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

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News Release

CALGARY - February 18, 2004

Petrofund Energy Trust (TSX: PTF.UN; AMEX: PTF)
Reports Financial and Reserve Results for 2003

Petrofund Energy Trust is pleased to present its year end financial results for 2003 as well as selected information from its independent engineering reserve report. Attractive commodity prices and successful drilling and acquisition programs all contributed to Petrofund's strong 2003 results.

Key accomplishments in 2003 include:

• a 67% increase in cash flow to $187.6 million
   
• a 22% increase in distributions to $2.09 per unit
   
• a 2003 payout ratio of 70%
   
• year end debt to cash flow ratio of 0.59
   
• a 10% increase in production to 28,418 boepd
   
• a 24% reduction per boe in General and Administrative costs
   

• an increase in the proved plus probable reserve life index to 11.1 years
   

• replacement of 200% of 2003 annual production through acquisitions and development
   

• disposition of high cost, low RLI properties for total proceeds of $33.7 million
   

• a 3% net increase in reserves after acquisitions, dispositions, revisions and production

Petrofund's financial results for the year ending December 31, 2003 are presented below. Selected information from Petrofund's independent engineering reserve report is also included after the financial results.

HIGHLIGHTS

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

For the year ended December 31,		2003		2002	Variance
INCOME STATEMENT
Revenues	$	393,109	$	270,669	45%
Cash flow (1)	$	187,585	$	112,570	67%
Cash flow available for distribution (2)	$	150,712	$	103,095	46%
Cash flow available for distribution per unit (2)
Before allocation for capital	$	2.96	$	2.27	30%
Allocation for capital	$	(0.49)	$	(0.20)	(145%)
After allocation for capital	$	2.47	$	2.07	19%
Cash distributions paid per unit	$	2.09	$	1.71	22%
Net income	$	85,804	$	24,379	252%
Net income per unit
Basic	$	1.41	$	0.49	188%
Diluted	$	1.40	$	0.49	186%
UNITS AND EXCHANGEABLE SHARES OUTSTANDING (3)
Weighted average		61,010		49,922	22%
Diluted		61,153		49,968	22%
At period end		73,628		54,108	36%
BALANCE SHEET
Working capital (deficit)	$	(30,006)	$	(6,909)	(334)%
Property, plant and equipment and other assets	$	879,633	$	835,366	5%
Long-term debt	$	110,315	$	219,218	50%
Unitholder's equity	$	649,240	$	480,097	35%
MARKET CAPITALIZATION, as at December 31 (4)	$	1,383,465	$	587,068	136%
ENTERPRISE VALUE (4)	$	1,493,780	$	806,286	85%
TRUST UNIT TRADING (TSX: PTF.UN)
High	$	19.15	$	13.90	38%
Low	$	10.69	$	10.10	6%
Close	$	18.79	$	10.85	73%
Volume (units)		53,118		25,820	106%
TRUST UNIT TRADING (AMEX: PTF)
High	$	14.73	$	6.48	127%
Low	$	6.89	$	8.78	(22)%
Close	$	14.46	$	6.90	110%
Volume (units)		84,319		12,147	594%

(1) Cash flow before net change in non-cash operating working capital balances. Non-GAAP measure, see special notes in the Management Discussion and Analysis.
⁽²⁾ See Note 12 to consolidated financial statements for details.
⁽³⁾ See Note 8 to consolidated financial statements for details.
⁽⁴⁾ Market capitalization equals units outstanding and issuable for exchangeable shares at December 31, 2003 multiplied by the closing price of the units on that date. Enterprise value equals market capitalization plus long-term debt.

OPERATIONAL HIGHLIGHTS
(thousands of Canadian dollars except per unit amounts)

For the year ended December 31,		2003		2002		Variance
DAILY PRODUCTION
Oil (bbls)		12,454			11,162	12%
Natural gas (mmcf)		83.3			76.9	8%
Natural gas liquids (bbls)		2,079			1,808	15%
BOE (6:1)		28,418			25,782	10%
Total annual production (mboe)		10,373			9,410	10%
PRODUCTION PROFILE
Oil		44%			43%
Natural Gas		49%			50%
Natural gas liquids		7%			7%
PRICES
Oil (per bbl)	$	37.91	$		34.68	9%
Natural gas (per mcf)	$	6.39	$		3.95	62%
Natural gas liquids (per bbl)	$	34.66	$		28.30	22%
BOE (6:1)	$	37.87	$		28.77	32%
Operating netback per BOE	$	20.93	$		15.46	35%
PROVED PLUS PROBABLE RESERVES (1)
Crude oil (millions of barrels)		53.4			46.7	14%
Natural gas (billions of cubic feet)		248.7			274.2	(9)%
Natural gas liquids (millions of barrels)		7.2			7.0	3%
Millions of barrels of oil equivalent at 6:1		102.0			99.4	3%
LEASE OPERATING COSTS	$	91,251	$		74,774	(22)%
Cost per boe	$	8.80	$		7.95	(11)%
GENERAL AND ADMINISTRATIVE COSTS	$	13,047	$		15,514	16%
Cost per boe	$	1.26	$		1.65	24%

(1) Reserves at December 31, 2003, are based on total proved plus probable company interest reserves prior to royalties as defined in National Instrument 51-101 ("NI 51-101"). Reserve numbers for other years are based on established company interest, (proved plus 50 per cent probable) reserves prior to royalties.

MANAGEMENT DISCUSSION &ANALYSIS

NAME CHANGE AND REVISED TRADING SYMBOL

This is the first annual report that reflects the name change of the Trust to Petrofund Energy Trust ("Petrofund" or the "Trust") from NCE Petrofund. The name change was announced on October 23, 2003, and became effective November 1, 2003. On the same date, the name of the Trust's 100% owned subsidiary was changed to Petrofund Corp. ("PC") from NCE Petrofund Corp. As a result of the name change, the Trust adopted the new trading symbols PTF.UN on the Toronto Stock Exchange and PTF on the American Stock Exchange. The Trust units commenced trading under the new symbols on November 3, 2003.

The name change reflects the restructuring of the Trust. The restructuring began with the internalization of management early in 2003 and the consolidation of the remaining activities in the Calgary office over the year. Petrofund has an experienced and competent team of oil and gas professionals and support groups who have assembled an excellent portfolio of quality assets. This team has been an instrumental part of the significant growth of the entity which had an enterprise value of $1.5 billion as at December 31, 2003.

