Edgar Filing: PETROFUND ENERGY TRUST

Filed by Filing Services Canada Inc. 403-717-3898

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

Form 6-K

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

For the month of: August 2005

Commission File Number: 00-115124

PETROFUND ENERGY TRUST

(Name of Registrant)

Barclay Centre

600 444 7Avenue SW

Calgary, Alberta

Canada T2P 0X8

(Address of Principal Executive Offices)

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

SIGNATURES

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

Date: August 9, 2005

By:

_signed "Hugo S^tJ. A. Potts"_________

Hugo S^tJ. A. Potts, Esq.

Corporate Secretary

EXHIBIT

Exhibit

Description of Exhibit

Second Quarter Report dated August 9, 2005.

EXHIBIT 1

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News Release

Calgary -August 9^th, 2005

CALGARY -October 5, 2004

Petrofund Energy Trust (TSX: PTF.UN; AMEX: PTF)

Announces Results for the Second Quarter of 2005

Petrofund Energy Trust is pleased to provide its results for the second quarter of 2005. Key items from the quarter include:

Average production for the second quarter was 36,011 boe per day, a 28% increase over the second quarter of last year.

Cash flow increased 76% over the second quarter of 2004 to $87.8 million. On a per unit basis, cash flow increased 34% to from $0.64 to $0.86.

Second quarter payout ratio was 56%, compared to 80% in the second quarter of 2004 and 67% in the first quarter of 2005.

Operating costs for the quarter, which include a prior period adjustment of $1.01 per boe, increased to $10.89 per boe due to increasing industry costs. This was an 18% increase over the second quarter of last year.

Net income increased from $817,000 in the second quarter of 2004 to $40.2 million in the second quarter of 2005, which equates to a per unit increase from $0.01 to $0.40.

General and administrative costs were down 8% from last year to $1.19 per boe.

The Trust exited the quarter with a 0.9:1.0 net debt to cash flow ratio based on annualized second quarter cash flow.

Second quarter development capital was $30.6 million with an over all drilling success rate of 96%.

Petrofund's second quarter report is presented below:

2nd Quarter Report

for three & six months ended June 30, 2005 & 2004

FINANCIAL HIGHLIGHTS
(thousands of Canadian dollars, except per unit amounts)
	3 months ended June 30,			6 months ended June 30,
	2005	2004	Variance	2005	2004	Variance
INCOME STATEMENT
Oil and natural gas sales ⁽⁵⁾	$ 172,831	$ 112,970	53%	$ 327,599	$ 212,669	54%
Cash flow ⁽¹⁾	$ 87,811	$ 49,820	76%	$ 160,770	$ 98,867	63%
Per unit ⁽²⁾	$ 0.86	$ 0.64	34%	$ 1.59	$ 1.30	22%
Per boe	$ 26.80	$ 19.52	37%	$ 24.93	$ 19.88	25%
Cash distributions paid per unit	$ 0.48	$ 0.48	-%	$ 0.96	$ 0.96	-%
Net income	$ 40,193	$ 817	4,821%	$ 59,436	$ 8,446	604%
Net income per unit
Basic	$ 0.40	$ 0.01	3,900%	$ 0.59	$ 0.11	436%
Diluted	$ 0.40	$ 0.01	3,900%	$ 0.59	$ 0.11	436%
UNITS AND EXCHANGEABLE SHARES OUTSTANDING ⁽²⁾
Weighted average	101,569	78,074	30%	101,088	75,874	33%
Diluted	101,593	78,229	30%	101,121	76,051	33%
At period-end	105,014	100,190	5%	105,014	100,190	5%
BALANCE SHEET
Working capital (deficit) ⁽³⁾				$ (47,812)	$ (30,955)		(55)%
Property, plant and equipment, net				$ 1,306,761	$ 1,251,484	4%
Long-term debt				$ 254,345	$ 212,537	20%
Unitholders' equity				$ 1,034,115	$ 1,063,704	1%
MARKET CAPITALIZATION, as at June 30				$ 2,047,767	$ 1,487,823	38%
TOTAL CAPITALIZATION, as at June 30 ^(3),(4)				$ 2,349,924	$ 1,731,615	36%
TRUST UNIT TRADING (TSX: PTF.UN)
High	$ 19.97	$ 18.08	10%	$ 19.97	$ 19.24	4%
Low	$ 17.00	$ 14.70	16%	$ 15.50	$ 14.56	6%
Close	$ 19.50	$ 14.85	31%	$ 19.50	$ 14.85	31%
Average daily volumes	176	189	(7)%	219	197	12%
TRUST UNIT TRADING (AMEX: PTF)
High	$ 16.25	$ 13.54	20%	$ 15.92	$ 14.96	9%
Low	$ 13.62	$ 10.95	24%	$ 12.66	$ 10.95	16%
Close	$ 15.92	$ 11.16	43%	$ 15.92	$ 11.16	43%
Average daily volumes	469	319	47%	554	477	16%

(1) Cash flow before net changes in non-cash operating working capital balances (Non-GAAP measure, see special notes in the Management Discussion and Analysis). (2) See Note 3 to Interim Consolidated Financial Statements. (3) Excludes net unrealized gains/losses on commodity contracts. (4) Total capitalization equals market capitalization plus net debt. (Non-GAAP measure, see special notes in the Management Discussion and Analysis). (5) Prices and revenue are before realized gains/losses on commodity contracts and before transportation costs.
FINANCIAL HIGHLIGHTS
(thousands of Canadian dollars, except per unit amounts)
	3 months ended June 30,			6 months ended June 30,
	2005	2004	Variance	2005	2004	Variance
INCOME STATEMENT
Oil and natural gas sales ⁽⁵⁾	$ 172,831	$ 112,970	53%	$ 327,599	$ 212,669	54%
Cash flow ⁽¹⁾	$ 87,811	$ 49,820	76%	$ 160,770	$ 98,867	63%
Per unit ⁽²⁾	$ 0.86	$ 0.64	34%	$ 1.59	$ 1.30	22%
Per boe	$ 26.80	$ 19.52	37%	$ 24.93	$ 19.88	25%
Cash distributions paid per unit	$ 0.48	$ 0.48	-%	$ 0.96	$ 0.96	-%
Net income	$ 40,193	$ 817	4,821%	$ 59,436	$ 8,446	604%
Net income per unit
Basic	$ 0.40	$ 0.01	3,900%	$ 0.59	$ 0.11	436%
Diluted	$ 0.40	$ 0.01	3,900%	$ 0.59	$ 0.11	436%
UNITS AND EXCHANGEABLE SHARES OUTSTANDING ⁽²⁾
Weighted average	101,569	78,074	30%	101,088	75,874	33%
Diluted	101,593	78,229	30%	101,121	76,051	33%
At period-end	105,014	100,190	5%	105,014	100,190	5%
BALANCE SHEET
Working capital (deficit) ⁽³⁾				$ (47,812)	$ (30,955)		(55)%
Property, plant and equipment, net				$ 1,306,761	$ 1,251,484	4%
Long-term debt				$ 254,345	$ 212,537	20%
Unitholders' equity				$ 1,034,115	$ 1,063,704	1%
MARKET CAPITALIZATION, as at June 30				$ 2,047,767	$ 1,487,823	38%
TOTAL CAPITALIZATION, as at June 30 ^(3),(4)				$ 2,349,924	$ 1,731,615	36%
TRUST UNIT TRADING (TSX: PTF.UN)
High	$ 19.97	$ 18.08	10%	$ 19.97	$ 19.24	4%
Low	$ 17.00	$ 14.70	16%	$ 15.50	$ 14.56	6%
Close	$ 19.50	$ 14.85	31%	$ 19.50	$ 14.85	31%
Average daily volumes	176	189	(7)%	219	197	12%
TRUST UNIT TRADING (AMEX: PTF)
High	$ 16.25	$ 13.54	20%	$ 15.92	$ 14.96	9%
Low	$ 13.62	$ 10.95	24%	$ 12.66	$ 10.95	16%
Close	$ 15.92	$ 11.16	43%	$ 15.92	$ 11.16	43%
Average daily volumes	469	319	47%	554	477	16%

(1)

Cash flow before net changes in non-cash operating working capital balances

(Non-GAAP measure, see special notes in the Management Discussion and Analysis).

(2)

See Note 3 to Interim Consolidated Financial Statements.

(3)

Excludes net unrealized gains/losses on commodity contracts.

(4)

Total capitalization equals market capitalization plus net debt.

(Non-GAAP measure, see special notes in the Management Discussion and Analysis).

(5)

Prices and revenue are before realized gains/losses on commodity contracts and before transportation costs.

OPERATIONAL HIGHLIGHTS
(thousands of Canadian dollars, except per unit amounts)
	3 months ended June 30,			6 months ended June 30,
	2005	2004	Variance	2005	2004	Variance
DAILY PRODUCTION
Oil (bbls)	17,500	12,679	38%	17,867	12,129	47%
Natural gas (mcf)	96,951	79,741	22%	92,635	78,833	18%
Natural gas liquids (bbls)	2,353	2,074	13%	2,318	2,057	13%
BOE (6:1)	36,011	28,043	28%	35,624	27,325	30%
Total production (mboe)	3,277	2,552	28%	6,448	4,973	30%
PRODUCTION PROFILE
Oil	49%	45%		50%	44%
Natural gas	44%	48%		43%	49%
Natural gas liquids	7%	7%		7%	7%
PRICES ⁽⁵⁾
Oil (per bbl)	$ 59.18	$ 47.01	26%	$ 56.93	44.86	27%
Natural gas (per mcf)	$ 7.65	$ 7.13	7%	$ 7.33	6.95	5%
Natural gas liquids (per bbl)	$ 51.10	$ 37.13	38%	$ 48.62	37.09	31%
BOE (6:1)	$ 52.69	$ 44.27	19%	$ 50.77	$ 42.75	19%
Cash operating netback per BOE	$ 29.28	$ 22.05	33%	$ 27.39	$ 22.38	22%
LEASE OPERATING COSTS	$ 35,677	$ 23,639	(51)%	$ 67,687	$ 43,468	(56)%
Cost per boe	$ 10.89	$ 9.26	(18)%	$ 10.50	$ 8.74	(20)%
GENERAL AND ADMINISTRATIVE COSTS	$ 3,902	$ 3,316	(18)%	$ 7,541	$ 6,454	(17)%
Cost per boe	$ 1.19	$ 1.30	8%	$ 1.17	$ 1.30	10%

Management Discussion & Analysis

three and six months ended June 30, 2005

The following Management Discussion and Analysis ("MD&A") of financial results should be read in conjunction with the unaudited Consolidated Financial Statements of Petrofund Energy Trust ("Petrofund" or the "Trust") for the six months ended June 30, 2005 and the December 31, 2004 audited Consolidated Financial Statements and Management's Discussion and Analysis included in the Trust's 2004 annual report. All oil and natural gas properties are held by Petrofund Corp. ("PC") a wholly owned subsidiary of the Trust. This commentary is based on information available to August 9, 2005. Additional information (including Petrofund's annual information form) can be obtained on SEDAR at www.sedar.com or on the Trust's website at www.petrofund.ca.

