Petrofund Energy Trust
AMEX : PTF
TSX : PTF.UN

Petrofund Energy Trust

November 08, 2005 17:29 ET

Petrofund Energy Trust Announces Results for the Third Quarter of 2005

CALGARY, ALBERTA--(CCNMatthews - Nov. 8, 2005) - Petrofund Energy Trust (TSX:PTF.UN) (AMEX:PTF) is pleased to provide its results for the third quarter of 2005. Key items from the quarter include:

- Average production for the third quarter reached a record high of 37,485 boe per day. This was a 7% increase over the third quarter production of last year.

- Cash flow increased 71% over the third quarter of 2004 to $111.1 million, which is also a new high for the Trust. On a per unit basis, cash flow increased 63% from a year ago to $1.06 per unit.

- The third quarter payout ratio moved down to 45% from 75% in the comparable quarter of 2004 and from 56% in the second quarter of 2005.

- Operating costs for the quarter increased to $10.31 per boe due to increasing industry costs. This was a 7% increase over the third quarter of last year but a 5.3% decrease from the second quarter of 2005.

- Net income increased from $15.1 million in the third quarter of 2004 to $51.2 million in the third quarter of 2005, which equates to a per unit increase from $0.15 to $0.49.

- General and administrative costs were up 20% from last year to $1.40 per boe due mainly to increasing compensation costs due to industry pressure.

- The Trust exited the quarter with a 0.5:1.0 net debt to cash flow ratio based on annualized third quarter cash flow.



Petrofund's third quarter report is presented below:

3rd Quarter Report
for three & nine months ended September 30, 2005 & 2004

FINANCIAL HIGHLIGHTS
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(thousands of Canadian dollars, except per unit amounts)

3 months ended September 30,
------------------------------------
2005 2004 Variance
---------------------------------------------------------------------
INCOME STATEMENT
Oil and natural gas sales (5) $ 212,404 $ 147,489 44 %
Cash flow (1) $ 111,122 $ 65,075 71 %
Per unit (2) $ 1.06 $ 0.65 63 %
Per boe $ 32.22 $ 20.24 59 %
Cash distributions paid
per unit $ 0.48 $ 0.48 - %
Net income $ 51,209 $ 15,147 238 %
Net income per unit
Basic $ 0.49 $ 0.15 227 %
Diluted $ 0.49 $ 0.15 227 %

UNITS AND EXCHANGEABLE
SHARES OUTSTANDING (2)
Weighted average 105,018 100,267 5 %
Diluted 105,039 100,353 5 %
At period-end 105,046 100,344 5 %

TRUST UNIT TRADING (TSX: PTF.UN)
High $ 23.31 $ 16.35 43 %
Low $ 19.30 $ 14.62 32 %
Close $ 22.82 $ 15.90 44 %
Average daily volumes 147 287 (49)%
TRUST UNIT TRADING (AMEX: PTF)
High $ 19.85 $ 12.83 55 %
Low $ 15.72 $ 11.10 42 %
Close $ 19.64 $ 12.60 56 %
Average daily volumes 579 431 34 %


9 months ended September 30,
------------------------------------
2005 2004 Variance
---------------------------------------------------------------------
INCOME STATEMENT
Oil and natural gas sales (5) $ 540,003 $ 360,158 50 %
Cash flow (1) $ 271,892 $ 163,942 66 %
Per unit (2) $ 2.65 $ 1.95 36 %
Per boe $ 27.47 $ 20.02 37 %
Cash distributions paid per unit $ 1.44 $ 1.44 - %
Net income $ 110,645 $ 23,593 369 %
Net income per unit
Basic $ 1.08 $ 0.28 286 %
Diluted $ 1.08 $ 0.28 286 %

UNITS AND EXCHANGEABLE
SHARES OUTSTANDING (2)
Weighted average 102,412 84,064 22 %
Diluted 102,441 84,211 22 %
At period-end 105,046 100,344 5 %

BALANCE SHEET
Working capital (deficit) (3) $ 12,077 $ (55,784) 122 %
Property, plant
and equipment, net $ 1,297,522 $ 1,230,636 5 %
Long-term debt $ 244,499 $ 199,474 23 %
Unitholders' equity $ 1,084,746 $ 1,031,226 5 %
MARKET CAPITALIZATION,
as at September 30 $ 2,397,156 $ 1,595,476 50 %
TOTAL CAPITALIZATION,
as at September 30 (3),(4) $ 2,629,578 $ 1,850,258 42 %
TRUST UNIT TRADING (TSX: PTF.UN)
High $ 23.31 $ 19.24 21 %
Low $ 15.50 $ 14.56 6 %
Close $ 22.82 $ 15.90 44 %
Average daily volumes 195 227 (14)%
TRUST UNIT TRADING (AMEX: PTF)
High $ 19.85 $ 14.96 33 %
Low $ 12.66 $ 10.95 16 %
Close $ 19.64 $ 12.60 56 %
Average daily volumes 562 462 22 %


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

3 months ended September 30,
------------------------------------
2005 2004 Variance
---------------------------------------------------------------------
DAILY PRODUCTION
Oil (bbls) 18,451 17,504 5 %
Natural gas (mcf) 97,825 90,119 9 %
Natural gas liquids (bbls) 2,730 2,427 12 %
---------------------------------------------------------------------
BOE (6:1) 37,485 34,950 7 %
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Total production (mmboe) 3,449 3,215 7 %

PRODUCTION PROFILE
Oil 49% 50%
Natural gas 44% 43%
Natural gas liquids 7% 7%

PRICES (1)
Oil (per bbl) $ 69.37 $ 52.02 33 %
Natural gas (per mcf) $ 9.10 $ 6.50 40 %
Natural gas liquids (per bbl) $ 50.36 $ 43.68 15 %
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BOE (6:1) $ 61.57 $ 45.85 34 %
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Cash operating netback per BOE $ 34.67 $ 22.57 54 %

LEASE OPERATING COSTS $ 35,558 $ 30,920 (15)%
Cost per boe $ 10.31 $ 9.62 (7)%

GENERAL AND ADMINISTRATIVE COSTS $ 4,816 $ 3,764 (28)%
Cost per boe $ 1.40 $ 1.17 (20)%


9 months ended September 30,
------------------------------------
2005 2004 Variance
---------------------------------------------------------------------
DAILY PRODUCTION
Oil (bbls) 18,064 13,934 30 %
Natural gas (mcf) 94,384 82,623 14 %
Natural gas liquids (bbls) 2,457 2,181 13 %
---------------------------------------------------------------------
BOE (6:1) 36,252 29,886 21 %
---------------------------------------------------------------------
Total production (mmboe) 9,897 8,189 21 %

PRODUCTION PROFILE
Oil 50% 47%
Natural gas 43% 46%
Natural gas liquids 7% 7%

PRICES (1)
Oil (per bbl) $ 61.21 $ 47.88 28 %
Natural gas (per mcf) $ 7.95 $ 6.78 17 %
Natural gas liquids (per bbl) $ 49.27 $ 39.55 25 %
---------------------------------------------------------------------
BOE (6:1) $ 54.53 $ 43.97 24 %
---------------------------------------------------------------------
Cash operating netback per BOE $ 29.93 $ 22.46 33 %

LEASE OPERATING COSTS $ 103,245 $ 74,388 (39)%
Cost per boe $ 10.43 $ 9.08 (15)%

GENERAL AND ADMINISTRATIVE COSTS $ 12,357 $ 10,218 (21)%
Cost per boe $ 1.25 $ 1.25 - %

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


Management Discussion & Analysis

three and nine months ended September 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 nine months ended September 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") and Petrofund Ventures Trust, wholly owned subsidiaries of the Trust. This commentary is based on information available to November 8, 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 in the Trust's 2004 annual report, 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. The Trust undertakes no obligation to update or revise any forward looking financial statements, except as required by applicable securities laws.

RESULT SUMMARY

THIRD QUARTER 2005 VERSUS SECOND QUARTER 2005

The Trust generated cash flow of $111.1 million or $1.06 per unit in the third quarter of 2005 compared to $87.8 million or $0.86 per unit in the second quarter of 2005. The Trust maintained monthly cash distributions of $0.48 per unit in the third quarter of 2005. The Trust's payout ratio of 45% in the third quarter of 2005 compared to a payout ratio of 56% in the second quarter of 2005.

The third quarter of 2005 was an active quarter for Petrofund in property acquisitions, plus drilling and development activities. Total expenditures for the quarter were $40.3 million. These activities provide new production in the third quarter and for the fourth quarter of 2005, as discussed further in the Operational Highlights.

Average daily production volumes in the third quarter of 2005 of 37,485 boe were above the second quarter of 2005 volumes of 36,011 boe. This increase resulted from acquisitions and development activities for the nine months ending September 30, 2005 offset by the natural production decline.

Net income of $51.2 million remained the same for the third and second quarters of 2005. Revenues increased 23% which reflects an increase of 17% in prices on a boe basis and a 4% increase in production. The increase in revenue has mainly been offset by a $20.9 million non-cash loss on commodity contracts and an increase of $9.0 million in depletion expense. The Trust recognized an unrealized (non-cash) commodity loss of $11.1 million versus an unrealized (non-cash) commodity gain of $9.7 million in the second quarter of 2005. Both adjustments were a result of the accounting standard governing price risk management activity. In addition, the future income tax in the third quarter of 2005 was a recovery of $1.9 million compared to $10.4 million expense in the second quarter of 2005, due to an increase in commodity contract, losses and other tax related asset balances.

The cash loss on commodity contracts during the third quarter of 2005 was $12.8 million compared to an $8.0 million loss in the second quarter of 2005.

Royalties represented amounts equal to 20% of revenue in the third quarter of 2005, compared to 18% for the three months ended June 30, 2005. The second quarter of 2005 was lower due to positive gas costs allowance adjustments.

