For the month of: November 2004
Commission File Number: 00-115124

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

Form 20-F _____         Form 40-F     X    

Indicate by 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:

Yes ______         No     X    

If "Yes" is marked, indicate below the file number assigned to the registrant in connection with Rule 12g3-2(b): N/A

    Pursuant to the requirements of the Securities Exchange Act of 1934, the Registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized.

Petrofund Energy Trust is pleased to provide its results for the third quarter of 2004. Key items from the quarter include:

• Cash flow of $65 million, up 63% over the third quarter last year, due primarily to additional production from the Ultima acquisition and higher commodity prices.
• Average production of 34,950 boe per day, a 21% increase over Q3 of 2003.
• A third quarter payout ratio of 75%, and a 76% payout ratio for the 9 month period.
• Operating costs of $9.62 per boe, up 4% over last year.
• Third quarter general and administrative costs down 6% from last year to $1.17 per boe.
• A 0.8 debt to cash flow ratio.

Petrofund's third quarter report is presented below:

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, 2004 and the December 31, 2003 annual financial statements and management's discussion and analysis included in the Petrofund Energy Trust ("Petrofund" or the "Trust") 2003 annual report.

The discussion and analysis included in this section is based on information available to October 31, 2004.

All amounts are stated in Canadian dollars unless otherwise noted. Where amounts and volumes are expressed on a barrel of oil equivalent ("boe") basis, natural gas volumes have been converted to barrels of oil at 6 mcf/bbl. A boe may be misleading, particularly if used in isolation. A boe conversion of 6 mcf/bbl is based on an energy equivalency conversion method primarily applicable at the burner tip and does not represent a value equivalency at the wellhead.

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 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.

Cash flow available for distribution is dependent on numerous factors including fluctuations in oil and natural gas prices; changes in the Canadian/U. S. dollar exchange rate; the size of the development drilling program including the portion funded from cash flow; and the level of debt within Petrofund Corp.("PC"), etc. A reconciliation of cash flow provided by operating activities on the Consolidated Statement of Cash Flows to cash flow available for distribution is included in Note 7 of the Notes to the Interim Consolidated Financial 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.

The results for the third quarter were impacted by a significant increase in production and a further increase in product prices. Production increased 6,149 boe/d from the third quarter of 2003 mainly due to the acquisition of Ultima Energy Trust on June 16, 2004. The increase from Ultima was offset by normal production declines and a disposition of properties effective December 31, 2003 which reduced volumes by approximately 1,500 boe/d. Average prices on a boe basis were up $1.58 from the second quarter of 2004 and up $9.67 from the same period in 2003. Due to this increase in volumes and prices, revenue was up 31% from the second quarter of 2004 and up 54% for three months ended September 30, 2004 from the same period in 2003. The increased revenue was partially offset by losses on hedging contracts mainly due to the strong oil prices. The cash loss on hedging contracts during the third quarter was $14.6 million. An additional non-cash loss of $15.3 million is recorded on the income statement reflecting the change in the fair value of the commodity contracts during the period.

Royalties were 19% of revenue, a reduction of 2% from the same period in 2003, and operating costs increased by $0.38 per boe. General and administrative costs were $ 1.17 per boe, a decrease of $0.08 per boe from 2003.

Net income for the three months ended September 30, 2004 was $15.1 million, the same as the corresponding amount in the prior year. Net income for the three months in 2004 was reduced by $15.3 million for the unrealized loss on commodity contracts (excluding the future income tax impact) versus nil in 2003 as a result of the adoption of the new policy on hedging relationships effective January 1, 2004 and net income was increased by $4.6 million due to a higher future income tax recovery.

Net income before income taxes for the nine months ended September 30, 2004 was $30.3 million as compared to $31.3 million for the same period in the prior year. Net income for 2004 was impacted by a non-cash loss of $32.6 million on commodity contracts and 2003 net income was reduced by $30.9 million for the cost of the internalization of the management contract.

Net income decreased $39.4 million in the nine months ended September 30, 2004 from 2003 due to a change in future income taxes of $38.9 million. A recovery of $32.6 million was recorded in 2003 reflecting income tax rate reductions enacted in that year, versus a future tax provision of $6.4 million recorded in 2004.

