   |          |   |          |   |         
|                                                  |   | 220,242  |   | 189,766  |   | 145,609 
|                                                  |   |          |   |          |   |         
|                                                  |   |          |   |          |   |         
|Expenses                                          |   |          |   |          |   |         
|Lease operating                                   |   | 74,774   |   | 48,237   |   | 28,715  
|Management fee (Note 4)                           |   | 4,728    |   | 5,307    |   | 4,383   
|Interest on long-term debt (Notes 5 and 6)        |   | 8,291    |   | 7,806    |   | 6,048   
|General and administrative (Note 4)               |   | 15,514   |   | 14,436   |   | 8,764   
|Capital taxes                                     |   | 2,137    |   | 2,620    |   | 1,519   
|Depletion and depreciation                        |   | 98,777   |   | 68,453   |   | 30,560  
|Provision for reclamation and abandonment         |   | 5,856    |   | 3,680    |   | 2,306   
|                                                  |   |          |   |          |   |         
|                                                  |   | 210,077  |   | 150,539  |   | 82,295  
|                                                  |   |          |   |          |   |         
|Net income before provision for income taxes      |   | 10,165   |   | 39,227   |   | 63,314  
|                                                  |   |          |   |          |   |         
|Provision for (recovery of) income taxes(Note 13) |   |          |   |          |   |         
|Current                                           |   | 38       |   | 800      |   | 265     
|Future                                            |   | (14,252) |   | (15,561) |   | 143     
|                                                  |   |          |   |          |   |         
|                                                  |   | (14,214) |   | (14,761) |   | 408     
|                                                  |   |          |   |          |   |         
|Net income                                        | $ | 24,379   | $ | 53,988   | $ | 62,906  
|                                                  |   |          |   |          |   |         
|Net income per Trust unit (Notes 2 and 14)        |   |          |   |          |   |         
|Basic                                             | $ | 0.49     | $ | 1.71     | $ | 3.31    
|Diluted                                           | $ | 0.49     | $ | 1.71     | $ | 3.30    
|                                                  |   |          |   |          |   |         





Consolidated Statement Of Unitholders' Equity

(thousands of dollars)



|For the years ended December 31           |   | 2002     |   | 2001      |   | 2000    
|----------------------------------------- | - | -------- | - | --------- | - | --------
|                                          |   |          |   |           |   |         
|Balance,beginning of year                 | $ | 398,702  | $ | 136,812   | $ | 97,309  
|Units issued, net of issue costs (Note 8) |   | 154,460  |   | 318,548   |   | 72,614  
|Net income                                |   | 24,379   |   | 53,988    |   | 62,906  
|Distributions accruing to unitholders     |   | (97,444) |   | (110,646) |   | (96,017)
|                                          |   |          |   |           |   |         
|Balance,end of year                       | $ | 480,097  | $ | 398,702   | $ | 136,812 
|                                          |   |          |   |           |   |         



The accompanying notes to consolidated financial statements are an integral part of these consolidated financial statements.





Consolidated Statement of Cash Flows

(thousands of dollars except per unit amounts)



|For the years ended December 31                             |   | 2002      |   | 2001      |   |  | 2000     
|----------------------------------------------------------- | - | --------- | - | --------- | - |  | ---------
|Cash provided by (used in):                                 |   |           |   |           |   |  |          
|Operating activities                                        |   |           |   |           |   |  |          
|Net income                                                  | $ | 24,379    | $ | 53,988    | $ |  | 62,906   
|Add items not affecting cash:                               |   |           |   |           |   |  |          
|Depletion and depreciation                                  |   | 98,777    |   | 68,453    |   |  | 30,560   
|Provision for reclamation and abandonment                   |   | 5,856     |   | 3,680     |   |  | 2,306    
|Future income taxes                                         |   | (14,252)  |   | (15,561)  |   |  | 143      
|Actual abandonment costs incurred (Note 7)                  |   | (2,190)   |   | (384)     |   |  | (402)    
|                                                            |   |           |   |           |   |  |          
|Cash flow from operating activities(Note 14)                |   | 112,570   |   | 110,176   |   |  | 95,513   
|                                                            |   |           |   |           |   |  |          
|Net change in non-cash operating working
  capital balances |   | (30,938)  |   | 18,334    |   |  | 1,716    
|                                                            |   |           |   |           |   |  |          
|Cash provided by operating activities                       |   | 81,632    |   | 128,510   |   |  | 97,229   
|                                                            |   |           |   |           |   |  |          
|Financing activities                                        |   |           |   |           |   |  |          
|Bank loan                                                   |   | 83,470    |   | 14,216    |   |  | 89,883   
|Distributions paid                                          |   | (85,218)  |   | (126,883) |   |  | (76,454) 
|Capital lease repayments                                    |   | (11,366)  |   | (2,629)   |   |  | -        
|Repayment of bank loan                                      |   | -         |   | -         |   |  | (65,000) 
|Issuance of Trust units (Note 8)                            |   | 55,821    |   | 161,409   |   |  | 72,614   
|Advances to affiliates (Note 4)                             |   | 948       |   | -         |   |  | -        
|                                                            |   |           |   |           |   |  |          
|Cash provided by financing activities                       |   | 43,655    |   | 46,113    |   |  | 21,043   
|                                                            |   |           |   |           |   |  |          
|Investing activities                                        |   |           |   |           |   |  |          
|Reclamation and abandonment reserve (Note 7)                |   | (706)     |   | (447)     |   |  | (322)    
|Acquisition of property interests                           |   | (158,516) |   | (177,729) |   |  | (123,620)
|Proceeds on disposition of properties                       |   | 30,019    |   | 3,736     |   |  | 6,496    
|Cash acquired on acquisition (Note 3a)                      |   | 427       |   | -         |   |  | -        
|                                                            |   |           |   |           |   |  |          
|Cash used in investing activities                           |   | (128,776) |   | (174,440) |   |  | (117,446)
|Net change in cash                                          |   | (3,489)   |   | 183       |   |  | 826      
|                                                            |   |           |   |           |   |  |          
|Cash,beginning of year                                      |   | 1,917     |   | 1,734     |   |  | 908      
|                                                            |   |           |   |           |   |  |          
|Cash (bank overdraft),end of year                           | $ | (1,572)   | $ | 1,917     | $ |  | 1,734    
|                                                            |   |           |   |           |   |  |          
|Cash flow from operating activities per Trust unit(Note 14) |   |           |   |           |   |  |          
|Basic                                                       | $ | 2.25      | $ | 3.49      | $ |  | 5.02     
|Diluted                                                     | $ | 2.25      | $ | 3.48      | $ |  | 5.01     
|                                                            |   |           |   |           |   |  |          
|Interest paid during the year                               | $ | 8,016     | $ | 7,806     | $ |  | 6,048    
|                                                            |   |           |   |           |   |  |          
|Income taxes paid during the year                           | $ | 1,281     | $ | 1,065     | $ |  | -        
|                                                            |   |           |   |           |   |  |          
|                                                            |   |           |   |           |   |  |          



The accompanying notes to consolidated financial statements are an integral part of these consolidated financial statements.



