600, 444- 7^th Ave. S.W.

Calgary, Alberta

T2P 0X8

Telephone: (403) 218-8625

Fax: (403) 269-5858

News Release

CALGARY- November 12, 2003

Petrofund Energy Trust (TSX: PTF.UN; AMEX: PTF)
Reports its Results for the Third Quarter of 2003

Petrofund Energy Trust announces its third quarter 2003 results.

Key items include:

• a 7% increase in production to 28,801 boepd
• a 41% increase in cash flow to $40.0 million or $0.60 per unit
• a 29% increase in distributions to $0.54 per unit
• a third quarter payout ratio of 92%
• a year to date payout ratio of 65% the closing of
• a $37.1 million property acquisition

The Trust's results for the three and nine month periods ended September 30^th are as follows:

Petrofund Energy Trust Highlights (unaudited)
(thousands of dollars, except per unit amounts)	3 Months Ended September 30,						9 Months Ended September 30,
	2003			2002	Variance		2003		2002	Variance
Revenues	$ 93,957		$	70,030	34%	$ 298,939		$	186,237	61%
Cash flow from operating activities (1)	$ 39,959		$	28,247	41%	$ 144,339		$	74,058	95%
Cash flow available for distribution (2)	$ 30,243		$	21,629	40%	$ 116,659		$	70,751	65%
Cash flow available for distribution per unit (2)
Before allocation for capital	$	0.57	$	0.49	16%	$	2.34	$	1.56	50%
Allocation for capital	$  (0.11)		$	(0.09)	(22)%	$	(0.37)	$	(0.10)	(270)%
After allocation for capital	$	0.46	$	0.40	15%	$	1.97	$	1.46	35%
Cash distributions paid per unit	$	0.54	$	0.42	29%	$	1.55	$	1.26	23%
Net income	$ 14,934		$	9,589	56%	$   62,226		$	19,027	227%
Net income per unit
Basic	$	0.23	$	0.18	28%	$	1.05	$	0.39	169%
Diluted	$	0.23	$	0.18	28%	$	1.05	$	0.39	169%

Units and Exchangeable Shares outstanding (Note 3)
Weighted average	66,143	54,100	22%		59,365		48,512	22%
Diluted	66,281	54,199	22%		59,491		48,546	23%
At period end	66,716	54,102	23%		66,716		54,102	23%
OPERATING
Daily Production
Oil (bbls)	12,518	11,718	7%		12,053		10,847	11%
Natural gas (mcf)	84,734	81,431	4%		84,324		75,845	11%
Liquids (bbls)	2,160	1,625	33%		2,043		1,762	16%
BOE (6:1)	28,801	26,915	7%		28,150		25,250	11%
Prices
Oil (per bbl)	$ 37.24 $	37.31	- %	$	39.00	$	34.01	15%
Natural gas (per mcf)	5.75	3.36	71%		6.56		3.52	86%
Liquids (per bbl)	30.86	31.51	(2)%		34.73		26.42	31%
BOE (6:1)	35.42	28.31	25%		38.87		27.02	44%
Operating netback per BOE	$ 18.45 $	14.99	23%	$	21.68	$	14.23	52%

(1) See special notes on page 2.
(2) See Note 6 to interim consolidated financial statements for details.

NAME CHANGE AND REVISED TRADING SYMBOL

This is the first quarterly report that reflects the name change of the Trust to Petrofund Energy Trust from NCE Petrofund. The name change was announced on October 23, 2003 and became effective November 1, 2003. On the same date, the name of the Trust's 100% owned subsidiary was changed to Petrofund Corp from NCE Petrofund Corp. As a result of the name change, the Trust adopted the new trading symbols PTF.UN on the Toronto Stock Exchange and PTF on the American Stock Exchange. The Trust units commenced trading under the new symbol on November 3, 2003.

The name change reflects the recent restructuring of the Trust. The restructuring began with the internalization of management earlier this year and the consolidation of the remaining activities in the Calgary office in the last few months. Petrofund has an experienced and competent team of oil and gas professionals and support groups who have assembled an excellent portfolio of quality assets. This team has been an instrumental part of the significant growth of the entity which currently has an enterprise value of $1.3 billion. The new name signifies recognition of these past achievements, while emphasizing the Trust's strengths going forward.

SPECIAL NOTES

The following discussion and analysis of financial results should be read in conjunction with the unaudited consolidated financial statements for the three and nine months ended September 30, 2003 included herein and the December 31, 2002 annual financial statements and management's discussion and analysis included in NCE Petrofund's ("Petrofund" or the "Trust") 2002 annual report.

All amounts are stated in Canadian dollars unless otherwise noted. Where amounts and volumes are expressed on a barrel of oil equivalent basis, gas volumes have been converted to barrels of oil at 6,000 cubic feet per barrel (6 mcf/bbl).

Management uses cash flow (before changes in non-cash working capital) to analyze operating performance and leverage. Cash flow as presented does not have any standardized meaning prescribed by Canadian GAAP and therefore, it may not be comparable with the calculation of similar measures for other entities. Cash flow as presented is not intended to represent operating cash flows or operating profits for the period, nor should it be viewed as an alternative to cash flow from operating activities, net earnings or other measures of financial performance calculated in accordance with Canadian GAAP. All references to cash flow throughout this report are based on cash flow before changes in non-cash working capital.