Lease operating costs on a unit basis decreased to $10.31/boe in the third quarter of 2005 from $10.89/boe in the second quarter of 2005. In the second quarter of 2005, 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. Costs for repairs and maintenance continue to increase as a result of high levels of activity in the upstream sector.

HIGHLIGHTS OF THE THREE AND NINE MONTHS ENDED SEPTEMBER 30, 2005

The Trust paid out cash distributions of $0.48 per unit in the third quarter of 2005, which equaled the $0.48 per unit in the third quarter of 2004. On September 13, 2005, the Trust announced October 2005 cash distributions of $0.17 per unit. Petrofund has since confirmed $0.17 per unit for November 2005 and based on current commodity prices and market conditions, Petrofund expects to maintain the $0.17 per unit distribution for December 2005 distribution month.

The Trust's payout ratio for the nine months ended September 30, 2005 was 55% compared to 76% in 2004. The payout ratio in the third quarter of 2005 was 45% compared to 75% in the same quarter of 2004.

Net income increased to $51.2 million in the third quarter of 2005 versus $15.1 million in the third quarter of 2004, reflecting increased average production and higher prices.

The Trust generated cash flow of $111.1 million in the third quarter of 2005, an increase of 71% over the third quarter of 2004.

Average production on a boe basis increased 7% to 37,485 boe/d in the third quarter of 2005 from 34,950 boe/d in the third quarter of 2004. The change in production reflects 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 third quarter of 2005 were up 34% on a boe basis from the same period the prior year and 24% on a boe basis for the nine months ending September 30, 2005 compared to the same period in 2004.

Petrofund has a strong balance sheet with a net debt to cash flow ratio of 0.5:1.0 based on annualized third quarter 2005 cash flow.

To date in 2005, Petrofund has acquired interests in various oil and gas properties for $73.8 million (excluding 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 and Joarcam areas. These acquisitions added approximately 1,650 boepd of production to the Trust. Petrofund's internal estimate of its working interest of reserves additions is 4.6 million boe on a proved plus probable basis.

The Trust has a balanced production profile which averaged 43% natural gas and 57% oil and liquids for the nine months ended September 30, 2005.

The Trust completed a "bought deal" financing of 4.15 million Trust units, raising gross proceeds of $75.7 million ($71.4 million net) in the second quarter of 2005. The weighted average number of Trust units outstanding increased from 100.3 million in the third quarter of 2004 to 105.0 million in the third quarter of 2005. As at September 30, 2005 there were 105.0 million Trust units outstanding.

The Trust market capitalization as at September 30, 2005, was approximately $2.4 billion ($1.6 billion as at September 30, 2004).

OPERATIONAL HIGHLIGHTS

Despite persistent wet weather across the western provinces, Petrofund carried out an active drilling program in the third quarter by drilling 61 wells, consisting of 57 working interest wells (25.3 net) and 4 farmout wells. This drilling activity resulted in 38 oil wells, 20 gas wells, 1 abandoned well and 2 service wells, for an overall success rate of 98%.

Following is a brief rundown of the properties having noteworthy activity in the quarter.

Brassey, British Columbia

Four new Cadomin gas wells (0.6 net) were brought on-stream early this quarter, adding average production of 500 mcf/d to Petrofund's production.

Fort Saskatchewan, Alberta

Petrofund added 2 mmcf/d of new production near the end of the quarter through two recompletions and the tie-in of a well drilled in the first quarter.

Turin, Alberta

Originally delayed by wet weather last quarter, Petrofund equipped and tied in a Taber gas well early this quarter that is producing 700 mcf/d for Petrofund's account.

Three Hills Creek, Alberta

Petrofund equipped and tied in a 100% working interest Edmonton Sand gas well that produced 750 mcf/d for most of the quarter. Petrofund also continued its participation in coalbed methane development by drilling an additional 6 wells (2.1 net). Several well recompletions during the quarter resulted in 500 mcf/d of added production.

Minehead, Alberta

Three successful Cardium gas wells (1.2 net) were drilled and completed on Petrofund lands during the quarter. These wells are scheduled to come on-stream in the fourth quarter.

Kerrobert, Saskatchewan

Petrofund, as operator, drilled sixteen 100% working interest Viking oil wells early this quarter but completions were delayed by wet weather. All wells are expected to be completed and on-stream early in the fourth quarter.

Dodsland, Saskatchewan

Three 100% working interest Viking gas wells commenced production mid-quarter at a combined rate of 1 mmcf/d.

Silverton, Saskatchewan

Petrofund, as operator, began producing a horizontal Frobisher oil well drilled in the second quarter. This well has averaged 15 boe/d net to Petrofund.

Weyburn, Saskatchewan

A total of 15 wells (3 net) were drilled in the Weyburn Unit during the quarter, mainly within the carbon dioxide flood area. These new wells added 250 boe/d to Petrofund's production base.

Midale, Saskatchewan

Six Frobisher wells (0.4 net) were drilled in the Midale Unit this quarter, although wet weather has delayed them from coming on-stream until early in the fourth quarter of 2005. Also, a full-scale commercial carbon dioxide injection project commenced within the Midale Unit late this quarter. Carbon dioxide injection is expected to extend the economic life of this unit by 20-25 years and recover an additional 45 million barrels of oil gross, 3 million barrels net to Petrofund, based on an internal estimate.



CASH DISTRIBUTIONS

3 months ended September 30, 9 months ended September 30,
---------------------------- ----------------------------
2005 2004 2005 2004
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Distributions
paid per unit $ 0.48 $ 0.48 $ 1.44 $ 1.44
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Trust unitholders who held their units throughout the third 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 $0.17 per unit in October, has announced $0.17 per unit for November, and has indicated $0.17 per unit for December.

Petrofund focuses on the ability to maintain distribution levels. As part of this strategy, the Trust has lowered its payout ratio; over the past two years in response to increasing oil and gas prices which currently exceed historical highs. At the same time, the Trust has allocated a higher percentage of cash flow for capital reinvestment. Petrofund monitors the distribution payout with respect to forecasted funds flow, debt levels and pending plans. The level of cash retained has historically varied between 10% and 30% of annual funds flow; however, Petrofund adjusts the payout levels in an effort to balance the investors' desire for distributions with the Trust's requirement to maintain a prudent capital structure. To reflect the treatment of capital expenditures funded from cash flow, Management has modified the calculation of distributions payable to Unitholders by applying the portion of capital expenditures funded from cash flow rather than an estimated amount as a reduction of Distributions Payable up to the amount available for such purposes. Any remaining cash flow continues to be shown as Distributions Payable to Unitholders at the end of the period.

The Trust generated cash flow available for distribution before funding of capital expenditures in the third quarter of 2005 of $110.3 million (2004 - $63.8 million). The Trust paid out $50.1 million (2004 - $47.7 million) in distributions representing a payout ratio of 45% (2004 - 75%).

During the nine months ended September 30, 2005 the Trust generated cash flow available for distribution before funding capital expenditures of $268.9 million (2004 - $160.4 million). The Trust paid out $146.8 million (2004 - $121.8 million) in distributions representing a payout ratio of 55% (2004 - 76%).

For the 12 months ended September 30, 2005, the Trust generated cash flow available for distribution of $340.0 million, and allocated $154.5 million of such amounts for investment in development drilling and other projects. Distributions of $194.6 million were paid out in such period, representing a payout ratio of 57%. 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
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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 1.4400(3) 1.3680 0.0720
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Cumulative $ 41.9250 $ 10.0004 $ 31.9246
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(1) Applies to unitholders who are residents of Canada and hold their
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% to 100% of cash
distributions paid in 2005 to Canadian and U.S. unitholders will
be taxable. Any non-taxable amounts 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. For most
U.S. taxpayers this should be a "Qualified Dividend" eligible for
the reduced tax rate. The non-taxable portion of the cash
distribution is a return of the cost (or other basis). The cost
(or other basis) is reduced by this amount for computing any gain
or loss arising from disposition. However, if the full amount of
the cost (or other basis) has been recovered, any further
non-taxable distributions should be reported as gains.

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 unitholder 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.


2005 MONTHLY CASH DISTRIBUTIONS

Actual Cash distributions paid for 2005 along with relevant payment
dates are as follows:

Record Date Payment Date Distribution/Per Unit
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January 17 January 31 $ 0.16
February 14 February 28 0.16
March 16 March 31 0.16
April 15 April 29 0.16
May 16 May 31 0.16
June 16 June 30 0.16
July 15 July 29 0.16
August 17 August 31 0.16
September 16 September 30 0.16
October 17 October 31 0.17 (Paid October 31, 2005)
November 16 November 30 0.17 (Announced November 7, 2005)
December 14 December 30 0.17 (Indicated September 13, 2005)
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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 37,485 boe/d in the third quarter of 2005, an increase of 7% over average production volumes of 34,950 boe/d in the third quarter of 2004. The change in production reflects, PC's development drilling program, the Central Alberta acquisition in November 2004, the Turin area acquisition in January 2005, the Northern Crown and Tahiti acquisitions in May 2005, Joarcam area acquisition in July 2005, positive prior period adjustments (300 boe/d), offset by natural production decline.



3 months ended September 30, 9 months ended September 30,
---------------------------- ----------------------------
Daily
Production 2005 2004 2005 2004
---------------------------------------------------------------------
Oil (bbls) 18,451 17,504 18,064 13,934
Natural gas
(mcf) 97,825 90,119 94,384 82,623
Natural gas
liquids (bbls) 2,730 2,427 2,457 2,181
---------------------------------------------------------------------
Total (boe 6:1) 37,485 34,950 36,252 29,886
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PRICING AND PRICE RISK MANAGEMENT

Revenues from the sale of crude oil, natural gas, and natural gas liquids and sulphur increased 44% to $212.4 million in the third quarter of 2005 from $147.5 million in the third quarter of 2004 due to a 7% increase in production and a 34% increase in prices on a boe basis.

