UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

Form 6-K

REPORT OF FOREIGN ISSUER PURSUANT TO ~~RULES~~RULE ~~13a~~13A-16 ~~AND~~OR 15D-16 OF THE SECURITIES EXCHANGE ACT OF 1934

~~UNDER~~For ~~THE~~the ~~SECURITIES~~month ~~EXCHANGE~~of: ~~ACT~~May, ~~OF 1934~~2003

~~November,~~Commission ~~2002~~File Number: 00-115124

NCE ~~Petrofund~~PETROFUND

(~~Translation~~Name of ~~registrant's name into English~~Registrant)

56Barclay ~~Temperance Street, 4th Floor, Toronto, Ontario, M5H 3V5~~Centre

~~(Address~~600 of444 ~~principal~~7Avenue ~~offices)~~SW

~~Unaudited Interim Financial Statements – “For the nine months ended November 30th~~Calgary, ~~2002”~~Alberta

~~Indicate~~Canada byT2P check mark whether the Registrant by furnishing the information contained in this Form is also thereby furnishing the information to the Commission pursuant to Rule 12g3-2 (b) under the Securities Exchange Act of 1934.0X8

~~Yes~~(Address ~~______ No~~of ~~_XXX~~Principal Executive Offices)

~~NCE~~Indicate ~~Petrofund~~by check mark whether the registrant files or will file annual reports under cover of Form 20-F or Form 40-F:

~~3RD QUARTER~~Form ~~REPORT~~20-F _____ Form 40-F __4_

~~FOR THE~~Indicate ~~THREE~~by ~~AND~~check ~~NINE~~mark ~~MONTHS~~whether ~~ENDED~~the ~~SEPTEMBER~~registrant ~~30,~~by ~~2002~~furnishing the information contained in this Form is also thereby furnishing the information to the Commission pursuant to Rule 12g3-2(b) under the Securities Exchange Act of 1934:

~~Introduction~~Yes ______ No __4_

~~The following~~If ~~discussion~~“Yes” ~~and~~is ~~analysis~~marked, ofindicate ~~financial~~below ~~results should be read in conjunction with~~ the ~~consolidated~~file ~~interim~~number ~~financial~~assigned ~~statements~~to ~~for~~ the ~~three months~~registrant ~~and~~in ~~nine~~connection ~~months~~with ~~ended~~Rule ~~September~~12g3-2(b): ~~30, 2002 included herein.~~N/A

Where amounts and volumes are expressed on a barrel of oil equivalent basis, gas volumes have been converted to barrels of oil at six thousand cubic feet per barrel. On July 6, 2001, the Trust units were consolidated on a one-for-three basis. Prior periods have been restated for comparative purposes.SIGNATURES

~~All~~Pursuant ~~figures~~to ~~are~~the ~~in Canadian~~requirements ~~dollar~~of ~~values~~the ~~unless~~Securities ~~otherwise~~Exchange ~~stated~~Act of 1934, the Registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized.

NCE Petrofund Highlights
(unaudited)
(thousands of dollars except per unit amounts)
		Three months ended September 30,					Nine months ended September 30,
		2002		2001	Variance		2002		2001	Variance
Financial
Revenues	$	70,030	$	56,973	23%	$	186,237	$	190,929	(2%)
Cash flow from operating activities	$	28,247	$	22,433	26%	$	74,058	$	91,841	(19%)
Cash flow available for distribution	$	21,629	$	21,000	3%	$	70,751	$	90,224	(22%)
Cash flow available for
distribution per unit	$	0.40	$	0.54	(26%)	$	1.46	$	2.80	(48%)
Net income	$	9,589	$	7,715	24%	$	19,027	$	50,379	(62%)
Net income per unit
- basic	$	0.18	$	0.20	(10%)	$	0.39	$	1.56	(75%)
- diluted	$	0.18	$	0.20	(10%)	$	0.39	$	1.56	(75%)
Units outstanding
Weighted average		54,100		38,711	40%		48,512		32,267	50%
Diluted		54,199		38,722	40%		48,546		32,344	50%
At period end		54,102		38,714	40%		54,102		38,714	40%
Operating
Daily Production
Oil (bbls)		11,718		10,364	13%		10,847		7,558	44%
Natural gas (mcf)		81,431		71,248	14%		75,845		64,398	18%
Liquids (bbls)		1,625		1,372	18%		1,762		1,377	28%
BOE (6:1)		26,915		23,611	14%		25,250		19,667	28%
Prices
Oil (per bbl)	$	37.31	$	33.64	11%	$	34.01	$	36.21	(6%)
Natural gas (per mcf)		3.36		3.27	3%		3.52		5.83	(40%)
Liquids (per bbl)		31.51		27.43	15%		26.42		36.23	(27%)
Operating netback per BOE	$	14.99	$	14.18	6%	$	14.23	$	20.98	(32%)

NCE PETROFUND

~~For~~Date: ~~further~~May ~~information regarding NCE Petrofund~~6, ~~please contact our Investor Services Department at 1-888-739-4623~~2003 By: ____________________________