SPECIAL NOTES

The following discussion and analysis of financial results should be read in conjunction with the consolidated financial statements of the Trust for the fiscal years ended December 31, 2003 and 2002 presented later in this report. This commentary is based on information available to February 15, 2004.

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

Management uses cash flow (before changes in non-cash working capital) to analyze operating performance and leverage. Cash flow as presented does not have any standardized meaning prescribed by Canadian GAAP and may not be comparable with the calculation of similar measures for other entities. Cash flow as presented is not intended to represent operating cash flows or operating profits for the period, nor should it be viewed as an alternative to cash flow from operating activities, net earnings or other measures of financial performance calculated in accordance with Canadian GAAP. All references to cash flow throughout this report are based on cash flow before changes in non-cash working capital.

Reserves at December 31, 2003, are based on total proved plus probable company interest reserves prior to royalties as defined in National Instruments 51-101 ("NI 51-101"). Reserves volumes and values for 2003 have been calculated and disclosed in accordance with this standard. Reserve numbers for other years and previously announced acquisitions for the current year, are based on established company interest (proved plus 50% probable) reserves prior to royalties. Under those definitions, probable reserves were adjusted by a factor to account for the risk associated with their recovery. The Trust previously applied a risk factor of 50% in reporting probable reserves. Under current NI 51-101 reserves definitions, estimates are prepared such that the full proved plus probable reserves are estimated to be recoverable (proved plus probable reserves are effectively a "best estimate"). The attached reconciliation reflects current probable versus previous risk adjusted (50%) probable reserves reported by the Trust.

FORWARD-LOOKING STATEMENTS

This disclosure includes statements about expected future events and/or financial results that are forward-looking in nature and subject to substantial risks and uncertainties. For those statements, Petrofund claims the protection of the safe harbor for forward-looking statements provisions contained in the U.S. Private Securities Litigation Reform Act of 1995. Petrofund cautions that actual performance will be affected by a number of factors, many of which are beyond its control. These include general economic conditions in Canada and the United States; industry conditions including changes in laws and regulations; changes in income tax regulations; increased competition; and fluctuations in commodity prices, foreign exchange and interest rates. In addition, there are numerous risks and uncertainties associated with oil and natural gas operations and the evaluation of oil and natural gas reserves. As a result, future events and results may vary substantially from what Petrofund currently foresees.

A more complete discussion of the various factors that may affect future results is contained in Petrofund's recent filings with the Securities and Exchange Commission and Canadian securities regulatory authorities.

CRITICAL ACCOUNTING ESTIMATES

The preparation of financial statements in accordance with GAAP requires management to make certain judgments and estimates. Changes in these judgments and estimates could have a material impact on the Trust's financial results and financial condition. The Trust has determined that the process of estimating reserves is critical to several accounting estimates. The process of estimating reserves is complex and requires significant judgments and decisions based on available geological, geophysical, engineering and economic data. These estimates may change substantially as additional data from ongoing development and production activities becomes available, and as economic conditions impacting oil and natural gas prices, operating costs, and royalty burdens change. Reserve estimates impact net income through depletion, the provision for site reclamation and abandonment and in the application of the ceiling test, whereby the value of the oil and natural gas assets are subjected to an impairment test. The reserve estimates are also used to asses the borrowing base for the Trust's credit facilities. Revision or changes in the reserve estimates can have either a positive or a negative impact on net income or the borrowing base of the Trust.

2003 HIGHLIGHTS

The Trust paid out cash distributions of $127.3 million or $2.09 per unit, an increase of 22% over the $1.71 per unit paid in 2002. The Trust's payout ratio for the year was 70% (87% for the fourth quarter). Net income increased 252% to $85.8 million. The Trust generated cash flow of $187.6 million, an increase of 67% over 2002. Production on a boe basis increased 10% to 28,418 boepd. Average prices were relatively strong, up 32% on a boe basis from the prior year. The Canadian dollar strengthened in the second half of the year more than offsetting the increase in the West Texas Intermediate ("WTI") U.S. oil prices. The average WTI price in the second half of 2003 was up 9% to $30.16 a barrel from the same period in 2002, however, the Canadian par price at Edmonton was down 6% or $2.77 per bbl over the same period.

The internalization of management transaction was completed resulting in the elimination of management fees and lower general and administrative costs. Petrofund acquired interests in various long-life oil and gas properties for $115.6 million (excluding the non-cash future income tax adjustment of $4.7 million on the purchase of Solaris Oil and Gas Inc.). The properties added proved plus probable reserves of 19.4 million boe. Petrofund continued an active development drilling and farmout program, investing $71.4 million on development drilling, facilities and other costs. During the year 254 wells were drilled at an overall success rate greater than 90%. These activities added production at $28,600 per boepd. The combined result of the acquisition and development programs was to add 20.3 million boe's of reserves and replace 200% of 2003 production. Petrofund ended 2003 with a very strong balance sheet with long-term debt outstanding equivalent to 59% of 2003 cash flow. The Trust completed two equity offerings, raising net proceeds of $193.4 million. The Trust had a balanced production profile consisting of 49% gas and 51% oil and liquids. The Trust reached a milestone with market capitalization exceeding $1.3 billion. Corporate governance was strengthened including the establishment of Governance, Reserve Audit, and Human Resources and Compensation committees all consisting of independent directors. The Audit committee previously consisted of all independent directors. Petrofund meets all governance guidelines prescribed by the TSX and the AMEX.

Internalization of Management

One of the key achievements in the first half of 2003 was the elimination of the external management contract and all related fees.

At the Annual and Special Meeting held on April 16, 2003, unitholders of the Trust voted over 90% in favour of the proposed internalization of management resolution, and on April 29, 2003, the transaction was closed. As a result of the internalization, NCE Petrofund Management Corp. ("NCEP Management"), the Previous Manager of the Trust and NCE Management Services Inc. ("NMSI"), which employed all of the Calgary-based personnel who provided services to the Trust and PC, became wholly-owned subsidiaries of PC. Effective January 1, 2004 all the Calgary employees became direct employees of PC, the operating company.

As a result of the transaction, all management, acquisition and disposition fees payable to the Previous Manager were eliminated effective January 1, 2003, and the Trust's operations were consolidated in Calgary. To ensure an orderly transition of the services previously provided by NCEP Management through its office in Toronto, PC entered into an agreement with Sentry Select Corp. ("Sentry") to provide certain services to the Trust and PC until December 31, 2003. The cost decreased from $1 million in the first quarter to $500,000 in the second quarter and to $250,000 in each of the third and fourth quarters, after which Sentry no longer provides any services to Petrofund. Sentry was an affiliate of NCEP Management and is a company in which John Driscoll, the Chairman of the Board of Directors, owns a controlling interest.