For the nine month period ended September 30, 2005, revenue increased 50% to $540.0 million from $360.2 million in 2004 due to a 21% increase in production to 36,252 boe/d and an increase of 24% in the average price per boe to $54.53 in 2005 from $43.97 in 2004.

Crude oil sales increased to $117.8 million in the third quarter of 2005 from $83.7 million in the third quarter of 2004 due to a 5% increase in production from 17,504 bbl/d in the third quarter of 2004 to 18,451 bbl/d in the third quarter of 2005 and a 33% increase in the oil price received. The average WTI oil price reported increased from U.S. $43.88/bbl in 2004 to U.S. $63.19/bbl in the third quarter of 2005 or 44%, however, the Canadian par price at Edmonton increased only 36% from $56.25/bbl to $76.51/bbl due to the significant strengthening of the Canadian dollar relative to the U.S. dollar which averaged 0.83 in the third quarter of 2005 versus 0.77 in the third quarter of 2004. The average Canadian wellhead price received by Petrofund increased from $52.02/bbl in the third quarter of 2004 to $69.37/bbl in the third quarter of 2005. Petrofund's negative differential from Edmonton par was $4.23/bbl in the third quarter of 2004 versus $7.14/bbl in the third quarter of 2005 as quality differentials for medium crudes have increased.

During the nine month period ended September 30, 2005, crude oil sales increased 65% to $301.9 million in 2005 from $182.8 million in the same period of 2004. Oil production increased 30% to 18,064 bbl/d for the period, compared to 13,934 bbl/d for the same period in 2004. The average price received increased from $47.88/bbl in 2004 to $61.21/bbl in 2005. The WTI U.S. price increased from U.S. $39.11/bbl for nine months ending September 30, 2004 to U.S. $55.40/bbl in the same period in 2005.

Natural gas sales increased to $81.9 million in the third quarter of 2005 from $53.9 million in the third quarter of 2004 due to 9% increase in production and a 40% increase in the average prices received from $6.50/mcf in the third quarter of 2004 to $9.10/mcf in the third quarter of 2005. The monthly AECO price per mmbtu increased from $6.66 in the third quarter of 2004 to $8.17 in the third quarter of 2005. Production volumes averaged 97.8 mmcf/d in the third quarter of 2005 compared to 90.1 mmcf/d in the third quarter of 2004.

During the nine month period ended September 30, 2005, natural gas sales increased 33% to $204.8 million in 2005 from $153.6 million in 2004. Natural gas production increased 14% from 82.6 mmcf/d in 2004 to 94.4 mmcf/d in 2005. The average price received increased 17% from $6.78/mcf in 2004 to $7.95/mcf in 2005.

Sales of natural gas liquids and sulphur increased to $12.7 million in the third quarter of 2005 from $9.9 million in the third quarter of 2004 as natural gas liquids production increased 12% to 2,730 bbl/d in the third quarter of 2005 from 2,427 bbl/d in the third quarter of 2004. The average price received, excluding sulphur, increased 15% from $43.68/bbl in the third quarter of 2004 to $50.36/bbl in the third quarter of 2005.

For the nine month period ended September 30, 2005, sales of natural gas liquids and sulphur increased 40% from $23.8 million in 2004 to $33.3 million in 2005. Production volumes of natural gas liquids for these periods increased 13% from 2,181 bbl/d in 2004 to 2,457 bbl/d in 2005 and the average price, excluding sulphur, increased 25% from $39.55/bbl in 2004 to $49.27/bbl in 2005.



3 months ended September 30, 9 months ended September 30,
---------------------------- ----------------------------
Average
Prices (1) 2005 2004 2005 2004
---------------------------------------------------------------------
Oil (per bbl) $ 69.37 $ 52.02 $ 61.21 $ 47.88
Natural gas
(per mcf) 9.10 6.50 7.95 6.78
Natural gas
liquids (per bbl) 50.36 43.68 49.27 39.55
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Weighted
average (6:1) $ 61.57 $ 45.85 $ 54.53 $ 43.97
---------------------------------------------------------------------
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3 months ended September 30, 9 months ended September 30,
---------------------------- ----------------------------
Production
Revenue
($ millions)
(1) 2005 2004 2005 2004
---------------------------------------------------------------------
Oil $ 117.8 $ 83.7 $ 301.9 $ 182.8
Natural gas 81.9 53.9 204.8 153.6
Natural gas
liquids
& sulphur 12.7 9.9 33.3 23.8
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Total $ 212.4 $ 147.5 $ 540.0 $ 360.2
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(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 September 30, 2005, Petrofund had 26.8 mmcf/d of natural gas and 5,000 bbl/d of crude oil hedged for the remainder of 2005 (approximately 28% of production) and 18.2 mmcf/d of natural gas and 4,500 bbl/d of crude oil hedged for 2006 (20% gas and 25% oil respectively). 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 Q4 2006 Q1 Q2 Q3 Q4
---------------------------------------------------------------------
Collars 12,632 10,658 9,474 14,211 14,211 4,737
Three way collars 7,895 5,132 9,474 4,737 4,737 1,579
Floors 6,316 2,369 9,474 - - -
---------------------------------------------------------------------
Total mcf/d 26,843 18,159 28,422 18,948 18,948 6,316
---------------------------------------------------------------------
---------------------------------------------------------------------


Average Volumes ($/mcf)
-------------------------------------------------
2005 2006
-------------------------- ---------------------------------------
Q4 2006 Q1 Q2 Q3 Q4
---------------------------------------------------------------------
Collar ceiling
price $ 12.87 $ 12.84 $ 14.94 $ 12.14 $ 12.14 $ 12.14
Collar floor
price 7.04 7.92 7.39 8.09 8.09 8.09
Three way ceiling
price 10.49 9.69 11.77 8.99 8.99 8.99
Three way floor
price 6.28 7.17 6.52 7.39 7.39 7.39
Three way floor
short 5.23 5.92 5.47 6.07 6.07 6.07
Floor price $ 8.44 $ 8.44 $ 8.44 $ - $ - $ -
---------------------------------------------------------------------
---------------------------------------------------------------------


Average Volumes (bbl/d)
-------------------------------------------------
2005 2006
-------------------------- ---------------------------------------
Oil Q4 2006 Q1 Q2 Q3 Q4
---------------------------------------------------------------------
Collared 1,000 4,000 5,000 5,000 4,000 2,000
Three way collars 4,000 500 1,000 1,000 - -
---------------------------------------------------------------------
Total bbl/d 5,000 4,500 6,000 6,000 4,000 2,000
---------------------------------------------------------------------


Average Prices ( $ /bbl)
-------------------------------------------------
Collar ceiling
price $ 69.76 $ 87.20 $ 85.52 $ 88.60$ 88.50 $ 86.16
Collar floor price 48.83 58.91 56.28 58.72 59.59 61.05
Three way ceiling
price 45.35 65.26 61.62 68.89 - -
Three way floor
price 34.30 47.67 46.51 48.83 - -
Three way floor
short $ 29.65 $ 41.86 $ 40.69 $ 43.02 $ - $ -
---------------------------------------------------------------------
---------------------------------------------------------------------


2005 2006
-------------------------- ---------------------------------------
Alberta Power Q4 2006 Q1 Q2 Q3 Q4
---------------------------------------------------------------------
Fixed MW/h $ 2.0 $ 2.0 $ 2.0 $ 2.0 $ 2.0 $ 2.0
Fixed price
($/MWh) $ 44.50 $ 57.00 $ 57.00 $ 57.00 $ 57.00 $ 57.00
---------------------------------------------------------------------
---------------------------------------------------------------------


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 September 30, 2005 and as at October 31, 2005, Petrofund had entered into the following additional hedge (not included in the table above):

1) Collar for April 1, 2006 to October 31, 2006 for 4.7 mmcf/d of natural gas between $8.97/mcf and $14.78/mcf.

Petrofund has no sales volumes hedged after December 31, 2006. All foreign exchange calculations in this section of the report incorporate the Bank of Canada U.S. dollar rate at the close on September 30, 2005 of CDN $1.1627:U.S. $1.



ROYALTIES
3 months ended September 30, 9 months ended September 30,
---------------------------- ----------------------------
2005 2004 2005 2004
---------------------------------------------------------------------

Royalties
($ millions) $ 42.1 $ 27.6 $ 105.0 $ 69.2
Average royalty
rate (%) 20 19 19 19
$/boe $ 12.21 $ 8.58 $ 10.61 $ 8.45
---------------------------------------------------------------------
---------------------------------------------------------------------


Royalties, which include crown, freehold and overrides paid on oil and natural gas production, increased to $42.1 million in the third quarter of 2005 from $27.6 million in the third quarter of 2004, net of the Alberta Royalty Credit ("ARC"). Royalties, as a percentage of revenues before hedging losses, increased to 20% of revenues in the third quarter of 2005 from 19% of revenues in the third quarter of 2004.

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



EXPENSES
3 months ended September 30, 9 months ended September 30,
---------------------------- ----------------------------
2005 2004 2005 2004
---------------------------------------------------------------------

Expenses ($ millions)
Lease operating $ 35.6 $ 30.9 $ 103.2 $ 74.4
Transportation 2.3 1.8 6.2 4.3
General &
administrative 4.8 3.8 12.4 10.2
Financing costs 2.1 1.7 6.9 3.8
---------------------------------------------------------------------

Expenses per boe
Lease operating $ 10.31 $ 9.62 $ 10.43 $ 9.08
Transportation 0.66 0.55 0.63 0.52
General &
administrative 1.40 1.17 1.25 1.25
Financing costs 0.62 0.55 0.69 0.46
---------------------------------------------------------------------
---------------------------------------------------------------------


Lease Operating

Oil and gas lease operating expenses increased 15% to $35.6 million in the third quarter of 2005 from $30.9 million in the third quarter of 2004 due to a 7% increase in production and an 7% increase in costs on a boe basis. Operating costs on a boe basis increased to $10.31 in the third quarter of 2005 from $9.62 in the third quarter of 2004.