FORWARD-LOOKING STATEMENTS

This discussion may include statements about expected future events and/or financial results that are forward-looking in nature and subject to risks and uncertainties. For those statements, Petrofund claims the protection of the safe harbor for forward-looking statements provisions contained in the U.S. Private Securities Litigation Reform Act of 1995. Petrofund cautions that actual performance will be affected by a number of factors, many of which are beyond its control. Future events and results may vary substantially from what Petrofund currently foresees. Discussion of the various factors that may affect future results is contained in Petrofund's recent filings with the Securities and Exchange Commission and Canadian securities regulatory authorities. Petrofund undertakes no obligation to update publication of or revise any forward-looking statements contained herein and such statements are expressly qualified by this cautionary statement.

RESULTS SUMMARY

We are pleased to present the results for Petrofund for the three and nine months ended September 30, 2003.

The third quarter was characterized by higher production volumes due to a number of acquisitions in 2002 and 2003 and an active development drilling program carried out in 2002 and throughout the first nine months of 2003. Oil prices continued at high levels throughout the third quarter although the increase in the value of the Canadian dollar dampened cash flows. Gas prices declined from the first to the second quarter and again in the third quarter. Gas prices in the fourth quarter will be largely determined by weather as storage levels are currently at a relatively high level.

Production increased 7% to 28,801 barrels of oil equivalent per day ("boe/d") in the third quarter of 2003 from 26,915 boe/d in 2002. Cash flow from operations increased 41% to $40.0 million in the third quarter of 2003 from $28.2 million in the third quarter of 2002. Prices on a boe basis increased 25% to $35.42 in 2003 from $28.31 in 2002.

The West Texas Intermediate (WTI) crude oil price averaged US$30.20 in the third quarter of 2003 as compared to US$28.27 in the third quarter of 2002. This resulted in Canadian wellhead prices of $37.24/bbl in 2003 as compared to $37.31/bbl in 2002. The increase in the WTI price was offset by the strengthening of the Canadian dollar. The average gas price increased 71% from $3.36/mcf in 2002 to $5.75/mcf in 2003.

For the nine month period ended September 30, 2003 cash flow from operating activities increased 95% from $74.1 million in 2002 to $144.3 million in 2003. The average oil price increased from $34.01/bbl in 2002 to $39.00/bbl in 2003. The average gas price was up 86% from $3.52/mcf in 2002 to $6.56/mcf in 2003.

Net income for the three months ended September 30, 2003 increased to $14.9 from $9.6 million for the same period in the prior year.

Net income for the nine month period ended September 30, 2003 increased 227% to $62.2 million from $19 million for the same period in 2002. The results were impacted by one-time adjustments for the costs of the internalization of the management contract and the recovery of future income taxes for the decrease in tax rates. Net income was reduced by $30.8 million for management internalization costs and increased by $29.3 million, for future tax rate reductions.

The Canadian dollar averaged $0.663 per U.S. dollar in the first quarter; however, it significantly strengthened to average $0.716 per U.S. dollar in the second quarter and to $0.725 in the third quarter which negatively affected the Canadian oil price received for these latest two quarters. The Canadian dollar is expected to strengthen in the fourth quarter. At a WTI oil price of $28.00, U.S. distributions per unit per year change by approximately $0.04 for every 1 cent change in the Canadian U.S. dollar exchange rate.

SIGNIFICANT FINANCIAL TRANSACTIONS

In the third quarter, Petrofund Corp. ("PC"), purchased a 7.22% interest in Swan Hills Unit #1 for $37.1 million from a private Canadian company. This acquisition builds on Petrofund's previous interest in the Unit, and brings Petrofund's total interest in the Unit to 9.87%. The effective date of the transaction was August 21, 2003.

This acquisition is consistent with Petrofund's strategy of acquiring longer life properties at attractive prices. The acquisition was accretive to distributable cash flow, production per unit, reserves per unit and Reserve Life Index.

The major highlights of the acquisition are:

• Mature, long life unit production with an established Reserve Life Index of over 20 years.
• High quality light gravity oil (41 degree API).
• Working interest average production of 839 bpd of oil, 1,096 mcfd of gas, and 114 bpd of NGL's at time of acquisition.
• Working interest established reserves (proven plus 50% probable) estimated at 8.5 million boe.
• A reserves purchase price of $4.36 per established boe.
• A production purchase price of $32,658 per boepd.
• A cash flow multiple of 4.8 times based on 2002 cash flow.

The completion of the Swan Hills Unit # 1 transaction brings Petrofund's 2003 year to date total net acquisition costs to $111.9 million. The combined acquisition metrics for these 2003 transactions are :

Total Established Reserves: 20.3 mmboe

Established Reserves Purchase Price: $5.52 per boe

Production Purchase Price: $28,190 per boepd

Reserve Life Index (Established): 14 years

Oil and Gas Reserves Split: 81% Oil, 19% Gas

The acquired reserves have replaced over 200% of Petrofund's base 2003 production.

These are high quality assets that complement our existing property base.

OPERATIONAL HIGHLIGHTS

A total of 116 wells were drilled on Petrofund lands during the quarter, consisting of 111 working interest wells (76.1 net wells) and 5 farmout wells. This drilling activity resulted in 38 oil wells and 78 gas wells, for an overall success rate of 100%.

A total of 205 wells have been drilled on Petrofund lands during the first 9 months of 2003 resulting in 139 gas wells, 62 oil wells and 4 dry and abandoned wells. Our year to date drilling success rate stands at 98%.

At Hatton in southwestern Saskatchewan, Petrofund drilled 72 long-life shallow gas wells on its 100% working interest lands. Completion and equipping operations are ongoing. About 25% of the wells came on-stream prior to the end of the quarter, with the remainder expected to be producing by the middle of the 4th quarter of 2003.

At Boundary Lake in northeastern British Columbia, Petrofund, as operator, successfully drilled and cased a Boundary Lake oil well late in the quarter. Completion operations are underway and a low risk follow-up well is drilling.