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

NON GAAP MEASURES

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 generally accepted accounting principles ("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 from operating activities before changes in non-cash working capital.

Management uses certain key performance indicators and industry benchmarks such as operating netbacks ("netbacks"), finding, development and acquisition costs ("FD&A"), and total capitalization to analyze financial and operating performance. These performance indicators and benchmarks as presented do not have any standardized meaning prescribed by Canadian GAAP and, therefore, may not be comparable with the calculation of similar measures for other entities.

FORWARD-LOOKING STATEMENTS

This discussion and analysis contains forward-looking statements relating to future events or future performance. In some cases, forward-looking statements can be identified by terminology such as "may", "will", "should", "expect", "projects", "plans", "anticipates" and similar expressions. These statements represent management's expectations or beliefs concerning, among other things, future operating results and various components thereof affecting the economic performance of the

Trust. Undue reliance should not be placed on these forward-looking statements which are based upon management's assumptions and are subject to known and unknown risks and uncertainties, including the business risks discussed above, which may cause actual performance and financial results in future periods to differ materially from any projections of future performance or results expressed or implied by such forward-looking statements. Accordingly, readers are cautioned that events or circumstances could cause results to differ materially from those predicted.

RESULT SUMMARY

SECOND QUARTER 2005 VERSUS FIRST QUARTER 2005

The Trust generated cash flow of $87.8 million or $0.86 per unit in the second quarter of 2005 compared to $73.0 million or $0.73 per unit in the first quarter of 2005. The Trust maintained monthly cash distributions of $0.16 per unit in the second quarter of 2005. The Trust's payout ratio of 56% in the second quarter of 2005 compared to payout ratio of 67% in the first quarter of 2005.

The second quarter of 2005 was an active quarter for Petrofund in property acquisitions, plus drilling and development activities. Total expenditures for the quarter were $104.1 million. These activities provide new production in the second quarter and for the third and fourth quarters of 2005, as discussed further in the Operational Highlights.

The Trust completed an equity offering raising gross proceeds of $75.7 million ($71.5 million net) in the second quarter of 2005. A total of 4,150,000 units were issued at $18.25 per unit.

Daily production volumes in the second quarter of 2005 of 36,011 boe were slightly above the first quarter volumes of 2005 of 35,234 boe. This increase resulted from acquisitions and development activities for the first and second quarters of 2005 offset by the natural production decline.

Net income of $40.2 million in the second quarter of 2005 increased from $19.2 million in the first quarter of 2005, mainly due to a change of $33.6 million in non-cash adjustments on commodity contracts. The Trust recognized an unrealized (non-cash) commodity gain of $9.7 million versus an unrealized (non-cash) commodity loss of $23.8 million in the first quarter of 2005. Both adjustments were a result of the accounting standard governing price risk management activity. In addition, the future income tax expense in the second quarter of 2005 was $10.4 million compared to $12.7 million recovery in the first quarter of 2005.

The cash loss on commodity contracts during the second quarter of 2005 was $8.0 million compared to an $8.2 million loss in the first quarter of 2005.

Royalties were 18% of revenue in the second quarter of 2005, compared to 20% for the three months ended March 31, 2005.

Lease operating costs on a unit basis increased to $10.89/boe in the second quarter of 2005 from $10.09/boe in the first quarter of 2005. Costs for repairs and maintenance continue to increase as a result of high levels of activity in the upstream sector. In addition, Petrofund incurred costs of $3.3 million or $1.01/boe from prior years' adjustments which includes a $1.0 million adjustment to processing fees for the years 2002 through 2004 from a partner operated facility.

HIGHLIGHTS OF THE THREE AND SIX MONTHS ENDED JUNE 30, 2005

The Trust paid out cash distributions of $0.48 per unit in the second quarter of 2005 as compared to $0.48 per unit in the second quarter of 2004.

The Trust's payout ratio for the six months ended June 30, 2005 was 61% compared to 77% in 2004. The payout ratio in the second quarter of 2005 was 56% compared to 80% in the same quarter of 2004.

Net income increased to $40.2 million in the second quarter of 2005 versus $817,000 in the second quarter of 2004.

The Trust generated cash flow of $87.8 million, an increase of 76% over the second quarter of 2004.

Average production on a boe basis increased 28% to 36,011 boe/d in the second quarter of 2005 from 28,043 boe/d in the second quarter of 2004. The change in production reflects the acquisition of Ultima Energy Trust ("Ultima") in June of 2004, PC's development drilling program, the Central Alberta acquisition in November 2004 and the 2005 acquisitions listed later in this section, offset by natural production decline.

Average prices in the second quarter of 2005 were up 19% on a boe basis from the same period the prior year and 19% on a boe basis for the six months ending June 30, 2005 compared to the same period in 2004.

Petrofund has a strong balance sheet with a net debt to cash flow ratio of 0.9:1.0 of annualized second quarter 2005 cash flow.

To date in 2005, Petrofund has acquired interests in various oil and gas properties for $62.6 million (excluding the non-cash working capital assumed of $4.8 million, future income taxes of $10.4 million and asset retirement obligations of $1.2 million), which includes the purchase of Northern Crown Petroleums Ltd. ("Northern Crown"), Tahiti Gas Ltd. ("Tahiti") and property interests in the Turin area. These acquisitions are expected to add approximately 1,365 boepd of production to the Trust. Petrofund's internal estimate of reserves additions is 4.0 million boe on a proved plus probable basis.

The Trust completed a "bought deal" financing of Trust units, raising gross proceeds of $75.7 million ($71.5 million net) in the second quarter of 2005.

The Trust has a balanced production profile which averaged 43% natural gas and 57% oil and liquids in the first half of 2005.

The weighted average Trust units outstanding increased from 78.1 million in the second quarter of 2004 to 101.6 million in the second quarter of 2005. As at June 30, 2005 there was 105.0 million Trust units outstanding.

The Trust market capitalization as at June 30, 2005, was approximately $2.0 billion ($1.5 billion June 30, 2004).

OPERATIONAL HIGHLIGHTS

Petrofund continued with its aggressive drilling program in the second quarter of 2005. In spite of adverse weather conditions, a total of 48 wells were drilled, comprising 46 working interest wells (14.7 net) and two farmout wells. This activity resulted in 30 oil wells, 16 gas wells and two abandoned wells for an overall success rate of 96%.

Significant second quarter activity included the following projects:

July Lake, British Columbia

Petrofund equipped and pipeline connected four 100% owned gas wells drilled earlier this year. Production from these new drills averaged 4.3 mmcf/d for the quarter.

Turin, Alberta

Petrofund drilled four wells during the quarter, resulting in two gas wells, one oil well and one dry hole. Two of these three wells (one gas well is yet to be equipped), together with four other wells drilled in the first quarter, are producing 150 boe/d net to Petrofund's production base.

Weyburn, Saskatchewan

A total of 10 wells (2.0 net) were drilled in the Weyburn Unit during the quarter, the majority of these within the carbon dioxide flood area. Petrofund's net incremental production from these new wells is approximately 200 boe/d.

Armisie, Alberta

Approximately 400 boe/d of production from this area was restored during the second quarter after it had been shut-in for most of the first quarter due to capacity restrictions at a third party gas processing facility.

Three Hills Creek, Alberta

Petrofund drilled a 100% working interest gas well in the second quarter but wet weather delayed completion and tie-in of the well until the third quarter. This well is expected to produce approximately 1 mmcf/d. In addition, Petrofund increased production by an incremental 750 mcf/d through its 35% working interest in a 28 well coalbed methane gas project that commenced production in the second quarter.

Silverton, Saskatchewan

Petrofund, as operator, drilled a successful horizontal Frobisher oil well that is expected to come on stream in the third quarter at approximately 30 boe/d net.

Swan Hills, Alberta

Six infill oil wells (0.7 net) were drilled in the Swan Hills Unit #1 during the second quarter. Based on initial test rates, these six new wells, plus a seventh well drilled earlier, boosted Petrofund's production by 100 boe/d net.

Brassey, British Columbia

Four successful gas wells (0.6 net) were drilled and completed on Petrofund lands during the quarter. These wells are scheduled to start producing in the third quarter and, in total, are expected to add 600 mcf/d net to Petrofund's production.

Dodsland, Saskatchewan

Three 100% working interest Viking gas wells were drilled and cased during the quarter, but wet weather delayed completion until the third quarter. It is expected that these wells will collectively produce 750 mcf/d.

CASH DISTRIBUTIONS

	3 months ended June 30,		6 months ended June 30,
	2005	2004	2005	2004
Distributions paid per unit	$ 0.48	$ 0.48	$ 0.96	$ 0.96

Trust unitholders who held their units throughout the second quarter of 2005 received cash distributions of $0.48 per unit as compared to $0.48 per unit in 2004. For 2005 the Trust distributed $0.16 per unit in July, has announced $0.16 per unit for August, and has indicated $0.16 per unit for September.

Petrofund monitors the distribution payout with respect to forecasted funds flow, debt levels and spending plans. The level of cash retained historically has varied between 10% and 30% of annual funds flow; however, Petrofund adjusts payout levels in an effort to balance the investor's desire for near-term distributions with the Trust's requirement to maintain a prudent capital structure.

The Trust generated cash flow available for distribution before reserve for capital expenditures in the second quarter of 2005 of $86.9 million (2004 - $48.7 million). The Trust paid out $48.8 million (2004 - $39.2 million) in distributions representing a payout ratio of 56% (2004 -80%).

During the six months ended June 30, 2005 the Trust generated cash flow available for distribution before reserve for capital expenditures of $158.6 million (2004 - $96.6 million). The Trust paid out $96.7 million (2004 - $74.1 million) in distributions representing a payout ratio of 61% (2004 - 77%).

For the 12 months ended June 30, 2005, the Trust generated cash flow available for distribution of $293.6 million, and allocated $60.0 million for investment in development drilling and other projects.

Distributions of $192.3 million were paid out, representing a payout ratio of 65%. For a detailed analysis of cash flow available for distribution and distributions paid refer to Note 8 to the Interim Consolidated Financial Statements.