Operating costs for the nine month period ended September 30, 2005 were up 15% to $10.43 per boe compared to $9.08 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.

The most significant contributor to the higher per unit operating costs to date in 2005 has been a general industry increase 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 fourth quarter of 2005 are expected to continue in the mid $10 per boe range.

Transportation Costs

Transportation costs on a boe basis were $0.66 in the third quarter of 2005 as compared to $0.55 for the third quarter of 2004 this increase mainly is due to a general increase in trucking costs of clean oil.

Transportation costs on a boe basis were $0.63 in the nine months ending September 30, 2005 as compared to $0.52 for the nine months ending September 30, 2004 reflecting general increase in trucking costs of clean oil and higher transportation costs associated with the Ultima properties.

General & Administrative ("G&A")

G&A costs on a boe basis were $1.40 per boe in the third quarter of 2005 as compared to $1.17 per boe in the same period in 2004. General and administrative costs, net of overhead recoveries, increased to $4.8 million in the third quarter of 2005 from $3.8 million in the third quarter of 2004, mainly due to higher employee compensation costs. G&A costs in the third quarter of 2005 included $126,000 directly relating to the external costs associated with compliance with Section 404 of the Sarbanes-Oxley Act ("SOX 404") which equates to $0.04 per boe.

General and administrative costs for the nine month period ended September 30, 2005, were $12.4 million compared to $10.2 million in 2004. Costs were $1.25 per boe in 2005 compared to $1.25 per boe in 2004. We expect our G&A costs to be approximately $1.30 per 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 $2.1 million in the third quarter of 2005 from $1.7 million in the third quarter of 2004 due to the increase in the average loan balance outstanding in the third quarter of 2005 of $245.9 million versus $195.6 million in the third quarter of 2004.

Interest and other financing costs for nine months ended September 30, 2005, increased to $6.9 million in 2005 compared to $3.8 million in 2004, which reflects the increase in the average loan balance outstanding in 2005 of $251.7 million from $138.7 million in 2004. Net debt as a percentage of total capitalization is 9% in 2005 compared to 14% in 2004.

The bank loan outstanding at September 30, 2005, was $244.5 million as compared to $214.4 million at December 31, 2004, $10.0 million of debt was repaid in the third quarter of 2005. At September 30, 2005, 100% of our debt was based on floating interest rates.

DEPLETION, DEPRECIATION & ACCRETION

Depletion, depreciation and accretion expense increased to $51.0 million in the third quarter of 2005 from $42.0 million in the third quarter of 2004 due to an increase in production and an increase in the depletion rate. The rate per boe increased to $14.80 in the third quarter of 2005 from $13.06 in the third 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 nine months ended in September 30, 2005, was $142.0 million or $14.34 per boe as compared to $104.6 million or $12.78 per boe for the same period in 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 September 30, 2005. The Federal Large Corporations Tax rate is being reduced in stages, so that by 2008, the tax will be eliminated.

Capital taxes of $1.0 million in the third quarter of 2005 (2004 - $788,000) 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, which holds certain Saskatchewan properties, 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 third quarter of 2005 was a recovery of $1.9 million compared to $6.1 million recovery in the third quarter of 2004 as a result of a decrease in non-capital losses available.



NET INCOME

3 months ended September 30, 9 months ended September 30,
---------------------------- ----------------------------
2005 2004 2005 2004
---------------------------------------------------------------------

Net income
($000's) $ 51,209 $ 15,147 $110,645 $ 23,593
Net income
per Trust unit
Basic $ 0.49 $ 0.15 $ 1.08 $ 0.28
Diluted $ 0.49 $ 0.15 $ 1.08 $ 0.28
---------------------------------------------------------------------
---------------------------------------------------------------------


Net income before taxes increased from $9.1 million in the third quarter of 2004 to $49.5 million in the third quarter of 2005 mainly due to a 44% increase in revenues reflected by 7% increase in production and a 34% increase in prices on a boe basis. These increases have been offset by a 15% increase in lease operating costs and a 22% increase in depletion.

The Trust recognized a net loss on commodity contracts of $24.0 million in the third quarter of 2005 compared to $29.9 million loss in the third quarter of 2004. The unrealized (non-cash) gain on commodity contracts was $11.1 million in the third quarter of 2005 compared to a $15.3 million loss in the third 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 nine months ended September 30, 2005 was $106.9 million compared to $30.3 million for the same period in the prior year. This is mainly due to a 50% increase in oil and natural gas sales. Production increased 21% and prices increased 24% on a boe basis. These increases have been offset by a 39% increase in lease operating costs and a 36% increase in depletion.

Total cash netbacks increased by $45.1 million for three months ended September 30, 2005 compared to the same period in 2004. On a boe basis cash netbacks were up to $32.29 in the third quarter of 2005 from $20.59 in the third quarter of 2004.



3 months ended September 30, 9 months ended September 30,
---------------------------- ----------------------------
Total Cash
Netbacks 2005 2004 2005 2004
---------------------------------------------------------------------

Operating
netback $ 34.67 $ 22.57 $ 29.93 $ 22.46
Financing costs 0.62 0.53 0.69 0.46
General and
administrative 1.40 1.17 1.25 1.25
Capital and
current taxes 0.36 0.28 0.36 0.34
---------------------------------------------------------------------
Total cash
netback per
BOE $ 32.29 $ 20.59 $ 27.63 $ 20.41
---------------------------------------------------------------------
---------------------------------------------------------------------


As a result of the changes discussed above, net income increased to
$51.2 million in the third quarter of 2005 from the $15.1 million
reported in the third quarter of 2004.


Operating Netbacks for the three months ended September 30, 2005

Oil $/bbl Gas $/mcf NGL $/bbl Total $/boe
---------------------------------------------------------------------
Selling price $ 69.37 $ 9.10 $ 50.36 $ 61.57
Cash cost of hedging (6.49) (0.21) - (3.72)
---------------------------------------------------------------------
Net selling price 62.88 8.89 50.36 57.85
---------------------------------------------------------------------
Royalties, net of ARC 12.20 2.01 13.18 12.21
Operating 11.17 1.57 9.99 10.31
Transportation 0.49 0.15 0.46 0.66
---------------------------------------------------------------------
Operating netback $ 39.02 $ 5.16 $ 26.73 $ 34.67
---------------------------------------------------------------------
---------------------------------------------------------------------


Operating Netbacks three months ended September 30, 2004

Oil $/bbl Gas $/mcf NGL $/bbl Total $/boe
---------------------------------------------------------------------
Selling price $ 52.02 $ 6.50 $ 43.68 $ 45.85
Cash cost of hedging (8.62) (0.09) - (4.53)
---------------------------------------------------------------------
Net selling price 43.40 6.41 43.68 41.32
---------------------------------------------------------------------
Royalties, net of ARC 9.04 1.17 9.36 8.58
Operating 11.48 1.27 8.48 9.62
Transportation 0.31 0.14 0.41 0.55
---------------------------------------------------------------------
Operating netback $ 22.57 $ 3.83 $ 25.43 $ 22.57
---------------------------------------------------------------------
---------------------------------------------------------------------


The operating netback increased by $112.5 million for nine months
ending September 30, 2005. On a boe basis operating netback increased
to $29.93 in 2005 from $22.46 in 2004.


Operating Netbacks for the nine months ended September 30, 2005

Oil $/bbl Gas $/mcf NGL $/bbl Total $/boe
---------------------------------------------------------------------
Selling price $ 61.21 $ 7.95 $ 49.27 $ 54.53
Cash cost of hedging (5.52) (0.08) - (2.93)
---------------------------------------------------------------------
Net selling price 55.69 7.87 49.27 51.60
---------------------------------------------------------------------
Royalties, net of ARC 10.72 1.70 12.36 10.61
Operating 13.09 1.25 9.52 10.43
Transportation 0.50 0.13 0.51 0.63
---------------------------------------------------------------------
Operating netback $ 31.38 $ 4.79 $ 26.88 $ 29.93
---------------------------------------------------------------------
---------------------------------------------------------------------


Operating Netbacks for the nine months ended September 30, 2004

Oil $/bbl Gas $/mcf NGL $/bbl Total $/boe
---------------------------------------------------------------------
Selling price $ 47.88 $ 6.78 $ 39.55 $ 43.97
Cash cost of hedging (6.88) (0.08) - (3.46)
---------------------------------------------------------------------
Net selling price 41.00 6.70 39.55 40.51
---------------------------------------------------------------------
Royalties, net of ARC 8.49 1.37 9.75 8.45
Operating 11.54 1.13 7.96 9.08
Transportation 0.25 0.14 0.42 0.52
---------------------------------------------------------------------
Operating netback $ 20.72 $ 4.06 $ 21.42 $ 22.46
---------------------------------------------------------------------
---------------------------------------------------------------------


CAPITAL EXPENDITURES

Acquisitions

During the nine months ended September 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, $6.3 million to acquire property interests in the Turin area effective January 1, 2005 and $11.8 million to acquire property interest in the Joarcam area effective July 1, 2005. These acquisitions added approximately 1,650 boepd of production to the Trust. On these acquisitions, Petrofund's internal estimate of its working interest of reserves is 4.6 million boe on a proved plus probable basis.

Dispositions

During the nine months ended September 30, 2005, PC disposed of minor properties for net proceeds of $871,000, which included one non-core area in the Acheson area of Alberta for $863,000.

Development Activities

During the three months ended September 30, 2005, PC incurred $29.9 million in drilling and development activities compared to $20.5 million in the three months ended September 30, 2004. A total of 61 wells were drilled, of which 20 were gas, 38 oil, 2 service wells and 1 dry and abandoned well for an overall success rate of 98%.