The elimination of management fees and the reduction in general and administrative costs resulting from the streamlining and consolidation of on-going management in Calgary improved the operating structure of the Trust. The internalization was accretive to Petrofund's net asset value, distributions and cash flow per unit.

The elimination of management fees and the increased management ownership further aligned the interests of the unitholders and management and improved Petrofund's competitiveness for acquisitions as a result of the elimination of acquisition and disposition fees. The completion of the internalization is also expected to enhance the attractiveness of the units to a wider range of potential investors, expand the investor base, and may result in a lower cost of capital.

The cost of the internalization to Petrofund was $30.9 million, consisting of the issue of 1,939,147 exchangeable shares, 100,244 Trust units, and cash of $8.0 million, including $3.4 million to repay indebtedness owing to NCEP Management. Initially, each Exchangeable Share was exchangeable into one Trust unit. The exchange rate is adjusted from time to time to reflect distributions paid on each Trust unit after the closing date. The purchase price was based on numerous factors, including a fairness opinion by CIBC World Markets, who were retained by a special committee of the Board of Directors formed to consider this transaction and negotiate the terms of the internalization.

CASH DISTRIBUTIONS

Trust unitholders who held their units throughout 2003 received cash distributions of $2.09 per unit as compared to $1.71 per unit in 2002 and $4.24 in 2001. During each of the first two months of 2004, the Trust distributed $0.16 per unit.

The Trust generated cash flow available for distributions of $180.7 million in 2003. A total of $30 million of this cash flow was allocated to capital expenditures during the year in accordance with the Trust's policy to use a portion of the cash flow generated to offset production decline and enhance long-term unitholder returns. The $30 million represents 17% of cash flow for the year. A total of $127.3 million was paid out in distributions representing a payout ratio of 70%. In the fourth quarter, the Trust generated cash flow available for distribution of $41.6 million before deducting $7.5 million of capital and paid out $36.3 million in distributions for a payout ratio of 87%. For a detailed analysis of cash flow available for distribution and distributions paid refer to Note 12 to the Consolidated Financial Statements.

At December 31, 2003, the Trust had $53.5 million available to pay future distributions, capital and other costs, of which $23.6 million was used to pay the January and February 2004 distributions.

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 28,418 boe/d, an increase of 10% over average production volumes of 25,782 boe/d in the previous year. The majority of the increase is due to the additional properties purchased for $62 million in the second quarter of 2003, the additional Swan Hills Unit interest purchased in the third quarter of 2003 and the acquisition of NCE Energy Trust on May 31, 2002. Production from the second quarter acquisition is included in this report effective June 1, 2003, and the additional Swan Hills interest is included effective September 1, 2003.

For the years ended December 31,	2003	2002	2001
Daily Production
Oil (bbls)	12,454	11,162	8,156
Gas (mmcf)	83.3	76.9	67.2
Natural gas liquids (bbls)	2,079	1,808	1,452
Total (boe 6:1)	28,418	25,782	20,810

PRICING & PRICE RISK MANAGEMENT

Revenues from the sale of crude oil, natural gas, and natural gas liquids and sulphur increased 45% to $393.1 million in 2003 from $270.7 million in 2002 due to a 10% increase in production and 32% increase in prices on a boe basis.

Crude oil sales increased to $172.3 million in 2003 from $141.3 million in 2002 due to a 12% increase in production from 11,162 bbl/d in 2002 to 12,454 bbl/d in 2003. The average WTI U.S. oil price increased from $26.08 per bbl in 2002 to $31.04 in 2003 or 19%, however, the Canadian par price at Edmonton increased only 8% from $39.91 per bbl to $43.14 bbl due to the significant strengthening of the Canadian dollar relative to the U.S. dollar, especially in the last half of the year. The average Canadian wellhead price increased from $34.68 per barrel in 2002 to $37.91 per barrel in 2003. Hedging losses reduced the price by $1.00 per bbl in 2003 and $2.10 per bbl in 2002. About 72% of the Trust's crude production is sold directly to refiners, up from 62% a year ago and nearly double the level of 2001. This reflects Petrofund's strategy of reducing sales to marketers and middlemen to achieve higher levels of security for both credit and the actual physical delivery of the crude. The balance of the crude is delivered to marketers. Crude differentials were relatively stable and tight during 2003 with Petrofund's actual differentials from Edmonton postings before hedging at $4.23/bbl versus $3.16/bbl the previous year. Western Canadian crude differentials for 2004 are expected to be similar to those seen in 2003. Heavy oil differentials, to which Petrofund has little exposure, may be weaker and the bias is for tighter differentials for the lighter and medium sour crudes comprising the bulk of the Trust's portfolio. Petrofund's crude portfolio is over 97% light and medium crudes.

Natural gas sales increased to $194.2 million in 2003 from $110.7 million in 2002 due to an 8% increase in production in addition to a 62% increase in average prices from $3.95 per mcf in 2002 to $6.39 per mcf in 2003 net of a hedging loss of $0.11 per mcf. The monthly AECO price increased from $4.07 per mcf in 2003 to $6.71 per mcf in 2003. Production volumes were 83.3 mmcf/d in 2003 compared to 76.9 mmcf/d in 2002. Petrofund sold 34% of its production in 2003 to aggregators at netback pricing, down slightly from 38% in 2002 and similar to volumes delivered in 2001. The Trust sold the remaining 66% on daily and monthly spot market pricing in Alberta, Saskatchewan and British Columbia.

Sales of natural gas liquids increased to $26.6 million in 2003 from $18.7 million in 2002 as production increased to 2,079 bbl/d in 2003 from 1,808 bbl/d in 2002. The average price increased from $28.30 per barrel in 2002 to $34.66 per barrel in 2003. The majority of the Trust's NGL is sold to two buyers under one-year contract terms at market sensitive pricing. NGL netbacks lagged the recovery in crude oil prices during the year owing to mid-year weakness in natural gas prices. Petrofund expects NGL's to continue to return attractive pricing for 2004 with very strong pricing for condensate.

Crude oil sales accounted for 44% of total production in 2003 (2002 - 43%, 2001 - 39%), while natural gas sales contributed 49% of production in 2003 (2002 - - 50%, 2001 - 54%). Natural gas

liquid volumes accounted for 7% of total production in all three years. The Trust continues to maintain an excellent balance between oil and gas production.

