Petrofund Energy Trust (PTF) 6-K Petrofund Energy Trust - Form 6-K

	444 - 7th Avenue S.W.
	Suite 600
	Calgary, Alberta
	T2P 0X8
	Telephone: (403) 218-8625
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News Release

CALGARY - August 11, 2004

Petrofund Energy Trust (TSX: PTF.UN; AMEX: PTF)
Reports its Results for the Second Quarter of 2004

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

• Completion of the Ultima Energy Trust acquisition.
• Second quarter exit production rate over 35,000 boepd.
• Quarter end production balance 58% oil and 42% gas.
• Cash flow for the quarter increased 9% over the same quarter in 2003 but net income is down sharply primarily because of an adjustment made in relation to accounting for future taxes.
• Cash distributions maintained at $0.16 per month resulting in a first half payout ratio of 77%.
• Debt to cash flow ratio below one.

Additional information on Petrofund's second quarter results are presented below:

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FINANCIAL HIGHLIGHTS
(thousands of Canadian dollars and units, except per unit amounts)
			3 months ended June 30,					6 months ended June 30,
			2004		2003(3)	Variance		2004		2003(3)	Variance
INCOME STATEMENT
	Revenues	$	112,970	$	98,911	14%	$	212,669	$	214,607		(1)%
	Cash flow (1)	$	49,820	$	45,761	9%	$	98,867	$	104,380		(5)%
	Per unit	$	0.64	$	0.78	(18)%	$	1.30	$	1.85		(30)%
	Per boe (2)	$	19.52	$	17.52	11%	$	19.88	$	20.73		(4)%
	Cash distributions paid per unit	$	0.48	$	0.53	(9)%	$	0.96	$	1.01		(5)%
	Net income	$	817	$	15,295	(95)%	$	8,446	$	47,907		(82)%
	Net income per unit
	Basic	$	0.01	$	0.26	(96)%	$	0.11	$	0.85		(87)%
	Diluted	$	0.01	$	0.26	(96)%	$	0.11	$	0.85		(87)%
UNITS AND EXCHANGEABLE SHARES OUTSTANDING (2)
	Weighted average		78,074		58,967	32%		75,874		56,562		34%
	Diluted		78,229		59,067	32%		76,051		56,682		34%
	At period end		100,190		65,667	53%	100,190			65,667		53%
BALANCE SHEET
	Working capital (deficit)						$	(30,955)	$	(56,547)		45%
	Property, plant and equipment						$	1,251,484	$	905,344		38%
	Long-term debt						$	212,537	$	166,351		(28)%
	Unitholders' equity						$	1,063,704	$	557,023		91%
TRUST UNIT TRADING (TSX: PTF.UN)
	High	$	18.08	$	13.59	33%	$	19.24	$	13.59		42%
	Low	$	14.70	$	10.69	38%	$	14.56	$	10.69		36%
	Close	$	14.85	$	13.15	13%	$	14.85	$	13.15		13%
	Volume (units)		11,902		15,646	(24)%		24,975		22,180		13%
TRUST UNIT TRADING (AMEX: PTF)
	High	$	13.54	$	10.06	35%	$	14.96	$	10.06		49%
	Low	$	10.95	$	7.36	49%	$	10.95	$	6.89		59%
	Close	$	11.16	$	9.78	14%	$	11.16	$	9.78		14%
	Volume (units)		20,066		19,558	3%		60,603		28,055		116%
(1)	Cash flow before net change in non-cash operating working capital balances. (Non-GAAP measure - see special notes in the Management Discussion and Analysis.)
(2)	See Notes 4 and 5 to Notes to Interim Consolidated Financial Statements for details.
(3)	Certain numbers have been restated to conform to the 2004 presentation.

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OPERATIONAL HIGHLIGHTS
(thousands of Canadian dollars except per unit amounts)
		6 months ended June 30,					3 months ended June 30,
		2004		2003	Variance		2004		2003	Variance
DAILY PRODUCTION
Oil (bbls)		12,679		12,363	3%		12,129		11,817	3%
Natural gas (mmcf)		79,741		86,210	(8)%		78,833		84,116	(6)%
Natural gas liquids (bbls)		2,074		1,971	5%		2,057		1,983	4%
BOE (6:1)		28,043		28,702	(2)%		27,325		27,819	(2)%
Total production (mboe)		2,552		2,612	(2)%		4,973		5,035	(2)%
PRODUCTION PROFILE
Oil		45%		43%			44%		43%
Natural gas		48%		50%			49%		50%
Natural gas liquids		7%		7%			7%		7%
PRICES
Oil (per bbl) (1)	$	47.01	$	36.20	30%	$	44.86	$	41.69	8%
Natural gas (per mcf) (1)	$	7.13	$	6.65	7%	$	6.95	$	7.35	(5)%
Natural gas liquids (per bbl) (1)	$	37.13	$	33.00	13%	$	37.09	$	37.27	- %
BOE (6:1)	$	44.27	$	37.85	17%	$	42.75	$	42.60	- %
Cash operating netback per BOE	$	22.05	$	20.04	10%	$	22.38	$	23.37	(4)%
LEASE OPERATING COSTS	$	23,639	$	22,404	(6)%	$	43,468	$	41,992	(4)%
Cost per boe	$	9.26	$	8.58	(8)%	$	8.74	$	8.34	(5)%
GENERAL & ADMINISTRATIVE COSTS	$	3,316	$	3,326	- %	$	6,454	$	6,781	5%
Cost per boe	$	1.30	$	1.27	(2)%	$	1.30	$	1.35	4%
(1) Prices are before realized gains/losses on hedging contracts and before transportation costs which were previously deducted from oil and natural gas prices and are now disclosed separately on the income statement. Prices previously reported for 2003 have been restated.

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Management Discussion and Analysis
         three and six months ended June 30, 2004

SPECIAL NOTES

The following discussion and analysis of financial results should be read in conjunction with the unaudited consolidated financial statements for the six months ended June 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" or the "Company") 2003 annual report.

The discussion and analysis included in this section is based on information available to July 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 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"). 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 7 to the Notes to Interim Consolidated Financial Statements.

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. 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.

RESULTS SUMMARY

Production increased 1,436 boe/d from the first quarter mainly due to the inclusion of 14 days of production from the additional properties resulting from the acquisition of Ultima Energy Trust on June 16, 2004. Prices

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for oil and gas continued to be strong. Average prices on a boe basis were up $3.12 from the first quarter of 2004 and up $6.42 from the same period in 2003. Due to this increase in volumes and prices, revenue was up 13% from the first quarter. The increased revenue was partially offset by losses on the hedging contracts mainly due to the strong oil prices. The cash loss on the hedging contracts during the second quarter was $8.9 million. An additional non-cash loss of $4.6 million is recorded on the income statement reflecting the change in the fair value of the commodity contracts during the period.

Royalties were 20% of revenue as expected. Operating costs were higher than anticipated at $9.26 per boe due to prior year adjustments which increased costs by $0.62 per boe. General and administrative costs per boe were the same as the first quarter at $1.30 per boe.