During the nine months ended September 30, 2005, PC incurred $108.9 million in drilling and development activities as compared to $47.9 million in the nine months ended September 30, 2004. A total of 197 wells were drilled, of which 96 were gas, 93 oil, 4 service wells and 4 dry and abandoned wells for an overall success rate of 98%.



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

3 months ended September 30, 9 months ended September 30,
---------------------------- ----------------------------
2005 2004 2005 2004
---------------------------------------------------------------------
Corporate and
property
acquisitions (1) $ 11,245 $ (6,234) $ 73,826 $ 3,344
Property
dispositions (871) - (871) -
---------------------------------------------------------------------
10,374 (6,234) 72,955 3,344
Development
expenditures:
Land & seismic 1,114 468 6,519 1,435
Drilling
& completion 12,489 11,731 49,391 25,875
Well equipping 2,571 3,051 8,571 5,083
Tie-ins 2,729 1,085 10,961 3,334
Facilities 5,684 1,876 19,789 6,541
CO2 purchases 5,197 2,275 13,375 5,663
Other 111 - 302 -
---------------------------------------------------------------------
Total 29,895 20,486 108,908 47,931
---------------------------------------------------------------------
Total net capital
expenditures
- cash 40,269 14,252 181,863 51,275
Corporate
acquisitions
- non-cash (2) 16 - 16,411 559,831
Current year ARO
capitalized 490 204 2,229 540
---------------------------------------------------------------------
Total capital
expenditures (3) $ 40,775 $ 14,456 $200,503 $611,646
---------------------------------------------------------------------
---------------------------------------------------------------------
(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 for 2005 to be approximately $150 million. We are planning a similar level of expenditure for 2006 in our capital program however, we may increase our capital as we identify and execute on more of the opportunities within our existing properties.

ASSET RETIREMENT FUND

As at September 30, 2005, PC had $8.5 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 $339,000 for these activities in the third quarter of 2005 compared to $1.2 million in the third quarter of 2004. Reclamation and abandonment costs incurred for the nine months ended September 30, 2005, were $1.8 million as compared to $3.2 million in 2004. PC expects to spend a further $500,000 on reclamation and abandonment work in the remainder of 2005.

GOODWILL

The goodwill balance of $190.2 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 September 30, 2005.

DEBT

As at September 30, 2005, the amount outstanding on our credit facility was $244.5 million, with $170.5 million available to finance future activities.

LIQUIDITY AND CAPITAL RESOURCES

Working capital was $12.1 million at September 30, 2005, an increase of $61.4 million from the $49.3 million deficit as at December 31, 2004. The September 30, 2005 and December 31, 2004 working capital exclude net unrealized gains/losses on commodity contracts. Current assets increased $23.7 million from $48.6 million at December 31, 2004 to $72.3 million at September 30, 2005. Current liabilities decreased $37.7 million from $97.9 million at December 31, 2004 to $60.2 million at September 30, 2005. This decrease in liabilities reflects decrease trade payables and a decrease in distributions payable to Unitholders.

During the third quarter of 2005 the Trust generated cash flow of $111.1 million and paid out $50.1 million in distributions. The excess of $61.0 million was used to partially fund the Trust's capital expenditure program.

In June 2005, the Trust completed a "bought deal" financing of Trust units, raising gross proceeds of $75.7 million ($71.4 million net). A total of 4.15 million 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 $244.5 million at September 30, 2005, from $214.4 million at December 31, 2004, due to the funding of acquisitions and development activities.



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

3 months ended September 30, 9 months ended September 30,
---------------------------- ----------------------------
($ thousands) 2005 2004 2005 2004
---------------------------------------------------------------------
Cash flow $111,122 $ 65,075 $271,892 $163,942
Proceeds received
from issuance of
Trust units 452 1,642 77,874 3,351
Net change in
non-cash working
capital balances (21,083) (2,395) (39,516) 24,797
Distributions paid (50,150) (47,684) (146,837) (121,759)
Expenditures on
oil & natural
properties, net (40,269) (14,252) (181,863) (51,275)
Assumption of debt,
net of cash on
acquisitions - - 88 (100,696)
Asset retirement
reserve (518) (482) (1,485) (1,228)
Redemption of
exchangeable
shares (258) (450) (904) (1,352)
Capital lease
repayments (74) (90) (608) (264)
(Increase)
decrease in cash 10,624 11,625 (8,726) (5,283)
Miscellaneous - 74 - 608
---------------------------------------------------------------------
$ 9,846 $ 13,063 $(30,085) $(89,159)
---------------------------------------------------------------------
---------------------------------------------------------------------


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


Capitalization Analysis

($ thousands, except per unit and percent amounts) 2005 2004
---------------------------------------------------------------------
Working capital (deficiency) (1) $ 12,077 $ (55,784)
Bank debt 244,499 199,474
---------------------------------------------------------------------
Net debt obligation $ 232,422 $ 255,258
---------------------------------------------------------------------
Units outstanding and issuable for
Exchangeable Shares 105,046 100,344
Market Price at September 30, $ 22.82 $ 15.90
Market capitalization $2,397,156 $1,595,476
---------------------------------------------------------------------
Total capitalization $2,629,578 $1,850,258
---------------------------------------------------------------------
Net debt as a percentage of total
capitalization 9% 14%
---------------------------------------------------------------------
---------------------------------------------------------------------

(1) Excludes net unrealized losses on commodity contracts.


Based on annualized third quarter 2005 cash flow, Petrofund's net
debt to cash flow ratio is 0.5:1.0. 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 September 30, 9 months ended September 30,
---------------------------- ----------------------------
2005 2004 2005 2004
---------------------------------------------------------------------
Basic 105,017,651 100,266,733 102,412,474 84,064,168
Diluted 105,039,185 100,353,257 102,441,345 84,210,974
---------------------------------------------------------------------
---------------------------------------------------------------------

Trust units/exchangeable shares outstanding:

As at September 30, 2005 2004
---------------------------------------------------------------------
Trust units outstanding 104,507,120 99,405,256
Trust units issuable for exchangeable shares 539,147 939,147
---------------------------------------------------------------------
105,046,267 100,344,403
---------------------------------------------------------------------
---------------------------------------------------------------------


The Trust had 104,507,120 Trust units outstanding at September 30, 2005 compared to 99,405,256 Trust units at the end of September 30, 2004. The weighted average number of Trust units outstanding including Trust units issuable for Exchangeable Shares, was 105,017,651 Trust units for the third quarter of 2005 as compared to 100,266,733 for 2004. During the nine months ending September 30, of 2005, 316,251 Exchangeable Shares were exchanged for 400,000 Trust units and 37,779 were redeemed for cash leaving 402,618 Exchangeable Shares outstanding at September 30, 2005 which are exchangeable into 539,147 Trust units.

FINANCIAL INSTRUMENTS

The net negative fair value of the commodity contracts at September 30, 2005 of $36.3 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 nine months ended September 30, 2005 of $25.0 million (2004 - $25.7 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 $12.8 million for three months ended September 30, 2005 compared to $14.6 million for three months ended September 30, 2004.



Jan 1, Amortized September
Deferred Commodity Contracts ($000's) 2005 to Expense 30, 2005
---------------------------------------------------------------------

Current Asset
Deferred loss $ 517 $ (388) $ 129

Current Liability
Deferred gain (184) 146 (38)
---------------------------------------------------------------------
$ 333 $ (242) $ 91
---------------------------------------------------------------------
---------------------------------------------------------------------

Jan 1, Change in September
Commodity Contracts ($000's) 2005 Fair Value 30, 2005
---------------------------------------------------------------------

Current Asset
Commodity contracts $ 3,281 $ (2,536) $ 745

Current Liability
Commodity contracts (14,599) (22,452) (37,051)
---------------------------------------------------------------------
$(11,318) $(24,988) $(36,306)
---------------------------------------------------------------------
---------------------------------------------------------------------


NON-RESIDENT OWNERSHIP

Based on information available to the Trust, Petrofund estimated that non-resident ownership was approximately 74% as of October 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 - U.S. 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 third quarter of 2005 moderated the net effect of these prices on Petrofund's cash flow. The WTI price increased 44% to U.S. $63.19/bbl in 2005 from U.S. $43.88/bbl in the third quarter of 2004, however, as the (U.S./CDN) exchange rate averaged 0.83 in 2005 as compared to 0.77 in the third quarter of 2004 the par price at Edmonton was up only 36%. 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.

CORPORATE DEVELOPMENTS

S&P Confirms Inclusion of Income Trusts In S&P/TSX Composite Index

On October 11, 2005 Standard & Poor's confirmed that it will proceed with its previously announced schedule for including income trusts in the S&P/TSX Composite Index. Following market close on December 15, 2005, income trusts, including Petrofund, will be added to the index at 50 per cent of their full float adjusted weight and at full weighting on the March 17, 2006 market close.

Federal Tax Consultation Process

In September of 2005, the Department of Finance issued a consultation paper outlining issues related to the tax treatment of certain entities including income trusts. The launch of this paper and a subsequent moratorium on advance tax rulings on proposed conversions of corporations to income trusts has created uncertainty in the market as to what future actions the government might take. This uncertainty has had a negative effect on the income trust public market.

The income trust sector, with its recent growth, has provided the average Canadian investor with an income vehicle with unique advantages. In addition, energy trusts are making significant investments in the finding and development of new oil and gas reserves. As a result, we believe that the overall impact of income trusts like Petrofund is positive to the Canadian economy.

The consultation process announced by the Department of Finance indicated they would seek input from concerned parties before they make any decisions which would impact the income trust sector and its investors. Petrofund will be active in this consultation process and will be making our views known to the Department of Finance through participation in a submission by the Canadian Association of Income Funds as well as our own corporate submission.