~~e-mail: info@nceresources~~ Vince P.~~com or www.nceresources.com~~ Moyer, CA

~~Results~~ Senior ~~summary~~Vice President, Finance and CFO

~~We are pleased to present the results for NCE Petrofund (or "Petrofund") for the three months and nine months ended September 30, 2002.~~EXHIBIT

For the three months ended September 30, production increased 14% from 23,611 barrels of oil equivalent per day (boe/d) in 2001 to 26,915 boe/d in 2002 mainly due to the acquisition of NCE Energy Trust ("NCE Energy") effective May 30, 2002. Cash flow from operating activities increased from $22.4 million in the third quarter of 2001 to $28.2 million in the third quarter of 2002 due to the production increase and an 8% increase in prices on a boe basis to $28.31 in 2002 from $26.23 in 2001.

Exhibit

Description of Exhibit

First Quarter Report dated May 26, 2003.

The West Texas Intermediate (WTI) crude oil price averaged US$28.27 in the third quarter of 2002 as compared to US$26.48 in the third quarter of 2001. This resulted in Canadian wellhead prices of $37.31 per bbl in 2002 as compared to $33.64 per bbl in 2001. The average gas price increased 3% from $3.27 per mcf in 2001 to $3.36 per mcf in 2002.

For the nine-month period ended September 30, cash flow from operating activities decreased 19% from $91.8 million in 2001 to $74.1 million in 2002 due to the lower product prices. Production increased 28% from 19,667 boe/d to 25,250 boe/d in 2002. The average oil price decreased from $36.21 per bbl in 2001 to $34.01 per bbl in 2002 after hedging adjustments. The average gas price was down 40% from $5.83 per mcf in 2001 to $3.52 per mcf in 2002.

Significant financial transactions

As noted in the second quarter report, NCE Petrofund completed the acquisition of NCE Energy Trust on May30,2002. The September 30, 2002 financial statements of NCE

Petrofund reflect the acquisition of the oil and gas properties and working capital of NCE Energy effective May 30 and include the operating income of NCE Energy effective June 1. This is the first quarterly report to include the operating results of NCE Energy for the full quarter.

Petrofund continues to source and evaluate new acquisition opportunities. Efforts have been hampered by a scarcity of properties suitable for inclusion in Petrofund's property portfolio. Those properties that were of interest to us were sold at prices significantly higher than our investment criteria could justify. We are expecting to see an increased supply of properties on the market and will actively pursue those that are of interest. In the meantime, Petrofund continues to emphasize development projects including drilling, recompletion work, workovers and optimization projects to capitalize on its significant undeveloped land base.

Operations highlights

Petrofund was very active implementing development and exploitation projects during the third quarter. Preparation and lead-in work completed during the first half of the year on our ongoing development program resulted in a high level of field activity in the third quarter. Petrofund participated in approximately 70 gross wells during the quarter (50 net wells) with an overall 95% success rate.

At Hatton, in southwestern Saskatchewan, Petrofund successfully drilled and completed 47 shallow Milk River and Medicine Hat gas wells on its 100%-owned lands. These new wells are currently being equipped and tied into existing gathering and compression infrastructure. All wells should be producing by mid to late October, adding 3,000 mcf/d of initial production and 2,000 mcf/d of stabilized production after six to eight months.

Near Medicine Hat in southeastern Alberta, Petrofund has a 10% working interest in a 212-well shallow gas drilling program that started late in the third quarter. Petrofund expects the operator to have all wells drilled and producing by year end. Petrofund expects to net 1,000 mcf/d initially from these wells (600 mcf/d stabilized).

Petrofund participated in the successful drilling of two new horizontal wells at Queensdale and Viewfield in southeastern Saskatchewan. Petrofund has a 50% interest in the Queensdale well and a 25% interest in the Viewfield well. Petrofund's net combined production from both wells is currently 150 bbl/d. An additional drilling location is currently contemplated for the Queensdale property.

At Alliance, in east-central Alberta, Petrofund drilled a 100% Dina oil well, which is currently producing 40 bbl/d. A subsequent location was drilled and abandoned. Petrofund is using additional seismic data to firm up a Dina gas location on its 100%-owned lands for possible drilling in the upcoming quarter.

At Sunchild, in west-central Alberta, the third quarter was very active for Petrofund, both as an operator and as a non-operator. As operator, Petrofund successfully drilled a Shunda gas well (50% working interest) that is currently being equipped and tied into existing infrastructure. Petrofund also took over operatorship of a 50% working interest Ostracod gas well drilled in the second quarter and is now equipping and tying it in. Petrofund participated for its 18% working interest in drilling a Belly River gas well late in the quarter. This well is currently being completed. Petrofund expects to net 1,500 mcf/d from these three new working interest wells. In addition, Petro-fund also farmed out its interest in two other Ostracod gas new drills, which have been completed and are awaiting tie-in.