Sales Prices

Average prices for the year ended December 31,		2003		2002		2001
Oil (1)	$	37.91	$	34.68	$	34.37
Gas (2)		6.39		3.95		5.09
Natural gas liquids		34.66		28.30		32.57
Weighted average (6:1)	$	37.87	$	28.77	$	32.19
(1) The oil price was increased (decreased) per bbl due to hedging	$	(1.00)	$	(2.10)	$	1.05
(2) The gas price was decreased per mcf due to hedging	$	(0.11)	$	-	$	(0.13)
Production Revenue (millions)
Oil	$	172.3	$	141.3	$	102.3
Gas		194.2		110.7		125.0
Natural gas liquids		26.6		18.7		17.2
Total	$	393.1	$	270.7	$	244.5

The Trust implemented a formal risk management policy which provides the Risk Management Committee with the ability to use specified price risk management strategies up to 50% 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 two years 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. In this way 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 December 31, 2003, Petrofund has hedged 26 mmcf/d of gas and 5,328 bbl/d of crude oil for 2004. The Trust increased its gas hedges for 2004 by 7 mmcf/d and its crude oil hedges by 1,569 bbl/d over the third quarter. Petrofund's 2004 gas hedges include: 18.5 mmcf/d collared between $5.42/mcf-$7.90/mcf and 7.5 mmcf/d fixed at $6.15/mcf. The Trust will lose its floor protection on about 9% of the collared volumes if AECO drops below $4.74/mcf but will receive a premium of $1.06/mcf in this event. Petrofund's 2004 crude hedges include 1,995 bbl/d fixed at $38.59/bbl in the first half and 668 bbl/d fixed at $36.41 in the second half of the year. The Trust has also collared 4,000 bbl/d in 2004 between $31.20/bbl-$36.86/bbl. The Trust will lose its floor protection on 50% of the collared volume in the event WTI averages less than $27.40/bbl ($21.13 US). Under these transactions Petrofund will receive a premium of $3.89/bbl ($3.00 US) to the actual price. For the first quarter of 2005, the Trust has 9.5 mmcf/d of gas hedged under a $5.80/mcf-$8.97/mcf three way collar. At year end, the Petrofund's 2005 crude hedges include 1,000 bbl/d in a three way collar between $31.12/bbl-$37.60/bbl.

Petrofund also fixed the price on approximately 50% of its power consumption at $44.50/MWh for 2004 and 2005 to control future costs. During 2003, the monthly average power costs ranged from $44.47/MWh to $89.80/MWh.

In early January 2004, Petrofund entered into the following additional hedge transactions:

1) 1,000 bbl/d of crude oil was fixed for March-May 2004 at $41.92/bbl;

2) 1,000 bbl/d of crude oil was fixed for November-December 2004 at $37.73/bbl;

3) 2,000 bbl/d of crude oil for 2005 under a three way WTI collar between $34.75 and $43.18/bbl ($26.81-$33.30 US). Under this transaction, if WTI averages less than $30.46 ($23.50 US), Petrofund will lose the floor protection, but will still receive a $4.54/bbl ($3.50 US) premium to the actual price.

The Trust also increased its AECO gas hedges subsequent to year-end by collaring an additional 1.9 mmcf/d between $5.28/mcf and $7.65/mcf for the period April 1, 2004 to October 31, 2004.

All foreign exchange calculations in this section of the report incorporate the Bank of Canada US dollar rate at the close on December 31, 2003, ($1.2965 C$:US$). For a complete listing of all hedge transaction details please see Note 14 to the Consolidated Financial Statements.

Royalties	2003	2002		2001
Royalties (millions)	$     84.8	$     50.4	$	54.7
Average royalty rate (%)	21.6%	18.6%	22.4%
$/boe	$     8.18	$     5.36	$	7.21

Royalties, which include crown, freehold and overrides paid on oil and natural gas production, increased to $84.8 million in 2003 from $50.4 million in 2002, net of the Alberta Royalty Credit. Royalties increased to 21.6% of revenues in 2003 from 18.6% of revenues in 2002 and 22.4% in 2001. The variation in the average rates is mainly due to the fluctuations in natural gas prices as the gas royalty rate changes with natural gas prices.

Expenses	2003	2002	2001
Expenses (millions)
Lease operating	$   91.3	$   74.8	$   48.2
General & administrative	13.0	15.5	14.4
Management fee	-	4.7	5.3
Net interest	8.7	8.3	7.8
Expenses per boe
Lease operating	$   8.80	$   7.95	$   6.35
General & administrative	1.26	1.65	1.90
Management fee	-	0.50	0.70
Net interest	0.84	0.88	1.03

Lease Operating

Oil and gas operating expenses increased to $91.3 million in 2003 from $74.8 million in 2002 (2001 - $48.2 million) due to the additional wells on production and the increase in costs on a boe basis. Operating costs on a boe basis increased to $8.80 in 2003 from $7.95 in 2002 (2001 - $6.35).

The most significant contributor to the higher operating costs in 2003 was the increased costs for workover activities. These activities included rate acceleration projects, well repair, facility turnarounds and other facility maintenance work. There are two components to the increased costs. Firstly, costs in general have risen due to high industry activity levels. Secondly, more

workover projects were undertaken for production enhancement because the return on these projects is very good in the current product price environment.

GENERAL & ADMINISTRATIVE

General and administrative costs decreased to $13.0 million in 2003 from $15.5 million in 2002 (2001 - $14.4 million). Costs decreased 24% to $1.26 per boe in 2003 from $1.65 per boe in 2002 as a result of the consolidation of all activities in Calgary and the increased production volumes.

MANAGEMENT FEES

No management fees were payable in 2003 and no future fees will be paid due to the internalization of management. Fees of $4.7 million were paid in 2002 to the Previous Manager (2001 - $5.3 million).

INTEREST

Interest expense increased to $8.7 million in 2003 from $8.3 million in 2002 (2001 - $7.8 million), due to the increase in the average loan balance outstanding.

The bank loan outstanding at December 31, 2003, was $109.7 million as compared to $212.3 million at the end of the previous year.

DEPLETION AND DEPRECIATION &
PROVISION FOR RECLAMATION AND ABANDONMENT

Depletion and depreciation is provided on the unit-of-production method based on total estimated proved reserves. Depletion and depreciation expense was $113.9 million in 2003 compared to $98.8 million in 2002 (2001 - $68.5 million). The depletion rate per boe increased to $10.98 in 2003 from $10.50 in 2002 (2001 - $9.01). The $0.48 increase in the depletion rate from 2002 to 2003 was mainly due to the negative reserve revisions at the end of 2002. Unproved properties are included in the depletion and depreciation rate. The provision for reclamation and abandonment per boe in 2003 was $0.60, compared to $0.62 in 2002 (2001 - $0.48).