Net income before income taxes was $13.1 million in the second quarter of 2004 from $8.1 million in the first quarter of 2004.

Net income was down $6.8 million from the first quarter of 2004 mainly due to the increase in non-cash deferred tax expense of $11.6 million from the first quarter, as discussed later in this report.

HIGHLIGHTS FOR THE THREE AND SIX MONTHS ENDED JUNE 30, 2004

• Petrofund closed the acquisition of Ultima Energy Trust on June 16, 2004.
• The Trust paid out cash distributions of $39.2 million or $0.48 per unit in the three months ended June 30, 2004.
• The Trust's payout ratio for the six months ended June 30, 2004 was 77% compared to 56% in 2003. The payout ratio in the second quarter was 80% as compared to 69% in the same quarter of 2003.
• Production on a boe basis increased to 28,043 boe/d compared to 26,607 in the first quarter.
• Canadian product prices on a boe basis increased to $44.27/boe from $41.15/boe in the first quarter.
• The Trust generated cash flow of $49.8 million in the second quarter of 2004 as compared to $49.0 million in the first quarter and $45.8 million in the second quarter of 2003.
• Net income decreased to $0.8 million from $7.6 million in the first quarter.

PETROFUND ACQUISITION OF ULTIMA ENERGY TRUST

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 was approved by the unitholders of Ultima at a meeting held on June 4, 2004 and the transaction closed on June 16, 2004.

Under the terms of the agreement, each Ultima unit was exchanged for 0.442 of a Petrofund unit on a tax-deferred rollover basis and Petrofund acquired all the assets and assumed all of the liabilities of Ultima. Ultima unitholders also received an aggregate $10 million one-time special distribution of $0.167113 per Ultima unit on June 15, 2004. The aggregate cost of the transaction was $567.4 million consisting of 26.4 million Petrofund Trust units valued at $17.12 per unit, which was the weighted average trading price of the units for the period commencing five days before and ending five days after the acquisition was announced, the assumption of debt and negative working capital of $125.9 million and transaction costs incurred by the Trust of $1.6 million.

As at June 30, 2004 Petrofund had long-term debt of $212 million, as compared to $325 million available on the increased credit line. Subsequent to the end of the quarter $19 million was paid on the loan reducing it to $193 million.

Production from the Ultima properties from January 1, 2004 to the date of closing was approximately 9,900 boe/d of which 78% was oil and natural gas liquids. Ultima has a diversified group of assets with a reserve life index of over 11 years. Production from the properties for the period from the closing date to June 30, 2004 is included in this report. The third quarter report will reflect the consolidated results for the entire quarter. The production for the combined entity is expected to be in the 35,000 boe/d range of which

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approximately 59% will be oil and natural gas liquids. Ultima's 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 per unit 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.

OPERATIONAL HIGHLIGHTS

Despite the usual spring break-up delays, the Trust remained active operationally during the second quarter. A total of 35 wells were drilled on Company lands, consisting of 28 working interest wells (7.9 net) and 7 farmout wells. This drilling activity resulted in 19 oil wells, 13 gas wells, one miscible fluid injector and two dry holes. This equates to an overall drilling success rate of 94% for the quarter.

Besides drilling, the Trust also continued its focus on optimizing its existing production base by a series of well recompletions, pump upgrades and facility additions and modifications.

Northern Alberta

A total of twelve wells (2.2 net) were drilled in areas such as Swan Hills, House Mountain, Fort Saskatchewan, Spirit River, Niton, Westerose and Minehead, resulting in eight oil wells, two gas wells, one miscible fluid injector and one dry hole. Of particular note, Petrofund, as operator, drilled two successful Charlie Lake oil wells at Spirit River subsequent to its recent acquisition of Ultima Energy Trust. Upwards of six to eight follow-up Spirit River drilling locations are being planned for later this year. At Minehead, the first well of a 3-well Cardium gas well program was successfully drilled late this quarter and is expected to come on-stream in the third quarter. At Hanlan, Petrofund participated in the successful recompletion of a previously shut-in well that is now producing 150 boe/d net to the Company's working interest. At Sunchild, 2 gas wells drilled in the prior quarter were equipped and tied in during the second quarter, netting Petrofund approximately 40 boe/d.

Central Alberta

Petrofund's development activity within Central Alberta increased significantly in the second quarter, with 11 gas wells (4.1 net) drilled. As operator, Petrofund drilled four successful Edmonton Sand/Scollard gas wells at Three Hills Creek near Red Deer. These wells are expected to come on-stream early next quarter at approximately 100 boe/d net.

In an effort to make use of existing wellbores, the Company successfully recompleted a marginal Three Hills Creek producer for Belly River gas, adding an incremental 125 boe/d net. Based on this encouraging result, the Trust is assessing other recompletion opportunities.

As well, Petrofund continued its coalbed methane participation through its joint venture with a major coalbed methane developer. Through this joint venture, the Trust participated in four new drills (0.7 net) at Three Hills Creek in the second quarter and has agreed to participate in a further twelve drills (4.2 net) during the upcoming quarter. In total, the Company expects to participate in 50 coalbed methane wells (14-18 net) throughout 2004.

Southern Alberta

Petrofund participated in drilling three (1.5 net) successful Taber oil wells on its Turin property near Lethbridge which are now collectively producing 125 boe/d net. In follow-up, Petrofund recently acquired some additional on-trend acreage and has plans to drill a further two or three wells by year end.

Southeastern Saskatchewan

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A total of ten (1.8 net) wells were drilled on Petrofund's lands at Silverton, Alida and Weyburn, resulting in nine oil wells and one dry hole. Petrofund's net added production from the nine successful wells amounts to about 175 boe/d. Petrofund is moving ahead with plans to drill two 100% working horizontal wells, one each at Silverton and Tatagwa, in the third quarter.

CHANGES IN ACCOUNTING POLICIES

Asset Retirement Obligations

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) of 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. Net income for the three and six months ended June 30, 2003 increased by $181,000 and $617,000 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 for three and six months ended June 30, 2004, increased by $1.0 million ($593,000 after tax) and $1.9 million ($1.1 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.

Financial Instruments

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.

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, less $2.5 million and $2.2 million amortized to expense in the first and second quarter of 2004 respectively, or $2.9 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 balance sheet also includes a deferred amount of $1.4 million relating to the Ultima acquisition.

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 June 30, 2004 in the amount of $17.2 million are recorded in the income statement on a separate line as "gain/loss on commodity contracts". The negative value of the

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commodity contracts increased $10.1 million in the first quarter and an additional $2.5 million in the second quarter. The non-cash loss also includes the amortization of the fair value of the contracts at January 1, 2004 of $2.5 in the first quarter and $2.2 in the second quarter. This line item also includes realized cash gain/losses on commodity contracts, of $4.9 million in the first quarter and $8.9 million in the second quarter, 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.

Transportation Costs

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 $1.1 million in the second quarter of 2004 and $2.5 million for the six months ended June 30, 2004. The comparative numbers for 2003 were $1.3 million and $2.8 million respectively.