On June 16, 2004 Petrofund acquired all the assets and assumed all liabilities of Ultima Energy Trust ("Ultima"). This report reflects the results of operations from Ultima's properties beginning June 17, 2004.

Petrofund acquired Ultima for an aggregate cost of $567.4 million consisting of 26.4 million Petrofund Trust units valued at $17.12 per unit, the assumption of debt and negative working capital of $119.7 million and transaction costs incurred of $1.9 million.

Despite being hampered by wet weather throughout much of the quarter, a total of 51 gross wells (11.6 net) and six farmout wells were drilled on Company lands during the quarter. This drilling resulted in 33 oil wells, 22 gas wells, one miscible injector and one dry hole for an overall 98% success rate for the quarter. Year to date, a total of 129 gross wells (28.0 net) and 24 farmout wells were drilled on Company lands, resulting in 75 oil wells and 71 gas wells for a 95% success rate.

In addition, the Trust also continued to optimize its base production during the quarter through a series of well workovers, well recompletions, production equipment upgrades and facility additions.

Fifteen wells (3.3 net) were drilled at Petrofund's Westerose, Pembina, Brazeau, Minehead, Swan Hills and Red Earth properties, resulting in ten oil wells and 5 gas wells. Most notably, Petrofund as operator drilled a 90% working interest horizontal Banff oil well at Cherhill that is now producing 200 boe/d net. At Minehead, Petrofund participated in drilling three high working interest Cardium gas wells which are scheduled to come on-stream early next quarter, netting the Company an incremental 1.75 mmcf/d of gas. At Brazeau, Petrofund participated in the drilling of an infill Rock Creek gas well that flow tested 1.0 mmcf/d gross. At Spirit River, Petrofund as operator recompleted an existing well for Charlie Lake gas that is now producing 750 mcf/d net to Petrofund.

Twenty six wells (3.8 net) were drilled at Bodo, Consort, Stanmore, Eyehill, Three Hills Creek and Medicine River, yielding 11 oil wells, 14 gas wells & one dry hole. Petrofund directed considerable attention towards the continued development of its Three Hills Creek gas property through its participation in the drilling of six coalbed methane gas wells along with the construction of an associated gathering and processing facility. These Three Hills Creek wells, along with others drilled earlier this year, are expected to net Petrofund an incremental 1.5 mmcf/d by mid next quarter. In addition, the Company realized a 900 mcf/d net production gain by bringing four previously drilled Edmonton Sand gas wells on-stream during the quarter.

At Ferrier, Petrofund as operator successfully recompleted two existing wells for Ellerlsie gas. These wells are expected to produce 600 mcf/d net next quarter once necessary facility additions are constructed.

A total of fifteen oil wells (4.5 net) were successfully drilled on Petrofund's lands at Silverton, Queensdale, Midale and Weyburn. At Silverton, Petrofund drilled a 100% working interest Frobisher oil well that is scheduled to come on-stream early next quarter at 150 boe/d.

CHANGES IN ACCOUNTING POLICIES

The Trust adopted the new Canadian accounting standard for accounting for asset retirement obligations ("ARO") effective January 1, 2004, as required by Canadian generally accepted accounting standards. The standard requires liability recognition for retirement obligations associated with our property, plant and equipment. The obligations are initially measured at fair value, which is the discounted future value of the liability. The fair value is capitalized as part of the cost of the related assets and amortized to expense over their useful lives. The liability accretes until the retirement obligations are settled. Previously reclamation and abandonment liabilities were calculated and recorded on a unit of production basis. The change is discussed in detail in Note 2(a) to the Notes to the Interim Consolidated Financial Statements.

As a result of adopting this standard, previously reported amounts for 2003 have been restated. Net property, plant and equipment on the Consolidated Balance Sheet as at December 31, 2003, increased by $18.6 million, future income taxes increased by $2.1 million and asset retirement obligations increased by $17.5 million with an offset of $1.0 million to Unitholders' Equity. Net income for the three and nine months ended September 30, 2003 increased by $170,000 and $785,000, respectively. Opening 2003 accumulated earnings decreased by $2.4 million ($700,000 after tax) to reflect the cumulative impact of accretion and depletion expense, less the previously recorded cumulative site restoration provision.

Net income before tax for the three and nine months ended September 30, 2004, increased by $1.1 million ($657,000 after tax) and $3.0 million ($1.8 million after tax) respectively, which reflects the impact of accretion and depletion expense.