Notes to consolidated financial statements

December 31, 2002, 2001 and 2000

(thousands of dollars except per unit amounts, unless otherwise stated)

1.   ORGANIZATION

NCE Petrofund (the Trust) is an open-ended investment trust created under the laws of the Province of Ontario pursuant to a trust indenture, as amended from time to time (the Trust Indenture), between NCE Petrofund Corp. (NCEP) and Computershare Trust Company of Canada (the Trustee). Active operations commenced March 3, 1989. The beneficiaries of the Trust are the holders of the trust units (Unitholders).

NCEP, a wholly owned subsidiary of the Trust, acquires oil and gas properties for its own account and sells a royalty interest (the Royalty) to the Trust. The Royalty acquired from NCEP effectively transfers substantially all of the economic interest in the oil and gas properties to the Trust. The Trust is entitled to 99% of the production revenue from properties purchased by NCEP, less operating costs, general and administrative expenses, management fees, debt service charges (including principal and interest) and taxes payable by NCEP. The residual 1% interest in the properties retained in NCEP is used to reduce the amount of the management and other fees ultimately paid by the Unitholders (see Note 4).

2.   SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

The consolidated financial statements have been prepared by the management of NCE Petrofund Management Corp. (the Manager) following Canadian generally accepted accounting principles. The preparation of financial statements requires the Manager to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosures of contingencies at the date of the financial statements and the reported amounts of revenues and expenses during the reporting period. Actual results could differ from those estimated. The following significant accounting policies are presented to assist the reader in evaluating these consolidated financial statements.

(a) Basis of consolidation

The consolidated financial statements include the accounts of the Trust and its wholly owned subsidiaries, NCEP, 418187 Alberta Ltd. and 418189 Alberta Ltd. (collectively, the Subsidiaries).

(b) Oil and gas royalty and property interests

Oil and gas royalty and property interests are accounted for using the full cost method of accounting whereby all costs of acquiring oil and gas royalty and property interests and equipment are capitalized. General and administrative costs and interest are not capitalized.

The provision for depletion and depreciation and the provision for site reclamation and abandonment costs are computed using the unit-of-production method based on the estimated gross proven oil and gas reserves. Proceeds on sale or disposition of oil and gas royalty and property interests are credited to oil and gas royalty and property interests, unless this results in a change in the depletion and depreciation rate by 20% or more, in which case a gain or loss is recognized in the consolidated statement of operations. The provision for reclamation and abandonment costs is accumulated as a long-term liability, which is reduced as actual expenditures are made.

The cost of the oil and gas royalty and property interests, net of accumulated depletion and depreciation, accrued reclamation and abandonment costs and future income taxes is limited to an amount equal to the estimated future net revenue, net of production-related general and administrative costs, reclamation and abandonment costs, and income taxes. Future net revenue was calculated using year-end oil and gas prices and costs.



(c) Distributions payable to Unitholders

Distributions payable to Unitholders are equal to amounts received or receivable by the Trust on the cash distribution date. Income earned, but not received, is distributed on the cash distribution date following receipt.

(d) Future income taxes

The Trust follows the liability method of accounting for income taxes. Under this method, income tax liabilities and assets are recognized for the estimated tax consequences attributable to differences between the amounts reported in the financial statements of the Subsidiaries and their respective tax bases, using enacted income tax rates. The effect of a change in income tax rates on future tax liabilities and assets is recognized in income in the period in which the change occurs. Temporary differences arising on acquisitions result in future income tax assets or liabilities.

The Trust is a taxable entity under the Income Tax Act (Canada) and is taxable only on income that is not distributed or distributable to the Unitholders. As the Trust distributes all of its taxable income to the Unitholders and meets the requirements of the Income Tax Act (Canada) applicable to the Trust, no provision for future income taxes in the Trust has been made.

(e) Net income and cash flow from operating activities per Trust unit

Basic net income per Trust unit and cash flow from operating activities per Trust unit are computed by dividing net income and cash flow from operating activities by the weighted average number of Trust units outstanding for the period. Diluted per unit amounts reflect the potential dilution that would occur if contracts to issue Trust units were exercised and Trust units were issued. The treasury stock method is used to determine the effect of dilutive instruments.

(f) Hedging activity

The Trust uses derivative instrume nts to reduce its exposure to commodity price fluctuations. Gains and losses on contracts, all of which constitute effective hedges, are deferred and recognized as a component of the price of the related transaction.

(g) Trust unit incentive plan

A Trust Unit Incentive Plan (the Unit Incentive Plan) has been established authorizing the issuance of options to acquire Trust units to directors, senior officers, employees and consultants of NCEP, the Manager, NCE Petrofund Advisory Corp., NCE Management Services Inc. (NMSI) and certain other related parties, all of whom are deemed to be employees of the Trust.

Effective for fiscal years beginning on or after January 1, 2002, the Trust adopted the recommendations of the CICA on accounting for stock-based compensation, which apply to new options granted on or after January 1, 2002. The Trust has elected to continue to measure compensation cost based on the intrinsic value of the award at the date of grant and recognize that cost over the vesting period. As the exercise price of the options granted approximates the market price of the Trust units at the grant date, no compensation cost has been provided in the statement of operations.

The exercise price of options granted under the Unit Incentive Plan may be reduced in future periods in accordance with the terms of the Unit Incentive Plan. The amount of the reduction cannot be reasonably determined as it is dependent upon a number of factors including, but not limited to, future prices received on the sale of oil and natural gas, future production of oil and gas, and the determination of the amount to be withheld from future distributions to fund capital expenditures. Therefore, it is not possible to determine a fair value for the options granted under the Unit Incentive Plan.

As it is not possible to determine the fair value of options granted under the Unit Incentive Plan, compensation cost for pro-forma disclosure purposes has been determined based on the excess of the unit price over the exercise price at the date of the financial statements. For the year ended December 31, 2002, net income would be reduced by $60 for the estimated compensation cost associated with options granted under the plan on or after January 1, 2002, with negligible impact on net income per Trust unit.