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

Product Prices

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

CASH DISTRIBUTIONS

Petrofund unitholders who held their units throughout the second quarter of 2004 received distributions of $0.48 in cash as compared to $0.53 in the second quarter of 2003. A cash distribution of $0.16 per unit was paid in July and $0.16 per unit has been announced for August.

The Trust generated cash flow available for distribution in the second quarter of $48.7 million before deducting $7.5 million for reinvestment in capital projects and $34.9 million for the payment of the deferred capital obligation on the Weyburn unit interest acquired from Ultima. Distributions of $39.2 million were paid out in the quarter representing a payout ratio of 80% (see Note 7).

For the 12 months ended June 30, 2004, the Trust generated cash flow available for distribution of $175.9 million, withheld $64.9 million for reinvestment in development drilling and other projects, and the deferred capital obligation and paid out distributions of $145.0 million, resulting in a payout ratio of 82%.

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.

RESULTS OF OPERATIONS

Revenue and Production

Revenues increased 14% to $113.0 million in the second quarter of 2004 from $98.9 million in the second quarter of 2003. Production was down 2%, however prices were up 17% on a boe basis.

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For the six month period ended June 30, 2004, revenue decreased 1% to $212.7 million from $214.6 million in 2003 due to a 2% decrease in production to 27,325 boe/d. This was partially offset by an increase in the average price per boe to $42.75 in 2004 from $42.60 in 2003.

Crude oil sales increased 33% to $54.2 million in the second quarter of 2004 from $40.7 million in the second quarter of 2003. Oil production volumes increased 3% to 12,679 bbl/d in the second quarter of 2004 as compared to 12,363 in the second quarter of 2003. The average price was up 30% to $47.01/bbl from $36.20/bbl.

During the six month period ended June 30, 2004, crude oil sales increased 11% to $99.0 million in 2004 from $89.2 million in 2003. Oil production increased 3% to 12,129 bbl/d for the period, compared to 11,817 bbl/d for the same period in 2003. The average price increased from $41.69/bbl in 2003 to $44.86/bbl in 2004. The WTI U.S. price increased from U.S. $28.91 in the second quarter of 2003 to U.S. $38.31 in the same period in 2004.

Natural gas sales decreased 1% from $52.2 million in the second quarter of 2003 to $51.7 million in the second quarter of 2004. Natural gas production declined 8% from 86.2 mmcf/d to 79.7 mmcf/d, however, the average natural gas price was up 7% from $6.65/mcf to $7.13/mcf. AECO monthly natural gas prices decreased from $6.99/mcf in the second quarter of 2003 to $6.80/mcf in the second quarter of 2004, however, daily AECO prices were up from $6.81/mcf to $7.00/mcf over the same period.

During the six month period ended June 30, 2004, natural gas sales decreased 11% to $ 99.7 million in 2004 from $112.0 million in 2003. Natural gas production decreased 6% from 84.1 mmcf/d in 2003 to 78.8 mmcf/d in 2004. The average price decreased 5% from $7.35/mcf in 2003 to $6.95/mcf in 2004.

Sales of natural gas liquids increased 17% to $7.0 million in the second quarter of 2004, from $6.0 million in the second quarter of 2003. Production was up 5% to 2,074 bbl/d from 1,971 bbl/d; and the average price was up 13% to $37.13/bbl from $33.00/bbl.

For the six month period ended June 30, 2004, sales of natural gas liquids increased 4% from $13.4 million in 2003 to $13.9 million in 2004. Production volumes increased 4% from 1,983 bbl/d to 2,057 bbl/d, however, the average price declined from $37.27/bbl in 2003 to $37.09/bbl in 2004.

Daily Production
	3 months ended June 30,		6 months ended June 30,
	2004	2003	2004	2003
Oil (bbls)	12,679	12,363	12,129	11,817
Natural gas (mmcf)	79,741	86,210	78,833	84,116
Natural gas liquids (bbls)	2,074	1,971	2,057	1,983
Total (boe 6:1)	28,043	28,702	27,325	27,819

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Sales Prices
Average prices		3 months ended June 30,				6 months ended June 30,
		2004		2003		2004		2003
Benchmark prices
WTI oil (U.S.$/bbl)	$	38.31	$	28.91	$	36.73	$	31.39
U.S. $ exchange rate		0.74		0.72		0.75		0.69
WTI oil (Cdn. equivalent/$/bbl)	$	51.77	$	40.15	$	48.97	$	45.49
AECO natural gas ($/mcf)	$	6.80	$	6.99	$	6.70	$	7.46
Average Petrofund prices
Oil	$	47.01	$	36.20	$	44.86	$	41.69
Natural gas		7.13		6.65		6.95		7.35
Natural gas liquids		37.13		33.00		37.09		37.27
Weighted average (6:1)	$	44.27	$	37.85	$	42.75	$	42.60
Production Revenue (millions)
Revenue		3 months ended June 30,				6 months ended June 30,
		2004		2003		2004		2003
Oil	$	54.2	$	40.7	$	99.0	$	89.2
Natural gas		51.7		52.2		99.7		112.0
Natural gas liquids		7.0		6.0		13.9		13.4
Total	$	112.9	$	98.9	$	212.6	$	214.6

Hedging and Risk Management

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 June 30, 2004 Petrofund has hedged 34.1 mmcf/d of gas and 7,500 bbl/d of crude for the remainder of 2004. Crude oil hedges for 2004 increased by 2,170 bbl/d with the acquisition of Ultima while gas hedges increased about 7 mmcf/d from the previous quarter as the Trust added additional hedges for next winter. The Trust's 2004 gas hedges include: 24.6 mmcf/d collared between $5.51/mcf-$8.79/mcf and 9.5 mmcf/d fixed at $6.15/mcf. The Trust will lose its floor protection on about 13% 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 $36.46/bbl and 5,500 bbl/d collared between $32.31/bbl-$38.06/bbl. The Trust will lose its floor protection on 55% of the collared volume in the event WTI averages less than $27.18/bbl ($20.38 US). Under these transactions Petrofund will receive a premium of $5.34/bbl ($4.00 US) if WTI remains below the $27.18/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 has no other gas hedged beyond this date. Petrofund's 2005 crude hedges include 3,000 bbl/d in three way collars ranging between $34.51/bbl-$42.51/bbl. The Trust will lose its floor protection on 100% of the collared volume if WTI averages less than $29.62/bbl ($22.21 US). Under these transactions Petrofund will receive a premium of $4.90/bbl ($3.67 US) if WTI remains below the $29.62/bbl level. The Trust has no oil fixed after 2004. Petrofund also contracted to control a portion of its Alberta power costs by fixing the price on two (2) Megawatts/hour (MW/h) of its Alberta consumption at $44.5/MWh for 2004 and 2005. The Ultima acquisition increased the 2004 average hedged power volume to three (3) Megawatts/hour (MW/h) at an average cost of $46.65/MWh.

