For the month of: May 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 first quarter of 2004. Key items from the quarter include:

The following discussion and analysis of financial results should be read in conjunction with the unaudited consolidated financial statements for the three months ended March 31, 2004 included herein 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 analyses included in the section is based on information available to April 30, 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 6,000 mcf/bbl. A boe 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.

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 PC, etc. A reconciliation of cash flow provided by operating activities on the Consolidated Statement of Cash Flows to the cash flow available for distribution is included in Note 6 to the Notes to 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. These include general economic conditions in Canada and the United States; industry conditions including changes in laws and regulations; changes in income tax regulations; increased competition; and fluctuations in commodity prices, foreign exchange and interest rates. In addition, there are numerous risks and uncertainties associated with oil and natural gas operations and the evaluation of oil and natural gas reserves as discussed in detail in Petrofund's Annual Information Form. As a result, future events and results may vary substantially from what Petrofund currently foresees.

On March 29, 2004, Petrofund announced that it had entered into an agreement providing for the combination of Petrofund and Ultima Energy Trust ("Ultima"). The transaction is subject to approval of the unitholders of Ultima at a meeting to be held on June 4, 2004 and regulatory approval.

Under the terms of the agreement, each Ultima unit will be exchanged for 0.442 of a Petrofund unit on a tax-deferred rollover basis and Petrofund will acquire all the assets and assume all of the liabilities of Ultima. Ultima unitholders will also receive an aggregate $10 million in the form of a one-time special distribution (approximately $0.17 per Ultima unit), payable prior to closing of the transaction. It is expected that approximately 26.4 million Petrofund Trust units will be issued to the Ultima Unitholders on closing.

Ultima has a diversified group of assets with a reserve life index over 10 years. Ultima had a production base of approximately 10,000 boe/d at December 31, 2003. The combined production of Petrofund and Ultima is expected to exceed 36,000 boe/d of which approximately 58% will be oil and natural gas liquids. Ultimas proved plus probable reserves were estimated at 41.4 mmboe as stated in their December 31, 2003 independent engineering report.

The transaction is expected to be accretive to cash flow, production and reserves per unit and result in lower per unit general and administrative costs; however, we do not expect the acquisition to affect the level of Petrofund's cash distributions. The increased size of Petrofund should provide it with a more competitive cost of capital and improve Petrofund's financing ability as well as its ability to compete for larger acquisitions.

As the consideration for Ultima is primarily Petrofund Trust units, the cash costs of the transaction will be financed using Petrofund's existing credit line.

Northeast British Columbia

Northern Alberta

Central Alberta

Southeast Saskatchewan

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 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. Income for the three months ended March 31, 2003 increased by $435,000 ($265,000 after tax). 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.

Income for three months ended March 31, 2004, increased by $860,000 ($510,000 after tax), 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 Note 2(a) and 6 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, however, a number do not qualify for hedge accounting due to the very detailed and complex rules outlined in AcG-13. Petrofund has elected to use the fair value method of accounting for all derivative transactions as we believe it would be confusing if the Trust were to use hedge accounting for some of its hedging contracts and fair value accounting for others.

As of January 1, 2004, all outstanding derivative instruments 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 will be amortized to expense over the remaining term of the contracts. The total amount of $7.6 million, less $2.5 million amortized to expense in the first quarter of 2004, or $5.1 million has been recorded as a current asset or liability, as appropriate, on the balance sheet as "deferred loss/gain on the 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 March 31, 2004 in the amount of $12.6 million, which does affect cash flow, are recorded in the income statement on a separate line as "gain/loss on commodity contracts". This line item also includes realized cash gain/losses on commodity contracts, which were previously added or deducted from oil and natural gas sales. The comparative number for 2003 represents realized losses on commodity contracts which were netted against sales.

This policy is discussed in detail in Note 2(b) to the Notes to 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 by $1.4 million in the first quarters of 2004 and 2003 as a result of the change. This change in classification has no impact on net income and the comparative figures have been restated to conform to the presentation adopted for the current period.

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 first quarter of 2004 received distributions of $0.48 in cash as compared to $0.48 in the first quarter of 2003. A cash distribution of $0.16 per unit was paid in April and $0.16 per unit has been announced for May.