Sarbanes-Oxley Update

On July 31, 2002, the United States Congress enacted the Sarbanes-Oxley Act ("SOX") that applies to all companies registered with the Securities and Exchange Commission ("SEC"). On March 2, 2005, the SEC announced a one year extension of the compliance date for all foreign private issuers. As a result of this extension, Petrofund is currently required to comply with section 404 of the SOX legislation as of December 31, 2006. Section 404 requires that management identify, document, and assess Internal Control over Financial Reporting and issue a report on their assessment of its effectiveness. The Trust has implemented a comprehensive program for meeting the requirements of section 404 by December 31, 2006.

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 third quarter of 2005 and production volumes of 37,500 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.



$/unit
Change $000's per year
---------------------------------------------------------------------

Price per barrel of oil(1) $ 1.00 U.S. WTI $ 7,607 $ 0.072
Price per mcf of natural gas(1) $ 0.25 CDN $ 7,052 $ 0.067
US/Cdn exchange rate $ 0.01 $ 6,185 $ 0.059
Interest rate on debt ($245 million) 1% $ 2,445 $ 0.023
Oil production volumes(1) 100 bbl/day $ 2,076 $ 0.020
Gas production volumes(1) 1 mmcf/day $ 2,624 $ 0.025
---------------------------------------------------------------------
---------------------------------------------------------------------

(1)After adjustment for estimated royalties.


QUARTERLY REVIEW
(thousands of Canadian dollars and units, except per unit amounts)


2005
-------------------------------------
Q3 Q2 Q1
---------------------------------------------------------------------

Daily Production

Oil (bbls) 18,451 17,500 18,238
Natural gas (mcf) 97,825 96,951 88,271
Natural gas liquids (bbl) 2,730 2,353 2,283
BOE (6:1) 37,485 36,011 35,234

Prices (5)

Oil (per bbl) $ 69.37 $ 59.18 $ 54.74
Natural gas (per mcf) $ 9.10 $ 7.65 $ 6.97
Natural gas liquids (per bbl) $ 50.36 $ 51.10 $ 46.04
BOE (6:1) $ 61.57 $ 52.69 $ 48.79

Operational Highlights

Oil and natural gas sales (5) $ 212,404 $ 172,831 $ 154,768
Net oil and natural gas
sales (1) $ 170,309 $ 141,722 $ 122,924

Cash flow (2) $ 111,122 $ 87,811 $ 72,959
Per unit $ 1.06 $ 0.86 $ 0.73
Per boe $ 32.22 $ 26.80 $ 23.01

Cash distribution paid $ 50,150 $ 48,793 $ 47,894
Cash distribution paid
per unit $ 0.48 $ 0.48 $ 0.48

Net income $ 51,209 $ 40,193 $ 19,243
Net income per unit - Basic $ 0.49 $ 0.40 $ 0.19
- Diluted $ 0.49 $ 0.40 $ 0.19

Cash operating netback
per BOE $ 34.67 $ 29.28 $ 25.45

Lease operating costs $ 35,558 $ 35,677 $ 32,010
Cost per BOE $ 10.31 $ 10.89 $ 10.09

General & administrative costs $ 4,816 $ 3,902 $ 3,639
Costs per BOE $ 1.40 $ 1.19 $ 1.15

Balance sheet

Working capital (deficit)(3) $ 12,077 $ (47,812) $ (59,531)
Property, plant
and equipment, net $ 1,297,522 $ 1,306,761 $ 1,259,248
Long-term debt $ 244,499 $ 254,345 $ 239,237
Unitholders' equity $ 1,084,746 $ 1,034,115 $ 992,882

Units and Exchangeable Shares Outstanding

Weighted average 105,018 101,569 100,603
Diluted 105,039 101,593 100,644
At period end 105,046 105,014 100,746

Market Capitalization $ 2,397,156 $ 2,047,767 $ 1,777,156

Total Capitalization(3)(4) $ 2,629,578 $ 2,349,924 $ 2,075,924

Trust Unit Trading (TSX:PTF.UN)

High $ 23.31 $ 19.97 $ 19.33
Low $ 19.30 $ 17.00 $ 15.50
Close $ 22.82 $ 19.50 $ 17.64
Average daily volumes 147 176 264

Trust Unit Trading (AMEX:PTF)

High $ 19.85 $ 16.25 $ 16.05
Low $ 15.72 $ 13.62 $ 12.66
Close $ 19.64 $ 15.92 $ 14.62
Average daily volumes 579 469 643

2004
----------------------------------------------
Q4 Q3 Q2 Q1
---------------------------------------------------------------------

Daily Production

Oil (bbls) 18,508 17,504 12,679 11,579
Natural gas (mcf) 90,089 90,119 79,741 77,925
Natural gas liquids
(bbl) 2,502 2,427 2,074 2,040
BOE (6:1) 36,025 34,950 28,043 26,607

Prices (5)

Oil (per bbl) $ 50.96 $ 52.02 $ 47.01 $ 42.50
Natural gas
(per mcf) $ 7.12 $ 6.50 $ 7.13 $ 6.76
Natural gas liquids
(per bbl) $ 48.20 $ 43.68 $ 37.13 $ 37.06
BOE (6:1) $ 47.33 $ 45.85 $ 44.27 $ 41.15

Operational Highlights

Oil and natural
gas sales (5) $ 156,922 $ 147,489 $ 112,970 $ 99,699
Net oil and natural
gas sales (1) $ 125,866 $ 119,911 $ 89,953 $ 81,121

Cash flow (2) $ 72,302 $ 65,075 $ 49,820 $ 49,047
Per unit $ 0.72 $ 0.65 $ 0.64 $ 0.67
Per boe $ 21.81 $ 20.24 $ 19.52 $ 20.26

Cash distribution
paid $ 47,734 $ 47,684 $ 39,165 $ 34,910
Cash distribution
paid per unit $ 0.48 $ 0.48 $ 0.48 $ 0.48

Net income $ 50,765 $ 15,147 $ 817 $ 7,629
Net income per
unit - Basic $ 0.51 $ 0.15 $ 0.01 $ 0.10
- Diluted $ 0.51 $ 0.15 $ 0.01 $ 0.10

Cash operating
netback per BOE $ 24.40 $ 22.57 $ 22.05 $ 22.71

Lease operating
costs $ 29,222 $ 30,920 $ 23,639 $ 19,829
Cost per BOE $ 8.82 $ 9.62 $ 9.26 $ 8.19

General &
administrative
costs $ 4,223 $ 3,764 $ 3,316 $ 3,138
Costs per BOE $ 1.27 $ 1.17 $ 1.30 $ 1.30

Balance sheet

Working capital
(deficit) (3) $ (49,310) $ (55,784) $ (30,955) $ (56,093)
Property, plant
and equipment, net $1,246,694 $1,230,636 $1,251,484 $ 883,191
Long-term debt $ 214,414 $ 199,474 $ 212,537 $ 90,040
Unitholders' equity $1,026,526 $1,031,226 $1,063,704 $ 615,952

Units and Exchangeable Shares Outstanding

Weighted average 100,396 100,267 78,074 73,674
Diluted 100,466 100,353 78,229 73,872
At period end 100,451 100,344 100,190 73,682

Market Capitalization $1,568,036 $1,595,476 $1,487,823 $1,278,390

Total Capitalization
(3) (4) $1,842,745 $1,850,258 $1,731,315 $1,434,515

Trust Unit Trading (TSX:PTF.UN)

High $ 17.15 $ 16.35 $ 18.08 $ 19.24
Low $ 14.52 $ 14.62 $ 14.70 $ 14.56
Close $ 15.61 $ 15.90 $ 14.85 $ 17.35
Average daily
volumes 185 287 189 204

Trust Unit Trading (AMEX:PTF)

High $ 13.65 $ 12.83 $ 13.54 $ 14.96
Low $ 12.16 $ 11.10 $ 10.95 $ 10.95
Close $ 13.04 $ 12.60 $ 11.16 $ 13.22
Average daily
volumes 518 431 319 633


2003
-------------
Q4
---------------------------------------------------------------------

Daily Production

Oil (bbls) 13,645
Natural gas (mcf) 80,286
Natural gas liquids (bbl) 2,185
BOE (6:1) 29,211

Prices (5)

Oil (per bbl) $ 36.07
Natural gas (per mcf) $ 5.87
Natural gas liquids (per bbl) $ 34.86
BOE (6:1) $ 35.60

Operational Highlights

Oil and natural gas sales (5) $ 95,763
Net oil and natural gas sales (1) $ 76,778

Cash flow (2) $ 43,246
Per unit $ 0.63
Per boe $ 16.09

Cash distribution paid $ 36,248
Cash distribution paid per unit $ 0.54

Net income $ 24,266
Net income per unit - Basic $ 0.35
- Diluted $ 0.35

Cash operating netback per BOE $ 18.72

Lease operating costs $ 24,777
Cost per BOE $ 9.22

General & administrative costs $ 2,948
Costs per BOE $ 1.10

Balance sheet

Working capital (deficit) (3) $ (30,006)
Property, plant and equipment, net $ 868,263
Long-term debt $ 110,315
Unitholders' equity $ 648,293

Units and Exchangeable Shares Outstanding

Weighted average 68,498
Diluted 68,691
At period end 73,628

Market Capitalization $ 1,383,465

Total Capitalization (3) (4) $ 1,523,786

Trust Unit Trading (TSX:PTF.UN)

High $ 19.15
Low $ 15.89
Close $ 18.79
Average daily volumes 234

Trust Unit Trading (AMEX:PTF)

High $ 14.55
Low $ 11.90
Close $ 14.46
Average daily volumes 436

(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 September 30, 2005
and December 31, 2004 2005 2004
---------------------------------------------------------------------
---------------------------------------------------------------------

Assets

Current assets
Cash $ 7,993 $ -
Accounts receivable 47,671 37,713
Deferred loss on commodity contracts 129 517
Commodity contracts (Note 9) 745 3,281
Prepaid expenses 16,591 10,847
---------------------------------------------------------------------