At Ogston, in north-central Alberta, an oil well drilled late in the second quarter continues to provide positive results. Based on this success, Petrofund, as operator, is preparing to drill a follow-up location early in the upcoming quarter. On this same 100%-owned property, Petrofund is expanding its production facilities using surplus equipment from a non-producing property, which will result in four shut-in wells being restarted (a 30-40 bbl/d gain).

At Strachan, in west-central Alberta, Petrofund as operator successfully worked over a previously uneconomic gas well that is currently being equipped and tied in. Petrofund's net share of production is expected to be 250 mcf/d. Petrofund is also preparing to spud an operated Viking oil well early in the fourth quarter. At Three Hills, in central Alberta, several farmout wells were drilled on Petrofund lands during the third quarter. Two of these farmout wells were abandoned; the others have been cased and are awaiting completion by the operators. Petrofund, as operator, plans to drill two to three lower risk gas wells on these lands next quarter. At the nearby Innisfail property, Petrofund farmed out a portion of its 100% working interest and participated for the remainder to drill a successful Pekisko gas well late in the third quarter. This well is expected to be producing by mid to late October.

Capital expenditures

As discussed in the second quarter report, NCE Petrofund acquired NCE Energy for $167 million. The total price consisted of the issue of 7.6 million Petrofund units with an assigned value of $98.6 million and the assumption of $39.5 million of debt and negative working capital as well as transaction costs of $2.0 million. In addition, the acquisition cost includes $27 million to account for the difference between the book and tax basis of the assets acquired. The NCE Energy acquisition was in addition to $40 million incurred for property acquisitions in the first quarter.

During the nine months ended September 30, 2002, $27.1 million was also incurred for other development drilling and production enhancement activities. A summary of total expenditures for the three- and nine-month periods appears below.

	Three months		Nine months
	ended Sept. 30,		ended Sept. 30,
($000)		2002		2002
Acquisitions	$	1,941	$	211,291
Dispositions		(3,004)		(6,132)
Net acquisitions		(1,063)		205,159
Finding and development cost:
Land and seismic		708		1,786
Drilling and completions		8,666		15,238
Well equipping		1,716		4,021
Tie-ins		585		1,723
Facilities		612		1,967
Other		558		2,363
Total		12,845		27,098
Total net capital expenditures	$	11,782	$	232,257

Cash distributions

NCE Petrofund unitholders who held their units throughout the third quarter of 2002 received distributions of $0.42 in cash compared to $0.93 in the third quarter of 2001. A cash distribution of $0.15 per unit was paid in October and $0.15 per unit was announced for November2002. Petrofund generated cash flow available for distribution of $21.6 million in the third quarter of 2002, after the deduction of $5 million for capital expenditures.

NCE Petrofund unitholders who held their units for the nine-month period ended September 30, 2002, received distributions of $1.26 per unit in cash compared to $3.51 per unit in 2001. Petrofund generated cash flow available for distribution of $70.8 million for the nine-month period ended September 30, 2002, compared to distributions paid of $60.9million. At September 30, 2002, the Trust had $22million in distributions accruing to unitholders. There is approximately a two-month delay in collecting revenues and the payment of distributions.

Production revenue

Revenues increased 23% to $70.0 million in the third quarter of 2002 from $57.0 million in the third quarter of 2001, due to the 14% increase in production plus an 8% increase in prices on a boe basis.

For the nine-month period ended September 30, 2002, revenue decreased 2% to $186.2 million from $190.9 million in 2001 in spite of a 28% increase in production. Prices decreased 24% on a boe basis to $27.02 in 2002 from $35.55 in 2001 as a result of the significant decline in natural gas prices.

Crude oil sales increased 25% from $32.1 million in the third quarter of 2001 to $40.2 million in the third quarter of 2002 due to the 13% rise in production. Oil production volumes were 11,718 bbl/d in the third quarter of 2002 as compared to 10,364 bbl/d in the third quarter of 2001. The average price increased 11% from $33.64 per bbl in the third quarter of 2001 to $37.31 per bbl in the third quarter of 2002. The price in the third quarter of 2002 is net of a negative hedging adjustment of $3.02 per bbl.

During the nine-month period ended September 30, 2002, crude oil sales increased 35% to $100.7 million in 2002 from $74.7 million in 2001. Oil production rose to 10,847 bbl/d for the period, compared to 7,558 bbl/d for the same period in 2001. The average price declined from $36.21 per bbl in 2001 to $34.01 per bbl in 2002.

Natural gas sales increased 17% from $21.4 million in the third quarter of 2001 to $25.2 million in the third quarter of 2002 due to a 14% increase in production from 71.2 mmcf/d to 81.4 mmcf/d. The average gas price rose 3% from $3.27permcf in the third quarter of 2001 to $3.36 per mcf in the third quarter of 2002.

During the nine-month period ended September 30, 2002, natural gas sales decreased 29% to $72.9 million from $102.5 million in 2001. Gas production was up 18% to 75.8 mmcf/d from 64.4 mmcf/d for the same period in 2001. However, the average gas price decreased 40% from $5.83permcf in 2001 to $3.52 per mcf in 2002.