The Trust generated cash flow available for distribution in the first quarter of $47.9 million, or $0.65 per unit before deducting $7.5 million or $0.10 per unit for reinvestment in capital projects. Of the remaining $40.4 million available, $34.9 million was paid out in distributions representing a payout ratio of 73 % (see Note 6).

For the 12 months ended March 31, 2004, the Trust generated cash flow available for distribution of $171.1 million, withheld $30.0 million for reinvestment in development drilling and other projects, and paid out distributions of $136.2 million, resulting in a payout ratio of 80%. The Trust is continuing its policy of stabilizing monthly distributions and reinvesting a portion of its cash flow for the long-term health of the Trust. In higher price environments, a larger percentage of the Trust's cash flow will be retained for reinvestment and to ensure more consistent monthly distributions. When prices are lower, less cash flow is required for capital expenditure as projects become less economic.

The major factors impacting the results of the operations for the first quarter of 2004 were the disposition of properties effective December 31, 2003, which reduced production volumes by approximately 1,775 boe/d from the fourth quarter of 2003, and lower product prices. The WTI US price increased from US $33.86/bbl in the first quarter of 2003 to US $35.14/bbl, in the first quarter of 2004 however, the Canadian wellhead price decreased to $42.50/bbl from $47.79/bbl for the same periods as the Canadian dollar strengthened from $0.66 US to $0.76 US. The natural gas price declined 17% to $6.76/mcf. On a boe basis average prices were down 14% to $41.15/boe from $47.73/boe in the first quarter of 2003.

Revenues decreased 14% to $99.7 million in the first quarter of 2004 from $115.7 million in the first quarter of 2003, as production was down 1% and prices were down 14% on a boe basis.

Sales of natural gas liquids decreased 7% to $6.9 million in the first quarter of 2004, from $7.5 million in the first quarter of 2003. Production was up 2% to 2,040 bbl/d from 1,996 bbl/d; however, average prices were down 11% to $37.06/bbl in the first quarter of 2004, from $41.53/bbl in the same period in the prior year.

As at March 31, 2004 Petrofund had 27.2 mmcf/d of natural gas and 5,331 bbl/d of crude hedged for the remainder of 2004. Crude oil hedges were unchanged and natural gas hedges increased only slightly from the previous quarter. The Trust's 2004 natural gas hedges include: 19.8 mmcf/d collared between $5.22/mcf-$7.32/mcf and 7.4 mmcf/d fixed at $5.80/mcf. The Trust will lose its floor protection on about 11% 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 had 1,331 bbl/d of oil fixed at $38.21/bbl and 4,000 bbl/d collared between $31.58/bbl-$37.36/bbl for 2004. The Trust will lose its floor protection on 50% of the collared volume in the event WTI averages less than $27.76/bbl ($21.17 US). Under these transactions Petrofund will receive a premium of $3.93/bbl ($3.00 US) if WTI remains below the $27.76/bbl level.

For the first quarter of 2005, the Trust has 9.5 mmcf/d of natural gas hedged under a $5.80/mcf-$8.97/mcf three way collar and 3,000 bbl/d of oil hedged in three way collars between $33.92/bbl-$41.80/bbl.

Petrofund also contracted a portion of its Alberta power costs by fixing the price on two (2) Megawatts/hour (MW/h) of its Alberta consumption at $44.50/MWh for 2004 and 2005.

ROYALTIES

FIELD OPERATING COSTS

GENERAL AND ADMINISTRATIVE EXPENSES

Interest expense decreased to $906,000 in 2004 from $2.1 million in 2003 due to the decrease in the average loan balance outstanding and a decrease in the average prime rate.

The provision for depletion, depreciation and accretion increased from $27.6 million in the first quarter of 2003 to $29.5 million in the first quarter of 2004 due to the increase in the depletion rate from $11.38/boe in 2003 to $12.20/boe in 2004. The 6.7% increase in the depletion rate is mainly due to the negative adjustments to reserves.

Net income before the provision for income taxes decreased from $29.9 million in the first quarter of 2003 to $8.1 million for the same period in 2004. Net income was reduced by $12.6 million due to the non-cash adjustment as a result of recording commodity contracts at fair value in accordance with AcG-13 which was adopted January 1, 2004. Prior to this adjustment, net income for the first quarter of 2004 would have been $20.7 million. The remainder of the decrease from 2003 was due to the 16% decline in operating netbacks as prices were down 14% on a boe basis.