In southeastern Saskatchewan, Petrofund drilled a 100% working interest horizontal Frobisher oil well on its Silverton property. At report time, completion operations were ongoing. Initial results indicate the well is capable of 125 bopd. At Queensdale, Petrofund participated for a 50% working interest in the drilling of a Frobisher-Alida oil well that is producing 100 bopd net to Petrofund. An additional 2 to 3 follow-up Queensdale wells are being considered before year end. Eight (8) horizontal Midale oil wells were drilled in the Weyburn unit during the quarter, adding 100 bopd net to Petrofund's 9.3% unit interest.

In the Pembina area of west central Alberta, 17 gross (2.0 net) oil wells were drilled within 2 large Cardium oil units owned by Petrofund. These new drills will add 75 bopd net to Petrofund. Further infill drilling within these units is scheduled to take place in the fourth quarter.

In north central Alberta, a total of 5 horizontal wells were drilled in the House Mountain Unit (14.5% WI) and the Swan Hills Unit #1 (9.8% WI). Petrofund's total net production from these new drills is 75 bopd.

Petrofund participated in drilling of 2 shallow gas wells (0.45 net wells) in Sylvan Lake and Garrington during the quarter. Both wells are currently being equipped and tied in. Follow-up drilling is contemplated.

Petrofund worked over/recompleted several gas wells located on its Fort Saskatchewan property, adding roughly 500 mscfd net. Additional workovers/ recompletions have been approved for the fourth quarter.

CAPITAL EXPENDITURES

Petrofund has shown good success on the acquisition front in the first nine months of this year acquiring long life properties at what we believe are attractive prices and below the average price paid by the industry during the same time period.

In the second quarter, Petrofund purchased a diverse group of oil and gas properties for $62.2 million, after adjustments. The properties contained a large percentage of unit production and had an established RLI of 11.6 years. As previously discussed in this report, the trust acquired an additional 7.22 % interest in Swan Hills Unit #1 in the third quarter. This property has an established RLI of over 20 years. These acquisitions along with Solaris Oil and Gas Inc. in the first quarter and other minor property purchases throughout the nine month period have resulted in total year-to-date net expenditures of $111.9 million. These properties will help achieve our objective of maintaining the long-term stability of the Trust.

During the three and nine months ended September 30, 2003, $19.2 and $48.7 million, respectively, have been incurred for development drilling and the other production enhancement activities discussed under Operational Highlights. These activities are instrumental in offsetting part of the decline on existing production. Total capital expenditures for these activities in 2003 are expected to be in the $60 million range.

A summary of expenditures for the periods appear below:

	Ended September 30, 2003
	Three months	Nine months
	(thousands of dollars)
Acquisitions	$40,724	$117,929
Dispositions	(5,397)	(6,013)
Net acquisitions	35,327	111,916
Finding & development costs:
Land and seismic	505	2,189
Drilling & completions	12,340	28,122
Well equipping	2,121	6,323
Tie-ins	1,567	3,512
Facilities	1,680	5,559
Other	983	3,028
Total	19,196	48,733
Total net capital expenditures	$54,523	$160,649

CASH DISTRIBUTIONS

Petrofund unitholders who held their units throughout the third quarter of 2003 received distributions of $0.54 per unit in cash as compared to $0.42 in the third quarter of 2002. A cash distribution of $0.18 per unit was paid in October and $0.18 per unit has been announced for November and indicated for December.

Petrofund generated cash flow available for distribution in the third quarter of $37.7 million, or $0.57 per unit before deducting $7.5 million or $0.11 per unit for reinvestment in capital projects. Of the $37.7 million, $34.7 million was paid out in distributions representing a payout ratio of 92% (see Note 6). Petrofund incurred $2.2 million in the third quarter on reclamation and abandonment activities which reduced distributable income by $0.03 per unit.

Petrofund unitholders who held their units for the nine month period ended September 30, 2003, received distributions of $1.55 per unit in cash compared to $1.26 per unit in 2002. Petrofund generated cash flow available for distributions of $139.2 million before deducting $ 22.5 million or $0.37 per unit for reinvestment in capitalprojects. Of the $139.2 million, $91.1 million was paid out in distributions representing a payout ratio of 65% (see Note 6).

The Trust is continuing its policy of stabilizing monthly distributions and reinvesting a portion of its cash flow for the long-term benefit of the Trust. Future distributions will depend on several factors, including future prices and capital expenditure needs.

PRODUCTION REVENUE

Revenues increased 34% to $93.9 million in the third quarter of 2003 from $70.0 million in the third quarter of 2002 as production increased 7% to 28,801 boe/d and prices were up 25% on a boe basis.

For the nine month period ended September 30, 2003, revenue increased 61% to $298.9 million from $186.2 million in 2002 due to an 11% increase in production to 28,150 boe/d and an increase in the average price per boe to $38.87 in 2003 from $27.02 in 2002.

Crude oil sales increased 7% from $40.2 million in the third quarter of 2002 to $42.9 million in the third quarter of 2003. Oil production volumes increased 7% to 12,518 bbl/d in the third quarter of 2003 as compared to 11,718 in 2002. The average price was $37.31 per bbl in the third quarter of 2002 as compared to $37.24 in the corresponding period of 2003. These prices are net of negative oil hedging adjustments of $0.28 per bbl in 2003 and $3.02 per bbl in 2002.

During the nine month period ended September 30, 2003, crude oil sales increased 27% to $128.3 million from $100.7 million in 2002. Oil production rose to 12,053 bbl/d for the period, compared to 10,847 bbl/d for the same period in 2002. The average price increased from $34.01 per bbl in 2002 to $39.00 per bbl in 2003.