Sales of natural gas liquids increased 36% from $3.5million in the third quarter of 2001 to $4.7 million in 2002. Production volumes increased 18% from 1,372 boe/d in the third quarter of 2001 to 1,625 boe/d in the third quarter of 2002. The average price rose from $27.43 per bbl in the third quarter of 2001 to $31.51 per bbl in the third quarter of 2002.

For the nine-month period ended September 30, sales of natural gas liquids decreased 7% from $13.6 million in 2001 to $12.7 million in 2002. Production volumes rose 28% from 1,377 bbl/d to 1,762 bbl/d. However, the average price received fell from $36.23 per bbl in 2001 to $26.42 per bbl in 2002.

Royalties

Royalties increased to 20.4% of revenues in the third quarter of 2002 from 20.2% in the third quarter of 2001, net of the Alberta Royalty Credit.Royalties for the nine-month period ended September 30, 2002 averaged 18.6% of revenues in 2002 compared to 23.2% for the corresponding period of 2001 due to the lower average gas prices in 2002.

Field operating costs

Operating expenses increased to $18.6 million in the third quarter of 2002 compared to $14.3 million in the third quarter of 2001. This reflects property acquisitions totaling $60 million at the end of 2001 and in the first quarter of 2002 and the NCE Energy Trust acquisition effective May 30, 2002.

Operating expenses were $53.5 million for the nine-month period ended September 30, 2002 compared to $32.5 million for the same period in 2001. Operating costs for the nine months ended September 30, 2002 were $7.76 per boe as compared to $6.05 per boe for the same period in the previous year. This is due to a general increase in operating costs and normal production decline. In addition, recent acquisitions made by the Trust have a higher cost per boe, part of which is due to additional equipment, maintenance and facility upgrades. Operating costs decreased from $7.76 per boe in the second quarter of 2002 to $7.52 per boe in the third quarter mainly due to lower repair and maintenance costs.

General and administrative expenses

General and administrative costs increased from $3.1 million in the third quarter of 2001, to $4.0 million for the same period in 2002. This excludes costs associated with an offering of Trust units in the United States that was launched on

September 10, 2001, but subsequently withdrawn following the attacks on key U.S. landmarks. For the nine-month period ended September 30, 2002, general and administrative costs rose from $8.6 million excluding the U.S. offering costs, to $11.9 million. General and administrative costs per boe in 2002 decreased to $1.63 in the third quarter from $1.73 in the second quarter and from $1.83 in the first quarter.

Management fees remained constant at $1.2 million as the higher cash flow was offset by a reduction in the management fee effective January 1, 2002. Management fees for the nine-month period ended September 30, 2002 were $3.2 million, compared to $4.3 million for the same period in 2001.

Price risk management

The Trust entered into several small transactions during the quarter to protect cash flows in late 2002 and the first quarter of 2003. The Trust continues to have 4,200 bbl/d hedged for the balance of the year. This is comprised of 1,200 bbl/d at $30.00 per bbl and 3,000 bbl/d between $30.13 and $38.65per bbl. The Trust has 1,320 bbl/d fixed at $44.60 per bbl in the first quarter of 2003 and no crude hedged thereafter.

The Trust has 27.4 mmcf/d of AECO-based price hedges in place until December 31, 2002. These hedges are comprised of:

8.2 mmcf/d subject to a price ceiling of $3.04 per mcf;

4.8 mmcf/d with an average floor price of $3.07 per mcf;

11.1 mmcf/d with an average floor price of $3.01 per mcf and an average ceiling price of $5.12 per mcf; and

3.4 mmcf/d fixed at $4.22 per mcf.

The Trust's hedged volumes of natural gas decline to approximately 9.8 mmcf/d for 2003. About 5.1 mmcf/d of this volume is a contract with a price cap of $3.16 per mcf and the balance is wide collar (from $4.59 per mcf to $7.97 per mcf) in the first quarter of the year. No hedges have been transacted beyond 2003. For a complete listing of all hedge transaction details please see Note 4 to the Consolidated Interim Financial Statements.

Depletion, reclamation and abandonment

The provision for depletion and reclamation costs rose from $21.8 million in the third quarter of 2001 to $26.8 million in the third quarter of 2002 due to the 14% increase in production and an increase in depletion rate from $9.60 per boe in 2001 to $10.16 per boe in 2002. In the third quarter of 2002, NCE Petrofund Corp. ("NCEP") set aside $186,000 in cash to fund future abandonment costs. As at September30,2002, NCEP has a cash abandonment reserve of $2.8 million.

For the nine-month period ended September 30, 2002, depletion and reclamation costs increased to $76.0 million compared to $48.2 million for the same period in the previous year. The depletion rate rose from $8.54 per boe in 2001 to

$10.38 per boe in 2002. This was due to the increase in the cost of acquiring reserves and future income taxes of $110 million recorded on the 2001 corporate acquisition of Magin Energy Inc. to account for the difference between the book and the tax basis of the assets acquired.