CASH DISTRIBUTION PAID HISTORY ⁽¹⁾

Calendar Year	Distributions ⁽²⁾	Taxable Portion	Return of Capital
1989 to 1996	$ 20.8950	$ -	$ 20.8950
1997	2.3700	-	2.3700
1998	1.4400	-	1.4400
1999	1.8300	-	1.8300
2000	3.9900	2.4633	1.5267
2001	4.2400	2.6771	1.5629
2002	1.7100	0.9365	0.7735
2003	2.0900	1.0706	1.0194
2004	1.9200	1.4849	0.4351
2005 Y-T-D	0.9600 (3)	0.9120	0.0480
Cumulative	$ 41.4450	$ 9.5444	$ 31.9006
(1) Applies to unitholders who are residents of Canada and hold the units as capital property. (2) Based on cash distributions paid in the calendar year and adjusted for unit splits. (3) Petrofund estimates that approximately 95% of cash distributions paid in 2005 to Canadian and U.S. unitholders will be taxable and the remaining 5% will be treated as a tax deferred return of capital. Actual taxable amounts may vary depending on actual distributions and are dependent upon production, commodity prices and funds flow experienced throughout the year. For U.S. taxpayers, the taxable portion of the cash distribution is considered to be a dividend for U.S. tax purposes and it is expected that the dividend should be a "Qualified Dividend" eligible for the reduced tax rate. This is a general guideline and not intended to be legal advice to any particular holder or potential holder of Petrofund Energy Trust. This information is not exhaustive of all possible U.S. income tax considerations. Unitholders or potential holders of Petrofund Energy Trust should consult their own legal and tax advisers as to the particular tax consequences of holding their Petrofund Energy Trust units.

Taxation of Cash Distributions

Cash distributions comprise a return of capital portion (tax deferred) and a return on capital portion (taxable). The return of capital component reduces the cost basis of the trust units held. For additional information, please see our website at www.petrofund.ca.

RESULTS OF OPERATIONS

PRODUCTION

In accordance with Canadian practice, production volumes and reserves are reported on a working interest basis, before deduction of Crown and other royalties, unless otherwise indicated.

Production volumes averaged 36,011 boe/d in the second quarter of 2005, an increase of 28% over average production volumes of 28,043 boe/d in the second quarter of 2004. The change in production reflects the acquisition of Ultima in June of 2004, PC's development drilling program, the Central Alberta acquisition in November 2004, Turin area in January 2005 and the Northern Crown and Tahiti acquisitions in May 2005, offset by natural production decline.

	3 months ended June 30,		6 months ended June 30,
Daily Production	2005	2004	2005	2004
Oil (bbls)	17,500	12,679	17,867	12,129
Natural gas (mcf)	96,951	79,741	92,635	78,833
Natural gas liquids (bbls)	2,353	2,074	2,318	2,057
Total (boe 6:1)	36,011	28,043	35,624	27,325

PRICING AND PRICE RISK MANAGEMENT

Revenues from the sale of crude oil, natural gas, and natural gas liquids and sulphur increased 53% to $172.8 million in the second quarter of 2005 from $113.0 million in the second quarter of 2004 due to a 28% increase in production and a 19% increase in prices on a boe basis.

For the six month period ended June 30, 2005, revenue increased 54% to $327.6 million from $212.7 million in 2004 due to a 30% increase in production to 35,624 boe/d and an increase of 19% in the average price per boe to $50.77 in 2005 from $42.75 in 2004.

Crude oil sales increased to $94.2 million in the second quarter of 2005 from $54.2 million in the second quarter of 2004 due to a 38% increase in production from 12,679 bbl/d in the second quarter of 2004 to 17,500 bbl/d in the second quarter of 2005 and a 26% increase in the oil price. The average WTI oil price increased from $38.31 US/bbl in 2004 to $53.20 US/bbl in the second quarter of 2005 or 39%, however, the Canadian par price at Edmonton increased only 30% from $50.61/bbl to $65.76/bbl due to the significant strengthening of the Canadian dollar relative to the U.S. dollar which averaged $0.80 in the second quarter of 2005 versus $0.74 in the second quarter of 2004. The average Canadian wellhead price received by Petrofund increased from $47.01/bbl in the second quarter of 2004 to $59.18/bbl in the second quarter of 2005. Petrofund's differential from Edmonton par was $3.60/bbl in the second quarter of 2004 versus $6.58/bbl in the second quarter of 2005 as quality differentials for medium crudes have increased.

During the six month period ended June 30, 2005, crude oil sales increased 86% to $184.1 million in 2005 from $99.0 million in 2004. Oil production increased 47% to 17,867 bbl/d for the period, compared to 12,129 bbl/d for the same period in 2004. The average price increased from $44.86/bbl in 2004 to $56.93/bbl in 2005. The WTI U.S. price increased from $36.73 US/bbl for six months ending June 30, 2004 to $51.52 US/bbl in the same period in 2005.

Natural gas sales increased to $67.5 million in the second quarter of 2005 from $51.7 million in the second quarter of 2004 due to 22% increase in production and a 7% increase in the average prices received from $7.13/mcf in the second quarter of 2004 to $7.65/mcf in the second quarter of 2005. The monthly AECO price per mmbtu increased from $6.80 in the second quarter of 2004 to $7.37 in the second quarter of 2005. Production volumes averaged 97.0 mmcf/d in the second quarter of 2005 compared to 79.7 mmcf/d in the second quarter of 2004.

During the six month period ended June 30, 2005, natural gas sales increased 23% to $122.9 million in 2005 from $99.7 million in 2004. Natural gas production increased 18% from 78.8 mmcf/d in 2004 to 92.6 mmcf/d in 2005. The average price increased 5% from $6.95/mcf in 2004 to $7.33/mcf in 2005.

Sales of natural gas liquids and sulphur increased to $11.1 million in the second quarter of 2005 from $7.0 million in the second quarter of 2004 as natural gas liquids production increased 13% to 2,353 bbl/d in the second quarter of 2005 from 2,074 bbl/d in the second quarter of 2004. The average price, excluding sulphur, increased 38% from $37.13/bbl in the second quarter of 2004 to $51.10/bbl in the second quarter of 2005.

For the six month period ended June 30, 2005, sales of natural gas liquids and sulphur increased 47% from $14.0 million in 2004 to $20.6 million in 2005. Production volumes of natural gas liquids increased 13% from 2,057 bbl/d to 2,318 bbl/d, and the average price, excluding sulphur, increased 31% from $37.09/bbl in 2004 to $48.62/bbl in 2005.

	3 months ended June 30,		6 months ended June 30,
Average Prices ⁽¹⁾	2005	2004	2005	2004
Oil (per bbl)	$ 59.18	$ 47.01	$ 56.93	$ 44.86
Natural gas (per mcf)	7.65	7.13	7.33	6.95
Natural gas liquids (per bbl)	51.10	37.13	48.62	37.09
Weighted average (6:1)	$ 52.69	$ 44.27	$ 50.77	$ 42.75

	3 months ended June 30,		6 months ended June 30,
Production Revenue ($ millions) ⁽¹⁾	2005	2004	2005	2004
Oil	$ 94.2	$ 54.2	$ 184.1	$ 99.0
Natural gas	67.5	51.7	122.9	99.7
Natural gas liquids & sulphur	11.1	7.0	20.6	14.0
Total	$ 172.8	$ 112.9	$ 327.6	$ 212.7

⁽¹⁾ Prices and revenue are before realized gains/losses on commodity contracts and before transportation costs.

The Trust has a formal risk management policy which permits the Risk Management Committee to use specified price risk management strategies for up to 40% of crude oil, 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 for a maximum of eighteen months beyond the current date. The program is designed to provide price protection on a portion of the Trust's future production in the event of adverse commodity price movement, while retaining significant exposure to upside price movements. By doing this, the Trust seeks to provide a measure of stability to cash distributions as well as ensure Petrofund realizes positive economic returns from its capital development and acquisition activities.

As at June 30, 2005, Petrofund had 22.9 mmcf/d of natural gas and 5,000 bbl/d of crude oil hedged for remainder of 2005 and 6.3 mmcf/d of natural gas and 2,750 bbl/d of crude oil hedged for 2006. A summary of the hedged volumes and prices by quarter is shown in the following table (see Note 9 to the Interim Consolidated Financial Statements for a detailed disclosure of all derivative financial instruments and their corresponding mark-to-market values):

	Average Volumes (mcf/d)
	2005			2006
Natural Gas	2005	Q3	Q4	2006	Q1	Q2	Q3	Q4
Fixed	2,369	4,737	-	-	-	-	-	-
Collars	14,211	18,948	9,474	1,184	4,737	-	-	-
Three way collars	6,316	4,737	7,895	5,132	9,474	4,737	4,737	1,579
Total mcf/d	22,896	28,422	17,369	6,316	14,211	4,737	4,737	1,579

	Average Prices ($/mcf)
Fixed price	$ 7.06	$ 7.06	$ -	$ -	$ -	$ -	$ -	$ -
Collar ceiling price	10.36	8.73	11.98	13.61	13.61	-	-	-
Collar floor price	6.65	6.33	6.96	7.28	7.28	-	-	-
Three way ceiling price	9.21	7.92	10.49	9.92	11.77	8.99	8.99	8.99
Three way floor price	6.04	5.80	6.28	7.10	6.52	7.39	7.39	7.39
Three way floor short	$ 4.99	$ 4.75	$ 5.23	$ 5.87	$ 5.47	$ 6.07	$ 6.07	$ 6.07

	Average Volumes (bbl/d)
	2005			2006
Oil	2005	Q3	Q4	2006	Q1	Q2	Q3	Q4
Collared	1,000	1,000	1,000	2,250	3,000	3,000	2,000	1,000
Three way collars	4,000	4,000	4,000	500	1,000	1,000	-	-
Total bbl/d	5,000	5,000	5,000	2,750	4,000	4,000	2,000	1,000

	Average Prices ( $ /bbl)
	2005			2006
Oil	2005	Q3	Q4	2006	Q1	Q2	Q3	Q4
Collar ceiling price	$ 72.61	$ 72.83	$ 72.38	$ 83.28	$ 81.18	$ 86.19	$ 86.09	$ 79.65
Collar floor price	50.55	50.77	50.33	59.69	55.96	60.25	61.27	61.27
Three way ceiling price	47.39	47.39	47.39	68.78	64.95	72.60	-	-
Three way floor price	35.75	35.75	35.75	50.25	49.02	51.47	-	-
Three way floor short	$ 30.97	$ 30.97	$ 30.97	$ 44.12	$ 42.89	$ 45.34	$ -	$ -

	2005			2006
Alberta Power	2005	Q3	Q4	2006	Q1	Q2	Q3	Q4
Fixed MW/h	2.0	2.0	2.0	-	-	-	-	-
Fixed price ($/MWh)	$ 44.50	$ 44.50	$ 44.50	$ -	$ -	$ -	$ -	$ -

Three-way Collars

A three-way collar is transacted by selling a call to create a ceiling, buying a put to create a floor, then selling a put below the floor to create a floor short. For example, a three-way collar of $35 - $40 - $50 would result in the following prices received. For market prices above the ceiling ($50), Petrofund receives $50. For market prices between the ceiling and the floor ($40-$50), Petrofund receives the market price. For market prices between the floor and the floor short ($35-$40), Petrofund receives $40. For market prices below the floor short ($35), Petrofund receives the market price plus $5.