3.   ACQUISITIONS

(a)   NCE Energy Trust

On May 30, 2002, NCE Petrofund acquired NCE Energy Trust for 0.2325 of an NCE Petrofund Trust unit for each NCE Energy Trust unit on a tax- free rollover basis. The value assigned to the NCE Petrofund Trust units of $13.024 per unit issued on the acquisition was based on the average market value of the NCE Petrofund units five days before and after the acquisition was announced.

The acquisition was accounted for using the purchase method. A summary of the net assets acquired is as follows:



|Working capital        | $ | (39,518)
|---------------------- | - | --------
|Oil and gas properties |   | 165,254 
|Future income taxes    |   | (27,097)
|                       |   |         
|                       | $ | 98,639  
|                       |   |         



Prior to the acquisition, NCE Petrofund advanced $37.3 million to NCE Energy Trust to pay down the bank debt of NCE Energy Trust.

(b)   Magin Energy Inc. (Magin)

On June 25, 2001, NCEP acquired 93.6% of the outstanding common shares of Magin and on July 3, 2001 acquired the remaining shares. Magin was amalgamated into NCEP on July 3, 2001.

In total, NCEP acquired 38,338,535 Magin common shares for $58.6 million in cash, 8.5 million Trust units with a deemed value of $18.56 per unit and the assumption of $43.7 million of debt including negative working capital, the outstanding bank loan and capital leases. In addition, other transaction costs of $11.8 million were incurred.

The acquisition was accounted for using the purchase method. A summary of the net assets acquired is as follows:



|Working capital        | $ | (4,749)  
|---------------------- | - | ---------
|Oil and gas properties |   | 381,043  
|Bank loan              |   | (21,569) 
|Capital leases         |   | (17,359) 
|Future income taxes    |   | (109,790)
|                       |   |          
|                       | $ | 227,576  



(c)   Pacific Cassiar Limited

Effective December 1, 2000, NCEP acquired the shares of Pacific Cassiar Limited and three private companies (collectively, the Companies) with interests in the same properties for $32.5 million including costs. NCEP accounted for this acquisition under the purchase method. The purchase price consisted of $323 of working capital and the remaining amount was allocated to oil and gas properties. In addition, future income taxes of $9.6 million based on the difference between the amount allocated to oil and gas properties and the tax basis of the properties were recognized and added to oil and gas properties. This amount is net of a future income tax asset of $5.3 million not previously recognized in NCEP. Current income taxes of $265 were paid on the taxable income of Pacific Cassiar Limited for the month of December in 2000 and $800 was paid for the period from January 1 to January 25, 2001. Effective January 26, 2001, the Companies were amalgamated into NCEP.



(d)   Acquisition of Control of NCE Petrofund Corp.

On November 1, 2000, the Trust acquired all of the issued and outstanding common shares of NCEP for the nominal amount of $1. The purchase price reflects the fact that the Trust already received substantially all of the risks and rewards of ownership of NCEP through the Royalty. At the same time, the Unitholders of the Trust approved organizational changes to the Trust and NCEP such that the Unitholders now have effective representation on the board of directors of NCEP and elect a majority of the NCEP executive committee. Prior to this time, although the Trust received substantially all of the risks and rewards of ownership of NCEP through the Royalty, the Trust did not control NCEP. Therefore, NCEP was not a subsidiary of the Trust and its accounts were not consolidated with the accounts of the Trust for financial statement purposes.

The acquisition of NCEP has been accounted for as a continuity of interests to reflect the Trusts continuing interest in the operating activities of NCEP. This is similar to pooling of interest accounting in that the assets and liabilities of the Trust and NCEP are combined and accounted for in the consolidated financial statements at their historic carrying values for all periods presented. Consolidated income includes the income of the Trust and NCEP as if they had been combined since their inception.

4.   RELATED-PARTY TRANSACTIONS

(a)   Management, advisory and administration agreement

NCEP, the Manager and the Trust entered into an agreement, as amended from time to time, whereby the Manager will provide management, advisory and administrative services to NCEP and the Trust. During 1999 and the first three quarters of 2000, the Manager was paid a management fee equal to 5.0% of net operating income plus Alberta Royalty Credit. Effective October 1, 2000, the fee was reduced to 3.75% and on January 1, 2002 was reduced to 3.25%. In addition, the Manager receives an investment fee of 1.50% (1.75% prior to January 1, 2002) of the purchase cost of all properties purchased by NCEP other than replacement properties, and a disposition fee equal to 1.25% (1.5% prior to January 1, 2002) of the sale price of properties sold. During 2002, the Manager received a management fee from NCEP of $4,728 (2001  $5,307, 2000  $4,383). In addition, the Manager received investment fees of $1,268 (2001  $5,195, 2000  $1,735), which were capitalized as part of the acquisitions and disposition fees of $116 (2001  $3, 2000  $132), which reduced the proceeds of disposition. No management fees have been charged directly to the Trust.

Under the terms of the agreement, the Manager is also entitled to be reimbursed by NCEP for general and administrative expenses. In any year, NCEP shall reimburse the Manager no less than $240 and no more than 5% of gross production revenue for general and administrative expenses. To the extent that general and administrative expenses exceed 5% of gross production revenue, NCEP is entitled to set off and deduct the excess from its liability to pay management fees to the Manager.

(b)   Management agreement

The Manager entered into an agreement with NMSI to provide oil and gas investment, consulting, administrative and management services to NCEP. An officer and director of the Manager is the sole beneficial shareholder of NMSI. During 2002 NCEP paid NMSI $11,672 (2001  $9,345, 2000  $6,828) for accounting and administrative services, which is included in general and administrative expenses and $838 (2001  $1.4 million, 2000  $1.5 million) for project sourcing and evaluation services, which have been capitalized to oil and gas properties, and $300 (2001  $600, 2000  $200) for marketing and other related equity issue costs. The amounts for general and administrative expenses paid to NMSI are subject to the same limitations noted for the Manager in (a) above.



5.   LONG-TERM DEBT

Under the loan agreements, NCEP has a revolving operating facility of $25 million and a syndicated facility of $220 million. Interest on the operating facility is at prime and interest on the syndicated facility varies with NCEPs debt-to-cash-flow ratio from prime to prime plus 50 basis points or, at the Trusts option, Bankers Acceptances rates plus stamping fees. As at December 31, 2002, there was $5 million outstanding under the working capital facility and $207 million outstanding under the syndicated facility.

The revolving period on the syndicated facility ends on May 30, 2003, unless extended for a further 364-day period. In the event that the revolving bank line is not extended at the end of the 364-day revolving period, no payments are required to be made to non-extending lenders during the first year of the term period. However, NCEP will be required to maintain certain minimum balances on deposit with the syndicate agent.