10

All foreign exchange calculations in this section of the report incorporate the Bank of Canada US dollar rate at the close on June 30, 2004 ($1.3338 C$:US$). For a complete listing of all hedge transaction details please see Note 10 to the Financial Statements.

Gain/ (loss) on commodity contracts

Revenue		3 months ended June 30,				6 months ended June 30,
		2004		2003		2004		2003
Realized gains/(losses)	$	(8,888)	$	(1,757)	$	(13,788)	$	(6,872)
Change in fair value
Fair value, beginning of period		16,901		-		6,771		-
Fair value of Ultima contracts acquired		5,584		-		5,584		-
Fair value June 30, 2004		(24,970)		-		(24,970)		-
Change in fair value of financial instruments		(2,485)		-		(12,615)		-
Amortization of negative fair value
at January 1, 2004		(2,167)		-		(4,628)		-
Total non-cash adjustments		(4,652)		-		(17,243)		-
Total	$	(13,540)	$	(1,757)	$	(31,031)	$	(6,872)

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:

Oil per bbl	$	(6.51)	$	(0.22)	$	(5.69)	$	(1.52)
Gas per mcf	$	(0.20)	$	(0.19)	$	(0.09)	$	(0.24)

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 incentives		3 months ended June 30,				6 months ended June 30,
	2004			2003	2004			2003
Royalties (millions)	$	23.0	$	21.0	$	41.6	$	45.2
Average royalty rate (%)		20%		21%		20%		21%
$/boe	$	9.02	$	8.04	$	8.36	$	8.98

Royalties, net of the Alberta Royalty Credit, were 20% of revenues for the three and six months ending June 30, 2004, as compared to 21% for the same periods in the prior year.

Expenses	3 months ended June 30,		6 months ended June 30,
	2004	2003	2004	2003
Expenses (millions)
Lease operating	$ 23.6	$ 22.4	$ 43.5	$ 42.0
General & administrative	3.3	3.3	6.5	6.8
Net interest	1.2	2.4	2.1	4.5
Expenses per boe	3 months ended June 30,		6 months ended June 30,
	2004	2003	2004	2003
Lease operating	$ 9.26	$ 8.58	$ 8.74	$ 8.34
General & administrative	1.30	1.27	1.30	1.35
Net interest	0.46	0.91	0.42	0.89

11

FIELD OPERATING COSTS

Operating expenses, net of processing income, were $23.6 million in the second quarter of 2004 compared to $22.4 million in the second quarter of 2003. Operating costs on a boe basis increased to $9.26 in 2004, as compared to $8.58 for the same period in 2003. Costs in the second quarter of 2004 include prior year adjustments from operators of $1.5 million or $0.62 per boe.

Operating costs for the six month period ended June 30, 2004, were up 5% to $8.74 per boe as compared to average of $8.34 in the prior year. Operating costs in the third and fourth quarters including the Ultima properties are expected to be in the $8.60 to $8.75 per boe range.

GENERAL AND ADMINISTRATIVE EXPENSES

General and administrative costs were $3.3 million in the second quarter of 2004 and 2003. Costs were up 2% on a boe basis to $1.30 as compared to $1.27 in 2003 due to the slightly lower volumes. General and administrative costs per boe are expected to decrease in the second half of the year to the $1.20 range with the acquisition of Ultima.

General and administrative costs for the six month period ended June 30, 2004, were $6.5 million in 2004 compared to $6.8 million in 2003. Costs were down 4% to $1.30 per boe compared to $1.35 per boe in 2003.

INTEREST

Interest expense decreased to $1.2 million in the second quarter of 2004 from $2.4 million for the same period as 2003 and to $2.1 million for the six month period ended June 30, 2004, from $4.5 million in 2003. The decreases reflect lower average loan balances outstanding and a decrease in the average prime rate.

DEPLETION, DEPRECIATION AND ACCRETION

The provision for depletion, depreciation and accretion increased from $29.3 million in the second quarter of 2003 to $33.1 million in the second quarter of 2004 due to the increase in the depletion rate from $11.24/boe in 2003 to $12.97/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 six months ended in June 30, 2004, was $62.6 million or $12.60 per boe as compared to $56.9 million or $11.31 per boe for 2003.

ASSET RETIREMENT RESERVE

In the second quarter of 2004, Petrofund has set aside $383,000 in cash to fund future ARO costs. In addition, the Ultima ARO reserve of $1.5 million was added to Petrofund on the consolidation of the entities. The total ARO reserve at June 30, 2004 was $6.1 million.

Effective January 1, 2004, Petrofund increased the reserve to $0.15/boe of production as compared to $0.075 in prior periods.

TAXABILITY OF DISTRIBUTIONS

As a general rule the Trust simply acts as a conduit as it receives a royalty from Petrofund Corp. and distributes it to unitholders. In the past, Petrofund has recorded royalty entitlements on a cash basis, thereby facilitating a matching of the distributions to unitholders.

12

Recent draft technical notes issued by the Department of Finance propose to change the method of calculating income for tax purposes to an accrual basis. This will have the effect of increasing the taxable portion of distributions to unitholders. These amendments are not as yet passed into law and Petrofund is unaware whether there will be transitional provisions or, if in fact, the legislation will be passed in the current year.

NET INCOME

Net income before the provision for income taxes was $13.1 million in the second quarter of 2004 as compared to a loss of $12.3 million in the same period of 2003.

Net income in the second quarter of 2003 was reduced by $29.1 million for the costs of the internalization of management. Excluding this amount, net income for 2003 would have been $16.8 million or $3.7 million higher than 2004. Net income for 2004 was reduced by the non-cash adjustment of $4.7 million as a result of recording commodity contracts at fair value in accordance with AcG-13 effective January 1, 2004.

Future income tax expense increased from $0.4 million in the first quarter of 2004 to $12.1 million in the second quarter. The increase in future taxes was attributable to the reduction of available tax pools which were utilized to offset the increase in taxable income of the operating subsidiary of the Trust. The increase in taxable income of the operating subsidiary resulted from the reduction of the royalty payable to the Trust, due to additional amounts withheld for capital expenditures. The additional amounts were withheld due to the payout of the Ultima deferred capital obligation of $34.9 million, which was a one time event. Net income is expected to recover in the third quarter.

For the three and six month periods ended June 30, 2003, there were future tax recoveries of $27.8 million and $30.9 million, respectively, due to legislative changes which reduced future tax rates.