RECLAMATION & ABANDONMENT RESERVE

At the end of the year, PC had $3.8 million set aside in cash to fund future abandonment costs. This cash fund is increased by $0.075 per boe produced on an ongoing basis. This cash fund is in place to fund significant future reclamation costs, such as the decommissioning of a major facility.

PC is committed to conducting its operations in a safe and environmentally responsible manner and has an established program in place to manage environmental liabilities. The Trust performs well reclamation and abandonments, flare pit remediation work, etc. on a routine basis to proactively address environmental concerns. Petrofund's activities in this area in 2003 were significant as $4.7 million was spent on these types of projects. This compares to $2.2 million in

2002 and $0.4 million in 2001. PC expects to spend a further $3 million on reclamation and abandonment work in 2004.

NET INCOME

Net income increased to $85.8 million, up 252% from the $24.4 million reported in 2002 (2001 - $54.0). The increase was mainly due to the 35% improvement in operating netbacks as prices were up 32% on a boe basis. In addition, production was up 10% over the prior year.

Net income for the year ended December 31, 2003, was impacted by the costs of the internalization of the management contract and the reduction of income taxes for the decrease in future income tax rates. Net income was reduced by $30.9 million for management internalization costs and increased by $36.7 million for future income tax reductions.

QUARTERLY FINANCIAL DATA

						Net income per
	Net Oil and		Net			Unit(2)
($millions, except per Unit amounts)	Natural Gas Sales (1)		Income			Basic	Diluted
2003
First quarter	$	84.9	$	32.2	$	0.59	$	0.59
Second quarter		74.8		15.1		0.26		0.26
Third quarter		73.4		14.9		0.23		0.23
Fourth quarter		75.2		23.6		0.33		0.33
	$	308.3	$	85.8	$	1.41	$	1.40
2002
First quarter	$	42.7	$	0.9	$	0.02	$	0.02
Second quarter		53.1		8.5		0.17		0.17
Third quarter		55.8		9.6		0.18		0.18
Fourth quarter		68.6		5.4		0.10		0.10
	$	220.2	$	24.4	$	0.49	$	0.49
2001
First quarter	$	54.4	$	26.3	$	1.19	$	1.19
Second quarter		46.9		16.4		0.60		0.60
Third quarter		45.4		7.7		0.20		0.20
Fourth quarter		43.0		3.6		0.09		0.09
	$	189.7	$	54.0	$	1.71	$	1.71

(1) Net after royalties
⁽²⁾ Net income per unit numbers are calculated quarterly and therefore do not add.

Discussion of Results for the Fourth Quarter of 2003

Production for the fourth quarter of 2003 was 29,211 boe/d as compared to 27,362 boe/d for the same period in the prior year. Oil was up 13% from 12,096 boe/d to 13,645 boe/d. Natural gas was up marginally to 80.3 mmcf/d from 79.9 mmcf/d and natural gas liquids increased to 2,185 boe/d from 1,946 boe/d. Oil revenues increased to $44.0 million from $40.6 million due to the

increase in volumes as the oil price decreased to $35.06 per bbl from $36.48 per bbl. Natural gas revenue was up to $43.1 million from $37.9 million mainly due to the natural gas price which increased 13% from $5.15 per mcf to $5.84 per mcf. Revenues from natural gas liquids increased to $6.9 million from $6.0 million due to volumes and prices. The average price was $34.46 per bbl in the fourth quarter of 2003, as compared to $33.34 per bbl in the fourth quarter of 2002.

Royalties increased from $15.8 million in 2002 to $19.0 million in 2003. Royalties were 19% of revenue in the fourth quarter of 2002 and 20% in the same period in 2003, mainly due to the increased natural gas prices.

Operating costs increased to $24.8 million in 2004 from $21.3 million in 2003, due to the additional wells on production and a general increase in costs experienced by the oil and gas industry.

General and administrative costs decreased from $3.6 million, or $1.43 per boe, in the fourth quarter of 2002 to $2.9 million or $1.10 per boe for the same period in 2003.

Depletion and site reclamation and abandonment expenses increased from $28.6 million in 2002 to $33.7 million in 2003 or $1.20 per boe.

Income before income taxes was $11.4 million in the fourth quarter of 2003 as compared to $10.2 million in the fourth quarter of 2002. Net income, however, was up to $23.6 million from $5.4 million due to a future income tax recovery in 2003 of $12 million as compared to a future tax expense of $5.0 million in 2002. The future tax liability at December 31, 2002 included a provision for income taxes for entities that were acquired by the Trust. These entities were under audit at the time and the CCRA (Canada Customs and Revenue Agency) had made large proposed adjustments. The Trust was successful in having these adjustments reversed to a minimal amount. As a result, the Trust has taken the provision back into income in 2003.

CAPITAL EXPENDITURES

Acquisitions

During the year, PC incurred $115.6 million for property acquisitions, excluding the non-cash future tax adjustment of $4.7 million recognized on the Solaris Oil and Gas Inc. ("Solaris") acquisition, and acquired 19.4 million boe of Established Reserves. The properties were heavily weighted to oil and had a reserve life index of 14.4 years.

Effective January 1, 2003, PC acquired 100% of the outstanding common share of Solaris, and on February 7, 2003, amalgamated Solaris into PC. PC paid $7.4 million in cash, and assumed debt and negative working capital of $1.2 million, for a total cost of the oil and gas properties of $8.6 million. The acquisition added 720,000 boe of Established Reserves and approximately 200 boe/d of production.

In the second quarter of 2003, PC closed the acquisition of a diverse group of oil and natural gas properties for $61.7 million after adjustment. The properties added Established Reserves of 9.7 million boe as estimated by the independent engineering firm, Gilbert Laustsen Jung Associates Ltd. At the time of acquisition, production from the properties was approximately 2,300 boe/d of which 42% was natural gas. Production and cash flow has been included in this report effective from June 1, 2003. The properties contained a large percentage of unit production, and had a reserve life index on an Established basis of 11.6 years.

On August 21, 2003, PC purchased a 7.22% interest in Swan Hills Unit #1 for $37.1 million from a private Canadian company. This acquisition increased PC's interest in the unit, bringing PC's total interest in the unit to 9.87%. This acquisition added 8.5 mmboe of Established Reserves and approximately 1,100 boe/d of production. The Established reserve life index of the property was over 20 years.

