Petrofund Energy Trust (PTF) 40-F 2002 FY Annual report (Canada)

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 fro m 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 Manage r 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		Weighted		Weighted
		Average		Average		Average
		Exercise		Exercise		Exercise
	Units	Price	Units	Price	Units	Price
Options outstanding, beginning
of year	1,840,190	$15.92	941,278	$16.71	612,167	$17.70
Issued	1,468,100	10.65	1,477,800	17.65	371,000	15.00
Forfeited	(272,044)	16.66	(237,583)	18.38	(14,334)	17.10
Exercised	(7,966)	10.65	(341,305)	16.47	(27,555)	15.39
Options outstanding before
reduction of exercise price	3,028,280	$13.31	1,840,190	$17.29	941,278	$16.71
Reduction of exercise price	-	(0.10)	-	(1.37)	-	-
Options outstanding,  end of year	3,028,280	$13.21	1,840,190	$15.92	941,278	$16.71
Options exercisable,  end of year	1,593,681	$14.10	745,565	$16.08	693,945	$17.31

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	$	(271)
Fixed price	February 1, 2003 to February 28, 2003	2,000	$44.25	Edmonton		(193)
Collar	January 1, 2003 to June 30, 2003	2,000	$37.06- 45.34	Edmonton		(728)
Three-way collar	March 1, 2003 to June 30, 2003	2,000	*(1)	Edmonton		(413)
Total					$	(1,605)

*(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	$	(5,020)
	October 31, 2003
Total					$	(5,020)

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 M anager, 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