	3 months ended June 30,		6 months ended, June 30,
Netback	2004	2003	2004	2003
Production (BOE) per day	28,043	28,702	27,325	27,819
Weighted average selling price	$ 44.27	$ 37.85	$ 42.75	$ 42.60
Cash cost of oil and natural gas hedging	(3.49)	(0.67)	(2.77)	(1.36)
Net weighted average selling price	40.78	37.18	39.98	41.24
Royalties, net of ARTC	9.02	8.04	8.36	8.98
Operating costs	9.26	8.58	8.74	8.34
Cost of transportation	0.45	0.52	0.50	0.55
Operating Netback	22.05	20.04	22.38	23.37
Interest expense	0.46	0.91	0.42	0.89
General and administrative	1.30	1.27	1.30	1.35
Capital and current taxes	0.45	0.28	0.39	0.35
Total cash netback per BOE before the effects
of the internalization of the management contract	19.84	17.58	20.27	20.78
Internalization of management contract	-	2.40	-	1.57
Total cash netback per BOE after the effects of the
internalization of the management contract	$ 19.84	$ 15.18	$ 20.27	$ 19.21

13

QUARTERLY FINANCIAL DATA

		Net Oil and		Net		Net income per unit (2)
($millions, except per unit amounts)		Natural Gas Sales (1)		Income		Basic	Diluted
2004
	First quarter		$ 81.1		$ 7.6	$ 0.10	$ 0.10
	Second quarter		89.9		0.8	0.01	0.01
2003
	First quarter		$ 84.9		$ 32.2	$ 0.59	$ 0.59
	Second quarter		74.8		15.1	0.26	0.26
	Third quarter		73.4		14.9	0.23	0.23
	Fourth quarter		75.2		23.6	0.23	0.33
2002
	Third quarter		$ 55.8		$ 9.6	$ 0.18	$ 0.18
	Fourth quarter		68.6		5.4	0.10	0.10
(1)	Net after royalties.
(2)	Net income per unit numbers are calculated quarterly and annually and therefore do not add.

GOODWILL

The goodwill balance of $182.4 million arose as a result of the acquisition of Ultima and was determined based on the excess of total consideration paid plus the future income tax liability less the fair value assigned to Ultima's assets.

Accounting standards require that the goodwill balance be assessed for impairment at least annually and if an impairment exists that it be charged to income in the period in which the impairment occurs. The Trust has determined that there was no goodwill impairment as of June 30, 2004.

CAPITAL EXPENDITURES

During the six months ended June 30, 2004, $27.4 million was incurred for development drilling, production enhancement and other activities. Total expenditure for these activities for all of 2004 is expected to be in the $75 million range.

During the second quarter of 2004, Petrofund drilled 28 working interest wells and entered into farmout agreements with various industry partners, which resulted in 7 wells being drilled on Petrofund's undeveloped land base. The drilling activity resulted in 19 oil wells and 13 natural gas wells for an overall success rate of 94%.

Petrofund completed the sale of various non-core properties effective December 31, 2003. Proceeds from these sales were used to reduce debt outstanding in the first quarter of 2004 and to fund additional capital expenditures.

A summary of capital expenditures for the three and six month periods appears below. Of the total amounts, $452 million was financed by the issue of 26.4 million Petrofund units with an assigned value of $17.12 per unit and the remainder was financed by cash and the assumption of debt on the Ultima acquisition.

14

	Ending June 30, 2004
	3 months	6 months
Acquisitions	$ 568,319	$ 569,409
Finding and development cost:
Land and seismic	360	967
Drilling and completions	8,458	14,144
Well equipping	834	2,032
Tie-ins	1,168	2,249
Facilities	2,119	4,665
Other	1,890	3,388
Total	14,829	27,445
Total net capital expenditures	$ 583,148	$ 596,854

DEBT

As at June 30, 2004, the amount outstanding on the credit facility was $212 million as compared to the $325 million available. Repayments were made on the loan during July reducing the balance outstanding to $193 million at July 31, 2004. The facility will be utilized for acquisitions and for additional development activities which are expected to be in the $45 million range for the last half of 2004. The revolving period on the syndicated facility has been extended for an additional 364-day period ending May 28, 2005. The maximum on the facility was increased to $325 million on June 30, 2004 as a result of the Ultima acquisition.

WORKING CAPITAL

The working capital deficit was $30.9 million on June 30, 2004, an increase of $0.9 million from the $30.0 million deficit as at December 31, 2003. The decrease in distributions payable at June 30, 2004 of $27.4 million is due mainly to the payout of the deferred capital obligation of $34.9 million with respect to the Weyburn unit interest acquired as part of the Ultima transaction. This decrease was offset by the net increase in liabilities of $17.0 million as a result of recording commodity contracts at fair value.

LIQUIDITY AND CAPITAL RESOURCES

During the six months ended June 30, 2004, the Trust generated cash flow of $98.9 million and paid out $74.1 million in distributions. The excess was used to fund the Trust's capital expenditure program.

Total long-term debt and capital leases increased to $212.5 million at June 30, 2004 from $110.3 million as at December 31, 2003 primarily due to the Ultima acquisition.

15

Details of all the changes to long-term debt are as follows:

	3 months	6 months
Cash flow from operations	$ 50,632	$ 100,841
Proceeds received from issuance of Trust units	802	1,709
Changes in working capital deficit	1,346	27, 192
Distributions paid	(39,165)	(74,075)
Expenditures on oil & natural properties, net	(124,013)	(137,719)
Asset retirement reserve	(383)	(746)
Redemption of exchangeable shares	(451)	(902)
Capital lease repayments	(88)	(174)
Actual abandonment costs incurred	(811)	(1,973)
Increase in cash	(10,493)	(16,908)
Miscellaneous	127	533
	$(122,497)	$ (102,222)

The ratio of long-term debt to cash flow at June 30, 2004 was 0.8:1.0 based on the combined annualized cash flow of Ultima and Petrofund for the six months ended for June 30, 2004 and 0.7:1.0 based on the debt outstanding at July 30, 2004.

Capitalization Analysis

($ thousands, except per unit & % amounts)		2004
Working capital (deficiency)	$	(30,955)
Bank debt		212,463
Capital lease obligation		74
Net debt obligation	$	243,492
Units outstanding & issuable for exchangeable shares		100,190
Market price at June 30, 2004	$	14.85
Market capitalization	$	1,487,823
Total capitalization	$	1,731,315
Net debt as a percentage of total capitalization		14%

UNITHOLDERS' EQUITY

The Trust had 99,250,968 Trust units outstanding at June 30, 2004, compared to 72,688,577 Trust units at the end of 2003. An additional 26,449,102 Trust units were issued on June 16, 2004 to the former unitholders of Ultima.

During this period no exchangeable shares were converted to Trust units, however, 23,701 shares were redeemed for cash during the quarter leaving 804,739 exchangeable shares outstanding at June 30, 2004, which can be converted, at the option of the unitholder into 939,147 Trust units.

OUTLOOK FOR 2004

As discussed in previous reports, 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 continue to be volatile.

The acquisition market is expected to continue to be active. The supply of properties has increased recently; 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 above record levels. Petrofund expects to be an active participant in this

16

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 second quarter were reviewed earlier in this report.

Production volumes in the fourth quarter of 2003 were in the 29,000 boe/d range. Production has declined to 27,325 boe/d in the first half of this year due to the sale of properties at the end of 2003 and normal decline. The third and fourth quarters of 2003 also reflected "flush" production from a number of oil and natural gas wells that came on production during that period. Production volumes are expected to be in the 35,000 boe/d range for the remainder of the year. The increase is primarily a result of the Ultima transaction.