Liquidity and capital resources

The credit facility was increased to $245.0 million in conjunction with the NCE Energy acquisition, of which $183.3 million was outstanding at September 30, 2002.

For the three months ended September 30, 2002, the Trust generated cash flow from operating activities of

$28.2 million and paid out $22.7 million in distributions. For the nine-month period the Trust generated cash flow of $74.1 million and paid out $60.9 million in distributions.

Total capital expenditures of $232.3 million were incurred during the nine-month period. The expenditures were financed by the increase in the bank loan outstanding from $128.8million at December 31, 2001 to $183.3 million at September30,2002, net proceeds of $55 million from an equity issue in the first quarter, and the issue of 7.6 million units for the purchase of NCE Energy.

NCE Petrofund Consolidated Balance Sheet
(unaudited)
(thousands of dollars)
As at September 30, 2002 and December 31, 2001		2002		2001
Assets
Current assets
Cash	$	10,302	$	1,917
Accounts receivable		15,985		12,965
Due from affiliates		903		-
Prepaid expenses		9,134		4,584
Total current assets		36,324		19,466
Reclamation and abandonment reserve		2,812		2,073
Oil and gas royalty and property interests at cost less accumulated
depletion and depreciation of $327,139 (2001 - $255,532)		838,426		677,776
	$	877,562	$	699,315
Liabilities and unitholders' equity
Current liabilities
Accounts payable and accrued liabilities	$	26,589	$	21,319
Payable to affiliates		899		1,056
Current portion of capital lease obligation		3,839		5,467
Distributions payable to unitholders		22,059		12,188
Total current liabilities		53,386		40,030
Bank loan		183,291		128,783
Capital lease obligations		7,410		16,168
Future income taxes		111,755		104,000
Accrued reclamation and abandonment costs		14,397		11,632
Total liabilities		370,239		300,613
Unitholders' equity		507,323		398,702
	$	877,562	$	699,315
The accompanying notes to the consolidated financial statements are an integral part of this consolidated statement.

NCE Petrofund Consolidated Statement of Operations
(unaudited)
(thousands of dollars except per unit amounts)
	Three months ended September 30,				Nine months ended September 30,
		2002		2001		2002		2001
Revenues
Oil and gas sales	$	70,030	$	56,973	$	186,237	$	190,929
Royalties, net of incentives		(14,280)		(11,529)		(34,637)		(44,199)
		55,750		45,444		151,600		146,730
Expenses
Lease operating		18,621		14,259		53,493		32,478
Management fee		1,207		1,170		3,189		4,285
Interest and other financing costs		2,482		2,909		6,085		6,030
General and administrative		4,035		4,216		11,907		9,680
Capital taxes		277		375		932		1,205
Depletion and depreciation		25,159		20,844		71,607		45,863
Provision for reclamation and abandonment		1,601		956		4,427		2,299
		53,382		44,729		151,640		101,840
Net income (loss) before provision for income taxes		2,368		715		(40)		44,890
Provision for (recovery of) income taxes
Current		188		-		275		1,072
Future		(7,409)		(7,000)		(19,342)		(6,561)
		(7,221)		(7,000)		(19,067)		(5,489)
Net income	$	9,589	$	7,715	$	19,027	$	50,379
Net income per Trust unit
Basic	$	0.18	$	0.20	$	0.39	$	1.56
Diluted	$	0.18	$	0.20	$	0.39	$	1.56
The accompanying notes to the consolidated financial statements are an integral part of this consolidated statement.
NCE Petrofund Consolidated Statement of Unitholders' Equity
(unaudited)
(thousands of dollars)
	Three months ended September 30,				Nine months ended September 30,
		2002		2001		2002		2001
Balance, beginning of period	$	519,326	$	342,031	$	398,702	$	136,812
Units issued, net of issue costs		37		48,442		154,693		280,221
Net income		9,589		7,715		19,027		50,379
Distributions accruing to unitholders		(21,629)		(21,000)		(65,099)		(90,224)
Balance, end of period	$	507,323	$	377,188	$	507,323	$	377,188
The accompanying notes to the consolidated financial statements are an integral part of this consolidated statement.