Natural gas sales increased 78% to $44.8 million in the third quarter of 2003 from $25.2 million in the third quarter of 2002. Gas production increased 4% to 84.7 mmcf/d from 81.4 mmcf/d and the average gas price was up 71% to $5.75 per mcf from $3.36 per mcf. These prices are after a negative hedging adjustment of $0.04 per mcf in 2003, and a positive adjustment of 0.05 per mcf in 2002. The AECO monthly spot gas prices increased from $3.25 per mcf in the third quarter of 2002 to $6.29 per mcf in the third quarter of 2003.

During the nine month period ended September 30, 2003, natural gas sales increased 107% to $151.1 million from $72.9 million in 2002. Gas production was up 11% to 84.3 mmcf/d from 75.8 mmcf/d for the same period in 2002. The average gas price increased 86% to $6.56 per mcf in 2003 from $3.52 per mcf in 2002.

Sales of natural gas liquids increased 30% to $6.1 million in the third quarter of 2003, from $4.7 million in the third quarter of 2002. Production was up 33% to 2,160 bbl/d from 1,625 bbl/d. The average price was $30.86 per bbl in the third quarter of 2003, as compared to $31.51 in the same period in the prior year.

For the nine month period ended September 30, 2003, sales of natural gas liquids increased 53% from $12.7 million in 2002 to $19.4 million in 2003. Production volumes increased 16% from 1,762 bbl/d to 2,043 bbl/d, while the average price received rose from $26.42 per bbl to $34.73 per bbl in 2003.

ROYALTIES

Royalties (net of the Alberta Royalty Credit) were 22% of revenues in the third quarter of 2003, as compared to 20.4% in the third quarter of 2002. The percentage increase was mainly due to the significant increase in average gas prices, which were up 71%. The Crown royalty rate increases as gas prices increase.

Royalties for the nine month period averaged 22% of revenue in 2003 compared to 19% for the corresponding period in 2002 due to the higher gas prices.

FIELD OPERATING COSTS

Operating expenses were $24.5 million in the third quarter of 2003 compared to $18.6 million in the third quarter of 2002. Operating costs on a boe basis increased to $9.24 in 2003, compared to $7.52 for the same period in the prior year.

Operating costs for the nine month period ended September 30, 2003, were up 11% to $8.65 per boe as compared to an average of $7.76 in the prior year.

The most significant contributor to the increase in operating costs is the increased costs for workover activities. These activities include rate acceleration projects, well repair, facility turnarounds and other facility maintenance work. There are two components to the increasing costs. Firstly, costs in general have risen due to high industry activity levels. Secondly, more workover projects are undertaken for production enhancement because the return on these projects is very good in the current product price environment.

GENERAL AND ADMINISTRATIVE EXPENSES

General and administrative costs were $3.3 million in the third quarter of 2003, as compared to $4.0 million for the same period in 2002. Costs for the quarter were down significantly on a boe basis to $1.25 in 2003 from $1.63 in 2002.

Costs averaged $1.65 per boe in 2002 and decreased from $1.43 in the first quarter of 2003 to $1.27 in the second quarter and to $1.25 in the third quarter. The decreases reflect the consolidation of activities in Calgary, a decrease in quarterly payments due under the transitional services agreement with Sentry Select Capital Corp., and the increased production volumes.

No management fees were payable in the first nine months of 2003 and no future fees will be paid due to the internalization of management. Fees of $3.2 million were paid in the first nine months of 2002 to the Manager.

PRICE RISK MANAGEMENT

As at September 30, 2003, PC's hedge position was as follows:

Crude oil hedged volumes for the balance of 2003 increased to 4,337 bbl/d, up 337 bbl/d from 4,000 bbl/d at the end of the second quarter. Gas volumes under hedges for the rest of the year are down, decreasing from 35.7 mmcf/d, to 27.4 mmcf/d. The Trust has increased its hedged position for 2004 to 3,759 bbl/d of crude and 15.8 mmcf/d of natural gas.

The Trust's portfolio of crude hedges for the balance of 2003 consists of 2,337 bbl/d fixed at $38.71/bbl and 2000 bbl/d collared between $33.41/bbl-$38.71/bbl. The Trust's gas hedge portfolio for the balance of the year is comprised of 2.1 mmcf/d fixed at $5.75/mcf and 25.3 mmcf/d collared between $5.52/mcf and $9.42/mcf.

For 2004, Petrofund has collared 19 mmcf/d for the winter between $5.80/mcf-$10.92/mcf and 19 mmcf/d during the summer of 2004 (ending October 31, 2004) at between $5.12/mcf-$7.05/mcf. Petrofund's crude hedges for 2004 total 3,759 bbl/d collared between $32.49-$38.42/bbl. The Trust will lose its floor protection on 53% of the collared volume in the event WTI averages less than $28.52/bbl ($21.13 US); however, in this event, PC will still receive a premium of $4.05/bbl ($3.00 US) no matter how low WTI goes. All foreign exchange calculations in this section of the report incorporate the Bank of Canada US dollar rate at the close on September 30, 2003 ($1.3499 C$/US$).

For a complete listing of all hedge transaction details as at September 30, 2003 please see Note 7 to the Financial Statements.