There was no impact on the Trust's cash flow as a result of adopting this new policy. See Notes 2(a) and 8 for additional information on the future liability and the impact on the financial statements.

Effective January 1, 2004, Petrofund adopted the new Canadian Accounting Guideline 13 ("AcG-13") pertaining to hedging relationships. AcG-13 established certain conditions for applying hedge accounting. If hedge accounting is not applied, the fair values of derivative financial instruments are recorded as an asset or a liability on the balance sheet. Petrofund enters into numerous derivative financial instruments to reduce price volatility and establish minimum prices for a portion of its oil and natural gas production. These contracts are effective economic hedges,

All outstanding derivative instruments as at January 1, 2004 have been recorded as assets or liabilities, as appropriate, at fair value. The net negative fair value of the contracts at January 1, 2004 of $6.8 million plus costs incurred on the acquisition of the derivative instruments in the amount of $0.8 million are being amortized to expense over the remaining term of the contracts. The total amount of $7.6 million plus $1.4 million relating to Ultima, less $6.9 million amortized to expense in the nine months ended September 30, 2004, has been recorded as a current asset or liability, as appropriate, on the balance sheet at September 30, 2004 as "deferred loss/gain on commodity contracts".

The amortized portion of the fair value of the contracts at January 1, 2004 and the net change in fair value of all such instruments from January 1 to September 30, 2004 in the amount of $32.6 million are recorded in the income statement on a separate line as "gain/loss on commodity contracts". This is an increase of $15.3 million in the third quarter. This line item also includes realized losses on commodity contracts, of $14.6 million in the third quarter of 2004 and $28.3 million for the nine month period which were previously deducted from oil and natural gas sales. The comparative numbers for 2003 represent realized losses on commodity contracts which were netted against sales.

This policy is discussed in detail in Note 2(b) to the Notes to the Interim Consolidated Financial Statements.

CICA Handbook Section 1100, "Generally Accepted Accounting Principles", is effective for fiscal years beginning on or after October 1, 2003. This standard focuses on what constitutes Canadian generally accepted accounting principles and its sources, including the primary sources of generally accepted accounting principles. In prior years, it had been industry practice to record revenue net of related transportation costs. In accordance with the new accounting standards, revenue is now reported before transportation costs with separate disclosure in the consolidated statement of operations of transportation costs. Petroleum and natural gas sales and transportation costs both increased $1.8 million in the third quarter of 2004 and $4.3 million for the nine months ended September 30, 2004. The comparative numbers for 2003 were $1.4 million and $4.1 million, respectively.

This change in classification has no impact on cash flow or net income.

Product prices, unless otherwise noted, reflect actual prices received, excluding hedging and transportation costs. Prices for prior periods have been restated where applicable.

Petrofund unitholders who held their units throughout the third quarter of 2004 received distributions of $0.48 in cash as compared to $0.54 in the third quarter of 2003. A cash distribution of $0.16 per unit was paid in October and $0.16 per unit has been announced for November and indicated for December.

The Trust generated cash flow available for distribution in the third quarter of $63.8 million before deducting $15.0 million for reinvestment in capital projects. Distributions of $47.7 million were paid out in the quarter representing a payout ratio of 75% (see Note 7).

For the 12 months ended September 30, 2004, the Trust generated cash flow available for distribution of $201.9 million, allocated $72.4 million for reinvestment in development drilling and other projects, and the deferred capital obligation and paid out distributions of $158.0 million, resulting in a payout ratio of 78%.

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.

Revenue and Production

Revenues increased 54% to $147.5 million in the third quarter of 2004 from $96.0 million in the third quarter of 2003. Production was up 21%, and prices were up 27% on a boe basis.

For the nine month period ended September 30, 2004, revenue increased 16% to $360.2 million from $310.6 million in 2003 due to a 7% increase in production to 29,886 boe/d and a 9% increase in the average price per boe to $43.97 in 2004 from $40.39 in 2003.

Crude oil sales increased 92% to $83.7 million in the third quarter of 2004 from $43.5 million in the third quarter of 2003. Oil production volumes increased 40% to 17,504 bbl/d as compared to 12,518 in the third quarter of 2003. The average price was up 38% to $52.02/bbl from $37.80/bbl. The WTI benchmark price increased 45% during the same period; however, the appreciation of the Canadian dollar offset part of the WTI increase.