CONTRACTUAL OBLIGATIONS

During the second quarter, PC acquired an additional interest in the Weyburn unit as part of the Ultima acquisition. This resulted in additional commitments for CO2 purchases. Subsequent to June 30, 2004 PC renewed its office lease and extended the term. As a result, PC has contractual obligations which range from $12.0 million to $15.1 million over the next five years. Full details are provided in Note 9 to the consolidated financial statements.

OFF-BALANCE SHEET ARRANGEMENTS/ VARIABLE INTEREST ENTITIES

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

CRITICAL ACCOUNTING ESTIMATES

The Trust has established procedures and internal control systems in place to ensure timely and accurate preparation of management, financial and other reports. Disclosure controls are in place to ensure all ongoing statutory reporting requirements are met and material information is disclosed on a timely basis.

The Trust's financial and operating results incorporate a number of estimates including:

(a) estimated revenues, royalties and operating costs on production as at a specific reporting date but for which actual revenues and costs have not yet been received;

(b) estimated capital expenditures on projects that are in progress;

(c) estimated depletion, depreciation and accretion that are based on estimates of oil and gas reserves that the Trust expects to recover in the future;

(d) estimated fair values of derivative contracts that are subject to fluctuation depending upon the underlying commodity prices and foreign exchange rates;

(e) estimated value of asset retirement obligations that are dependent upon estimates of future costs and timing of expenditures.

The estimates are prepared by qualified individuals who have knowledge of operations and related activities. Prior estimates are compared to actual results to confirm or improve accrual procedures and to make more informed decisions on future estimates.

17

Consolidated Balance Sheet
(thousands of dollars) (unaudited)

As at June 30, 2004 and at December 31, 2003		2004		2003
				(Restated Note 2)
Current assets
Cash	$	19,090	$	2,182
Accounts receivable		32,840		48,268
Deferred hedging loss on commodity contracts (Note 2(b) )		4,754		-
Commodity contracts (Notes 2(b) and 10)		386		-
Prepaid expenses		10,208		10,036
Total current assets		67,278		60,486
Asset retirement reserve (Note 8)		6,074		3,779
Goodwill (Note 3)		182,440		-
Oil and gas royalty and property interests,
at cost less accumulated depletion and depreciation
of $543,878 (2003 - $482,349)		1,251,484		898,263
	$	1,507,276	$	962,528
Liabilities and Unitholders' Equity
Current liabilities
Accounts payable and accrued liabilities	$	49,277	$	36,684
Current portion of capital lease obligations		716		356
Deferred hedging gain on commodity contracts (Note 2(b))		434		-
Commodity contracts (Notes 2(b) and 10)		21,777		-
Distributions payable to Unitholders		26,029		53,452
Total current liabilities		98,233		90,492
Long-term debt (Note 6)		212,463		109,707
Capital lease obligations		74		608
Commodity contracts (Notes 2(b) and 10)		3,578		-
Future income taxes		78,718		79,065
Asset retirement obligations (Notes 2(a) and 8)		50,506		34,363
Total liabilities		443,572		314,235
Unitholders' equity
Unitholders' capital (Note 4)		1,475,195		1,020,677
Exchangeable shares (Note 5)		10,518		10,518
Accumulated earnings		206,699		198,253
Accumulated cash distributions (Note 7)		(628,708)		(581,155)
Total unitholders' equity		1,063,704		648,293
	$	1,507,276	$	962,528

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

18

Consolidated Statement of Operations and Accumulated Earnings
(thousands of dollars except per unit amounts) (unaudited)

		Three months ended June 30,				Six months ended June 30,
		2004		2003		2004		2003
Revenues				(Restated Note2)				(Restated Note2)
Oil and gas sales	$	112,970	$	98,911	$	212,669	$	214,607
Royalties, net of incentives		(23,017)		(21,007)		(41,595)		(45,234)
Gain/loss on commodity contracts
(Note 2(b))		(13,540)		(1,757)		(31,031)		(6,872)
		76,413		76,147		140,043		162,501
Expenses
Lease operating		23,639		22,404		43,468		41,992
Transportation costs (Note 2(c))		1,156		1,347		2,511		2,753
Interest on long-term debt		1,183		2,372		2,089		4,501
General and administrative		3,316		3,326		6,454		6,781
Capital taxes		919		556		1,656		1,195
Depletion, depreciation and accretion		33,091		29,347		62,637		56,928
Internalization of management
contract		-		29,115		-		30,762
		63,304		88,467		118,815		144,912
Income (loss) before provision for
income taxes		13,109		(12,320)		21,228		17,589
Provision for (recovery of) income
taxes
Current		221		168		268		563
Future (Note 11)		12,071		(27,783)		12,514		(30,881)
		12,292		(27,615)		12,782		(30,318)
Net income		817		15,295		8,446		47,907
Accumulated Earnings, beginning of
period		205,882		143,098		199,200		113,341
Retroactive application of change in accounting policy
(Note 2(a))		-		436		(947)		(2,419)
Accumulated Earnings, beginning of
period
as restated		205,882		143,534		198,253		110,922
Accumulated Earnings, end of period	$	206,699	$	158,829	$	206,699	$	158,829
Net income per Trust unit
Basic	$	0.01	$	0.26	$	0.11	$	0.85
Diluted	$	0.01	$	0.26	$	0.11	$	0.85

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

Consolidated Statement of Cash Flows
(thousands of dollars except per unit amounts) (unaudited)

	Three months ended June 30,				Six months ended June 30,
		2004		2003		2004		2003
			(Restated Note 2)				(Restated Note 2)
Cash provided by (used in) operating
activities
Net income	$	817	$	15,295	$	8,446	$	47,907
Add items not affecting cash:
Depletion, depreciation and accretion		33,091		29,347		62,637		56,928
Gain/loss on commodity contracts		4,652		-		17,243		-
Future income taxes		12,071		(27,783)		12,514		(30,881)
Actual abandonment costs incurred (Note 8(a))		(811)		(213)		(1,973)		(336)
Internalization of management contract		-		29,115		-		30,762
Cash flow from operating activities		49,820		45,761		98,867		104,380
Net change in non-cash working capital
balances		1,346		(3,955)		27,192		19,488
Cash provided (used in) by operating
activities		51,166		41,806		126,059		123,868
Financing activities
Bank loan		122,625		(46,899)		102,756		(52,702)
Distributions paid (Note7)		(39,165)		(30,440)		(74,075)		(56,427)
Redemption of exchangeable shares		(451)		(698)		(902)		(698)
Capital lease repayments		(88)		(953)		(174)		(1,888)
Issuance of trust units (Note 4)		802		95,281		1,709		95,712
Cash provided by (used in) financing
activities		83,723		16,291		29,314		(16,003)
Investing activities
Asset retirement reserve (Note 8)		(383)		(196)		(746)		(378)
Acquisition of property interests		(124,013)		(77,081)		(137,719)		(102,066)
Proceeds on disposition of property		-		87		-		616
Internalization of management contract		-		(6,274)		-		(7,921)
Cash used in investing activities		(124,396)		(83,464)		(138,465)		(109,749)
Net change in cash		10,493		(25,367)		16,908		(1,884)
Cash (bank overdraft), beginning of period		8,597		21,911		2,182		(1,572)
Cash (bank overdraft), end of period	$	19,090	$	(3,456)	$	19,090	$	(3,456)
Interest paid during the period	$	223	$	2,159	$	1,167	$	4,435
Income taxes paid during the period	$	51	$	236	$	106	$	375

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

20

Notes to Interim Consolidated Financial Statements June 30, 2004 and 2003
(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 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.