Subsequent to the end of the quarter, Petrofund had increased its hedge position, fixing the price on an incremental 1,000 bbl/d for November 2003 and December, 2003 at $40.78 (30.21 US). PC also fixed 1,170 bbl/d for the first half of 2004 at an average of $38.35 ($28.41 US). PC collared an additional 1,000 bbl/d between $32.40 and $37.79 ($24-$28 US) for the fourth quarter of 2004. For 2005, Petrofund placed a three way WTI collar on 1,000 bbl/d, collaring the price between $32.39-$39.15 (if WTI averages less than $27.00 ($20 US) the Trust will lose the floor but will still receive a $5.40 premium ($4 US).

The Trust also fixed 4,737 mcf/d at $6.77/mcf at AECO for the November 2003-March 2004 period.

DEPLETION, RECLAMATION AND ABANDONMENT

The provision for depletion and reclamation costs increased to $28.9 million in the third quarter of 2003 from $26.8 million in the third quarter of 2002 due to the 7% increase in production and an increase in the depletion rate from $10.81 per boe in 2002 to $10.90 per boe in 2003.

The provision for depletion and reclamation costs for the nine months ended September 30, 2003, was $86.4 million, or $11.24 per boe as compared to $76.0 million or $11.03 per boe for 2002. The increase was mainly due to the downward revision to reserves at December 31, 2002. The cost of the proven reserves acquired during the first nine months of 2003 was in the $9.00 range, which offset part of the increase.

In the third quarter of 2003, PC set aside $198,000 in cash to fund future abandonment costs. PC has a cash abandonment reserve of $3.6 million at September 30, 2003. This cash fund is in place to fund significant future reclamation costs, such as the decommissioning of a major facility.

PC is committed to conducting its operations in a safe and environmentally responsible manner and has an established program in place to manage environmental liabilities. It continues to perform well reclamation and abandonments, flare pit remediation work etc. to proactively address environmental concerns. PC was very active in this area in the third quarter incurring $2.2 million of expenditures as compared to $336,000 in the first six months of the year. It is expected that this amount will decrease to about $500,000 in the fourth quarter. Expenditures for all of 2003 are expected to be $3.0 million which meets our original target. These amounts are deducted directly from distributions accruing to unitholders.

DEBT

As at September 30, 2003, the amount outstanding on the credit facility was $189 million with $76 million available to finance future activities.

The revolving period on the syndicated facility was scheduled to end on May 30, 2003; however, it has been extended for an additional 364-day period ending May 28, 2004. The borrowing base was increased to $265 million, in conjunction with the closing of the second quarter property acquisition.

WORKING CAPITAL

Accounts receivable decreased by $21.4 million as amounts due on the sale of properties as at December 31, 2002 were received in the first half of 2003.

Current liabilities increased by $34.9 million from December 31, 2002, due to the increase in distributions payable to unitholders and higher accrued liabilities due to an active third quarter drilling program.

LIQUIDITY AND CAPITAL RESOURCES

During the nine months ended September 30, 2003, the Trust incurred $160.6 million for capital expenditures. The expenditures were financed by the following:

-an equity issue which closed on May 22, 2003. A total of 9.2 million units were issued at $10.60 per unit for net proceeds of $92.3 million.
- proceeds of $15.8 million from 1.4 million options exercised and the total equivalent number of units issued.
- proceeds of $23.6 million received in the first half of 2003 on the disposition of properties.
- cash flow of $ 22.5 million withheld from distributions accruing to unitholders to fund capital programs.

In addition cash distributions accruing to unitholders exceeded distributions paid by $25.6 million and the bank loan was paid down by $22.8 million.

TAXABILITY OF DISTRIBUTIONS

The portion of distributions that will be taxable in 2003 depends on numerous factors that are not determinable at this time including cash flow for the fourth quarter, changes to tax pools, etc. Based on product price and other assumptions at this time, however, we expect the taxability portion to be in the 58% range.

Petrofund Energy Trust Consolidated Balance Sheet
(Unaudited)
As at September 30, 2003 and December 31, 2002		2003		2002
	(thousands of dollars)
Assets
Current assets
Cash	$	2,771	$	-
Accounts receivable		20,664		41,953
Due from affiliates		-		164
Prepaid expenses		10,096		10,090
Total current assets		33,531		52,207
Reclamation and abandonment reserve		3,577		3,001
Oil and gas royalty and property interests,
at cost less accumulated depletion and depreciation
of $436,616 (2002 - $354,309)		913,708		835,366
	$	950,816	$	890,574
Liabilities and unitholders' equity
Current liabilities
Bank overdraft	$	-	$	1,572
Accounts payable and accrued liabilities		37,614		22,007
Payable to affiliates		-		2,168
Current portion of capital lease obligations		710		3,304
Distributions payable to unitholders		55,647		30,065
Total current liabilities		93,971		59,116
Long-term debt		189,460		212,253
Capital lease obligations		6,700		6,965
Future income taxes		88,967		116,845
Accrued reclamation and abandonment costs		16,808		15,298
Total liabilities		395,906		410,477
Unitholders' equity		554,910		480,097
	$	950,816	$	890,574

Petrofund Energy Trust Consolidated Statement of Operations
(Unaudited)

		Three months ended				Nine months ended
		September 30,				September 30,
		2003		2002		2003		2002
		(thousands of dollars, except per unit amounts)
Revenues
Oil and gas sales	$	93,957	$	70,030	$	298,939	$	186,237
Royalties, net of incentives		(20,582)		(14,280)		(65,816)		(34,637)
		73,375		55,750		233,123		151,600
Expenses
Lease operating		24,482		18,621		66,474		53,493
Management fee (Note 4)		-		1,207		-		3,189
Interest and other financing costs		2,511		2,482		7,012		6,085
General and administrative		3,318		4,035		10,099		11,907
Capital taxes		675		277		1,870		932
Depletion and depreciation		27,567		25,159		82,307		71,607
Provision for reclamation and abandonment		1,324		1,601		4,045		4,427
Internalization of management contract (Note 4)		88		-		30,850		-
		59,965		53,382		202,657		151,640
Net income (loss) before provision for income taxes		13,410		2,368		30,466		(40)
Provision for (recovery of) income taxes
Current		231		188		794		275
Future		(1,755)		(7,409)		(32,554)		(19,342)
		(1,524)		(7,221)		(31,760)		(19,067)
Net income	$	14,934	$	9,589	$	62,226	$	19,027
Net income per trust unit
Basic	$	0.23	$	0.18	$	1.05	$	0.39
Diluted	$	0.23	$	0.18	$	1.05	$	0.39
The accompanying notes to consolidated financial statements are an integral part of these consolidated statements.