After June 30, 2005 and as at August 9, 2005, Petrofund had entered into the following additional hedges (not included in the table above):

Collar for November 1, 2005 to March 31, 2006 for 4.7 mmcf/d of natural gas between $7.39/mcf and $16.14/mcf.

Collar for April 1, 2006 to October 31, 2006 for 4.7 mmcf/d of natural gas between $7.39/mcf and $10.55/mcf.

Collar for January 1, 2006 to March 31, 2006 for 1,000 bbl/d of crude (WTI) between $61.27/bbl and $98.03/bbl.

Collar for April 1, 2006 to June 30, 2006 for 1,000 bbl/d of crude (WTI) between $61.27/bbl and $99.26/bbl.

Collar for July 1, 2006 to September 30, 2006 for 1,000 bbl/d of crude (WTI) between $61.27/bbl and $98.95/bbl.

Petrofund has no volumes hedged after December 31, 2006. All foreign exchange calculations in this section of the report incorporate the Bank of Canada US dollar rate at the close on June 30, 2005 of CDN $1.2254:US$.

GAIN (LOSS) ON COMMODITY CONTRACTS ($ thousands)
	3 months ended June 30,		6 months ended June 30,
	2005	2004	2005	2004
Realized cash losses	$ (8,023)	$ (8,888)	$ (16,189)	$(13,788)
Change in fair value
Fair value, beginning of period	(35,090)	(16,901)	(11,318)	(6,771)
Fair value of Ultima contracts required	-	(5,584)	-	(5,584)
Less fair value, end of period	(25,262)	(24,970)	(25,262)	(24,970)
Change in fair value of financial instruments	9,828	(2,485)	(13,944)	(12,615)
Amortization of deferred commodity contracts	(91)	(2,167)	(150)	(4,628)
Total non-cash adjustments	9,737	(4,652)	(14,094)	(17,243)
Total	$ 1,714	$ (13,540)	$(30,283)	$ (31,031)

ROYALTIES
	3 months ended June 30,		6 months ended June 30,
	2005	2004	2005	2004
Royalties ($ millions)	$ 31.1	$ 23.0	$ 63.0	$ 41.6
Average royalty rate (%)	18	20	19	20
$/boe	$ 9.49	$ 9.02	$ 9.76	$ 8.36

Royalties, which include crown, freehold and overrides paid on oil and natural gas production, increased to $31.1 million in the second quarter of 2005 from $23.0 million in the second quarter of 2004, net of the Alberta Royalty Credit ("ARC"). Royalties, as a percentage of revenues before hedging losses, decreased to 18% of revenues in the second quarter of 2005 from 20% of revenues in the second quarter of 2004.

For the six months period ended June 30, 2005 royalties were 19% in 2005 compared to 20% in 2004. We expect royalties to remain at approximately 20% of oil and gas sales for the remainder of the year.

EXPENSES
	3 months ended June 30,		6 months ended June 30,
	2005	2004	2005	2004
Expenses ($ millions)
Lease operating	$ 35.7	$ 23.6	$ 67.7	$ 43.5
Transportation	1.9	1.2	3.9	2.5
General & administrative	3.9	3.3	7.5	6.5
Financing costs	2.6	1.2	4.7	2.1


Expenses per boe
Lease operating	$ 10.89	$ 9.26	$ 10.50	$ 8.74
Transportation	0.58	0.45	0.61	0.50
General & administrative	1.19	1.30	1.17	1.30
Financing costs	0.79	0.46	0.73	0.42

Lease Operating

Oil and gas lease operating expenses increased 51% to $35.7 million in the second quarter of 2005 from $23.6 million in the second quarter of 2004 due to a 28% increase in production and an 18% increase in costs on a boe basis. Operating costs on a boe basis increased to $10.89 in the second quarter of 2005 from $9.26 in the second quarter of 2004. Costs in the second quarter of 2005 include prior years' adjustments of $3.3 million or $1.01 per boe.

Operating costs for the six month period ended June 30, 2005 were up 20% to $10.50 per boe compared to $8.74 per boe in the prior year. Costs for repairs and maintenance continue to increase as a result of high level of activity in the upstream sector. In addition, Petrofund incurred costs of $5.9 million or $0.91 per boe from prior years' adjustments.

The most significant contributor to the higher per unit operating costs to date in 2005 has been a general industry increases for all types of services and supplies including surface and downhole well repair and maintenance costs and facility maintenance work. In addition, the current high product price environment is driving average operating costs higher because marginal, higher cost properties continue to generate positive cash flow at higher than historical per unit costs and, as a result, remain on production longer. Operating costs in the second half of 2005 are expected to remain above $10.00 per boe.

Transportation Costs

Transportation costs on a boe basis were $0.58 in the second quarter of 2005 as compared to $0.45 for the second quarter of 2004, which reflects the higher transportation costs associated with the Ultima properties.

Transportation costs on a boe basis were $0.61 in the six months ending June 30, 2005 as compared to $0.50 for the six months ending June 30, 2004, which reflects the higher transportation costs associated with the Ultima properties.

General & Administrative ("G&A")

G&A costs on a boe basis were $1.19 per boe in the second quarter 2005 as compared to $1.30 per boe in the same period 2004. General and administrative costs, net of overhead recoveries, increased to $3.9 million in 2005 from $3.3 million in 2004. G&A costs in the second quarter of 2005 included $101,000 directly relating to the external costs associated with compliance with Section 404 of the Sarbanes-Oxley Act ("SOX 404") which equates to $0.03 per boe.

General and administrative costs for the six month period ended June 30, 2005, were $7.5 million in 2005 compared to $6.5 million in 2004. Costs were down 10% to $1.17 per boe compared to $1.30 per boe in 2004. We are maintaining our G&A cost target of approximately $1.25/boe for 2005.

Financing Costs

Financing costs and increases in loan balances as noted below reflects PC's active property acquisitions, plus drilling and development activities.

Interest and other financing costs increased to $2.6 million in the second quarter of 2005 from $1.2 million in the second quarter of 2004 due to the increase in the average loan balance outstanding in the second quarter of 2005 was $275.8 million versus $130.7 million in the second quarter of 2004.

Interest and other financing costs for six months ended June 30, 2005, increased to $4.7 million in 2005 compared to $2.1 million in 2004, which reflects the increase in the average loan balance outstanding in 2005 of $254.5 million from $110.3 million in 2004.

The bank loan outstanding at June 30, 2005, was $254.3 million as compared to $214.4 million at December 31, 2004. At June 30, 2005, 100% of our debt was based on floating interest rates.

DEPLETION, DEPRECIATION & ACCRETION

Depletion, depreciation and accretion expense increased to $47.2 million in the second quarter of 2005 from $33.1 million in the second quarter of 2004 due to the increase in production and an increase in the depletion rate. The rate per boe increased to $14.41 in the second quarter of 2005 from $12.97 in the second quarter of 2004. The

increase in the rate over 2004 and into 2005 reflects the increasing cost of acquisitions. Unproved properties are included in the depletion and depreciation expense calculation.

The provision for depletion, depreciation and accretion for the six months ended in June 30, 2005, was $90.9 million or $14.10 per boe as compared to $62.6 million or $12.60 per boe for 2004.

INCOME TAXES

Current taxes consist of the Federal Large Corporations Tax and some minor amounts relating to income taxes of corporate entities acquired. The Federal Large Corporations Tax is based primarily on the debt and equity balances of the Trust's 100% owned subsidiary, PC as at June 30, 2005. The Federal Large Corporations Tax rate is being reduced in stages over a period of five years, so that by 2008, the tax will be eliminated.

Capital taxes of $1.4 million in the second quarter of 2005 (2004 - $919,000) are primarily the Saskatchewan Capital Tax and Resource Surcharge, which is based upon gross revenues earned in Saskatchewan. On March 23, 2005, Saskatchewan Finance passed its 2005 budget that included an amendment to subject Trusts to the Corporation Capital Tax Resources Surcharge ("Resource Surcharge") effective April 1, 2005. Previously, the resource surcharge did not apply to resource trusts and therefore Petrofund Ventures Trust ("PVT"), a 100% owned subsidiary of the Trust, was not previously impacted by the resource surcharge. The resource surcharge is calculated based on a rate applicable to working interest oil and natural gas revenue earned in Saskatchewan at a rate of 3.6 percent on revenue from wells drilled prior to October 1, 2002 and a rate of two percent on revenue from wells drilled on or after October 1, 2002. PVT has estimated that cash flow will be reduced by approximately $500,000 per quarter, commencing in the second quarter of 2005.

Future income tax liabilities arise due to the differences between the tax basis of PC's assets and their respective accounting carrying cost. The future income tax expense in the second quarter of 2005 was $10.4 million compared to $12.1 million expense in the second quarter of 2004 as a result of a decrease in the statutory rate.

NET INCOME

	3 months ended June 30,		6 months ended June 30,
	2005	2004	2005	2004
Net income ($000's)	$ 40,193	$ 817	$ 59,436	$ 8,446
Net income per Trust unit
Basic	$ 0.40	$ 0.01	$ 0.59	$ 0.11
Diluted	$ 0.40	$ 0.01	$ 0.59	$ 0.11

Net income before taxes increased from $13.1 million in the second quarter of 2004 to $50.8 million in the second quarter of 2005 mainly due to a 53% increase in revenues reflected by a 28% increase in production and a 19% increase in prices on a boe basis. These increases have been offset by a 51% increase in lease operating costs and a 43% increase in depletion.

The Trust recognized a net gain on commodity contracts of $1.7 million in the second quarter of 2005 compared to $13.5 million loss in the second quarter of 2004. The unrealized (non-cash) gain on commodity contracts was $9.7 million in the second quarter of 2005 compared to $4.6 million loss in the second quarter of 2004.

The increase in depletion is due to increased production and the increase in the depletion rate reflecting the increasing cost of acquisitions.

Net income before income taxes for the six months ended June 30, 2005 was $57.4 million compared to $21.2 million for the same period in the prior year. This is mainly due to a 54% increase in oil and natural gas sales. Production increased 30% and prices increased 19% on a boe basis. These increases have been offset by a 56% increase in lease operating costs and a 45% increase in depletion.

Total cash netbacks increased by $37.5 million for three months ended June 30, 2005 compared to the same period in 2004. On a boe basis cash netbacks were up to $26.85 in the second quarter of 2005 from $19.84 in the second quarter of 2004.

	3 months ended June 30,		6 months ended June 30,
Total Cash Netbacks	2005	2004	2005	2004
Operating netback	$ 29.28	$ 22.05	$ 27.39	$ 22.38
Financing costs	0.79	0.46	0.73	0.42
General and administrative	1.19	1.30	1.17	1.30
Capital and current taxes	0.45	0.45	0.37	0.39
Total cash netback per BOE	$ 26.85	$ 19.84	$ 25.12	$ 20.27

As a result of the changes discussed above, net income increased to $40.2 million in the second quarter of 2005 from the $817,000 reported in the second quarter of 2004.