The limit of the syndicated facility is subject to adjustment from time to time to reflect changes in NCEPs asset base.

The credit facility is secured by a debenture in the amount of $350 million pursuant to which a Canadian chartered bank (the Lender), as principal and as agent for the other lenders, received a first ranking security interest on all of NCEPs assets.

The loan is the legal obligation of NCEP. While principal and interest payments are allowable deductions in the calculation of royalty income, the Unitholders have no direct liability to the bank or to NCEP should Bankers Acceptances the assets securing the loan generate insufficient cash flow to repay the obligation.

Substantially all of the credit facility is financed with Bankers Acceptances, resulting in a reduction in the stated bank loan interest rates of approximately 0.70%.

6.   CAPITAL LEASE OBLIGATIONS

The future minimum lease payments under the capital leases are as follows:



|2003                                                       | $ | 9,871  
|---------------------------------------------------------- | - | -------
|2004                                                       |   | 423    
|2005                                                       |   | 621    
|Total minimum lease payments                               |   | 10,915 
|Less imputed interest at rates ranging from 6.88% to 8.43% |   | (646)  
|Obligation under capital leases                            |   | 10,269 
|Current portion                                            |   | (3,304)
|Long-term portion                                          | $ | 6,965  



The bargain purchase option of $6 million due in 2002 was refinanced by long-term debt. The bargain purchase option of $6 million due in 2003 will be refinanced by long-term debt.

7.   RECLAMATION AND ABANDONMENT RESERVE

NCEP maintains a cash reserve to finance large and unusual oil and gas property reclamation and abandonment costs by withholding distributions accruing to Unitholders. At December 31, 2002, the cash reserve was $3,001 (2001  $2,073, 2000  $1,625). In 2002, NCEP increased the cash reserve by withholding $706 (2001  $447, 2000  $322) from distributions accruing to Unitholders. The reserve also includes $222 transferred to NCEP on the acquisition of NCE Energy Trust (Note 3a).



In addition, routine ongoing reclamation and abandonment costs of $2,190 in 2002 (2001  $384, 2000  $402) were incurred and deducted from distributions accruing to Unitholders.

8.   TRUST UNITS

On July 6, 2001, the Trust units were consolidated on a one- for-three basis. All unit-related numbers including units outstanding, options outstanding and option prices, net income per unit and distributions per unit have been restated for all prior periods to reflect this consolidation.



|                                   |                 |   |         
|---------------------------------- | --------------- | - | --------
|                                   | Number of units |   | Amount  
|                                   |                 |   |         
|Issued                             |                 |   |         
|December 31, 1999                  | 16,130,324      | $ | 248,730 
|                                   |                 |   |         
|Issued for cash                    | 5,741,667       |   | 79,250  
|Commissions and issue costs        | -               |   | (7,268) 
|Options exercised                  | 27,555          |   | 424     
|Unit purchase plan                 | 13,877          |   | 208     
|                                   |                 |   |         
|December 31, 2000                  | 21,913,423      |   | 321,344 
|                                   |                 |   |         
|Issued for cash                    | 11,183,334      |   | 167,350 
|Issued for Magin acquisition       | 8,464,399       |   | 157,139 
|Commissions and issue costs        | -               |   | (11,781)
|Options exercised                  | 341,305         |   | 5,620   
|Unit purchase plan                 | 13,279          |   | 220     
|                                   |                 |   |         
|December 31, 2001                  | 41,915,740      |   | 639,892 
|                                   |                 |   |         
|Issued for cash                    | 4,600,000       |   | 59,800  
|Issued for NCE Ene rgy acquisition | 7,573,874       |   | 98,639  
|Commissions and issue costs        | -               |   | (4,190) 
|Options exercised                  | 7,966           |   | 85      
|Unit purchase plan                 | 10,184          |   | 126     
|                                   |                 |   |         
|December 31, 2002                  | 54,107,764      | $ | 794,352 
|                                   |                 |   |         



The Trust has a Distribution Reinvestment and Unit Purchase Plan (the Plan). Under the terms of the Plan, Unitholders can elect, firstly, to reinvest their cash distributions and obtain either newly issued units of the Trust directly from the Trust or previously issued units of the Trust purchased in the open market and, secondly, to purchase for cash newly issued units directly from the Trust.



|For the years ended December 31                             | 2002    | 2001    | 2000   
|----------------------------------------------------------- | ------- | ------- | -------
|Distributions reinvested to acquire previously issued units | $ 3,387 | $ 6,979 | $ 5,585
|Price per unit                                              | $ 12.15 | $ 16.61 | $ 14.71
|Number of units acquired                                    | 278,297 | 420,100 | 379,674
|                                                            |         |         |        
|Distributions reinvested to acquire newly issued units      | $ 126   | $ 220   | $ 208  
|Price per unit                                              | $ 12.36 | $ 16.59 | $ 15.00
|Number of units acquired                                    | 10,184  | 13,279  | 13,877 
|                                                            |         |         |        



9.   UNIT INCENTIVE PLAN

A total of 5,200,000 units may be reserved for issuance under the Unit Incentive Plan, of which 2,598,000 have been reserved for issuance at December 31, 2002. A summary of the status of the Unit Incentive Plan as of December 31, 2002, 2001 and 2000, and changes during the years then ended are presented below:



|                                     | 2002      | 2001     | 2000     
|------------------------------------ | --------- | -------- | ---------
|                                     |           | Weighted |          
|                                     |           | Average  |          
|                                     |           | Exercise |          
|                                     | Units     | Price    | Units    
|Options outstanding, beginning       |           |          |          
|of year                              | 1,840,190 | $15.92   | 941,278  
|Issued                               | 1,468,100 | 10.65    | 1,477,800
|Forfeited                            | (272,044) | 16.66    | (237,583)
|Exercised                            | (7,966)   | 10.65    | (341,305)
|Options outstanding before           |           |          |          
|reduction of exercise price          | 3,028,280 | $13.31   | 1,840,190
|Reduction of exercise price          | -         | (0.10)   | -        
|Options outstanding,
  end
  of year | 3,028,280 | $13.21   | 1,840,190
|                                     |           |          |          
|Options exercisable,
  end
  of year | 1,593,681 | $14.10   | 745,565  



The options granted in 2002 and 2001 are exercisable at the original option prices, which were the market prices of the units on the date of the grants, or if so elected by the participant, at reduced prices as described below. The option prices are reduced for each calendar quarter ending after the date of the grant by the positive amount, if any, equal to the amount by which the aggregate distributions made by the Trust in any calendar quarter ending after the date of the grant exceed 2.5% of the oil and gas royalty and property interests on the Trusts consolidated balance sheet at the beginning of the applicable calendar quarter divided by the issued and outstanding units at the beginning of the applicable quarter.