Finding & Development Costs

During the year PC incurred $71.4 million on drilling and development activities as compared to $40.8 million in 2002. A total of 214 wells were drilled, of which 115 were gas, 84 oil and 15 dry and abandoned for an overall success rate of 93%. These activities added 2,500 boepd of production at an average cost of $28,600 per boepd and offset more than half of the decline in existing production.

Farmout Activities

During 2003, Petrofund entered into farmout agreements with various industry partners which resulted in 40 wells being drilled in 2003 on Petrofund's undeveloped land base. This drilling yielded 32 natural gas wells, 3 oil wells and 5 abandoned wells.

Although terms are slightly different for each farmout, they are generally structured such that Petrofund is carried for the costs of each well and receives a gross overriding royalty before payout of such costs and an after payout working interest for each well which generally equates to 50% of it pre-farmout interest.

Disposition of Properties

During 2003, Petrofund disposed of approximately 5 million boe of Established Reserves for $33.5 million. Eighty percent of these reserves were sold as a package of non-core east central Alberta properties marketed publicly late in the year. All of the properties disposed of were non-core to Petrofund's ongoing operations, had high operating costs and high decline rates. These dispositions are an integral part of Petrofund's ongoing portfolio management process.

A summary of capital expenditures for the last three years is as follows (in millions):

For the years ended December 31,	2003	2002	2001
Property acquisitions (1)	$ 115.6	$ 218.5	$ 222.4
Property dispositions	(33.5)	(30.0)	(3.7)
Net acquisitions	82.1	188.5	218.7
Finding & development costs:
Land & seismic	2.5	2.8	2.1
Drilling & completion	42.5	22.2	17.0
Well equipping	7.9	6.7	2.1
Tie-ins	5.2	2.7	2.2
Facilities	8.4	3.2	3.5
Other	4.9	3.2	-
Total	71.4	40.8	26.9
Total net capital expenditures	$ 153.5	$ 229.3	$ 245.6

(1) The property acquisition totals exclude non-cash future income tax adjustments for the difference between the cost and tax bases of assets acquired by way of corporate acquisitions.

DEBT

The borrowing base was increased to $265 million, in conjunction with the closing of the second quarter 2003 property acquisition. As at December 31, 2003, the amount outstanding on the credit facility was $110 million with $155 million available to finance future activities.

The revolving period on the syndicated facility was scheduled to end on May 30, 2003; however, it has been extended for an additional 364-day period ending May 28, 2004.

WORKING CAPITAL

The working capital deficit was $30 million at December 31, 2003, an increase of $23.1 from the $6.9 million deficit at the end of the prior year. The primary reason for this change is a corresponding increase in distributions payable to unitholders of $23 million. This amount represents the cash flow available for distribution generated during the year in excess of distributions paid.

LIQUIDITY AND CAPITAL RESOURCES

Total long-term debt and capital leases decreased $108.9 million from $219.2 million at December 31, 2002 to $110.3 million at the end of the current year.

The major changes in total long term debt were due to:

		$000's
Net proceeds from the May and December equity issues	$	193.4
Proceeds received from the exercise of options		20.5
Proceeds received from the sale of properties		33.5
Increases in working capital deficit		23.1
Cash flow available for distributions in excess of distributions paid		23.4
Property acquisitions		(115.6)
Expenditures on oil and gas properties		(71.4)
Miscellaneous		2.0
	$	108.9

Capitalization Analysis
($ thousands, except per unit and percent amounts)		2003		2002		2001
Working capital (deficiency)	$	(30,006)	$	(6,909)	$	(20,564)
Bank debt		109,707		212,253		128,783
Capital lease obligation		608		6,965		16,168
Net debt obligation	$	140,321	$	226,127	$	165,515
Units outstanding and issuable for exchangeable shares		73,628		54,108		41,916
Market Price at December 31,	$	18.79	$	10.85	$	11.97
Market capitalization	$    1,383,465		$	587,069	$	501,731
Total capitalization	$    1,523,786		$	813,196	$	667,246
Net debt as a percentage of total capitalization		9.2%		27.8%		24.8%
Cash flow	$	187,585	$	112,570	$	110,176
Net debt to cash flow		0.7:1.0		2.0:1.0		1.5:1.0

Long-term debt will increase in 2004 due to the capital expenditure program which is expected to be in the $60 million range. If the Trust is successful in completing one or more significant acquisitions in 2004 these would be financed by further utilization of the credit facility or a combination of additional bank borrowing and a possible equity issue of treasury units.

UNITHOLDERS' EQUITY

The Trust had 72,688,577 trust units outstanding at December 31, 2003, compared to 54,108,420 trust units at the end of 2002. In April 2003, 1,939,147 exchangeable shares and 100,244 Trust units were issued in connection with the internalization transaction. During the year, 906,635 Exchangeable Shares were converted to 1,000,000 Trust units and 181,041 were redeemed for cash leaving 851,471 exchangeable shares outstanding at year end which can be converted, at the option of the unitholder into 939,147 trust units. The weighted average number of trust units outstanding including those issuable on the exchange of exchangeable shares, was 61,010,105 trust units for 2003 as compared to 49,921,523 for 2002.

During 2003, the Trust completed two equity offerings. In May 2003, the Trust issued 9.2 million units at a price of $10.60 per unit for net proceeds of $92.3 million. In December 2003, 6.6 million units were issued at a price of $16.20 per unit for net proceeds of $101.1 million.

During the year, 1,673,404 options were exercised for the same number of trust units generating proceeds of $20.5 million. (For complete details of options exercised and outstanding at the end of the year refer to note 11 of the Consolidated Financial Statements).

Under the Distribution Reinvestment Plan ("DRIP") unitholders can elect to receive distributions or make optional cash payments to acquire trust units from treasury or in the open market. Under the DRIP plan 316,785 trust units were issued at an average price of $13.21 for total proceeds of $4.2 million. In 2002, 288,981 units were issued under the DRIP plan at an average price of $12.16 per trust unit.

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 PC at the end of the year. The Federal Large Corporations Tax rate is proposed in the Federal Budget of 2003 to be reduced in stages over a period of five years so that by 2008, the tax will be eliminated.

Capital taxes of $2.5 million in 2003 and $2.1 million in 2002 are primarily the Saskatchewan Capital Tax and Resource Surcharge, which is based upon Saskatchewan gross revenues.