Operating Netbacks for the three months ended June 30, 2005
	Oil $/bbl	Gas $/mcf	NGL $ /bbl	Total $ /boe
Selling price	$ 59.18	$ 7.65	$ 51.10	$ 52.69
Cash cost of hedging	(5.01)	(0.02)	-	(2.45)
Net selling price	54.17	7.63	51.10	50.24
Royalties, net of ARC	9.76	1.47	12.15	9.49
Operating	13.96	1.30	9.19	10.89
Transportation	0.43	0.12	0.56	0.58
Operating netback	$ 30.02	$ 4.74	$ 29.20	$ 29.28

Operating Netbacks three months ended June 30, 2004
	Oil $/bbl	Gas $/mcf	NGL $ /bbl	Total $ /boe
Selling price	$ 47.01	$ 7.13	$ 37.13	$ 44.27
Cash cost of hedging	(6.51)	(0.22)	-	(3.49)
Net selling price	40.50	6.91	37.13	40.78
Royalties, net of ARC	8.54	1.58	8.71	9.02
Operating	11.29	1.24	8.50	9.26
Transportation	0.19	0.12	0.45	0.45
Operating netback	$ 20.48	$ 3.97	$ 19.47	$ 22.05

The operating netback increased by $61.4 million for six months ending June 30, 2005. On a boe basis operating netback increased to $27.39 in 2005 from $22.38 in 2004.

Operating Netbacks for the six months ended June 30, 2005
	Oil $/bbl	Gas $/mcf	NGL $ /bbl	Total $ /boe
Selling price	$ 56.93	$ 7.33	$ 48.62	$ 50.77
Cash cost of hedging	(5.01)	(0.01)	-	(2.51)


Net selling price	51.92	7.32	48.62	48.26
Royalties, net of ARC	9.95	1.54	11.82	9.76
Operating	13.87	1.13	9.37	10.50
Transportation	0.51	0.12	0.53	0.61
Operating netback	$ 27.59	$ 4.53	$ 26.90	$ 27.39

Operating Netbacks for the six months ended June 30, 2004
	Oil $/bbl	Gas $/mcf	NGL $ /bbl		Total $ /boe
Selling price	$ 44.86	$ 6.95	$ 37.09		$ 42.75
Cash cost of hedging	(5.75)	(0.11)		-	(2.77)
Net selling price	39.11	6.84	37.09		39.98
Royalties, net of ARC	7.54	1.48	9.90		8.36
Operating	11.60	1.05	7.67		8.74
Transportation	0.20	0.13	0.43		0.50
Operating netback	$ 19.77	$ 4.18	$ 19.09		$ 22.38

CAPITAL EXPENDITURES

Acquisitions

During the six months ended June 30, 2005, PC spent $37.5 million to acquire Northern Crown Petroleums Ltd. ("Northern Crown") effective May 10, 2005, $23.4 million to acquire Tahiti Gas Ltd. ("Tahiti") effective May 1, 2005 and $6.3 million to acquire property interests in the Turin area effective January 1, 2005. These acquisitions are expected to add approximately 1,365 boepd of production to the Trust. On these acquisitions, Petrofund's internal estimate of reserves is 4.0 million boe on a proved plus probable basis.

Development Activities

During the three months ended June 30, 2005, PC incurred $30.6 million in drilling and development activities as compared to $14.8 million in the three months ended June 30, 2004. A total of 48 wells were drilled, of which 16 were gas, 30 oil and 2 dry and abandoned for an overall success rate of 96%

During the six months ended June 30, 2005, PC incurred $79.0 million in drilling and development activities as compared to $27.4 million in the six months ended June 30, 2004. A total of 133 wells were drilled, of which 72 were gas, 56 oil, 1 service well and 4 dry and abandoned for an overall success rate of 97%.

A summary of capital expenditures for the three and six month's periods is as follows ($ thousands):

	3 months ended June 30,		6 months ended June 30,
	2005	2004	2005	2004
Corporate and property acquisitions ⁽¹⁾	$ 56,330	$ 8,488	$ 62,581	$ 9,578
Development expenditures:
Land & seismic	1,436	360	5,405	967
Drilling & completion	14,504	8,458	36,902	14,144
Well equipping	949	834	6,000	2,032
Tie-ins	3,881	1,168	8,232	2,249

Facilities	5,389		2,119	14,105	4,665
CO² purchases	4,360	1,890		8,178	3,388
Other	104		-	191	-
Total	30,623		14,829	79,013	27,445
Total net capital expenditures -cash	86,953		23,317	141,594	37,023
Corporate acquisitions - non-cash ⁽²⁾	16,395		559,831	16,395	559,831
Current year ARO capitalized	736		121	1,739	336
Total capital expenditures ⁽³⁾	$104,084		$ 583,269	$159,728	$ 597,190

⁽¹⁾

The corporate and property acquisition totals exclude the impact of non-cash items on corporate acquisitions such as future income taxes and ARO.

⁽²⁾

Includes non-cash items such as: Trust units issued, working capital assumed, future income tax adjustments for the difference between the cost and tax basis of assets acquired and asset retirement obligations recognized for corporate acquisitions.

⁽³⁾

Includes change in oil and natural gas royalty and property interest and goodwill.

We expect total development expenditures in 2005 to be approximately $150 million, however, we may increase our capital program as we identify and execute on more of the opportunities within our existing properties, particularity if higher commodity prices prevail.

ASSET RETIREMENT FUND

As at June 30, 2005, PC had $8.0 million set aside in cash to fund future abandonment costs. This cash fund is in place to fund significant future reclamation costs, such as the decommissioning of a major facility. PC performs well reclamation and abandonments, flare pit remediation work, etc. on a routine basis, which reduces cash flow available for distribution to proactively address environmental concerns. Petrofund incurred $322,000 for these activities in the second quarter of 2005 compared to $811,000 in the second quarter of 2004. Reclamation and abandonment costs incurred for the six months ended June 30, 2005, was $1.4 million as compared to $2.0 million in 2004. PC expects to spend a further $4 million on reclamation and abandonment work in the remainder of 2005.

GOODWILL

The goodwill balance of $190.3 million arose as a result of the Ultima and Central Alberta acquisitions in 2004 and Northern Crown and Tahiti acquisitions in 2005. The goodwill balance was determined based on the excess of total consideration paid plus the future income tax liability less the fair value of the assets acquired in each transaction.

Accounting standards require that the goodwill balance be assessed for impairment at least annually or more frequently if events or changes in circumstances indicate that the balance might be impaired. If such an impairment exists, it would be charged to income in the period in which the impairment occurs. The Trust has determined that there was no indication of goodwill impairment as of June 30, 2005.

DEBT

As at June 30, 2005, the amount outstanding on the credit facility was $254.3 million, with $160.7 million available to finance future activities.

On April 29, 2005, PC's borrowing base was increased to $415 million and the revolving period on the syndicated facility of $390 million was extended for a further 364 day period ending on April 28, 2006. In the event that the revolving bank line is not extended at the end of the 364 day revolving period, no payments are required to be made to non-extending lenders during the first year of the term period. However, Petrofund will be required to maintain certain minimum balances on deposit with the syndicate agent.

LIQUIDITY AND CAPITAL RESOURCES

The working capital deficit was $47.8 million at June 30, 2005, a decrease of $1.5 million from the $49.3 million deficit as at December 31, 2004. The June 30, 2005 and December 31, 2004 deficits exclude net unrealized gains/losses on commodity contracts. Current assets increased $21.2 million from $48.6 million at December 31, 2004 to $69.8 million at June 30, 2005. Current liabilities increased $19.7 million from $97.9 million at December 31, 2004 to $117.6 million at June 30, 2005. This increase in liabilities reflects an increase in the capital expenditures and an increase in distributions payable to Unitholders.

During the second quarter of 2005 the Trust generated cash flow of $87.8 million and paid out $48.8 million in distributions. The excess of $39.0 million was used to partially fund the Trust's capital expenditure program.

The Trust completed a "bought deal" financing of Trust units raising gross proceeds of $75.7 million ($71.5 million net). A total of 4,150,000 units were issued at $18.25 per unit. The net proceeds were used to pay down debt and fund capital expenditures.

Total long-term debt increased to $254.3 million at June 30, 2005, from $214.4 million at December 31, 2004, due to the cost of acquisitions and development activities.

The changes in total long-term debt for the three and six months ended June 30 were due to:

	3 months ended June 30,			6 months ended June 30,
($ thousands)	2005	2004	2005	2005	2004
Cash flow	$ 87,811	$ 49,820		$ 160,770	$ 98,867
Proceeds received from issuance of Trust units	73,232	802		77,422	1,709
Net change in non-cash working capital balances	(11,301)	1,346		(18,433)	27,192
Distributions paid	(48,793)	(39,165)		(96,687)	(74,075)
Expenditures on oil & natural properties, net	(86,953)	(23,317)		(141,594)	(37,023)
Assumption of debt, net of cash on acquisitions	88	(100,696)		88	(100,696)
Asset retirement reserve	(491)	(383)		(967)	(746)
Redemption of exchangeable shares	(259)	(451)		(646)	(902)
Capital lease repayments	(128)	(88)		(534)	(174)
(Increase) decrease in cash	(28,314)	(10,493)		(19,350)	(16,908)
	$(15,108)	$(122,625)		$ (39,931)	$(102,756)

We anticipate we will continue to have adequate liquidity to fund future working capital and planned capital expenditures during 2005 primarily through funds from operations and utilization of our credit facility.

Capitalization Analysis

($ thousands, except per unit and percent amounts)	2005	2004
Working capital (deficiency) ⁽¹⁾	$ (47,812)	$ (30,955)
Bank debt	254,345	212,463
Capital lease obligation	-	74
Net debt obligation	$ 302,157	$ 243,492
Units outstanding and issuable for Exchangeable Shares	105,014	100,190
Market Price at June 30,	$ 19.50	$ 14.85
Market capitalization	$ 2,047,767	$ 1,487,823
Total capitalization	$ 2,349,924	$ 1,731,315
Net debt as a percentage of total capitalization	13%	14%

(1)

Excludes net unrealized losses on commodity contracts.

Based on annualized second quarter 2005 cash flow, Petrofund's net debt to cash flow ratio is 0.9:1.0. Total capitalization as presented does not have any standardized meaning prescribed by Canadian GAAP and therefore it may not be comparable with the calculation of similar measures for other entities.