The following table summarizes the options outstanding at December 31, 2002:



|                |                |                        |             |       |                 
|--------------- | -------------- | ---------------------- | ----------- | ----- | ----------------
|Number of Units | Exercise Price | Reduced Exercise Price | Expiry Date
|197,850         | $              | 15.00                  |             | N/A   | May 8, 2005     
|628,124         | $              | 19.35                  | $           | 16.88 | January 30, 2006
|423,872         | $              | 17.25                  | $           | 15.44 | April 4, 2006   
|321,000         | $              | 14.71                  | $           | 13.95 | July 20, 2006   
|1,457,434       | $              | 10.65                  | $           | 10.57 | July 25, 2007   
|                |                |                        |             |       |                 
|                |                |                        |             |       |                 



10.   DISTRIBUTIONS ACCRUING TO UNITHOLDERS

Under the terms of the Trust Indenture, the Trust makes monthly distributions within a specified period following the end of each month (Cash Distribution Date).  Distributions are equal to amounts received by the Trust on the Cash Distribution Date less permitted expenses. Distributions to Unitholders coincide with cash receipts of royalty income from NCEP. An overall analysis is as follows:



|Cash Distribution                   |              |      |      |      |      |      |     
|----------------------------------- | ------------ | ---- | ---- | ---- | ---- | ---- | ----
|For the period ended                | Date         |      | 2002 |      | 2001 |      | 2000
|                                    |              |      |      |      |      |      |     
|November 30                         | January 31   | $    | 0.15 | $    | 0.42 | $    | 0.27
|December 31                         | February 28  |      | 0.15 |      | 0.42 |      | 0.30
|January 31                          | March 31     |      | 0.13 |      | 0.42 |      | 0.33
|February 28                         | April 30     |      | 0.13 |      | 0.42 |      | 0.33
|March 31                            | May 31       |      | 0.14 |      | 0.45 |      | 0.33
|April 30                            | June 30      |      | 0.14 |      | 0.45 |      | 0.33
|May 31                              | July 31      |      | 0.14 |      | 0.36 |      | 0.33
|June 30                             | August 31    |      | 0.14 |      | 0.32 |      | 0.33
|July 31                             | September 30 |      | 0.14 |      | 0.25 |      | 0.36
|August 31                           | October 31   |      | 0.15 |      | 0.25 |      | 0.36
|September 30                        | November 30  |      | 0.15 |      | 0.25 |      | 0.36
|October 31                          | December 31  |      | 0.15 |      | 0.23 |      | 0.36
|                                    |              |      |      |      |      |      |     
|Cash distributions per
  Trust unit | $            | 1.71 | $    | 4.24 | $    | 3.99
|                                    |              |      |      |      |      |      |     



Reconciliation of Distributions Accruing to Unitholders

(thousands of dollars except per unit amounts)



|For the years ended December 31                |   | 2002     |   | 2001      |   | 2000    
|---------------------------------------------- | - | -------- | - | --------- | - | --------
|                                               |   |          |   |           |   |         
|Distributions payable, beginning of year       | $ | 12,188   | $ | 28,425    | $ | 8,862   
|Distributions accruing during the year         |   |          |   |           |   |         
|Cash flow from operating activities            |   | 112,570  |   | 110,176   |   | 95,513  
|Proceeds on disposition of property interests  |   | 946      |   | 3,546     |   | 826     
|Reclamation and abandonment reserve            |   | (706)    |   | (447)     |   | (322)   
|Less capital lease repayment (2)               |   | (5,366)  |   | (2,629)   |   | -       
|Capital expenditures                           |   | (10,000) |   | -         |   | -       
|Accrual for future debt repayment              |   | -        |   | -         |   | 7,000   
|Less discretionary debt repayment              |   | -        |   | -         |   | (7,000) 
|                                               |   |          |   |           |   |         
|Total distributions accruing during the year   |   | 97,444   |   | 110,646   |   | 96,017  
|                                               |   |          |   |           |   |         
|NCE Energy Trust cash flow (1)                 |   | 5,651    |   | -         |   | -       
|                                               |   |          |   |           |   |         
|Total distributable income for the year        |   | 103,095  |   | 110,646   |   | 96,017  
|                                               |   |          |   |           |   |         
|Distributions paid                             |   | (85,218) |   | (126,883) |   | (76,454)
|                                               |   |          |   |           |   |         
|Distributions payable, end of year             | $ | 30,065   | $ | 12,188    | $ | 28,425  
|Distributions accruing to unitholder per Trust |   |          |   |           |   |         
|Unit (Note 14)                                 |   |          |   |           |   |         
|Basic                                          | $ | 2.07     | $ | 3.50      | $ | 5.05    
|Diluted                                        | $ | 2.06     | $ | 3.49      | $ | 5.04    
|                                               |   |          |   |           |   |         



(1) Remaining undistributed cash flow of NCE
Energy Trust on May 30, 2002 (see Note 3a).

(2) Net of $6 million refinanced by increased bank loan in 2002.

11.   FINANCIAL INSTRUMENTS

The Trusts financial instruments consist of cash, accounts receivable, accounts payable and accrued liabilities, amounts due from and payable to affiliates, long-term debt, capital lease obligations and derivative instruments. As at December 31, 2002, the carrying values of the cash and accounts receivable and payable approximated their fair value due to their short-term nature. The carrying values of the long-term debt approximated its fair value due to the floating rate of interest charged under the facilities. The carrying values of the capital lease obligations is not significantly different from their fair values.

The derivative instruments have no carrying value (see Note 12). The derivative instruments at December 31, 2002 had a negative fair value of $1.2 million based on quo tes provided by brokers. This fair value represents an approximation of amounts that would be paid to counterparties to settle these instruments at the balance sheet date. The Trust plans to hold all derivative instruments outstanding at December 31, 2002 to maturity.

12.   DERIVATIVE FINANCIAL INSTRUMENTS AND PHYSICAL CONTRACTS



The Trust is exposed to risks resulting from fluctuations in commodity prices and interest rates. The Trust enters into various pricing mechanisms to reduce price volatility and establish minimum prices for a portion of its oil and gas production. These include fixed-price contracts and the use of derivative financial instruments.