Petrofund Energy Trust Consolidated Statement of Unitholders' Equity
(Unaudited)
		Three months ended				Nine months ended
		September 30,				September 30,
		2003		2002		2003		2002
				(thousands of dollars)
Balance, beginning of period	$	558,826	$	519,326	$	480,097	$	398,702
Units issued, net of issue costs (Note 3)		12,440		37		109,273		154,694
Exchangeable shares issued (Note 5)		-		-		21,718		-
Redemption of exchangeable shares (Note 5)		(1,047)		-		(1,745)		-
Net income		14,934		9,589		62,226		19,027
Distributions accruing to unitholders (Note 6)		(30,243)		(21,629)		(116,659)		(65,100)
Balance, end of period	$	554,910	$	507,323	$	554,910	$	507,323

Petrofund Energy Trust Consolidated Statement of Cash Flows
(Unaudited)

		Three months ended			Nine months ended
		September 30,				September 30,
		2003		2002		2003		2002
				(thousands of dollars)
Cash provided by (used in) operating activities
Net income	$	14,934	$	9,589	$	62,226	$	19,027
Add items not affecting cash:
Depletion and depreciation		27,567		25,159		82,307		71,607
Provision for reclamation and abandonment		1,324		1,601		4,045		4,427
Future income taxes		(1,755)		(7,409)		(32,554)		(19,342)
Actual abandonment costs incurred		(2,199)		(693)		(2,535)		(1,661)
Internalization of management contract (Note 4)		88		-		30,850		-
Cash flow from operating activities		39,959		28,247		144,339		74,058
Net change in non-cash working capital balances		15,397		6,097		34,885		569
Cash provided by operating activities		55,356		34,344		179,224		74,627
Financing activities
Bank loan		29,909		5,782		(22,793)		54,508
Distributions paid		(34,650)		(22,721)		(91,077)		(60,880)
Redemption of exchangeable shares		(1,047)		-		(1,745)		-
Capital lease repayments		(971)		(7,432)		(2,859)		(10,387)
Issuance of trust units		12,439		37		108,151		56,054
Advances to affiliates, net		-		(3,416)		-		(38,445)
Cash provided by (used in) financing activities		5,680		(27,750)		(10,323)		850
Investing activities
Reclamation and abandonment reserve		(198)		(186)		(576)		(517)
Acquisition of property interests		(59,920)		(14,786)		(161,986)		(73,134)
Proceeds on disposition of property interests		5,397		3,004		6,013		6,132
Cash acquired on acquisition		-		-		-		427
Internalization of management contract (Note 4)		(88)		-		(8,009)		-
Cash used in investing activities		(54,809)		(11,968)		(164,558)		(67,092)
Net change in cash		6,227		(5,374)		4,343		8,385
Cash(bank overdraft), beginning of period		(3,456)		15,676		(1,572)		1,917
Cash, end of period	$	2,771	$	10,302	$	2,771	$	10,302
Interest paid during the period	$	2,585	$	2,604	$	7,020	$	5,949
Income taxes paid during the period	$	212	$	160	$	587	$	1,569

Notes to Interim Consolidated Financial Statements
(unaudited)
(thousands of dollars except per unit amounts unless otherwise stated)

1. INTERIM FINANCIAL STATEMENTS

These unaudited interim consolidated financial statements follow the same accounting policies and methods of their application as the most recent annual financial statements. The note disclosure requirements for annual statements provide additional disclosures to that required for interim statements. Accordingly, these statements should be read in conjunction with the audited consolidated financial statements of NCE Petrofund (the "Trust") as at December 31, 2002 and 2001 and for each of the years in the three-year period ended December 31, 2002.

On November 1, 2003 the name of the Trust was changed to Petrofund Energy Trust. On the same date the name of the Trust's 100% owned subsidiary was changed to Petrofund Corp. ("PC") from NCE Petrofund Corp. ("NCEP").

2. ACQUISITION

On February 7, 2003, PC acquired 100% of the outstanding common shares of Solaris Oil & Gas Inc. for $7.4 million in cash and assumed $1.2 million of debt including negative working capital and outstanding bank loan. The acquisition was accounted for using the purchase method. A summary of the net assets acquired is as follows:

Working capital	$	(813)
Oil and gas properties		13,219
Bank loan		(370)
Future income taxes		(4,676)
	$	7,360

3. TRUST UNITS

Authorized: unlimited number of trust units

	Number
	of units		Amount
Issued
December 31, 2002	54,107,764	$	794,352
Issued for cash	9,200,000		97,520
Issued for internalization of management contract	100,244		1,123
Commissions and issue costs	-		(5,268)
Options exercised	1,363,071		15,831
Unit purchase plan	5,341		68
September 30, 2003	64,776,420	$	903,626

The weighted average trust units/exchangeable shares outstanding are as follows:

	Three months		Nine months
	ended September 30,		ended September 30,
	2003	2002	2003	2002
Basic	66,142,502	54,099,739	59,364,939	48,512,318
Diluted	66,280,745	54,198,724	59,491,134	48,545,676

Trust units/exchangeable shares, at end of period:	As at September 30,
	2003	2002
Trust units outstanding	64,776,420	54,101,518
Trust units issuable on exchangeable shares (Note 5)	1,939,147	-
	66,715,567	54,101,518

4. INTERNALIZATION OF MANAGEMENT

On April 29, 2003, PC purchased 100% of NCE Petrofund Management Corp. (the "Manager"), the manager of the Trust and NCE Management Services Inc., which employed all of the Calgary based personnel who provide services to the Trust. As a result of these transactions, all management acquisition and disposition fees payable to the Manager were eliminated retroactive to January 1, 2003. In addition, all of the Trust's operations are now consolidated in PC's Calgary offices.

The total consideration paid was $30.8 million as detailed below.

Total Consideration	$ 000's
Issuance of 1,939,147 exchangeable shares to the shareholder of the Manager	$ 21,718
Cash payment to Trust the repayment of indebtedness owing by the Manager	3,400
Issuance of 100,244 units to executive management	1,123
Cash payment to executive management	780
Cash payment for distributions on exchangeable shares and trust units from January 1
to April 30, 2003	1,326
Transaction costs	2,503
Total Purchase Price	$ 30,850

To ensure an orderly transition of the services that were provided by the Manager through its offices in Toronto, PC entered into an agreement with Sentry Select Capital Corp. ("Sentry") to provide certain services to the Trust and PC until December 31, 2003 for a maximum cost of $2 million. The amount incurred decreased from $1 million in the first quarter to $500,000 in the second quarter and to $250,000 in the third quarter. A further $250,000 will be paid in the fourth quarter, after which Sentry will no longer provide such services. Sentry is a company in which John Driscoll, the Chairman of the Board of Directors of PC, owns a controlling interest.

Prior to the acquisition, the Manager was paid a management fee equal to 3.25% of net operating income plus Alberta Royalty Credit, an investment fee equal to 1.50% of the purchase price of all properties purchased by PC and a disposition fee of 1.25% of properties sold, except replacement properties.

5. EXCHANGEABLE SHARES

The number of exchangeable shares to be issued in connection with the internalization of the management contract was determined based on a negotiated value of $12.17 per share as set out in the Information Circular dated March 10, 2003. For accounting purposes, the 1,939,147 exchangeable shares were deemed to be issued at a value of $11.20 per share, being the average trading value of the trust units for the last ten days prior to the closing date. Initially, each Exchangeable Share was exchangeable into one Trust Unit. The exchange ratio is adjusted from time to time to reflect the per unit distributions paid to unitholders after the closing date. Under the terms of the Exchangeable Share Agreement, the holder of the Exchangeable Shares is entitled to redeem for cash the number of shares equal to the cash distributions that would have been received had the Exchangeable Shares been converted to trust units. As a result of the redemption feature, the number of trust units issuable upon conversion is expected to remain constant over time. As the substance of this feature is to allow the holder of the Exchangeable Shares to receive cash distributions, the redemption has been accounted for as a distribution of earnings rather than a return of capital. At September 30, 2003, 1,814,303 Exchangeable Shares were outstanding, at an exchange ratio of 1.06881 per Trust Unit.

Issued and Outstanding	Number of Shares	$ 000's
Issued for internalization of Management Contract	1,939,147	$21,718
Redemption of Shares	(124,844)	-
Balance, September 30, 2003	1,814,303	21,718
Exchange ratio, end of period	1.06881	-
Trust Units issuable upon conversion	1,939,147	$21,718

6. DISTRIBUTIONS ACCRUING TO UNITHOLDERS

Under the terms of the Trust Indenture, the Trust makes monthly distributions on the last business day 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 receipts of royalty income, other income and other cash receipts from PC. An overall analysis is as follows:

For the period ended	Cash Distribution Date		2003		2002
November 30	January 31	$	0.15	$	0.15
December 31	February 28		0.16		0.15
January 31	March 31		0.17		0.13
February 28	April 30		0.17		0.13
March 31	May 31		0.18		0.14
April 30	September 30		0.18		0.14
May 31	July 31		0.18		0.14
June 30	August 31		0.18		0.14
July 31	September 30		0.18		0.14
Cash distributions paid per Trust unit		$	1.55	$	1.26

Reconciliation of Distributions Accruing to Unitholders

		Three months				Nine months
		ended September 30				ended September 30
		2003		2002		2003		2002
Distributions payable, beginning of period	$	60,054	$	23,151	$	30,065	$ 12,188
Distributions accruing during the period
Cash flow from operating activities		39,959		28,247		144,339		74,058
Redemption of exchangeable shares		(1,047)		-		(1,745)		-
Proceeds on disposition of property interests		-		-		-		946
Reclamation and abandonment reserve		(198)		(186)		(576)		(517)
Capital lease payments (2)		(971)		(1,432)		(2,859)		(4,387)
Capital expenditures		(7,500)		(5,000)		(22,500)		(5,000)
Total distributions accruing during the period		30,243		21,629		116,659		65,100
NCE Energy Trust cash flow (1)		-		-		-		5,651
Total distributable income for the period		30,243		21,629		116,659		70,751
Distributions paid		(34,650)		(22,721)		(91,077)		(60,880)
Distributions payable, end of period	$	55,647	$ 22,059		$	55,647	$	22,059
Distributions accruing to unitholder per Trust unit
Basic	$	0.46	$	0.40	$	1.97	$	1.46
Diluted	$	0.46	$	0.40	$	1.96	$	1.46

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

(2) For the three and nine months ended September 30, 2002, $6 million of lease payments paid on the buyout of tangible assets was financed by the bank loan.