NCE Petrofund Consolidated Statement of Cash Flows
(unaudited)
(thousands of dollars except per unit amounts)
	Three months ended September 30,				Nine months ended September 30,
		2002		2001		2002		2001
Cash provided by (used in) operating activities
Net income	$	9,589	$	7,715	$	19,027	$	50,379
Add items not affecting cash:
Depletion and depreciation		25,159		20,844		71,607		45,863
Provision for reclamation and abandonment		1,601		956		4,427		2,299
Future income taxes		(7,409)		(7,000)		(19,342)		(6,561)
Actual abandonment costs incurred		(693)		(82)		(1,661)		(139)
Cash flow from operating activities		28,247		22,433		74,058		91,841
Net change in non-cash operating balances		6,097		(20,233)		569		14,683
Cash provided by operating activities		34,344		2,200		74,627		106,524
Financing activities
Bank loan		5,782		(21,686)		54,508		30,064
Distributions paid		(22,721)		(34,766)		(60,880)		(97,889)
Increase in capital lease obligation		-		-		-		19,137
Capital lease repayments		(7,432)		(1,302)		(10,387)		(1,302)
Issuance of Trust units		37		48,442		56,054		123,082
Deferred issue costs		-		(82)		-		(750)
Advances to affiliates, net (Note 2)		(3,416)		-		(38,445)		-
Cash provided by (used in) financing activities		(27,750)		(9,394)		850		72,342
Investing activities
Reclamation and abandonment reserve		(186)		(131)		(517)		(315)
Acquisition of property interests		(14,786)		(8,830)		(73,134)		(176,533)
Proceeds on disposition of property interests		3,004		(13)		6,132		162
Cash acquired on acquisition (Note 2)		-		-		427		-
Cash used in investing activities		(11,968)		(8,974)		(67,092)		(176,686)
Net change in cash		(5,374)		(16,168)		8,385		2,180
Cash, beginning of period		15,676		20,082		1,917		1,734
Cash, end of period	$	10,302	$	3,914	$	10,302	$	3,914
Cash flow from operating activities per Trust unit
Basic	$	0.52	$	0.58	$	1.53	$	2.85
Diluted	$	0.52	$	0.58	$	1.53	$	2.84
Interest paid during the period	$	2,604	$	2,919	$	5,949	$	6,626
Income taxes paid during the period	$	160	$	-	$	1,569	$	325
The accompanying notes to the consolidated financial statements are an integral part of this consolidated statement.

NCE Petrofund Consolidated Statement of Distributions Accruing to Unitholders
(unaudited)
(thousands of dollars except per unit amounts)
	Three months ended September 30,				Nine months ended September 30,
		2002		2001		2002		2001
Distributions payable, beginning of period	$	23,151	$	34,526	$	12,188	$	28,425
Distributions accruing during the period
Cash flow from operating activities		28,247		22,433		74,058		91,841
Proceeds on disposition of property interests		-		-		946		-
Reclamation and abandonment reserve		(186)		(131)		(517)		(315)
Capital lease repayments (2)		(1,432)		(1,302)		(4,387)		(1,302)
Capital expenditure		(5,000)		-		(5,000)		-
NCE Energy Trust cash flows (1)		-		-		5,651		-
Total distributions accruing during the period		21,629		21,000		70,751		90,224
Distributions paid		(22,721)		(34,766)		(60,880)		(97,889)
Distributions payable, end of period	$	22,059	$	20,760	$	22,059	$	20,760
Distributions accruing to unitholders per Trust unit
Basic	$	0.40	$	0.54	$	1.46	$	2.80
Diluted	$	0.40	$	0.54	$	1.46	$	2.79

(1) Remaining undistributed cash flow of NCE Energy Trust on May 30, 2002 (see Note 2). (2) Net of $6 million refinanced by increased bank loan.

The accompanying notes to the consolidated financial statements are an integral part of this consolidated statement.

NCE Petrofund Notes to Consolidated Interim Financial Statements

September 30, 2002 and 2001 (Unaudited)

1. INTERIM FINANCIAL STATEMENTS

These unaudited consolidated interim financial statements have been prepared by management following the same accounting policies and methods of their application as the most recent annual financial statements, except as noted below. The note disclosure for annual financial statements provides additional disclosure to that required for interim financial statements. Accordingly, these interim financial statements should be read in conjunction with the audited consolidated financial statements included in NCE Petrofund's or (the "Trust's") 2001 annual report.

2. ACQUISITION OF NCE ENERGY TRUST

On May 30, 2002, NCE Petrofund acquired NCE Energy Trust for 0.2325 of a 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 issued on the acquisition is based on the market value of the Petrofund units at the time the acquisition was announced.

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

		($000)
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.

3. TRUST UNITS
Authorized: unlimited number of Trust units
			Number of units	Amount ($000)
Issued
December 31, 2001			41,915,740	$	639,892
Issued for cash			4,600,000		59,827
Issued for NCE Energy Trust			7,573,753		98,639
Commissions and issue costs			-		(3,917)
Options exercised			3,733		40
Unit purchase plan			8,292		104
September 30, 2002			54,101,518	$	794,585
The weighted average units outstanding are as follows:
	Three months ended September 30,		Nine months ended September 30,
	2002	2001	2002		2001
Basic	54,099,739	38,711,170	48,512,318		32,267,308
Diluted	54,198,724	38,722,130	48,545,676		32,343,714

Unit Incentive Plan

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 rights 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 rights 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 rights granted under the Trust's rights plan may be reduced in future periods in accordance with the terms of the rights 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 determination of the amounts to be withheld from future distributions to fund capital expenditures. Therefore, it is not possible to determine a fair value for the rights granted under the plan.