The outstanding derivative financial instruments, all of which constitute effective hedges, and the related unrealized gains or losses, and physical contracts as at December 31, 2002 are summarized separately below:



|                          |                                     |        |                 |          |             |        
|------------------------- | ----------------------------------- | ------ | --------------- | -------- | ----------- | -------
|Natural Gas               | Term                                | Volume | Price $/mcf     | Delivery | Unrealized 
|                          |                                     | mcf/d  |                 | point    | gain (loss)
|                          |                                     |        |                 |          |             |        
|Call option
  (purchased) | July 1, 2001 to
  October 31, 2003  | 6,159  | $4.91           | AECO     | $           | 2,400  
|Collar                    | January 1, 2003 to
  March 31, 2003 | 14,212 | $4.59 -
  $7.97 | AECO     |             | (46)   
|Collar                    | January 1, 2003 to
  March 31, 2003 | 4,737  | $4.59 -
  $7.97 | AECO     |             | (6)    
|                          |                                     |        |                 |          |             |        
|Collar                    | January 1, 2003
  to March 31, 2003 | 4,737  | $5.17 -
  $6.75 | AECO     |             | (55)   
|Collar                    | January 1, 2003 to
  March 31, 2003 | 4,737  | $5.17 -
  $7.07 | AECO     |             | (13)   
|Collar                    | April 1, 2003 to
  October 31, 2003 | 4,737  | $4.64 -
  $6.23 | AECO     |             | (510)  
|Collar                    | April 1, 2003 to
  October 31, 2003 | 9,475  | $4.64 -
  $6.23 | AECO     |             | (1,051)
|Collar                    | April 1, 2003 to
  October 31, 2003 | 4,737  | $4.64 -
  $6.24 | AECO     |             | (308)  
|                          |                                     |        |                 |          |             |        
|Total                     |                                     |        |                 |          | $           | 411    



|Oil              | Term                                    | Volume | Price $/bbl     | Delivery | Unrealized 
|---------------- | --------------------------------------- | ------ | --------------- | -------- | -----------
|                 |                                         | bbl/d  |                 | point    | gain (loss)
|Fixed price      | January 1, 2003 to
  January 31, 2003   | 2,000  | $44.49          | Edmonton | $          
|Fixed price      | February 1, 2003 to
  February 28, 2003 | 2,000  | $44.25          | Edmonton |            
|                 |                                         |        |                 |          |            
|Collar           | January 1, 2003 to
  June 30, 2003      | 2,000  | $37.06-
  45.34 | Edmonton |            
|                 |                                         |        |                 |          |            
|Three-way collar | March 1, 2003 to
  June 30, 2003        | 2,000  | *(1)            | Edmonton |            
|                 |                                         |        |                 |          |            
|Total            |                                         |        |                 |          | $          
|                 |                                         |        |                 |          |            



*(1)  At prices above $45.87 Petrofund receives $45.87.

At prices between $38.65 and $45.87 Petrofund receives actual price.

At prices between $32.34 and $38.65 Petrofund receives $38.65.

At prices below $32.34 Petrofund receives actual price plus $6.31/bbl.

In addition to the financial instruments, the Trust has the following physical gas contract:



|Natural Gas        | Term                | Volume | Price | Delivery | Unrealized 
|------------------ | ------------------- | ------ | ----- | -------- | -----------
|                   |                     | mcf/d  | $/mcf | point    | gain (loss)
|Call option (sold) | November 1, 1999 to | 6,159  | $3.17 | AECO     | $          
|                   | October 31, 2003    |        |       |          |            
|Total              |                     |        |       |          | $          
|                   |                     |        |       |          |            



The gains or losses on the hedges are recognized on a monthly basis over the terms of the contracts and adjust the prices received.



Derivative financial instruments and physical contracts involve a degree of credit risk, which the Trust controls through the use of financially sound counterparties.  Market risk relating to changes in value or settlement cost of the Trusts derivative financial instruments is essentially offset by gains or losses on the underlying physical sales.

13.   INCOME TAXES

The future income tax liability (asset) includes the following temporary differences:



|As at December 31      |   | 2002    |   | 2001    |   | 2000  
|---------------------- | - | ------- | - | ------- | - | ------
|                       |   |         |   |         |   |       
|                       |   |         |   |         |   |       
|Oil and gas properties | $ | 119,825 | $ | 106,961 | $ | 10,305
|Resource allowance     |   | (2,980) |   | (2,961) |   | (534) 
|                       |   |         |   |         |   |       
|                       | $ | 116,845 | $ | 104,000 | $ | 9,771 
|                       |   |         |   |         |   |       



The provision for current and future income taxes differs from the result which would be obtained by applying the combined federal and provincial statutory tax rates to income before income taxes.  This difference results from the following:



|                                                 |   |            |   |           |   |         
|------------------------------------------------ | - | ---------- | - | --------- | - | --------
|As at December 31                                |   | 2002       |   | 2001      |   | 2000    
|                                                 |   |            |   |           |   |         
|                                                 |   |            |   |           |   |         
|                                                 |   |            |   |           |   |         
|Net income before income tax
  provision         |   | $10,165    |   | $39,227   |   | $63,314 
|                                                 |   |            |   |           |   |         
|                                                 |   |            |   |           |   |         
|                                                 |   |            |   |           |   |         
|Income tax provision computed at statutory rates | $ | 4,294      | $ | 16,915    | $ | 28,251  
|                                                 |   |            |   |           |   |         
|                                                 |   |            |   |           |   |         
|                                                 |   |            |   |           |   |         
|Effect on income tax of:                         |   |            |   |           |   |         
|                                                 |   |            |   |           |   |         
|Income attributed to the Trust                   |   | (24,435)   |   | (32,665)  |   | (28,251)
|                                                 |   |            |   |           |   |         
|Non-deductible Crown charges, net of             |   |            |   |           |   |         
|Alberta Royalty Credit                           |   | 17,055     |   | 19,276    |   | 140     
|Resource allowance                               |   | (15,045)   |   | (16,661)  |   | (312)   
|                                                 |   |            |   |           |   |         
|Capital taxes                                    |   | 831        |   | 1,130     |   | 678     
|                                                 |   |            |   |           |   |         
|Income tax rate reductions on
  opening balances |   | -          |   | (329)     |   | -       
|                                                 |   |            |   |           |   |         
|Temporary differences in
  resource allowance    |   | (19)       |   | (2,427)   |   | (907)   
|                                                 |   |            |   |           |   |         
|Increase (decrease) in
  valuation allowance     |   | -          |   | -         |   | (276)   
|                                                 |   |            |   |           |   |         
|Other                                            |   | 3,105      |   | -         |   | 1,085   
|                                                 |   |            |   |           |   |         
|Provision for (recovery of) income taxes         |   | $ (14,214) |   | $(14,761) |   | $408    
|                                                 |   |            |   |           |   |         
|                                                 |   |            |   |           |   |         



The petroleum and natural gas properties and facilities owned by the subsidiaries have a tax basis of $212 million ($153.3 million in 2001, $113.4 million in 2000) available for future use as deductions from taxable income. Included in this tax basis are non-capital loss carryforwards of $34.0 million ($33.6 million in 2001, $24.3 million in 2000), which could expire in various years through 2009.