7. DERIVATIVE FINANCIAL INSTRUMENTS AND PHYSICAL CONTRACTS

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 and physical contracts as at September 30, 2003, and the related unrealized gains or losses, are summarized below:

		Volume	Price		Unrealized Gain
Natural Gas	Term	mcf/d	$/mcf	Delivery Point		(Loss)
Fixed	March 1, 2003 to	6,159	$5.75	AECO		$ -
	October 31, 2003
Collar	April 1, 2003 to	9,475	$4.64-$6.23	AECO		-
	October 31, 2003
Collar	April 1, 2003 to	4,737	$4.64-$6.23	AECO		-
	October 31, 2003
Collar	April 1, 2003 to	4,737	$4.64-$6.24	AECO		-
	October 31, 2003
Collar	April 1, 2003 to	14,212	$5.86-$9.60	AECO		-
	October 31, 2003
Collar	April 1, 2003 to	4,737	$5.86-$9.82	AECO		-
	October 31, 2003
Collar	November 1, 2003	9,475	$5.80-$10.87	AECO		662
	to March 31, 2004
Collar	November 1, 2003	9,475	$5.80-$10.98	AECO		258
	to March 31, 2004
Collar	April 1, 2004	9,475	$5.17-$7.28	AECO		690
	to October 31, 2004
Collar	April 1, 2004	9,475	$5.07-$6.81	AECO		374
	to October 31, 2004
Total					$	1,984
		Volume	Price		Unrealized Gain
Oil	Term	bbl/d	$/bbl	Delivery Point	(Loss)
Fixed Price	July 1, 2003 to	2,000	$38.10	Edmonton	$	(131)
	December 31, 2003
Fixed Price	October, 2003	1,000	$42.24	Edmonton		91
Three Way Collar	July 1, 2003 to	2,000	*(1)	Edmonton		(47)
	December 31, 2003
Collar	January 1, 2003 to	2,000	$32.40-$37.46	Edmonton		(290)
	March 31, 2004
Three Way Collar	January 1, 2004 to	2,000	*(2)	Edmonton		(366)
	June 30, 2004
Collar	April 1, 2004 to	2,000	$32.40-$38.07	Edmonton		(104)
	June 1, 2004
Three Way Collar	July 1, 2004 to	2,000	*(3)	Edmonton		(184)
	December 31, 2004
Collar	July 1, 2004 to	2,000	$32.40-$37.80	Edmonton		(4)
	September 30, 2004
Collar	October 1, 2004 to	1,000	$32.40-$37.80	Edmonton		(10)
	December 31, 2004
Total					$	(1,045)

*(1) At Prices above $41.51, Petrofund receives $41.51/bbl.
        At Prices between $33.41 and $41.51/bbl Petrofund receives the market price.
        At Prices below $28.01, Petrofund receives a premium of $5.40/bbl.

*(2) At Prices above $38.81, Petrofund receives $38.81/bbl.
        At Prices between $32.40 and $38.81/bbl Petrofund receives the market price.
        At Prices below $28.35, Petrofund receives a premium of $4.05/bbl.

*(3) At Prices above $39.15, Petrofund receives $39.15/bbl.
        At Prices between $32.75 and $39.15/bbl Petrofund receives the market price.
        At Prices below $28.70, Petrofund receives a premium of $4.05/bbl.

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 hedge contracts involve a degree of credit risk, which the Trust controls through the use of financially sound counter parties. 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.

8. BANK LOAN

The revolving period on the syndicated facility was scheduled to expire on May 30, 2003, however, it has been extended for an additional 364-day period ending May 28, 2004. In addition, the borrowing base on the facility was increased to $265 million from $250 million in conjunction with the closing of a second quarter property acquisition.

9. FUTURE INCOME TAXES

The future income tax recovery for the nine months ended September 30, 2003, has been increased by $29.3 million due to the substantively enacted reduction in federal and Alberta income tax rates. The changes, to be phased in over five years, reduce the applicable rate on resource income from 28% to 21%.

Canadian Ownership

As at October 31, 2003, based on the information provided by our transfer agent, Petrofund estimates that non-resident ownership of the trust was approximately 55%.

Petrofund Energy Trust is a Calgary based royalty trust that acquires and manages producing oil and gas properties in Western Canada. The Trust makes monthly cash distributions to unitholders which are derived from the Trust's cash flow from these properties. Petrofund Energy Trust was founded in 1988 and was one of the first oil and gas royalty trusts in Canada.

This news release may include statements about expected future events and/or financial results that are forward-looking in nature and subject to risks and uncertainties. For those statements, we claim the protection of the safe harbor for forward-looking statements provisions contained in the U.S. Private Securities Litigation Reform Act of 1995. Petrofund Energy Trust cautions that actual performance will be affected by a number of factors, many of which are beyond its control. Future events and results may vary substantially from what Petrofund Energy Trust currently foresees. Discussion of the various factors that may affect future results is contained in Petrofund Energy Trust's recent filings with the Securities and Exchange Commission and Canadian securities regulatory authorities.

PETROFUND ENERGY TRUST

Jeffery E. Errico
President and Chief Executive Officer

For Petrofund Investor Relations:

Phone: (403) 218-4736
Fax: (403) 539-4300
Toll Free: 1-866-318-1767
E-mail: info@petrofund.ca
Website: www.petrofund.ca

For information regarding this press release:

Chris Dutcher
Director, Business Development
Phone: (403) 218-8625

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