Future income tax liabilities arise due to the differences between the tax basis of PC's assets and their respective accounting carrying cost. Future income taxes were increased by $4.7 million due to the purchase of Solaris. This liability arose as the purchase price of Solaris's assets was in excess of its tax pools. In the Trust's structure, payments are made between PC and the Trust which thereby transfers both income and future tax liability to the individual unitholders. Accordingly, it is the opinion of management that no cash income taxes will be paid by PC in the future and, as such, the future income tax liability recorded on the balance sheet will be recovered through earnings over time. Future income tax recoveries of $44.5 million in 2003 and $14.3 million in 2002 have resulted in a remaining future income tax liability of $77.0 million at

December 31, 2003. The future income tax liability was reduced by approximately $36.7 million to reflect reductions in the Federal and Alberta income tax rates in 2003.

Cash distributions paid to unitholders resident in Canada or the United States have differing tax consequences depending on each unitholder's circumstances. The Trust sets out some brief comments regarding the taxability of the distributions but does not intend to provide legal or tax advice. Unitholders or potential investors should seek their own legal or tax advice in this regard.

Generally, Canadian unitholders include in their income the portion of the distribution that is taxable income earned by the Trust. The portion that is a return of capital reduces the adjusted cost base of the Trust unit of the unitholder. In 2003, 51.223% of distributions paid to unitholders was ordinary income and 48.777% was a return of capital.

Generally, United States unitholders include in their income the portion of the distribution that is taxable income earned by the trust. Such amount is considered a dividend for U.S. purposes and is subject to Canadian withholding tax. The portion that is a return of capital and not taxable reduces the tax basis of the Trust unit. In 2003, 83.346% of distributions to United States unitholders was dividend income and 16.654% was a return of capital.

BUSINESS RISKS

The success of the Trust in meeting its objective of stable distributions over the long term depends mainly on management's ability to:

1) Identify and acquire oil and gas properties and/or companies at prices that add value to the Trust.

2) Cost effectively add or extend reserves with internal development and drilling or farmouts.

3) Manage and control costs.

There are numerous factors beyond management's control that have a major influence on distribution levels including product prices, unforeseen production declines and cost increases from major suppliers. (A detailed assessment of risk factors and offsetting strategies appears elsewhere in this report). Below is a table that shows sensitivities to pre-hedging cash flow as a result of product price and operational changes. The table is based on actual 2003 prices received and production volumes of 27,000 boepd. 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.

Sensitivity Analysis

					$/unit
		Change	$000's		per year
Price per barrel of oil*	$	1.00 U.S.	$	5,331	$	0.072
Price per mcf of natural gas*	$	0.25 Cdn.	$	5,585	$	0.076
US/Cdn exchange rate	$	0.01	$	2,650	$	0.036
Interest rate on debt ($125 million)		1%	$	1,250	$	0.017
Oil production volumes*	100 bbl/day		$	1,131	$	0.015
Gas production volumes*	1 mmcf/day		$	1,784	$	0.024

* After adjustment for estimated royalties.

OUTLOOK FOR 2004

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

Acquisition activities will be complemented by an extensive drilling and farmout program that will be conducted on our existing land base.

Although product prices have remained at high levels, the strengthening of the Canadian dollar in the second half of 2003 significantly moderated the net effect of these prices on Petrofund's cash flow. We expect the Canadian dollar to remain very strong in the short term with a possible decrease toward the end of 2004.

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 position appears elsewhere in this report.

CONTRACTUAL OBLIGATIONS

PC has the following long-term commitments for the years indicated:

(thousands of dollars)		2004		2005		2006		2007		2008
Capital leases (Note 6)	$	0.4	$	0.6	$	-	$	-	$	-
Office lease		1.1		0.8		-		-		-
Processing & transportation agreement		1.8		1.8		2.0		2.1		2.2
CO2 purchases		3.9		4.7		4.1		3.5		3.3
	$	7.2	$	7.9	$	6.1	$	5.6	$	5.5

⁽¹⁾ The amount increases to $2,223 in 2008 and then decreases to $1,474 in 2019 at which time it expires.

OFF-BALANCE SHEET ARRANGEMENTS/ VARIABLE INTEREST ENTITIES

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

IMPACT OF NEW CANADIAN ACCOUNTING PRONOUNCEMENTS

In September 2002, the CICA approved Section 3063, "Impairment of Long-Lived Assets" (S.3063). S.3063 establishes standards for the recognition, measurement and disclosure of the impairment of long-lived assets, and applies to long-lived assets held for use. An impairment loss is recognized when the carrying amount of a long-lived asset is not recoverable and exceeds its fair value. The new Section is effective for fiscal years beginning on or after April 1, 2003. The application of the impairment test for companies following the full cost method of accounting for oil and natural gas activities has been included in Accounting Guideline 16, "Oil and Gas Accounting - Full Cost" AcG-16 issued in September 2003. The new guideline limits the carrying value of oil and natural gas properties to their fair value. The fair value is equal to estimated future cash flows from proved and risked probable reserves using future price forecasts and costs discounted at a risk-free rate. This differs from the current cost recovery ceiling test that uses undiscounted cash flows and constant prices and costs less general and administrative and financing costs. There is no write-down of the Trust's oil and gas royalty and property interests under either method at December 31, 2003. AcG-16 also adopted the reserve evaluation and disclosure requirements of NI 51-101 which have been followed in the preparation of this report.

In December 2001, the Canadian Institute of Chartered Accountants (CICA) issued Accounting Guideline 13, "Hedging Relationships" (AcG-13) originally effective for fiscal years commencing on or after July 1, 2002. Implementation was then postponed to the fiscal years commencing on or after July 1, 2003. AcG-13 established certain conditions for when hedge accounting may be applied. If hedge accounting is not applied, the fair values of derivative financial instruments are recorded as an asset or a liability on the balance sheet. As the guideline is effective for fiscal years beginning on or after July 1, 2003, Petrofund will be adopting the guideline effective January 1, 2004. Petrofund enters into numerous derivative financial instruments to reduce price volatility and establish minimum prices for a portion of its oil and natural gas production. These contracts are effective economic hedges, however, a number do not qualify for hedge accounting due to the very detailed and complex rules outlined in AcG-13. Petrofund has elected to use the fair value method of accounting for all derivative transactions as we believe it would be confusing to the reader if the Trust were to use hedge accounting for some of its hedging contracts and fair value accounting for others. Also the additional costs to use hedge accounting would be significant as detailed documentation requirements must be met and each individual contract would need to be analyzed to determine which method of accounting to use. Effective January 1, 2004, Petrofund will record the fair value of the derivative financial instruments as at December 31, 2003, in the amount of $6.8 million as a liability on the balance sheet. The change in the fair value from period to period will be recorded in the income statement on a separate line as unrealized gains/losses. This line item will also include realized gains and losses on the derivative financial instruments which currently are recorded in oil and gas sales.