In the first quarter of 2004 future tax expense was $0.4 million as compared to a recovery of $3.1 million in 2003. This was partially due to the utilization of tax loss carry forwards in 2004.

CAPITAL EXPENDITURES

DEBT

The working capital deficit was $66.1 million on March 31, 2004, an increase of $36.1 million from the $30.0 million deficit as at December 31, 2003. The increase was mainly due to the application of the cash received on the sale of properties in the first quarter of 2004 to long-term debt, and the negative fair value of the commodity contracts recorded on the balance sheet of $10.0 million net.

The Trust had 72,743,253 Trust units outstanding at March 31, 2004, compared to 72,688,577 Trust units at the end of 2003. During this period no Exchangeable Shares were converted to Trust units. During the quarter 23,031 were redeemed for cash leaving 828,440 Exchangeable Shares outstanding at March 31, 2004, which can be converted, at the option of the unitholder into 939,147 Trust units.

As discussed in the Trust's annual report, the level of cash flow for 2004 will be affected by oil and gas prices, the Canadian - US dollar exchange rate and the Trust's ability to add reserves and production in a cost effective manner. Both product prices and the exchange rate showed significant volatility in 2003 and this trend is expected to continue in 2004. The acquisition market is expected to continue to be active and supply should increase, nevertheless, competition for these assets is expected to be fierce due to increased demand resulting from the increasing number of oil and gas companies that have converted to a trust structure. We expect prices for quality, long life assets to be at or near record levels. Petrofund expects to be an active participant in this market but success will be tempered by a commitment to maintain historic discipline and bid only at levels consistent with the best long term interest of our unitholders.

Acquisition activities will be complemented by an extensive drilling and farmout program that will be conducted on our existing land base. Activities for the first quarter of 2004 were reviewed earlier in this report.

Production volumes in the fourth quarter of 2003 were in the 29,000 boe/d range, which have declined to 26,607 boe/d in the first quarter of this year due to the sale of properties at the end of 2003. The third and fourth quarters also reflected " flush" production from a number of oil and natural gas well that come on production during this period. If the Ultima acquisition is successful, production volumes for the second half of the year are expected to be in the 36,000 boe/d range.

There has been no change to contractual obligations disclosed in the Trust's annual report.

The Trust has no off-balance sheet arrangements or variable interest entities.

The accompanying notes to interim consolidated financial statements are an integral part of this consolidated balance sheet.

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

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

These unaudited interim consolidated financial statements follow the same accounting policies and methods of their application as the most recent annual financial statements except as disclosed in Note 2 below. 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 Petrofund Energy Trust ("Petrofund" or the "Trust") as at December 31, 2003 and 2002 and for each of the years in the three-year period ended December 31, 2003.

Effective January 1, 2004, the Trust adopted the new Canadian accounting standard for accounting for Asset Retirement Obligations ("ARO"). This standard requires recognition of a liability for the future retirement obligations associated with property, plant and equipment. These obligations are initially measured at fair value, which is the discounted future value of the liability. The liability is accreted each period for the change in present value and the accretion expense is charged to income. The fair value of the liability is capitalized as part of the cost of the related asset and amortized to expense over its useful life.

The Trust has estimated the net present value of its total ARO to be $34.4 million as at December 31, 2003, based on a total future liability of $85.5 million. These payments are expected to be made over the next 35 years. The Trust's credit adjusted risk free rate of 6.5 per cent and an inflation rate of 1.5 per cent were used to calculate the present value of the ARO.

Income for the three months ended March 31, 2003 and 2004 increased by $265,000 and $510,000 respectively as a result of adopting this policy, with negligible impact on per income per unit.

The impact of this change on the balance sheet is as follows:

In December 2001, the Canadian Institute of Chartered Accountants (CICA) issued Accounting Guideline 13, "Hedging Relationships" (AcG-13), effective for fiscal years commencing on or after July 1, 2003. AcG-13 established certain conditions for when hedge accounting may be applied. 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 adopted the guideline effective January 1, 2004.