During the nine month period ended September 30, 2004, crude oil sales increased 38% to $182.8 million from $132.7 million in 2003. Oil production increased 16% to 13,934 bbl/d for the period as compared to 12,053 bbl/d for the same period in 2003. The average price increased from $40.33/bbl in 2003 to $47.88/bbl in 2004.

Natural gas sales increased 17% from $46.1 million in the third quarter of 2003 to $53.9 million in the third quarter of 2004. Natural gas production was up 6% from 84.7 mmcf/d to 90.1 mmcf/d, and the average natural gas price was up 10% to $6.50/mcf from $5.92/mcf. Also, AECO monthly natural gas prices increased 10% in the third quarter of 2004 over the third quarter of 2003.

Sales of natural gas liquids increased 55% to $9.9 million in the third quarter of 2004, from $6.4 million in the third quarter of 2003. Production was up 12% to 2,427 bbl/d from 2,160 bbl/d; and the average price was up 40% to $43.68/bbl from $31.23/bbl.

For the nine month period ended September 30, 2004, sales of natural gas liquids increased 20% to $23.8 million in 2004 from $19.8 million in 2003. Production volumes increased 7% from 2,043 bbl/d to 2,181 bbl/d and the average price increased 13% from $35.12/bbl in 2003 to $39.55/bbl in 2004.

The Trust has implemented a formal risk management policy which provides the Risk Management Committee with the ability to use specified price risk management strategies for its crude, natural gas and NGL production including: fixed price contracts; costless collars; the purchase of floor price options; and other derivative financial instruments to reduce price volatility and ensure minimum prices to a maximum of 40% of its annual production for up to eighteen months beyond the current date.

As at September 30th, 2004 Petrofund has hedged 31.3 mmcf/d of gas and 7,500 bbl/d of crude for the remainder of 2004. Crude oil hedges for 2004 were unchanged over the quarter while natural gas hedges decreased by 2.8 mmcf/d as contracts expired. The Trust's 2004 gas hedges include: 26.5 mmcf/d collared between $5.81/mcf-$10.23/mcf and 4.8 mmcf/d fixed at $6.15/mcf. The Trust will lose its floor protection on about 24% of the collared volumes if AECO drops below $4.74/mcf but will receive a premium of $1.06/mcf in this event. At the end of the quarter, Petrofund's 2004 crude hedges include 2,000 bbl/d fixed at $35.64/bbl and 5,500 bbl/d collared between $30.56/bbl-$35.99/bbl. The Trust will lose its floor protection on 64% of the collared volume in the event WTI averages less than $26.43/bbl. Under these transactions Petrofund will receive a premium of $4.33/bbl if WTI remains below the $26.43/bbl level.

For the first quarter of 2005, the Trust has 28.4 mmcf/d of gas collared between $6.09/mcf-$11.49/mcf. The Trust will lose its floor protection on 33% of this volume should AECO average less than $4.74/mcf. The Trust collared the price at AECO on an additional 4.75 mmcf/d for the summer of 2005 between $6.33/mcf-$8.44/mcf. No gas has been hedged beyond October 31, 2005. Over the quarter Petrofund collared an additional 1,000 bbl/d for the first half of 2005 between $49.83/bbl and $62.45/bbl increasing hedge levels for the first half to 4,000 bbl/d (3,500 bbl/d annualized). The trust has no oil fixed in 2005, as 100% of the hedges are WTI collars ranging between $35.08/bbl-$43.37/bbl. The trust will lose its floor protection on 93% of the collared volume if WTI averages less than $29.24/bbl. Under these transactions Petrofund will receive a premium of $4.76/bbl if WTI remains below the $29.24/bbl level.

Petrofund has contracted to control a portion of its Alberta power costs by fixing the price on three (3) Megawatts/hour (MW/h) of its Alberta consumption at $46.65/MWh for 2004. In 2005, the Trust has two (2) Megawatts/hour (MW/h) fixed at $44.50/MWh.

All foreign exchange calculations in this section of the report incorporate the Bank of Canada US dollar rate closing on September 30, 2004 ($1.2616 C$:US$). For a complete listing of all hedge transaction details please see Note 10 to the Interim Consolidated Financial Statements.