14.   NET INCOME AND CASH FLOW FROM OPERATING ACTIVITIES PER TRUST UNIT

Basic per unit calculations are based on the weighted average number of Trust units outstanding. Diluted calculations include additional Trust units for the dilutive impact of options. There were no adjustments to net income or cash flow from operating activities in calculating diluted per Trust unit amounts. A total of 1,676,934 options (2001  1,019,002 options; 2000  1,851,625 options) are anti-dilutive and therefore have not been included in the dilution calculations.

The weighted average units outstanding are as follows:



|        |            |            |           
|------- | ---------- | ---------- | ----------
|        | 2002       | 2001       | 2000      
|Basic   | 49,921,523 | 31,593,378 | 19,026,926
|Diluted | 49,967,648 | 31,635,976 | 19,049,086
|        |            |            |           



Cash flow from operating activities was calculated by adding depletion and depreciation, provision for reclamation and abandonment, actual abandonment costs incurred and future income taxes to net income and dividing by the weighted average number of Trust units.

15.   SUBSEQUENT EVENT

On March 10, 2003, the Trust announced plans to internalize its management structure and eliminate all management, acquisition and disposition fees payable to the Manager effective January 1, 2003. Under the terms of the agreements, the Manager will, prior to closing, acquire NCE Management Services Inc., which employs all of the individuals who provide services to Petrofund on behalf of the Manager. At closing, NCEP will purchase all the issued shares of the Manager from Petro Assets Inc., and the outstanding obligations of the Manager for cash of $3.4 million, and the issue of 1,939,147 exchangeable shares valued at $12.1703 per unit, representing the weighted average trading price of the units on the Toronto Stock Exchange over the 10 trading days ending on March 4, 2003. In addition, NCEP will provide an aggregate of $2 million to certain senior executives of the Manager, such payment to be comprised of $780,000 in cash and 100,244 units, subject to adjustment.

16.   DIFFERENCES BETWEEN CANADIAN AND UNITED STATES GENERALLY ACCEPTED ACCOUNTING PRINCIPLES ("GAAP") (all amounts are stated in Canadian dollars)

The Trust's consolidated financial statements have been prepared in accordance with Canadian generally accepted accounting principles ("Canadian GAAP"). These principles, as they pertain to the Trust's consolidated financial statements, differ from United States generally accepted accounting principles ("U.S. GAAP") as follows:

(a) The Canadian GAAP ceiling test is comparable to the Securities and Exchange Commission ("SEC") method using constant prices, costs and tax legislation except that the SEC requires the resulting amounts to be discounted at 10%. In addition, the SEC does not require the inclusion of any general and administrative or interest expenses in the calculation.



(b) U.S. GAAP utilizes the concept of comprehensive income, which includes items not included in net income.

(c) Effective January 1, 2001, for U.S. reporting purposes, the Trust adopted Statement of Financial Accounting Standards (SFAS) No. 133, Accounting for Derivative Instruments and Hedging Activities. SFAS 133 establishes accounting and reporting standards requiring that all derivative instruments (including derivative instruments embedded in other contracts), as defined, be recorded in the balance sheet as either an asset or a liability measured at fair value and requires that changes in fair value be recognized currently in income unless specific hedge accounting criteria are met. There are no similar standards under Canadian GAAP at this time.



Hedge accounting treatment allows unrealized gains and losses to be deferred in other comprehensive income (for the effective portion of the hedge) until such time as the forecasted transaction occurs and requires that an entity formally document, designate and assess effectiveness of derivative instruments that receive hedge accounting treatment. Upon adoption, the Trust formally documented and designated all hedging relationships and verified that its hedging instruments are effective in offsetting changes in actual prices received by the Trust. Such effectiveness is monitored at least quarterly and any ineffectiveness is reported in other revenues (losses) in the consolidated statement of operations.

On the transition date, January 1, 2001, the Trust recognized a derivative liability of $7,139 related to its cash flow hedges.

A reconciliation of the components of the unrealized gain (loss) on derivatives included in accumulated other comprehensive income related to the Trusts derivative activities is presented below:



|                                                      |   | Gross    |   | After-Tax
|----------------------------------------------------- | - | -------- | - | ---------
|Cumulative effect of change in accounting principle   | $ | (7,139)  | $ | (3,954)  
|Reclassification of net realized losses into earnings |   | 98       |   | 56       
|Net change in derivative fair value                   |   | 8,856    |   | 5,037    
|Effect of reduction in income tax rates               |   | -        |   | (107)    
|                                                      |   |          |   |          
|Accumulated other comprehensive income                |   |          |   |          
|related to derivatives at December 31, 2001           |   | 1,815    |   | 1,032    
|                                                      |   |          |   |          
|Reclassification of net realized losses into earnings |   | 8,668    |   | 5,007    
|Net change in derivative fair value                   |   | (11,264) |   | (6,506)  
|Effect of reduction in income tax rates               |   | -        |   | 16       
|Accumulated other comprehensive income                |   |          |   |          
|related to derivatives at December 31, 2001           | $ | (781)    | $ | 581      
|                                                      |   |          |   |          



Under Canadian GAAP, compensation expense for options granted under the Unit Incentive Plan is measured based on the intrinsic value of the award at the grant date. For U.S. GAAP purposes, the Trust uses the intrinsic value method of accounting for compensation expense related to options granted. For options granted prior to January 1, 2001, the exercise price of the options was equal to the market price of the Trust units on the grant date and no compensation expense was recorded for U.S. GAAP purposes. For options granted in 2001 and subsequent years, the Unit Incentive Plan is a variable compensation plan as the exercise price of the options is subject to downward revisions from time to time. Accordingly, compensation expense is determined as the excess of the market price of the Trust units over the adjusted exercise price of the options at each financial reporting date and is deferred and recognized in income over the vesting period of the options. After the options have vested, compensation expense is recognized in income in the period in which a change in the market price of the Trust units or the exercise price of the options occurs. At December 31, 2001, the exercise price of the options granted under the Unit Incentive Plan exceeded the market price of the Trust units. Therefore, no compensation expense was recorded in 2001.