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, however, a number do not qualify for hedge accounting due to the very detailed and complex rules outlined in AcG-13. Petrofund has elected to use the fair value method of accounting for all derivative transactions

As of January 1, 2004, all outstanding derivative instruments 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 will be amortized to expense over the remaining term of the contracts. The total amount of $7.6 million, less $2.5 million amortized to expense in the first quarter of 2004, or $5.1 million has been recorded as a current asset or liability on the balance sheet as deferred loss/gain on the commodity contracts. The negative fair value of the contracts at March 31, 2004 of $16.9 million has been recorded on the balance sheet as "commodity contracts under asset or liabilities", as appropriate.

The change in the fair value of the contracts from January 1, 2004 to March 31, 2004 of $10.1 million plus the amortized amount as noted above is recorded in the income statement on a separate line as "gain/loss on commodity contracts". The line item also includes realized cash gain/loss on the commodity contracts which were previously deducted from or added to oil and natural gas sales. The comparative number for 2003 represents realizes losses on commodity contracts which were previously netted against sales.

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 standard, 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 by $1.4 million in the first quarters of 2004 and 2003 as a result of the change. This change in classification has no impact on net income and the comparative figures have been restated to conform to the presentation adopted for the current period.

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 March 31, 2004, 828,440 Exchangeable Shares were outstanding, at an exchange ratio of 1.13363 per Trust unit.

The revolving period on the bank loan has been extended for an additional 364 day period ending May 28, 2005 with all other terms and conditions remaining the same.

The total future asset retirement obligation was estimated by management based on the Trust's net ownership interest in wells and facilities and the estimated timing of the costs to be incurred in future periods. The following reconciles the Trust's outstanding ARO for the periods indicated:

Previously this cash fund was increased at $0.075 per boe produced. Effective January 1, 2004, this was increased to $0.15 per boe produced. The total amount of the reserve fund at March 31, 2004 is $4.1 million.

The Trust enters into various pricing mechanisms to reduce price volatility and establish minimum prices for a portion of its oil and natural gas production. These include fixed price contracts and the use of derivative financial instruments.

The outstanding derivative financial instruments as at March 31, 2004, and the related unrealized gains or losses, are summarized separately below:

*(1) At Prices above $8.97/mcf Petrofund receives $8.97/mcf.
        At Prices between $5.80/mcf and $8.97/mcf Petrofund receives the market price.
       At Prices below $4.74/mcf Petrofund receives a premium of $1.06/mcf.

*(1) At Prices above $37.70 Petrofund receives $37.70/bbl.
        At Prices between $31.47 and $37.70/bbl Petrofund receives the market price.
        At Prices below $27.86 Petrofund receives a premium of $3.93/bbl.

*(2) At Prices above $38.03 Petrofund receives $38.03/bbl.
        At Prices between $31.81 and $38.03/bbl Petrofund receives the market price.
        At Prices below $28.19 Petrofund receives a premium of $3.93/bbl.

*(3) At Prices above $38.03 Petrofund receives $38.03/bbl.
        At Prices between $31.47 and $38.03/bbl Petrofund receives the market price.
        At Prices below $26.22 Petrofund receives a premium of $5.25/bbl.

*(4) At Prices above $44.34 Petrofund receives $44.34/bbl
        At Prices between $35.16 and $44.34/bbl Petrofund receives the market price.
        At Prices below $31.47 Petrofund receives a premium of $3.93/bbl.

*(5) At Prices above $43.02 Petrofund receives $43.02/bbl.
        At Prices between $35.14 and $43.02/bbl Petrofund receives the market price.
        At Prices below $30.16 Petrofund receives a premium of $5.25/bbl.

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.

On March 29, 2004 Petrofund Energy Trust ("Petrofund") and Ultima Energy Trust ("Ultima") announced that they have entered into an agreement providing for the combination of the two entities.

This transaction will be accounted for as an acquisition of Ultima by Petrofund.

As at April 30, 2004, based on the information provided by our transfer agent, Petrofund estimates that nonresident ownership of the Trust was approximately 69%. Management of the Trust continues to review its options to achieve non-resident ownership levels below 50% by the January 1, 2007 deadline proposed by the Federal Government. The Ultima Energy Trust merger is a positive first step toward reducing non-resident ownership levels as the proportion of Ultima units that are held by non-residents is significantly lower than that of Petrofund, such that the non-resident ownership levels of the combined entity going forward will be lower than Petrofund's current 69%.

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.

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