Total current assets 73,129 52,358

Asset retirement reserve fund (Note 7(b)) 8,538 7,053

Goodwill (Note 2) 190,247 180,307

Oil and natural gas royalty and property
interests, at cost less accumulated
depletion and depreciation of $772,403
(2004 - $632,668) 1,297,522 1,246,694
---------------------------------------------------------------------
$ 1,569,436 $ 1,486,412
---------------------------------------------------------------------
---------------------------------------------------------------------

Liabilities and Unitholders' Equity

Current liabilities
Bank overdraft $ - $ 733
Accounts payable and accrued liabilities 42,052 60,961
Current portion of capital lease
obligations - 608
Deferred gain on commodity contracts 38 184
Commodity contracts (Note 9) 37,051 14,599
Distributions payable to Unitholders
(Note 8) 18,126 35,568
---------------------------------------------------------------------
Total current liabilities 97,267 112,653

Long-term debt (Note 6) 244,499 214,414

Future income taxes 87,658 81,411

Asset retirement obligations (Note 7(a)) 55,266 51,408
---------------------------------------------------------------------
Total liabilities 484,690 459,886

Unitholders' equity
Unitholders' capital (Note 3) 1,560,317 1,477,963
Exchangeable shares (Note 4) 6,038 10,518
Accumulated earnings 383,257 272,612
Accumulated cash distributions (Note 8) (864,866) (734,567)
---------------------------------------------------------------------
Total unitholders' equity 1,084,746 1,026,526
---------------------------------------------------------------------
$ 1,569,436 $ 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 September 30, 9 months ended September 30,
---------------------------- ----------------------------
2005 2004 2005 2004
---------------------------------------------------------------------
---------------------------------------------------------------------

Revenues
Oil and natural
gas sales $ 212,404 $ 147,489 $ 540,003 $ 360,158
Royalties (42,095) (27,578) (105,048) (69,173)
Loss on
commodity
contracts (23,971) (29,903) (54,254) (60,934)
---------------------------------------------------------------------
146,338 90,008 380,701 230,051
---------------------------------------------------------------------

Expenses
Lease operating 35,558 30,920 103,245 74,388
Transportation
costs 2,291 1,753 6,222 4,264
Financing costs 2,123 1,703 6,858 3,792
General and
administrative 4,816 3,764 12,357 10,218
Capital taxes 1,023 788 3,167 2,444
Depletion,
depreciation
and accretion 51,027 41,982 141,960 104,619
---------------------------------------------------------------------
96,838 80,910 273,809 199,725
---------------------------------------------------------------------
Income before
provision for
income taxes 49,500 9,098 106,892 30,326
---------------------------------------------------------------------

Provision for
(recovery of)
income taxes
Current 202 100 418 368
Future (1,911) (6,149) (4,171) 6,365
---------------------------------------------------------------------
(1,709) (6,049) (3,753) 6,733
---------------------------------------------------------------------
Net income 51,209 15,147 110,645 23,593
---------------------------------------------------------------------
Accumulated
earnings,
beginning
of period 332,048 206,699 272,612 198,253
Accumulated
earnings,
end of period $ 383,257 $ 221,846 $ 383,257 $ 221,846
---------------------------------------------------------------------
---------------------------------------------------------------------
Net income per
Trust unit
(Note 3)
Basic $ 0.49 $ 0.15 $ 1.08 $ 0.28
Diluted $ 0.49 $ 0.15 $ 1.08 $ 0.28
---------------------------------------------------------------------
---------------------------------------------------------------------

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 September 30, 9 months ended September 30,
---------------------------- ----------------------------
2005 2004 2005 2004
---------------------------------------------------------------------
---------------------------------------------------------------------

Cash provided by (used in):

Operating activities
Net income $ 51,209 $ 15,147 $ 110,645 $ 23,593
Add items
not affecting
cash:
Depletion,
depreciation
and accretion 51,027 41,982 141,960 104,619
Commodity
contracts
unrealized loss 11,136 15,344 25,230 32,587
Future income
taxes
(recovery) (1,911) (6,149) (4,171) 6,365
Actual
abandonment
costs incurred
(Note 7(b)) (339) (1,249) (1,772) (3,222)
---------------------------------------------------------------------
111,122 65,075 271,892 163,942
Net change in
non-cash
operating
working capital
balances (21,083) (2,395) (39,516) 24,797
---------------------------------------------------------------------
Cash provided by
operating
activities 90,039 62,680 232,376 188,739
---------------------------------------------------------------------

Financing activities
Long-term debt (9,846) (12,989) 30,085 (20,640)
Distributions
paid (Note 8) (50,150) (47,684) (146,837) (121,759)
Redemption of
exchangeable
shares (Note 4) (258) (450) (904) (1,352)
Capital lease
repayments (74) (90) (608) (264)
Issuance of
Trust units
(Note 3) 452 1,642 77,874 3,351
---------------------------------------------------------------------

Cash used in
financing
activities (59,876) (59,571) (40,390) (140,664)
---------------------------------------------------------------------

Investing activities
Asset retirement
reserve
(Note 7(b)) (518) (482) (1,485) (1,228)
Corporate
acquisitions
(Note 2 (a)(b)) 42 5,636 (56,058) (1,800)
Property
acquisitions (11,287) 598 (17,768) (1,544)
Property
dispositions 871 - 871 -
Development
expenditures (29,895) (20,486) (108,908) (47,931)
Cash acquired
on acquisitions
(Note 2 (b)) - - 88 9,711
---------------------------------------------------------------------
Cash used in
investing
activities (40,787) (14,734) (183,260) (42,792)
---------------------------------------------------------------------
Net change
in cash (10,624) (11,625) 8,726 5,283
Cash (bank
overdraft),
beginning of
period 18,617 19,090 (733) 2,182
---------------------------------------------------------------------
Cash, end
of period $ 7,993 $ 7,465 $ 7,993 $ 7,465
---------------------------------------------------------------------
---------------------------------------------------------------------
Interest paid
during the
period $ 2,087 $ 2,504 $ 6,521 $ 3,671
---------------------------------------------------------------------
Income taxes
paid during
the period $ 144 $ 141 $ 77 $ 247
---------------------------------------------------------------------
---------------------------------------------------------------------

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


Notes to the Interim Consolidated Financial Statements
September 30, 2005 and 2004
(unaudited)
(tabular amounts in thousands of dollars, except unit
and per unit amounts)


1. INTERIM FINANCIAL STATEMENTS

These unaudited interim consolidated financial statements follow the same accounting policies and methods of their application as the most recent annual financial statements. The note disclosure requirements for annual 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.

2. 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 $7.1 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 7,120
Oil and gas royalties and property interests 38,556
Current liabilities (6,550)
Asset retirement obligations (756)
Future income taxes (7,398)
---------------------------------------------------------------------
$ 32,705
---------------------------------------------------------------------
---------------------------------------------------------------------


(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 2,820
Oil and gas royalties and property interests 23,974
Current liabilities (161)
Asset retirement obligations (420)
Future income taxes (3,020)
---------------------------------------------------------------------
$ 23,377
---------------------------------------------------------------------
---------------------------------------------------------------------


3. TRUST UNITS

Authorized: unlimited number Number
of Trust units 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 exchanged (Note 4) 400,000 4,480
Commissions and issue costs - (4,296)
Options exercised 405,424 5,751
Unit purchase plan 4,118 79
Unit incentive plan 36,002 602
---------------------------------------------------------------------
Balance, September 30, 2005 104,507,120 $ 1,560,317
---------------------------------------------------------------------
---------------------------------------------------------------------


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

3 months ended September 30, 9 months ended September 30,
---------------------------- ----------------------------
2005 2004 2005 2004
---------------------------------------------------------------------
Basic 105,017,651 100,266,733 102,412,474 84,064,168
Diluted 105,039,185 100,353,257 102,441,345 84,210,974
---------------------------------------------------------------------
---------------------------------------------------------------------

The diluted amounts include all dilutive instruments.

Trust units/exchangeable shares outstanding:

As at September 30, 2005 2004
---------------------------------------------------------------------
Trust units outstanding 104,507,120 99,405,256
Trust units issuable for exchangeable
shares (Note 4) 539,147 939,147
---------------------------------------------------------------------
105,046,267 100,344,403
---------------------------------------------------------------------
---------------------------------------------------------------------


4. EXCHANGEABLE SHARES

Number of
Issued and Outstanding Shares $000's
---------------------------------------------------------------------
Balance, December 31, 2004 756,648 $ 10,518
Redemption of shares (37,779) -
Exchanged for Trust Units (1) (316,251) (4,480)
---------------------------------------------------------------------
Balance, September 30, 2005 402,618 6,038
Exchangeable ratio, end of period 1.3391 -
---------------------------------------------------------------------
Exchangeable for Trust units 539,147 $ 6,038
---------------------------------------------------------------------
---------------------------------------------------------------------

(1) On March 7, 2005, 316,251 Exchangeable Shares were exchanged for
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, 2004, 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 54,326 31,156
Granted 110,067 61,245
Units issued (20,315) (51,571)
Forfeitures (20,905) -
---------------------------------------------------------------------
Balance, September 30, 2005 123,173 40,830
---------------------------------------------------------------------
---------------------------------------------------------------------


The Trust recorded compensation expenses of $2.6 million in the nine months ended September 30, 2005 (2004 - $1.2 million). The compensation expense was based on the September 30, 2005 unit price of $22.82, distributions of $1.44 per unit during the period and management's estimate of the number of RUP and LTIP units to be issued on maturity.

6. LONG-TERM DEBT

Under the loan agreements, as at September 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, 2004 - $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 September 30, 2005 was 4.50%. As at September 30, 2005, there was no amount outstanding under the working capital facility and $244.5 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.