On July 25, 2002, 1,468,100 rights were granted at an initial exercise price of $10.65. Under the Incentive Plan, distributions per Trust unit to Petrofund unitholders in a calendar quarter, which represent a return of more than 2.5% of the net oil and gas royalty and property interests of Petrofund at the end of such quarter would result in a reduction of the exercise price of the rights. During the period from July 25 to September 30, 2002, the exercise price of the rights was reduced to $10.63.

As it is not possible to determine the fair value of rights granted under the 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 period from July 25, 2002 to September 30, 2002, net income would be reduced by $108,000 for the estimated compensation cost associated with rights granted under the plan on or after January 1, 2002, with negligible impact on net income per Trust unit.

4. DERIVATIVE FINANCIAL INSTRUMENTS AND PHYSICAL CONTRACTS

NCE Petrofund 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 and physical contracts as at September 30, 2002, all of which constitute
effective hedges, and the related unrealized gains or losses, are summarized separately below:
Financial Gas Hedges
		Volume		Delivery	Unrealized gain
Natural Gas	Term	mcf/d	Price $/mcf	point	(loss) ($000)
Call option
(purchased)	July 1, 2001 to October 31, 2002	6,064	$4.91	AECO	$	-
Call option
(purchased)	July 1, 2001 to October 31, 2003	6,159	$4.91	AECO		2,910
Collar	April 1, 2002 to December 31, 2002	4,737	$2.80 - $4.70	AECO		(552)
Collar	April 1, 2002 to December 31, 2002	4,737	$2.80 - $5.07	AECO		(237)
Floor	August 1, 2002 to November 1, 2002	7,106	$2.96	AECO		-
Floor	August 1, 2002 to November 1, 2002	7,106	$3.17	AECO		-
Collar	January 1, 2003 to March 31, 2003	4,737	$4.59 - $7.97	AECO		8
Total					$	2,129
Financial Oil Hedges
		Volume		Delivery	Unrealized gain
Oil	Term	bbl/d	Price $/bbl	point	(loss) ($000)
Fixed Price	January 1, 2002 to December 31, 2002	1,200	$30.00	Edmonton	$	(1,941)
Collar	April 1, 2002 to December 31, 2002	1,500	$30.13 - $38.45	Edmonton		(1,285)
Collar	April 1, 2002 to December 31, 2002	1,500	$30.13 - $38.85	Edmonton		(1,605)
Fixed Price	January 1, 2003 to January 31, 2003	2,000	$44.72	Edmonton		(68)
Fixed Price	February 1, 2003 to February 28, 2003	2,000	$44.48	Edmonton		(16)
Total					$	(4,915)
In addition to the financial instruments, the Trust has the following physical gas contracts:
		Volume		Delivery	Unrealized gain
Natural Gas	Term	mcf/d	Price $/mcf	point	(loss) ($000)
Collar	April 1, 2002 to October 31, 2002	4,737	$4.27 - $6.54	AECO	$	-
Capped	November 1, 1999 to October 31, 2002	6,064	$2.90	AECO		(322)
Capped	November 1, 1999 to October 31, 2003	6,159	$3.16	AECO		(6,345)
Fixed	September 1, 2002 to October 31, 2002	9,996	$4.22	AECO		(123)
Collar	January 1, 2003 to March 31, 2003	14,212	$4.59 - $7.97	AECO		(122)
Total					$	(6,912)
The gains or losses 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.

5. MANAGEMENT ADVISORY AND ADMINISTRATION AGREEMENT

Effective January 1, 2002, management fees were reduced from 3.75% of net operating income to 3.25% and acquisition fees were reduced from 1.75% of the purchase cost of oil and gas properties to 1.50%.

6. LONG-TERM DEBT

In conjunction with its acquisition of NCE Energy Trust, NCEP increased the maximum it can borrow under its credit facility. NCEP currently has a revolving working capital operating facility of $25 million and a syndicated facility of $220 million. The revolving period ends on May 30, 2003 unless extended for a further 364-day period. If not extended, the balance outstanding would be due and payable on May 30, 2004.

The limit of the syndicated facility is subject to adjustment from time to time to reflect changes in NCEP's asset base. The next review was scheduled for September 30, 2002 but has been extended to November 15, 2002.