UNITHOLDERS' EQUITY

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

	3 months ended June 30,		6 months ended June 30,
	2005	2004	2005	2004
Basic	101,568,982	78,073,936	101,088,297	75,873,858
Diluted	101,592,632	78,229,404	101,120,837	76,050,805

Trust units/exchangeable shares outstanding:

As at June 30,	2005	2004
Trust units outstanding	104,474,542	99,250,968
Trust units issuable for exchangeable shares	539,147	939,147
	105,013,689	100,190,115

The Trust had 104,474,542 Trust units outstanding at June 30, 2005 compared to 99,250,968 Trust units at the end of June 30, 2004. The weighted average number of Trust units outstanding including Exchangeable Shares, was 101,568,982 Trust units for the second quarter of 2005 as compared to 78,073,936 for 2004. During the first half of 2005, 316,251 Exchangeable Shares were converted into 400,000 Trust units and 28,679 were redeemed for cash leaving 411,718 Exchangeable Shares outstanding at June 30, 2005 which are convertible into 539,147 Trust units.

FINANCIAL INSTRUMENTS

The net negative fair value of the commodity contracts at June 30, 2005 of $25.3 million has been recorded on the balance sheet as "commodity contracts" under assets or liabilities, as appropriate. The negative change in the fair value of the contracts, for the six months ended June 30, 2005 of $13.9 million (2004 - $12.6 million) is recorded in the income statement on a separate line as "loss on commodity contracts". The line item also includes realized losses on commodity contracts of $8.0 million for three months ended June 30, 2005 compared to $8.9 million for three months ended June 30, 2004.

Deferred Commodity Contracts ($000's)	Jan 1, 2005	Amortized to Expense		Jun 30, 2005
Current Asset
Deferred loss	$ 517	$ (258)			$ 259
Current Liability
Deferred gain	(184)		108	(76)
	$ 333	$ (150)			$183
Commodity Contracts ($000's)	Jan 1, 2005	Change in Fair Value		Jun 30, 2005
Current Asset
Commodity contracts	$ 3,281	$ (2,871)			$ 410
Current Liability
Commodity contracts	(14,599)		(11,073)		(25,672)
	$ (11,318)		$ (13,944)		$(25,262)

NON-RESIDENT OWNERSHIP

Based on information available to the Trust, Petrofund estimated that non-resident ownership was approximately 72% as of July 31, 2005. While there are, at present, no restrictions or deadlines on Petrofund pertaining to non-resident ownership levels, the Trust will continue to provide non-resident ownership level updates on a quarterly basis. Petrofund continues to monitor developments in this area.

OFF-BALANCE SHEET ARRANGEMENTS

The Trust has no off-balance sheet financing arrangements.

OUTLOOK FOR 2005

The level of cash flow for 2005 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 volatility in 2005 to date and this trend is expected to continue for the remainder of 2005. The acquisition market is expected to continue to be active. 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. The Trust expects 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.

Although product prices have remained at high levels, the strengthening of the Canadian dollar in the second quarter of 2005 moderated the net effect of these prices on Petrofund's cash flow. The WTI U.S. price increased 39% to $53.20/bbl in 2005 from $38.31/bbl in the second quarter of 2004, however, as the (US/CDN) exchange rate averaged $0.80 in 2005 as compared to $0.74 in the second quarter of 2004 the par price at Edmonton was up only 30%. The Trust expects the Canadian dollar to remain strong throughout 2005.

Petrofund pursues a well defined risk management program to help offset the effect of price fluctuations. This program utilizes collars as the main hedging tool but Petrofund also enters into fixed price transactions when commodity prices approach historic highs. To date, the Trust has not entered into any currency related transactions. A discussion of the risk management strategies and hedged positions appear elsewhere in this report.

SENSITIVITY ANALYSIS

Below is a table that shows sensitivities to pre-hedging cash flow as a result of product price and operational changes that can significantly affect cash flow and results of operations. The table is based on actual 2005 prices received for the second quarter of 2005 and production volumes of 35,600 boe/d. These sensitivities are approximations only and are not necessarily valid at other price and production levels. As well, hedging activities can significantly affect these sensitivities.

	Change	$000's	$/unit per year
Price per barrel of oil*	$ 1.00 US	$ 7,552	$ 0.072
Price per mcf of natural gas*	$ 0.25 CDN	$ 6,678	$ 0.064
US/Cdn exchange rate	$ 0.01	$ 5,894	$ 0.056
Interest rate on debt ($254 million)	1%	$ 2,543	$ 0.002

Oil production volumes*	100 bbl/day	$ 1,704	$ 0.016
Gas production volumes*	1 mmcf/day	$ 2,114	$ 0.020

*After adjustment for estimated royalties.

*QUARTERLY REVIEW*
(thousands of Canadian dollars and units, except per unit amounts)
	2005			2004					2003
	Q2	Q1	Q4		Q3	Q2	Q1	Q4		Q3
Daily Production
Oil (bbls)	17,500	18,238	18,508		17,504	12,679	11,579	13,645		12,518
Natural gas (mcf)	96,951	88,271	90,089		90,119	79,741	77,925	80,286		84,734
Natural gas liquids (bbls)	2,353	2,283	2,502		2,427	2,074	2,040	2,185		2,160
BOE (6:1)	36,011	35,234	36,025		34,950	28,043	26,607	29,211		28,801
Prices ⁽⁵⁾
Oil (per bbl)	$ 59.18	$ 54.74	$ 50.96		$ 52.02	$ 47.01	$ 42.50	$ 36.07		$ 37.80
Natural gas (per mcf)	$ 7.65	$ 6.97	$ 7.12		$ 6.50	$ 7.13	$ 6.76	$ 5.87		$ 5.92
Natural gas liquids (per bbls)	$ 51.10	$ 46.04	$ 48.20		$ 43.68	$ 37.13	$ 37.06	$ 34.86		$ 31.23
BOE (6:1)	$ 52.69	$ 48.79	$ 47.33		$ 45.85	$ 44.27	$ 41.15	$ 35.60		$ 36.18
Operational Highlights
Oil and natural gas sales ⁽⁵⁾	$ 172,831	$ 154,768	$ 156,922		$ 147,489	$ 112,970	$ 99,699	$ 95,763		$ 95,976
Net oil and natural gas sales ⁽¹⁾	$ 141,722	$ 122,924	$ 125,866		$ 119,911	$ 89,953	$ 81,121	$ 76,778		$ 75,394
Cash flow ⁽²⁾	$ 87,811	$ 72,959	$ 72,302		$ 65,075	$ 49,820	$ 49,047	$ 43,246		$ 39,959
Per unit	$ 0.86	$ 0.73	$ 0.72		$ 0.65	$ 0.64	$ 0.67	$ 0.63		$ 0.60
Per boe	$ 26.80	$ 23.01	$ 21.81		$ 20.24	$ 19.52	$ 20.26	$ 16.09		$ 15.08
Cash distribution paid	$ 48,793	$ 47,894	$ 47,734		$ 47,684	$ 39,165	$ 34,910	$ 36,248		$ 34,650
Cash distribution paid per unit	$ 0.48	$ 0.48	$ 0.48		$ 0.48	$ 0.48	$ 0.48	$ 0.54		$ 0.54
Net income	$ 40,193	$ 19,243	$ 50,765		$ 15,147	$ 817	$ 7,629	$ 24,266		$ 15,104
Net income per unit - Basic	$ 0.40	$ 0.19	$ 0.51		$ 0.15	$ 0.01	$ 0.10	$ 0.35		$ 0.23
- Diluted	$ 0.40	$ 0.19	$ 0.51		$ 0.15	$ 0.01	$ 0.10	$ 0.35		$ 0.23
Cash operating netback per BOE	$ 29.28	$ 25.45	$ 24.40		$ 22.57	$ 22.05	$ 22.71	$ 18.72		$ 18.41
Lease operating costs	$ 35,677	$ 32,010	$ 29,222		$ 30,920	$ 23,639	$ 19,829	$ 24,777		$ 24,482
Cost per BOE	$ 10.89	$ 10.09	$ 8.82		$ 9.62	$ 9.26	$ 8.19	$ 9.22		$ 9.24
General & administrative costs	$ 3,902	$ 3,639	$ 4,223		$ 3,764	$ 3,316	$ 3,138	$ 2,948		$ 3,318
Costs per BOE	$ 1.19	$ 1.15	$ 1.27		$ 1.17	$ 1.30	$ 1.30	$ 1.10		$ 1.25

*QUARTERLY REVIEW -continued*
(thousands of Canadian dollars and units, except per unit amounts)
		2005			2004					2003
		Q2	Q1	Q4		Q3	Q2	Q1	Q4		Q3
Balance sheet
Working capital (deficit) ⁽³⁾		$ (47,812)	$ (59,531)	$ (49,310)		$ (55,784)	$ (30,955)	$ (56,093)	$ (30,006)		$ (60,440)
Property, plant and equipment, net		$ 1,306,761	$1,259,248	$1,246,694		$ 1,230,636	$ 1,251,484	$ 883,191	$ 868,263		$ 932,361
Long-term debt		$ 254,345	$ 239,237	$ 214,414		$ 199,474	$ 212,537	$ 90,040	$ 110,315		$ 196,160
Unitholders' equity		$ 1,034,115	$ 992,882	$1,026,526		$ 1,031,226	$ 1,063,704	$ 615,952	$ 648,293		$ 553,276
Units and Exchangeable Shares Outstanding
Weighted average	101,569		100,603	100,396		100,267	78,074	73,674	68,498		66,143
Diluted	101,593		100,644	100,466		100,353	78,229	73,872	68,691		66,281
At period end	105,014		100,746	100,451		100,344	100,190	73,682	73,628		66,716
Market Capitalization	$ 2,047,767		$1,777,156	$1,568,036		$ 1,595,476	$ 1,487,823	$1,278,390	$1,383,465		$ 1,067,449
Total Capitalization ^{(3) (4)}	$ 2,349,924		$2,075,924	$1,842,745		$ 1,850,258	$ 1,731,315	$1,434,515	$1,523,786		$ 1,324,053
Trust Unit Trading (TSX:PTF.UN)
High	$ 19.97		$ 19.33	$ 17.15		$ 16.35	$ 18.08	$ 19.24	$ 19.15		$ 16.70
Low	$ 17.00		$ 15.50	$ 14.52		$ 14.62	$ 14.70	$ 14.56	$ 15.89		$ 13.01
Close	$ 19.50		$ 17.64	$ 15.61		$ 15.90	$ 14.85	$ 17.35	$ 18.79		$ 16.00
Average daily volumes	176		264	185		287	189	204	234		257
Trust Unit Trading (AMEX:PTF)
High	$ 16.25		$ 16.05	$ 13.65		$ 12.83	$ 13.54	$ 14.96	$ 14.55		$ 12.24
Low	$ 13.62		$ 12.66	$ 12.16		$ 11.10	$ 10.95	$ 10.95	$ 11.90		$ 9.51
Close	$ 15.92		$ 14.62	$ 13.04		$ 12.60	$ 11.16	$ 13.22	$ 14.46		$ 11.90
Average daily volumes	469		643	518		431	319	633	436		443
(1) Net after royalties. (2) Cash flow before net changes in non-cash operating capital balances. (Non-GAAP measures, see special notes in Management Discussion and Analysis). (3) Excludes net unrealized gains/losses on commodity contracts. (4) Total capitalization equals market capitalization plus net debt. (Non-GAAP measures, see special notes in Management Discussion and Analysis). (5) Prices and revenue are before realized gains/losses on commodity contracts and before transportation costs.