(a) Acquisition of Ultima Energy Trust

On June 16, 2004, Petrofund Energy Trust acquired Ultima Energy Trust ("Ultima") and its wholly owned subsidiaries. After the amalgamation of Ultima Ventures Inc. into Petrofund Corp. and the wind-up of the inactive subsidiaries, the only remaining Ultima entity is Ultima Ventures Trust. The name of this entity has been changed to Petrofund Ventures Trust. The consolidated financial statements of Petrofund Energy Trust include the results of the Ultima entities effective June 17, 2004, see Note 3.

(b) Goodwill

Under the terms of section 1581 of the CICA handbook, goodwill must be recorded upon a corporate acquisition when the total purchase price exceeds the fair value of the net identifiable assets and liabilities of the acquired company. The goodwill balance is not amortized but instead is assessed for impairment each reporting period. Impairment is determined based on the fair value of the reporting entity (the consolidated Trust) compared to the book value of the reporting entity. Any impairment will be charged to the earnings in the period in which the fair value of the reporting entity is below the book value.

2. RETROACTIVE CHANGE IN ACCOUNTING POLICIES

(a) Asset Retirement Obligations

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.

Previously, the Trust recognized a provision for future site reclamation and abandonment "SR&A" costs calculated on the unit-of-production method over the life of the petroleum and natural gas properties based on total estimated proved reserves and an estimated future liability.

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.

Net income for the three and six months ended June 30, 2003 and 2004 increased by $1.0 million ($593,000 after tax) and $1.9 million ($1.1 million after tax) respectively; as a result of adopting this policy, with negligible impact on net income per unit.

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

	Net	Future	ARO	Change in Accumulated Earnings
December 31, 2003 Restatement	PP&E	Tax	Liability	Prior 2003	2003	Total
Balance, beginning of period	$ 879,633	$ 77,005	$16,846	$-	$ -	$       199,200
Initial fair value of ARO liability	32,771	-	32,771	-	-	-
Depletion expense	(14,141)	-	-	(11,977)	(2,164)	(14,141)
Accretion expense	-	-	10,230	(7,986)	(2,244)	(10,230)
Previously recorded SR&A provision expense	-	-	(25,484)	19,284	6,200	25,484
Future income tax adjustment	-	2,060	-	(1,740)	(320)	(2,060)
Change in accounting policies	18,630	2,060	17,517	(2,419)	1,472	(947)
Balance, beginning of period as "Restated"	$ 898,263	$ 79,065	$ 34,363	$ (2,419)	$  1,472	$       198,253

(b) Financial Instruments

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.

All outstanding derivative instruments as of 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, less $2.5 million amortized to expense in the first quarter of 2004 and $2.2 million in the second quarter, or $2.9 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 June 30, 2004 of $25.0 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 June 30, 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 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.

(c) Transportation Costs

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 $1.1 million in the second quarter of 2004 and $1.3

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million in 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.

3. ACQUISITION

Ultima Energy Trust

On June 16, 2004, Petrofund Energy Trust acquired Ultima Energy Trust for 0.442 of a Petrofund unit on a tax-free rollover basis. The value assigned to each Petrofund unit was $17.12 based on the weighted average trading price of the Trust units for the period commencing five days before and ending five days after the acquisition was announced. Petrofund issued 26.4 million Trust units which were distributed to former unitholders of Ultima.

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

		$000's
Current assets	$	16,764
Asset retirement reserve		1,549
Goodwill		182,440
Oil and gas royalties and property interest		384,987
Current liabilities		(17,115)
Long-term debt		(110,407)
Asset retirement obligations		(16,672)
Future income taxes		12,861
	$	454,407

4. TRUST UNITS

	Number
Authorized: unlimited number of Trust units	of units	$000's
Issued
December 31, 2003	72,688,577	$ 1,020,677
Issued for Ultima Energy Trust acquisition (Note 3)	26,449,102	452,809
Options exercised	73,766	1,018
Commission and issue cost adjustment	-	13
Unit purchase plan	2,724	44
Unit incentive plans	36,799	634
June 30, 2004	99,250,968	$ 1,475,195

The weighted average Trust units/Exchangeable Shares outstanding are as follows:

	3 months ended June 30,		6 months ended June 30,
	2004	2003	2004	2003
Basic	78,073,936	58,967,204	75,873,858	56,561,904
Diluted	78,229,404	59,067,223	76,050,805	56,682,075

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Trust units/Exchangeable Shares, at end of period:

For the period ended June 30,	2004	2003
Trust units outstanding	99,250,968	63,728,338
Trust units issuable on exchangeable shares	939,147	1,939,147
	100,190,115	65,667,485

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 June 30, 2004, 804,739 Exchangeable Shares were outstanding, at an exchange ratio of 1.16702 per Trust unit.

Issued and Outstanding	Number of Shares	$000's
December 31, 2003	851,471	$ 10,518
Redemption of shares	(46,732)	-
Balance at end of period	804,739	10,518
Exchange ratio, end of period	1.16702	-
Trust units issuable upon conversion	939,147	$ 10,518

6. BANK LOAN

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 maximum on the credit facility was increased to $325 million on June 30, 2004.

7. DISTRIBUTIONS ACCRUING TO UNITHOLDERS

Under the terms of the Trust Indenture, the Trust makes monthly distributions within a specified period following the end of each month ("Cash Distribution Date"). Distributions are equal to amounts received by the Trust on the Cash Distribution Date less permitted expenses. Distributions to Unitholders coincide with cash receipts of royalty income to the Trust. An overall analysis is as follows:

For the period ended	Cash Distribution Date		2004		2003
November 30	January 31	$	0.16	$	0.15
December 31	February 28		0.16		0.16
January 31	March 31		0.16		0.17
February 29	April 30		0.16		0.17
March 31	May 31		0.16		0.18
April 30	June 30		0.16		0.18
Cash distributions per Trust unit		$	0.96	$	1.01

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Reconciliation of Distributions Accruing to Unitholders