Definitions and Descriptions

Abbreviations		Glossary of Terms
bbl	barrel	boe: Barrel of oil equivalent, which	Proved reserves: Those reserves
bcf	billion cubic feet	is determined on the basis that	estimated as recoverable with a high
boe	barrels of oil equivalent	6,000 cubic feet (6 mcf) of natural	degree of certainty under current tech-
boe/d	barrels of oil equivalent per day	gas is equivalent to one barrel of oil.	nology and existing economic conditions.
bbl/d	barrels per day
mbbls	thousand barrels	Caps: A contract that establishes a	Reserve production ratio: A measure
mboe	thousand barrels of oil equivalent	maximum price to be paid for a	of the expected future life of a resource,
mmbtu	million British thermal units	security or commodity. See also Floors.	also known as reserve life index. Reserves
mbbl/d	thousand barrels of oil per day		divided by production.
mcf	thousand cubic feet	Collars: A contract that establishes
mcf/d	thousand cubic feet per day	a maximum and a minimum price to	Spud: The first boring of the hole in
mlt	thousand long tons	be paid for a security or commodity	the drilling of a well.
mmbbls	million barrels	- a combination of a cap and a floor.
mmboe	million barrels of oil equivalent		Swaps: An exchange of streams of
mmcf	million cubic feet	Crown royalty: The government's	payments between two counterparties,
mmcf/d	million cubic feet per day	share of a property's production.	sometimes directly and at other times
mstb	thousand stock tank barrels		through an intermediary.
tcf	trillion cubic feet	Established reserves: Proved reserves
API	American Petroleum Institute	plus 50% of probable reserves.	Watercut: The percentage of water
APO	after payout		produced per thousand barrels of oil.
ARC	Alberta Royalty Credit	Floors: A contract that establishes
BPO	before payout	a minimum price to be paid for a	Water flood: A method of secondary
Gj	gigajoules	security or commodity. See also Caps.	recovery in which water is injected into
NGLs	natural gas liquids		an oil reservoir for the purpose of washing
RLI	reserve life index (in years)	Netback: The amount received from	the oil out of the reservoir rock and into
WTI	West Texas Intermediate	the sale of a barrel of oil or barrel of oil	the bore of a producing well.
		equivalent after deduction of operating
		costs and royalty payments.	Working interest: The interest in a
			lease that carries with it the rights and
		Net production: The working interest	obligations to develop and operate an
		share of gross production.	oil or natural gas property.
		Probable reserves: Those reserves that
		analysis suggests exist and whose future
		recovery, under current technology, is
		highly likely.

Corporate Directory
NCE PETROFUND CORP.	Jeffrey Newcommon	Peter N. Thomson 1 2
DIRECTORS AND OFFICERS	Senior Vice-President, Land and Exploration	Director
John F. Driscoll 1	John Vooglaid	Frank Potter 1 2
Chief Executive Officer,	Vice-President and Secretary-Treasurer	Director
Chairman of the Board and Director
	Gordon M. Thompson	Sandra Cowan 2
Jeffery E. Errico	Senior Vice-President, Corporate Development	Director
President and Chief Operating Officer
	John Nestor	1 Member of the Executive Committee
Glen Fischer	Director	2 Member of the Audit Committee
Senior Vice-President, Operations
	Richard J. Zarzeczny
Vince P. Moyer	Director
Senior Vice-President, Finance
LEGAL COUNSEL	PETROLEUM CONSULTANTS
Goodman and Carr	Gilbert Laustsen Jung Associates Ltd.
Toronto, Ontario	Calgary, Alberta
Burnet, Duckworth & Palmer	Paddock Lindstrom & Associates Ltd.
Calgary, Alberta	Calgary, Alberta
AUDITORS	STOCK EXCHANGE LISTINGS
Deloitte & Touche LLP	Toronto Stock Exchange
Calgary, Alberta	Symbol: NCF.UN
TRUSTEE AND TRANSFER AGENT	American Stock Exchange
Computershare Investor Services of Canada	Symbol: NCN
Toronto, Ontario

Investor Services		Head Office	Operations Office
Tel:	416-364-9297	The Exchange Tower	444-7th Avenue SW
	1-888-739-4623	130 King Street West	Suite 600
Fax:	416-364-1197	Suite 2850, P.O. Box 104	Calgary, Alberta T2P 0X8
E-mail: info@nceresources.com		Toronto, Ontario M5X 1A4	Tel:	403-218-8625
Web site: www.nceresources.com		Tel: 416-364-8788	Fax:	403-269-5858
		1-800-563-4623
		Fax: 416-364-5615

Certain statements contained herein may constitute forward-looking statements. The use of any of the words "anticipate", "continue", "expect" "may", "will", "project", "should", "believe" and similar expressions are intended to identify forward-looking statements. These statements will involve known and unknown risks, uncertainties and other factors that may cause actual results or events to differ materially from those anticipated in our forward-looking statements. These risks and uncertainties include among other things, product supply and demand, volatility of oil and gas prices, imprecision of reserve estimates, our ability to replace and expand oil and gas reserves, risks and uncertainties inherent in our oil and gas operations, market competition, our ability to generate sufficient cash flow from operations to meet our current and future obligations, our ability to access external sources of debt and equity capital, and such other risks and uncertainties described from time to time in our filings with the Ontario Securities Commission and SEDAR.

SIGNATURE

Pursuant to the requirements of the Securities Exchange Act of 1934, the registrant has duly cause this Form 6-K to be signed on its behalf by the undersigned, thereunto duly authorized.

NCE Petrofund - SEC File No. 00-115124

(Registrant)

Date - November 22, 2002

By: _"John Vooglaid"____________

John Vooglaid, V-President, Finance

Filing Compare · PETROFUND ENERGY TRUST