(e) Recent Developments in U.S. Accounting Standards

In June 2001, the U.S. Financial Accounting Standards Board issued Statement No. 143, "Accounting for Asset Retirement Obligations" (FAS 143). FAS 143 requires recognition of a liability for the future retirement obligations associated with property, plant and equipment. These obligations are initially measured at fair value, which is the discounted future value of the liability. This fair value is capitalized as part of the cost of the related asset and amortized to expense over its useful life. The liability accretes until the date of expected settlement of the retirement obligations. FAS 143 is effective for all fiscal years beginning after June 15, 2002. The impact of the effect on the consolidated financial statements at January 1, 2003 has not been determined.

In November 2002, the FASB issued Interpretation No. 45, "Guarantors' Accounting and Disclosure Requirements for Guarantees, Including Indirect Guarantees of Indebtedness of Others" (FIN 45). FIN 45 elaborates on the disclosures that must be made regarding obligations under certain guarantees issued by the Trust. It also requires that the Trust recognize, at the inception of a guarantee, a liability for the fair value of the obligations undertaken in issuing the guarantee. The initial recognition and initial measurement provisions are to be applied to guarantees issued or modified after December 31, 2002. Adoption of these provisions will not have a material impact on the Trust's financial position or results of operations. The disclosure requirements are effective for annual or interim periods ending after December 15, 2002.

In January 2003, the FASB issued Statement No. 148 "Accounting for Stock-Based Compensation  Transition and Disclosures, an Amendment of FASB Statement No. 123" (FAS 148). FAS 148 amends FAS 123 "Accounting for Stock-Based Compensation", to provide alternative methods of transition for a voluntary change to the fair-value-based method of accounting for stock-based employee compensation. In addition, FAS 148 amends the disclosure requirements of FAS 123 to require prominent disclosures in both annual and interim financial statements about the method of accounting for stock-based employee compensation and the effect of the method used on reported results. FAS 148 will not have a material impact on the Trust, as the Trust Unit Incentive Plan is a variable compensation plan.



The following standards issued by the FASB do not impact the Trust:



 Statement No. 145  "Rescission of FASB Statements No. 4, 44, and 64, Amendment of FASB Statement No. 13, and Technical Corrections," effective for financial statements issued on or after May 15, 2002;

 Statement No. 146  "Accounting for Costs Associated with Exit or Disposal Activities," effective for exit or disposal activities initiated after December 31, 2002;

 Statement No. 147  "Acquisitions of Certain Financial Institutions  an Amendment of FASB Statements No. 72 and 144 and FASB Interpretation No. 9," effective for acquisitions on or after October 1, 2002; and

 Interpretation No. 46  "Consolidation of Variable Interest Entities," effective for financial statements issued after January 31, 2003.

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



|                                              |   |         |   |           |   |       
|--------------------------------------------- | - | ------- | - | --------- | - | ------
|                                              |   | 2002    |   | 2001      |   | 2000  
|Net income as reported in consolidated        |   |         |   |           |   |       
|statement of operations                       | $ | 24,379  | $ | 53,988    | $ | 62,906
|                                              |   |         |   |           |   |       
|Adjustments (net of tax)                      |   |         |   |           |   |       
|Unrealized loss on derivatives                |   | (238)   |   | -         |   | -     
|Compensation expense                          |   | (59)    |   | -         |   | -     
|Depletion and depreciation                    |   | 17,338  |   | 993       |   | 1,059 
|Ceiling test write down                       |   | -       |   | (154,937) |   | -     
|Deferred income taxes                         |   | (1,339) |   | -         |   | -     
|                                              |   |         |   |           |   |       
|Net income (loss), as adjusted                |   | 40,081  |   | (99,956)  |   | 63,965
|                                              |   |         |   |           |   |       
|Unrealized gain on derivatives, net of        |   |         |   |           |   |       
|income taxes of $1,113 (2001 - $783)          |   | (1,483) |   | 1,032     |   | -     
|                                              |   |         |   |           |   |       
|Comprehensive income (loss)                   | $ | 38,598  | $ | (98,924)  | $ | 63,965
|                                              |   |         |   |           |   |       
|Net income (loss) per unit, as adjusted       |   |         |   |           |   |       
|Basic                                         | $ | 0.77    | $ | (3.16)    | $ | 3.36  
|Diluted                                       | $ | 0.77    | $ | (3.16)    | $ | 3.36  
|                                              |   |         |   |           |   |       
|Accumulated other comprehensive income        |   |         |   |           |   |       
|Opening balance at January 1                  | $ | 1,032   | $ | -         | $ | -     
|Unrealized gain (loss) on derivatives, net of |   |         |   |           |   |       
|income taxes of $1,113 (2001 - $783)          |   | (1,483) |   | 1,032     |   | -     
|                                              |   |         |   |           |   |       
|Closing balance at December 31                | $ | (451)   | $ | 1,032     | $ | -     
|                                              |   |         |   |           |   |       





The application of U.S. GAAP would have the following effects on the consolidated balance sheets as reported:



|                                                |            |           |   | Increase  |   |        
|----------------------------------------------- | ---------- | --------- | - | --------- | - | -------
|As reported                                     | (Decrease) | U.S. GAAP
|                                                |            |           |   |           |   |        
|December 31, 2002                               |            |           |   |           |   |        
|Oil and gas derivative instruments              | $          | -         | $ | (1,194)   | $ | (1,194)
|Oil and gas royalty and property interests, net |            | 835,366   |   | (198,651) |   | 636,715
|Future income taxes                             |            | 116,845   |   | (58,344)  |   | 58,501 
|Unitholders' equity                             |            | 480,097   |   | (141,501) |   | 338,596
|                                                |            |           |   |           |   |        
|December 31, 2001                               |            |           |   |           |   |        
|Oil and gas derivative instruments              |            | -         |   | 1,815     |   | 1,815  
|Oil and gas royalty and property interests, net |            | 677,776   |   | (223,203) |   | 454,573
|Future income taxes                             |            | 104,000   |   | (65,609)  |   | 38,391 
|Unitholders' equity                             |            | 398,702   |   | (155,779) |   | 242,923
|                                                |            |           |   |           |   |        
|December 31, 2000                               |            |           |   |           |   |        
|Oil and gas royalty and property interests, net |            | 281,044   |   | (2,867)   |   | 278,177
|Unitholders' equity                             |            | 136,812   |   | (2,867)   |   | 133,945
|                                                |            |           |   |           |   |        
|                                                |            |           |   |           |   |