	3 months ended June 30,		6 months ended June 30,
	2004	2003	2004	2003
Distributions payable, beginning of period	$ 58,968	$ 54,080	$ 53,452	$ 30,065
Distributions accruing during the period
Cash flow provided by operating activities	51,166	41,806	126,059	123,868
Net change in non-cash operating working
capital balance	(1,346)	3,955	(27,192)	(19,488)
Amortization of the cost of commodity contracts	(242)	-	(463)	-
Redemption of exchangeable shares	(451)	(698)	(902)	(698)
Asset retirement reserve	(383)	(196)	(746)	(378)
Capital lease repayment	(88)	(953)	(174)	(1,888)
Cash flow before capital reinvestment	48,656	43,914	96,582	101,416
Weyburn deferred capital obligation	(34,930)	-	(34,930)	-
Capital expenditures	(7,500)	(7,500)	(15,000)	(15,000)
Total distributions accruing during the period	6,226	36,414	46,652	86,416
Distributions paid	(39,165)	(30,440)	(74,075)	(56,427)
Distributions payable, end of period	$ 26,029	$ 60,054	$ 26,029	$ 60,054

Accumulated Cash Distributions

	3 months ended June 30,		6 months ended June 30,
	2004	2003	2004	2003
Accumulated cash distributions, beginning of period	$ 622,032	$ 477,653	$ 581,155	$ 427,651
Distributions accruing during the period	6,226	36,414	46,652	86,416
Redemption of exchangeable shares	451	698	902	698
Accumulated cash distributions, end of period	$ 628,709	$ 514,765	$ 628,709	$ 514,765

8. ASSET RETIREMENT OBLIGATIONS and RESERVE FUND

(a) Asset Retirement Obligations

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:

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For the period ended June 30,	2004	2003
Balance at beginning of year	$ 16,846	$ 15,298
Initial fair value of ARO liability	32,771	30,497
Accretion expense	10,230	7,986
Previous recorded SR&A provision	(25,484)	(19,284)
Balance as at January 1, 2004 and 2003	34,363	34,497
Increase in liabilities during the period	336	1,137
Accretion expense during the period	1,108	1,122
Actual costs incurred during the period	(1,973)	(336)
Acquisition of Ultima properties (Note 3)	16,672	-
Balance at end of period	$ 50,506	$ 36,420

(b) Asset Retirement Reserve Fund

Previously this cash fund was being built up at a rate of $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 June 30, 2004 is $6.1 million, which includes the addition of $1.5 million on the acquisition of Ultima.

9. LONG-TERM COMMITMENTS

In the second quarter of 2004, PC acquired an additional interest in the Weyburn unit as a part of the Ultima acquisition which resulted in an increase in CO2 purchase commitments. Subsequent to end of the quarter, PC renewed its office lease and extended the term. The table below has been updated to reflect these changes.

(thousands of dollars)		2004		2005		2006		2007		2008
Capital leases	$	0.4	$	0.6	$	-	$	-	$	-
Office lease		1.6		2.1		2.3		2.3		2.3
Processing and transportation agreement		1.8		1.8		2.0		2.1		2.2
CO2 purchases		8.8		10.6		9.3		7.9		7.5
	$	12.6	$	15.1	$	13.6	$	12.3	$	12.0

10. 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 related contracts as at June 30, 2004 and the related unrealized gains or losses are summarized separately below:

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					Unrealized
		Volume	Price	Delivery	Gain (Loss)
Natural Gas	Term	mcf/d	$/mcf	Point	$000's
Collar	April 1, 2004 to	9,475	$5.17-$7.28	AECO	$(183)
	October 31, 2004
Collar	April 1, 2004 to	9,475	$5.07-$6.81	AECO	(345)
	October 31, 2004
Collar	April 1, 2004 to	1,895	$5.28-$7.39	AECO	(38)
	October 31, 2004
Fixed Price	April 1, 2004 to	4,737	$5.33	AECO	(907)
	October 31, 2004
Fixed Price	April 1, 2004 to	4,737	$6.26	AECO	(416)
	October 31, 2004
Collar	April 1, 2004 to	1,895	$5.28-$7.65	AECO	(26)
	October 31, 2004
Fixed Price	May 1, 2004 to	4,737	$6.86	AECO	(28)
	October 31, 2004
Three Way Collar	November 1, 2004 to	9,475	$4.74-$5.80-	AECO	(704)
	March 31, 2005		$8.97
Collar	November 1, 2004 to	9,475	$6.23-$10.82	AECO	(66)
	March 31, 2005
Collar	November 1, 2004 to	9,475	$6.23-$14.67	AECO	280
	March 31, 2005
Total					$(2,433)
					Unrealized
		Volume	Price	Delivery	Loss
Oil	Term	bbl/d	$/bbl	Point	$000's
Fixed Price	January 1, 2004 to	1,000	$35.01	Edmonton	$(2,571)
	December 31, 2004
Fixed Price	July 1, 2004 to	1,000	$37.90	Edmonton	(2,047)
	December 31, 2004
Three Way Collar	January 1, 2004 to	800	$26.67-$32.01-	Edmonton	(1,813)
	December 31, 2004		$36.55
Three Way Collar	January 1, 2004 to	700	$28.01-$33.35-	Edmonton	(1,200)
	December 31, 2004		$40.01
Three Way Collar	July 1, 2004 to	2,000	$28.36-$32.36-	Edmonton	(3,785)
	December 31, 2004		$38.68
Collar	July 1, 2004 to	2,000	$32.01-$37.35	Edmonton	(2,218)
	September 30, 2004
Collar	October 1, 2004 to	2,000	$32.01-$37.35	Edmonton	(2,132)
	December 31, 2004
Three Way Collar	January 1, 2005 to	1,000	$26.67-$32.01-	Edmonton	(3,365)
	December 31, 2005		$38.68
Three Way Collar	January 1, 2005 to	1,000	$31.76-$35.76-	Edmonton	(1,812)
	December 31, 2005		$45.10
Three Way Collar	January 1, 2005 to	1,000	$30.41-$35.75-	Edmonton	(1,979)
	December 31, 2005		$43.76
Total					$(22,922)

The oil contracts are transacted in U.S. dollars. They have been converted to Canadian dollars at the June 30, 2004 closing rate of $1.3338 C$: US$.

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					Unrealized
		Volume	Price		Gain
Electricity	Term	MW/h	$/MWh	Delivery Point	$000's
Fixed Price	February 1, 2004 to	2.0	$44.50	Alberta Power Pool	$329
	December 31, 2005
Fixed Price	January 1, 2004 to	1.0	$51.00	Alberta Power Pool	57
	December 31, 2004
Total					$386

Derivative financial instruments and physical 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 product sales.

11. INCOME TAX EXPENSE

Future income taxes increased by $12.1 million for the second quarter. The increase was attributable to the reduction of available tax pools which were utilized to offset the increase in taxable income of the operating subsidiary of the Trust. The increase resulted from the reduction of the royalty payable to the Trust, due to additional amounts withheld for capital expenditures.

NON-RESIDENT OWNERSHIP

As at July 30, 2004, based on the information provided by our transfer agent, Petrofund estimates that non-resident ownership of the Trust was approximately 58% down from 69% on April 30, 2004. This reduction is primarily due to the issuance of Petrofund Trust units in association with the acquisition of Ultima Energy Trust. Management of the Trust continues to review its options to achieve and maintain non-resident ownership levels below 50% by the January 1, 2007 deadline proposed by the Federal Government.

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

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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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