If oil and natural gas prices received by the Trust were adjusted for realized gains/(losses) in accordance with the 2003 presentation, the prices would have decreased as follows:

The realized gain/(losses) on derivative instruments and the change in their fair value is dependent on future product prices, the volumes hedged, the exchange rate and the term of the contracts. As there has been significant variation in all these factors, which is unlikely to change, we can expect to see high volatility in these amounts and the changes could be significant.

ROYALTIES

Royalties, net of the Alberta Royalty Credit, were 19% of revenues for the three and nine months ending September 30, 2004, as compared to 21% for the same periods in the prior year. The decrease in mainly due to the increase in the relative percentage of oil production which has a lower royalty rate than gas.

Operating expenses, net of processing income, were $30.9 million in the third quarter of 2004 as compared to $24.5 million in the third quarter of 2003. Operating costs on a boe basis increased 4% to $9.62 in 2004, as compared to $9.24 for the same period in 2003. For the nine month period ended September 30, 2004, operating costs were up 6% to $9.08 per boe as from $8.65 in the prior year.

Fixed costs, including lease rentals, property taxes, cost of field services and employees continue to increase. Repair and maintenance and workover expenditures are generally higher in the third quarter of the year.

Transportation costs which range from $0.52 per boe to $0.55 per boe were previously deducted from sales revenue. Due to the changes in the accounting policy, sales revenues have been increased by this amount and the costs disclosed as a separate item.

GENERAL AND ADMINISTRATIVE EXPENSES

General and administrative costs were $3.8 million in the third quarter of 2004 compared to $3.3 million in the third quarter of 2003. Costs were down 6% on a boe basis to $1.17 as compared to $1.25 in 2003 due to increased production. General and administrative costs for the third quarter include $251,000 with respect to the proposed reclassification of units and for activities undertaken to meet the requirements of Section 302 and Section 404 of the Sarbanes Oxley Act.

General and administrative costs for the nine month period ended September 30, 2004, were $10.2 million in 2004 compared to $10.1 million in 2003. Costs, on a per boe basis, were down 5% to $1.25 per boe compared to $1.31 per boe in 2003. Management was successful in maintaining its general and administrative costs at approximately the same level as the prior year while at the same time increasing production by 7%.

Interest expense decreased to $1.7 million in the third quarter of 2004 from $2.5 million for the same period as 2003 and to $3.8 million for the nine month period ended September 30, 2004, from $7.0 million in 2003. The decreases reflect lower average loan balances outstanding and a decrease in the average prime rate.

The provision for depletion, depreciation and accretion increased from $28.6 million in the third quarter of 2003 to $42.0 million in the third quarter of 2004 due to the increase in the depletion rate from $10.81/boe in 2003 to $13.06/boe in 2004. The increase in the depletion rate is due to the increased acquisition costs of properties and the negative adjustments to reserves at December 31, 2003.

The provision for depletion, depreciation and accretion for the nine months ended in September 30, 2004, was $104.6 million or $12.78 per boe as compared to $85.6 million or $11.13 per boe for 2003.

GOODWILL

CAPITAL EXPENDITURES

The oil hedges are transacted in U.S. dollars. They have been converted to Canadian dollars at the September 30, 2004 closing rate of $1.2616 C$:US$.

Derivative financial instruments and physical hedge 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 product sales.

On October 13, 2004, Petrofund announced that it is holding a special meeting of unitholders to consider, and if thought fit, approve amendments to its trust indenture that would provide for a reclassification of its trust unit capital (the "Reclassification"). Under the Reclassification, existing units of the Trust will be reclassified into Class R Units, which can only be held by Canadian residents, and Class N Units, which will contain no residency restrictions. Unitholders will also be asked to consider other amendments to Petrofund's trust indenture at the special meeting

The Reclassification is aimed at enhancing the Trust's ability to regulate non-resident ownership of units to ensure the Trust continues to qualify as a mutual fund trust under the Income Tax Act (Canada) (the "Tax Act"), while maintaining active markets for the units and the ability to raise capital in Canada and the United States.

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 that 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.

In regards to barrels of oil equivalent (boe), boes may be misleading, particularly if used in isolation. A BOE conversion of 6 mcf:1 bbl is based on an energy equivalency conversion method primarily applicable at the burner tip and does not represent a value equivalency at the wellhead.

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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