Consolidated Balance Sheet

(thousands of dollars) (unaudited)

As at June 30, 2005 and December 31, 2004	2005	2004
Assets
Current assets
Cash	$ 18,617	$ -
Accounts receivable	35,158	37,713
Deferred loss on commodity contracts	259	517
Commodity contracts (Note 9)	410	3,281
Prepaid expenses	16,028	10,847
Total current assets	70,472	52,358
Asset retirement reserve fund (Note 7(b))	8,020	7,053
Goodwill (Note 2)	190,271	180,307
Oil and natural gas royalty and property interests,
at cost less accumulated depletion and depreciation
of $722,365 (2004 - $632,668)	1,306,761	1,246,694
	$ 1,575,524	$ 1,486,412
Liabilities and Unitholders' Equity
Current liabilities
Bank overdraft	$ -	$ 733
Accounts payable and accrued liabilities	50,037	60,961
Current portion of capital lease obligations	74	608
Deferred gain on commodity contracts	76	184
Commodity contracts (Note 9)	25,672	14,599
Distributions payable to Unitholders (Note 8)	67,504	35,568
Total current liabilities	143,363	112,653
Long-term debt (Note 6)	254,345	214,414
Future income taxes	89,575	81,411
Asset retirement obligations (Note 7(a))	54,126	51,408
Total liabilities	541,409	459,886
Unitholders' equity
Unitholders' capital (Note 3)	1,559,865	1,477,963
Exchangeable shares (Note 4)	6,038	10,518
Accumulated earnings	332,048	272,612
Accumulated cash distributions (Note 8)	(863,836)		(734,567)
Total unitholders' equity	1,034,115	1,026,526
	$ 1,575,524	$ 1,486,412

The accompanying notes to the Interim Consolidated Financial Statements are an integral part of this consolidated balance sheet.

Consolidated Statement of Operations and Accumulated Earnings

(thousands of dollars, except per unit amounts) (unaudited)

	3 months ended June 30,		6 months ended June 30,
	2005	2004	2005		2004
Revenues
Oil and natural gas sales	$ 172,831	$ 112,970	$ 327,599		$ 212,669
Royalties	(31,109)	(23,017)		(62,953)	(41,595)
Gain (loss) on commodity contracts	1,714	(13,540)		(30,283)		(31,031)
	143,436	76,413	234,363		140,043
Expenses
Lease operating	35,677	23,639	67,687		43,468
Transportation costs	1,895	1,156	3,931		2,511
Financing costs	2,604	1,183	4,735		2,089
General and administrative	3,902	3,316	7,541		6,454
Capital taxes	1,357	919	2,144		1,656
Depletion, depreciation and accretion	47,231	33,091	90,933		62,637
	92,666	63,304	176,971		118,815
Income before provision for income taxes	50,770	13,109	57,392		21,228
Provision for (recovery of) income taxes
Current	131	221	216		268
Future	10,446	12,071	(2,260)		12,514
	10,577	12,292	(2,044)		12,782
Net income	40,193	817	59,436		8,446
Accumulated earnings, beginning of period	291,855	205,882	272,612		198,253
Accumulated earnings, end of period	$332,048	$ 206,699	$332,048		$ 206,699
Net income per Trust unit (Note 3)
Basic	$ 0.40	$ 0.01	$ 0.59		$ 0.11
Diluted	$ 0.40	$ 0.01	$ 0.59		$ 0.11

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) (unaudited)

	3 months ended June 30,		6 months ended June 30,
	2005	2004	2005	2004
Cash provided by (used in):
Operating activities
Net income	$ 40,193	$ 817	$ 59,436	$ 8,446
Add items not affecting cash:
Depletion, depreciation and accretion	47,231	33,091	90,933	62,637
Commodity contracts	(9,737)	4,652	14,094	17,243
Future income taxes	10,446	12,071	(2,260)	12,514
Actual abandonment costs incurred (Note 7(b))	(322)	(811)	(1,433)	(1,973)
	87,811	49,820	160,770	98,867
Net change in non-cash operating working capital balances	(11,301)	1,346	(18,433)	27,192
Cash provided by operating activities	76,510	51,166	142,337	126,059
Financing activities
Bank loan	15,108	12,218	39,931	(7,651)
Distributions paid (Note 8)	(48,793)	(39,165)	(96,687)		(74,075)
Redemption of exchangeable shares (Note 4)	(259)	(451)	(646)		(902)
Capital lease repayments	(128)	(88)	(534)		(174)
Issuance of Trust units (Note 3)	73,232	802	77,422	1,709
Cash provided by(used in) financing activities	39,160	(26,684)	19,486	(81,093)
Investing activities
Asset retirement reserve (Note 7(b))	(491)	(383)	(967)		(746)
Corporate acquisitions (Note 2 (a)(b))	(56,100)	(7,436)	(56,100)		(7,436)
Property acquisitions	(230)	(1,052)	(6,481)		(2,142)
Development expenditures	(30,623)	(14,829)	(79,013)		(27,445)
Cash acquired on acquisitions (Note 2 (b))	88	9,711	88	9,711
Cash used in investing activities	(87,356)	(13,989)	(142,473)		(28,058)
Net change in cash	28,314	10,493	19,350	16,908
Cash (bank overdraft), beginning of period	(9,697)	8,597	(733)		2,182
Cash, end of period	$ 18,617	$ 19,090	$ 18,617	$ 19,090


Interest paid during the period	$ 2,286	$ 223	$ 4,434	$ 1,167
Income taxes paid (received) during the period	$ (311)	$ 51	$ (67)	$ 106

The accompanying notes to the Interim Consolidated Financial Statements are an integral part of these consolidated statements.

Notes to Interim Consolidated Financial Statements

June 30, 2005 and 2004

(unaudited)

(tabular amounts in thousands of dollars, except unit and per unit amounts)

INTERIM FINANCIAL STATEMENTS

These unaudited interim consolidated financial statements follow the same accounting policies and methods of their application as the most recent annual financial statements. The note disclosure requirements for annual financial statements are prepared in accordance with Canadian generally accepted accounting principles and provide additional disclosures to that required for interim financial statements. Accordingly, these interim financial statements should be read in conjunction with the audited consolidated financial statements of Petrofund Energy Trust ("Petrofund" or the "Trust") as at December 31, 2004 and 2003 and for each of the years in the three-year period ended December 31, 2004.

ACQUISITIONS

(a)

Acquisition of Northern Crown Petroleums Ltd.

On May 10, 2005 Petrofund acquired 100% of the outstanding shares of Northern Crown Petroleums Ltd. and its wholly owned subsidiary Spiral Resources Ltd. for $32.7 million in cash and assumed debt and negative working capital of $4.8 million. Of the total acquisition costs of $45.7 million, $38.5 million was allocated to oil and gas royalty and property interest and $7.2 million to goodwill, which is not deductible for tax purposes.

A summary of the estimated net assets acquired is as follows:

	(000's)
Current assets	$ 1,733
Goodwill	7,169
Oil and gas royalties and property interests	38,556
Current liabilities	(6,550)
Asset retirement obligations	(756)
Future income taxes	(7,410)
	$ 32,742

(b)

Acquisition of Tahiti Gas Ltd.

On May 31, 2005 Petrofund acquired 100% of the outstanding shares of Tahiti Gas Ltd. ("Tahiti") for $23.4 million in cash and assumed debt and working capital of $23,000. Of the total acquisition costs of $26.8 million, $24.0 million was allocated to oil and gas royalty and property interest and $2.8 million to goodwill, which is not deductible for tax purposes.

A summary of the estimated net assets acquired is as follows:

	(000's)
Current assets	$ 184
Goodwill	2,795
Oil and gas royalties and property interests	23,974
Current liabilities	(161)
Asset retirement obligations	(420)
Future income taxes	(3,014)
	$ 23,358

TRUST UNITS

Authorized: unlimited number of Trust units	Number of Units	$000's
Issued
Balance, December 31, 2004	99,511,576	$ 1,477,963
Issued for cash	4,150,000	75,738
Exchangeable shares converted (Note 4)	400,000	4,480
Commissions and issue costs	-	(4,259)
Options exercised	374,224	5,291
Unit purchase plan	2,881	53
Unit incentive plan	35,861	599
Balance, June 30, 2005	104,474,542	$ 1,559,865

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

	3 months ended June 30,		6 months ended June 30,
	2005	2004	2005	2004
Basic	101,568,982	78,073,936	101,088,297	75,873,858
Diluted	101,592,632	78,229,404	101,120,837	76,050,805

The diluted amounts include all dilutive instruments.

Trust units/exchangeable shares outstanding:

As at June 30,	2005	2004
Trust units outstanding	104,474,542	99,250,968
Trust units issuable for exchangeable shares (Note 4)	539,147	939,147
	105,013,689	100,190,115

EXCHANGEABLE SHARES

Issued and Outstanding	Number of Shares	$000's
Balance, December 31, 2004	756,648	$ 10,518
Redemption of shares	(28,679)		-
Exchanged for Trust Units ⁽¹⁾	(316,251)	(4,480)
Balance, June 30, 2005	411,718	6,038
Exchangeable ratio, end of period	1.30950	-
Exchangeable for Trust units	539,147	$ 6,038

⁽¹⁾

On March 7, 2005, 316,251 Exchangeable Shares were converted to 400,000 Trust units at an exchange rate of 1.26482

5. RESTRICTED UNIT PLAN ("RUP") AND LONG-TERM INCENTIVE PLAN ("LTIP")

On February 17, 2005, the Board of Directors approved the adoption of the RUP and LTIP which authorizes the Trust to issue units to directors, officers, employees, or consultants of the Trust or any of its subsidiaries. The units, plus accrued distributions, vest over time and upon vesting may be redeemed by the holder for cash or units under the RUP and for units only under the LTIP. The units are issued, or the cash paid out, on the vesting dates based upon the weighted average trading prices of the units for the last 20 trading days prior to the vesting dates. The estimated value of the units to be issued, or the cash to be paid out, is charged to expense over the vesting periods of the grants. The number of units outstanding, excluding accrued distributions, is as follows:

	RUP	LTIP
Balance, December 31, 2004	51,426	31,156
Granted	93,510	61,245
Units issued	(18,760)		(51,571)
Forfeitures	(6,462)		-
Balance, June 30, 2005	119,714	40,830

The Trust recorded compensation expenses of $1.0 million in the six months ended June 30, 2005 (2004 - $693,000). The compensation expense was based on the June 30, 2005 unit price of $19.50, distributions of $0.96 per unit during the period and management's estimate of the number of RUP and LTIP units to be issued on maturity.