7. 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 September 30, 9 months ended September 30,
---------------------------- ----------------------------
($000's) 2005 2004 2005 2004
---------------------------------------------------------------------
Balance, at
beginning of
period $ 54,126 $ 50,506 $ 51,408 $ 34,363
Increase in
liabilities
during the
period 490 204 2,229 540
Accretion
expense
during
period 989 824 2,225 1,932
Actual costs
incurred
during the
period (339) (1,249) (1,772) (3,222)
Acquisitions
additions
during the
period
(Note 2) - - 1,176 16,672
---------------------------------------------------------------------
Balance, at
end of period $ 55,266 $ 50,285 $ 55,266 $ 50,285
---------------------------------------------------------------------
---------------------------------------------------------------------


(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 September 30, 2005, the cash reserve was $8.5 million (December 31, 2004 - $7.1 million). In the third quarter of 2005, PC increased the cash reserve by withholding $518,000 (2004 - $482,000) from distributions accruing to Unitholders. In addition, routine ongoing reclamation and abandonment costs of $339,000 in the third quarter of 2005 (2004 - $1.2 million) were incurred and deducted from distributions accruing to Unitholders. Ongoing reclamation and abandonment cost of $1.8 million for nine months ended September 30, 2005 (2004 - $3.2 million) were incurred and deducted from distributions accruing the unitholders.

8. RECONCILIATION OF CASH FLOW AND DISTRIBUTIONS

Cash distributions are calculated in accordance with the Trust Indenture. To arrive at cash distributions, funds from operations, before changes in non-cash working capital, is reduced by reclamation fund contributions including interest earned on the fund, a portion of capital expenditures, debt repayments, Trust expenses, unit retraction or repurchases, if any, and all amounts paid into the reserve account. The portion of cash flow withheld to fund capital expenditures and to made debt repayments is at the discretion of the Board of Directors.



Reconciliation of Distributions Accruing to Unitholders
(thousands of dollars)

3 months ended September 30, 9 months ended September 30,
---------------------------- ----------------------------
2005 2004 2005 2004
---------------------------------------------------------------------
Distributions
payable,
beginning of
period $ 67,504 $ 26,029 $ 35,568 $ 53,452
---------------------------------------------------------------------
Distributions
accruing
during the
period
Cash provided
by operating
activities 90,039 62,680 232,376 188,739
Net change in
non-cash
operating
working
capital
balance 21,083 2,395 39,516 (24,797)
Amortization
of the cost
of commodity
contracts - (238) - (701)
Redemption of
exchangeable
shares (258) (450) (904) (1,352)
Asset
retirement
reserve
contributions (518) (482) (1,485) (1,228)
Capital
lease
repayment (74) (90) (608) (264)
---------------------------------------------------------------------
Cash flow
before
capital
reinvestment 110,272 63,815 268,895 160,397
Weyburn
deferred
capital
obligation - (1) - (34,931)
Capital
expenditures
funded from
cash flow (109,500) (15,000) (139,500) (30,000)
---------------------------------------------------------------------
Total
distributions
accruing
during the
period 772 48,814 129,395 95,466
Distributions
paid (50,150) (47,684) (146,837) (121,759)
---------------------------------------------------------------------
Distributions
payable,
end of period $ 18,126 $ 27,159 $ 18,126 $ 27,159
---------------------------------------------------------------------
---------------------------------------------------------------------


Accumulated Cash Distributions
(thousands of dollars)

3 months ended September 30, 9 months ended September 30,
---------------------------- ----------------------------
2005 2004 2005 2004
---------------------------------------------------------------------
Accumulated
cash
distributions,
beginning of
period $ 863,836 $ 628,709 $ 734,567 $ 581,155
Distributions
accruing
during the
period 772 48,814 129,395 95,466
Redemption of
exchangeable
shares 258 450 904 1,352
---------------------------------------------------------------------
Accumulated
cash
distributions,
end of period $ 864,866 $ 677,973 $ 864,866 $ 677,973
---------------------------------------------------------------------
---------------------------------------------------------------------


9. DERIVATIVE FINANCIAL INSTRUMENTS

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 September 30, 2005 and the related unrealized gains or losses are summarized separately below:



Unrealized
Natural Volume Price Delivery Gain (Loss)
Gas Term mcf/d $/mcf Point $000's
---------------------------------------------------------------------
Collar April 1, 2005 $ 6.33-
to October 31, 2005 4,737 $ 8.44 AECO $ (491)

Collar April 1, 2005 $ 6.33-
to October 31, 2005 4,737 $ 9.60 AECO (288)

Collar April 1, 2005 $ 6.33-
to October 31, 2005 4,737 $ 8.44 AECO (491)

Collar April 1, 2005 $ 6.33-
to October 31, 2005 4,737 $ 8.44 AECO (455)

Three $ 4.75-
way April 1, 2005 $ 5.80-
collar to October 31, 2005 4,737 $ 7.92 AECO (535)

Three $ 5.65-
way November 1, 2005 $ 6.70-
collar to March 31, 2006 4,737 $10.55 AECO (2,809)

Three $ 5.28-
way November 1, 2005 $ 6.33-
collar to March 31, 2006 4,737 $12.98 AECO (1,583)

Collar November 1, 2005 $ 7.39-
to March 31, 2006 4,737 $13.72 AECO (1,351)

Collar November 1, 2005 $ 7.39-
to March 31, 2006 4,737 $16.15 AECO (815)

Floor November 1, 2005
to March 31, 2006 4,737 $ 8.44 AECO 43

Floor November 1, 2005
to March 31, 2006 4,737 $ 8.44 AECO 53

Three $ 6.07-
way April 1, 2006 $ 7.39-
collar to October 31, 2006 4,737 $ 8.99 AECO (2,237)

Collar April 1, 2006 $ 7.39-
to October 31, 2006 4,737 $10.55 AECO (1,318)

Collar April 1, 2006 $ 8.44-
to October 31, 2006 4,737 $11.35 AECO (794)

Collar April 1, 2006 $ 8.44-
to October 31, 2006 4,737 $14.51 AECO 38
---------------------------------------------------------------------
Total $ (13,033)
---------------------------------------------------------------------
---------------------------------------------------------------------



Unrealized
Volume Price Delivery Gain (Loss)
Oil Term bbl/d $/bbl Point $000's
---------------------------------------------------------------------
Three $23.25-
way January 1, 2005 $27.90-
collar to December 31, 2005 1,000 $33.72 Edmonton $ (5,244)

Three $27.90-
way January 1, 2005 $31.39-
collar to December 31, 2005 1,000 $39.53 Edmonton (4,539)

Three $26.74-
way January 1, 2005 $31.39-
collar to December 31, 2005 1,000 $38.37 Edmonton (4,680)

Three $40.69-
way July 1, 2005 $46.51-
collar to December 31, 2005 1,000 $69.76 Edmonton (978)

Collar October 1, 2005 $48.83-
to December 31, 2005 1,000 $69.76 Edmonton (794)

Three $40.69-
way January 1, 2006 $46.51-
collar to March 31, 2006 1,000 $61.62 Edmonton (1,571)

Collar January 1, 2006 $48.83-
to March 31, 2006 1,000 $69.76 Edmonton (964)

Collar January 1, 2006 $52.32-
to March 31, 2006 1,000 $81.39 Edmonton (425)

Collar January 1, 2006 $58.14-
to March 31, 2006 1,000 $93.02 Edmonton (117)

Collar January 1, 2006 $58.14-
to March 31, 2006 1,000 $79.94 Edmonton (462)

Collar January 1, 2006 $63.95-
to June 30, 2006 1,000 $103.48 Edmonton 194

Three $43.02-
way April 1, 2006 $48.83-
collar to June 30, 2006 1,000 $68.89 Edmonton (1,179)

Collar April 1, 2006 $55.23-
to June 30, 2006 1,000 $81.39 Edmonton (487)

Collar April 1, 2006 $58.14-
to June 30, 2006 1,000 $75.58 Edmonton (638)

Collar April 1, 2006 $58.14-
to June 30, 2006 1,000 $88.37 Edmonton (241)

Collar April 1, 2006 $58.14-
to June 30, 2006 1,000 $94.18 Edmonton (124)

Collar July 1, 2006 $58.14-
to September 30, 2006 1,000 $75.58 Edmonton (648)

Collar July 1, 2006 $58.14-
to September 30, 2006 1,000 $87.78 Edmonton (268)

Collar July 1, 2006 $58.14-
to September 30, 2006 1,000 $93.89 Edmonton (138)

Collar July 1, 2006 $63.95-
to September 30, 2006 1,000 $96.74 Edmonton (24)

Collar October 1, 2006 $58.14-
to December 31, 2006 1,000 $75.58 Edmonton (653)
---------------------------------------------------------------------
Total $ (23,980)
---------------------------------------------------------------------
---------------------------------------------------------------------


Unrealized
Volume Price Delivery Gain
Electricity Term MW/h $/MWh Point $000's
---------------------------------------------------------------------

Alberta
Fixed February 1, 2004 Power
Price to December 31, 2005 2.0 $44.50 Pool $ 155

Alberta
Fixed January 1, 2006 Power
Price to December 31, 2008 2.0 $57.00 Pool 552
---------------------------------------------------------------------
Total $ 707
---------------------------------------------------------------------
---------------------------------------------------------------------


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 U.S. dollar rate at the close on September 30, 2005 of CDN $1.1627: U.S.

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 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 in the Trust's 2004 annual report, 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. The Trust undertakes no obligation to update or revise any forward looking financial statements, except as required by applicable securities laws.

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


Contact Information

  • Petrofund Energy Trust
    Investor Relations
    (403) 218-4736 or Toll Free: 1-866-318-1767
    (403) 539-4300 (FAX)
    Email: info@petrofund.ca
    Website: www.petrofund.ca
    or
    Petrofund Energy Trust
    Chris Dutcher
    Director, Business Development
    (403) 218-8625