LONG-TERM DEBT

Under the loan agreements, as at June 30, 2005, Petrofund Corp. ("PC"), a wholly-owned subsidiary of the Trust had a revolving working capital operating facility of $25 million and a syndicated facility of $390 million. On April 29, 2005, PC increased its syndicated facility to $390 million, bringing PC's borrowing base to $415 million (December 31, 2005 - $325 million). Interest on the working capital loan is at prime and interest on the syndicated facility varies with PC's debt to cash ratio from prime or, at the Trust's option, Banker's Acceptances rates plus 80 to 125 basis points plus stamping fees. The prime rate at June 30, 2005 was 4.25%. As at June 30, 2005, there was no amount outstanding under the working capital facility and $254.3 million outstanding under the syndicated facility.

The revolving period on the syndicated facility ends on April 28, 2006, unless extended for a further 364 day period. In the event that the revolving bank line is not extended at the end of the 364 day revolving period, no payments are required to be made to non-extending lenders during the first year of the term period. However, PC will be required to maintain certain minimum balances on deposit with the syndicate agent.

The limit of the syndicated facility is subject to adjustment from time to time to reflect changes in PC's asset base.

The credit facility is secured by a debenture of $600 million pursuant to which a Canadian chartered bank, as principal and as agent for the other lenders, received a first ranking security interest on all of PC's assets.

The loan is the legal obligation of PC. While principal and interest payments are allowable deductions in the calculation of royalty income, the Unitholders have no direct liability to the bank or to PC should the assets securing the loan generate insufficient cash flow to repay the obligation.

Substantially all of the credit facility is financed with Banker's Acceptances, resulting in a reduction in the stated bank loan interest rates.

ASSET RETIREMENT OBLIGATIONS AND RESERVE FUND

(a)

Asset Retirement Obligations ("ARO")

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:

	3 months ended June 30,		6 months ended June 30,
($000's)	2005	2004	2005	2004
Balance, at beginning of period	$ 51,913	$ 33,970	$ 51,408	$ 34,363
Increase in liabilities during the period	736	121	1,739	336
Accretion expense during period	623	554	1,236	1,108
Actual costs incurred during the period	(322)	(811)	(1,433)	(1,973)
Acquisitions additions during the period (Note 2)	1,176	16,672	1,176	16,672
Balance, at end of period	$ 54,126	$ 50,506	$ 54,126	$ 50,506

(b)

Asset Retirement Reserve Fund

PC maintains a cash reserve to finance large and unusual oil and natural gas property reclamation and abandonment costs by withholding amounts, which would otherwise represent distributions accruing to Unitholders. At June 30, 2005, the cash reserve was $8.0 million (December 31, 2004 - $7.1 million). In the second quarter of 2005, PC increased the cash reserve by withholding $491,000 (2004 - $383,000) from distributions accruing to Unitholders. In addition, routine ongoing reclamation and abandonment costs of $322,000 in the second quarter of 2005 (2004 - $811,000) were incurred and deducted from distributions accruing to Unitholders. Ongoing reclamation and abandonment cost of $1.4 million for six months ended June 30, 2005 (2004 - $2.0 million) were incurred and deducted from distributions accruing to the unitholders.

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 and income and debt repayments from PC. An overall analysis is as follows:

For the period ended	Cash Distribution Date	2005	2004
November 30	January 31	$ 0.16	$ 0.16
December 31	February 28	0.16	0.16
January 31	March 31	0.16	0.16
February 28	April 30	0.16	0.16
March 31	May 31	0.16	0.16
April 30	June 30	0.16	0.16
Cash Distributions per Trust unit		$ 0.96	$ 0.96

Reconciliation of Distributions Accruing to Unitholders

(thousands of dollars)

	3 months ended June 30,		6 months ended June 30,
	2005	2004	2005		2004
Distributions payable, beginning of period	$ 44,364	$ 58,968	$ 35,568		$ 53,452
Distributions accruing during the period
Cash flow provided by operating activities	76,510	51,166	142,337		126,059
Net change in non-cash operating working
capital balance	11,301	(1,346)		18,433	(27,192)
Amortization of the cost of commodity contracts	-	(242)		-	(463)
Redemption of exchangeable shares	(259)	(451)		(646)	(902)
Asset retirement reserve contributions	(491)	(383)		(967)	(746)
Capital lease repayment	(128)	(88)		(534)	(174)

Cash flow before capital reinvestment	86,933	48,656	158,623			96,582
Weyburn deferred capital obligation	-	(34,930)			-	(34,930)
Reserve for capital expenditures	(15,000)	(7,500)			(30,000)	(15,000	)
Total distributions accruing during the period	71,933	6,226	128,623			46,652
Distributions paid	(48,793)	(39,165)		(96,687)		(74,075)
Distributions payable, end of period⁽¹⁾	$ 67,504	$ 26,029	$ 67,504			$ 26,029

⁽¹⁾

It is expected that the majority of this amount will be used to fund capital expenditures in the future.

Accumulated Cash Distributions (thousands of dollars)
	3 months ended June 30,		6 months ended June 30,
	2005	2004	2005	2004
Accumulated cash distributions, beginning of period	$ 791,644	$ 622,032	$ 734,567	$ 581,155
Distributions accruing during the period	71,933	6,226	128,623	46,652
Redemption of exchangeable shares	259	451	646	902
Accumulated cash distributions, end of period	$ 863,836	$ 628,709	$ 863,836	$ 628,709

9. 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, all of which constitute effective economic hedges, but for which hedge accounting has not been applied and the related unrealized gains or losses since inception of the contracts to June 30, 2005, are summarized separately below:

Natural Gas	Term	Volume mcf/d	Price $/mcf	Delivery Point	Unrealized Gain (Loss) $000's
Collar	April 1, 2005 to October 31, 2005	4,737	$6.33-$8.44	AECO	$ (15)
Collar	April 1, 2005 to October 31, 2005	4,737	$6.33-$9.60	AECO	19
Collar	April 1, 2005 to October 31, 2005	4,737	$6.33-$8.44	AECO	(15)
Collar	April 1, 2005 to October 31, 2005	4,737	$6.33-$8.44	AECO	(17)
Three way collar	April 1, 2005 to October 31, 2005	4,737	$4.75-$5.80-$7.92	AECO	(72)
Fixed	July 1, 2005 to September 30, 2005	4,737	$7.06	AECO	(124)
Three way collar	November 1, 2005 to March 31, 2006	4,737	$5.65-$6.70-$10.55	AECO	(323)
Three way collar	November 1, 2005 to March 31, 2006	4,737	$5.28-$6.33-$12.98	AECO	(126)

Collar	November 1, 2005 to March 31, 2006	4,737	$7.28-$13.61	AECO	87
Three way collar	April 1, 2006 to October 31, 2006	4,737	$6.07-$7.39-$8.99	AECO	(226)
Total					$ (812)

Oil	Term	Volume bbl/d	Price $/bbl	Delivery Point		Unrealized Gain (Loss) $000's
Three way collar	January 1, 2005 to December 31, 2005	1,000	$24.51-$29.41-$35.54	Edmonton		$ (7,569)
Three way collar	January 1, 2005 to December 31, 2005	1,000	$29.41-$32.85-$41.43	Edmonton		(6,273)
Three way collar	January 1, 2005 to December 31, 2005	1,000	$28.18-$32.84-$40.19	Edmonton		(6,532)
Three way collar	July 1, 2005 to December 31, 2005	1,000	$41.77-$47.90-$72.41	Edmonton		(667)
Collar	July 1, 2005 to September 30, 2005	1,000	$50.77-$72.83	Edmonton		(188)
Collar	October 1, 2005 to December 31, 2005	1,000	$50.33-$72.38	Edmonton	(460)
Three way collar	January 1, 2006 to March 31, 2006	1,000	$42.89-$49.02-$64.95	Edmonton	(980)
Collar	January 1, 2006 to March 31, 2006	1,000	$51.47-$73.52	Edmonton	(545)
Collar	January 1, 2006 to March 31, 2006	1,000	$55.14-$85.78	Edmonton	(159)
Three way collar	April 1, 2006 to June 30, 2006	1,000	$45.34-$51.47-$72.60	Edmonton	(660)
Collar	April 1, 2006 to June 30, 2006	1,000	$58.21-$85.78	Edmonton	(125)
Collar	April 1, 2006 to June 30, 2006	1,000	$61.27-$79.65	Edmonton	(189)
Collar	April 1, 2006 to June 30, 2006	1,000	$61.27-$93.13	Edmonton	88
Collar	July 1, 2006 to September 30, 2006	1,000	$61.27-$79.65	Edmonton	(178)
Collar	July 1, 2006 to September 30, 2006	1,000	$61.27-$92.52	Edmonton	85
Collar	October 1, 2006 to December 31, 2006	1,000	$61.27-$79.65	Edmonton	(149)
Collar	January 1, 2006 to March 31, 2006	1,000	$61.27-$84.25	Edmonton	(80)
Total					$ (24,581)

Electricity

Term

Volume MW/h

Price $/MWh

Delivery Point

Unrealized Gain

$000's

Fixed Price

February 1, 2004 to December 31, 2005

2.0

$ 44.50

Alberta Power Pool

$ 131

Derivative financial instruments and related hedge contracts involve a degree of credit risk, which the Trust controls through the use of financially sound counterparties. The gains or losses incurred are recognized on a monthly basis over the terms of the hedge contracts. All foreign exchange calculations incorporate the Bank of Canada US dollar rate at the close on June 30, 2005 of CDN $1.2254:US$.

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

This news release may contain forward-looking statements relating to future events or future performance. In some cases, forward-looking statements can be identified by terminology such as "may", "will", "should", "expect", "projects", "plans", "anticipates" and similar expressions. These statements represent management's expectations or beliefs concerning, among other things, future operating results and various components thereof affecting the economic performance of the Trust. Undue reliance should not be placed on these forward-looking statements which are based upon management's assumptions and are subject to known and unknown risks and uncertainties, including the business risks discussed above, which may cause actual performance and financial results in future periods to differ materially from any projections of future performance or results expressed or implied by such forward-looking statements. Accordingly, readers are cautioned that events or circumstances could cause results to differ materially from those predicted.

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

PETROFUND ENERGY TRUST

Jeffery E. Errico

President and Chief Executive Officer

For Petrofund Investor Relations:

Phone: (403) 218-4736

Fax: (403) 539-4300

Toll Free: 1-866-318-1767

E-mail: info@petrofund.ca

Website: www.petrofund.ca

For information regarding this press release:

Chris Dutcher

Director, Business Development

Phone: (403) 218-8625

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