In December 2002, the CICA approved Section 3110, "Asset Retirement Obligations" which requires liability recognition for retirement obligations associated with our property, plant and equipment. The obligations are initially measured at fair value, which is the discounted future value of the liability. The fair value is capitalized as part of the cost of the related assets and amortized to expense over their useful lives. The liability accretes until the retirement obligations are settled. S.3110 is effective for fiscal years beginning on or after January 1, 2004. The accrued reclamation and abandonment liabilities on the balance sheet which have been calculated on a unit of production basis will be reversed January 1, 2004. Oil and gas properties will be increased and a liability set up for the amount calculated under the new standard. In 2004 the accounting

will follow the new standard and the comparative numbers for 2003 and prior periods will be restated.

The impact of this standard will be to increase oil and gas royalty and property interests on the balance sheet by $18.6 million at December 31, 2003, and by $18.5 million at December 31, 2002. The accrued reclamation and abandonment liability (asset retirement obligation) will increase to $34.4 million at December 31, 2003, from $16.8 million and the liability at December 31, 2002 will increase to $34.5 million from $15.3 million. The effect on the income statement will be to increase (decrease) net income before income taxes by $ 1.5 million in 2003, (2002- $1.1 million, 2001- $(0.9) million).

Effective March 31, 2004, the Trust and all reporting issuers in Canada will be subject to new disclosure requirements as per National Instrument 51-102 "Continuous Disclosure Obligations". This new instrument is effective for fiscal years beginning on or after January 1, 2004. The Instrument proposes shorter reporting periods for filing of annual and interim financial statements, MD&A and the Annual Information Form ("AIF"). The Instrument also proposes enhanced disclosure in the annual and interim financial statements, MD&A and AIF. Under this new instrument, it will no longer be mandatory for the Trust to mail annual and interim financial statements and MD&A to unitholders, but rather these documents will be provided on an "as requested" basis. The Trust continues to assess the implications of this new instrument which will be implemented in 2004. Other accounting standards issued by the CICA during the year ended December 31, 2003, are not expected to impact the Trust at this time.

CONTROLS AND PROCEDURES

Evaluation of disclosure controls and procedures. The Trust's principal executive officer and its principal financial officer, after evaluating the effectiveness of the Trust disclosure controls and procedures (as defined in U.S. Exchange Act Rules 13a - 14(c) and 15d - 14(c)) as of a date within 90 days prior to the filing date of this annual report, have concluded that, as of such date, the Trust's disclosure controls and procedures were adequate and effective to ensure that material information relating to the Trust and its subsidiaries would be made known to them by others within those entities. Changes in internal controls. There were no significant changes in the Trust's internal controls or in other factors that could significantly affect the Trust's internal controls subsequent to the date of their evaluation nor were there any significant deficiencies or material weaknesses in the Trust's internal controls. As a result, no corrective actions were required or undertaken.

STATEMENT OF CORPORATE GOVERNANCE

Petrofund adheres to all required regulatory and security commission guidelines as required by the TSX and the AMEX at December 31, 2003. This has resulted in Petrofund's acceptance of a 'best practices' corporate governance structure. To this end, four sub-committees of the Board, all composed of independent directors, act in the best interests of the Trust. Additional information about the board and the committee compositions are detailed in this annual report and within Petrofund's annual information form.

Consolidated Balance Sheet
(unaudited) (thousands of dollars)

As at December 31,		2003		2002
Assets
Current assets
Cash	$	2,182	$	-
Accounts receivable		48,268		41,953
Due from affiliates		-		164
Prepaid expenses and deferred charges		10,036		10,090
Total current assets		60,486		52,207
Reclamation and abandonment reserve (Note 7)		3,779		3,001
Oil and gas royalty and property interests,
at cost less accumulated depletion and depreciation
of $468,208 (2002 - $354,309) (Notes 2 and 3)		879,633		835,366
	$	943,898	$	890,574
Liabilities and unitholders' equity
Current liabilities
Bank overdraft	$	-	$	1,572
Accounts payable and accrued liabilities		36,684		22,007
Payable to affiliates (Note 4)		-		2,168
Current portion of capital lease obligations (Note 6)		356		3,304
Distributions payable to Unitholders		53,452		30,065
Total current liabilities		90,492		59,116
Long-term debt (Note 5)		109,707		212,253
Capital lease obligations (Note 6)		608		6,965
Future income taxes (Notes 2 and 15)		77,005		116,845
Accrued reclamation and abandonment costs		16,846		15,298
Total liabilities		294,658		410,477
Unitholders' equity (Notes 8 and 9)		649,240		480,097
	$	943,898	$	890,574

Signed on behalf of Petrofund Energy Trust by Petrofund Corp.:

    Jeffery E. Errico, Director                                 James E. Allard, Director

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

Consolidated Statement of Operations

(unaudited) (thousands of dollars)

For the years ended December 31,		2003		2002		2001
Revenues
Oil and gas sales	$	393,109	$	270,669	$	244,512
Royalties, net of incentives		(84,804)		(50,427)		(54,746)
		308,305		220,242		189,766
Expenses
Lease operating		91,251		74,774		48,237
Management fee (Note 4)		-		4,728		5,307
Interest on long-term debt (Note 5)		8,748		8,291		7,806
General and administrative (Note 4)		13,047		15,514		14,436
Capital taxes		2,454		2,137		1,719
Depletion and depreciation		113,899		98,777		68,453
Provision for reclamation and abandonment		6,199		5,856		3,680
Internalization of management contract (Note 9)		30,850		-		-
		266,448		210,077		149,638
Net income before provision for income taxes		41,857		10,165		40,128
Provision for (recovery of) income taxes (Note 15)
Current		569		38		1,701
Future		(44,516)		(14,252)		(15,561)
		(43,947)		(14,214)		(13,860)
Net income	$	85,804	$	24,379	$	53,988
Net income per trust unit (Notes 2 and 16)
Basic	$	1.41	$	0.49	$	1.71
Diluted	$	1.40	$	0.49	$	1.71

Consolidated Statement Of Unitholders' Equity
(unaudited) (thousands of dollars)

For the years ended December 31,		2003		2002		2001
Balance, beginning of year	$	480,097	$	398,702	$	136,812
Units issued, net of issue costs (Note 8)		226,325		154,460		318,548
Exchangeable shares issued/ converted						-
to Trust units (Note 10)		10,518		-
Redemption of exchangeable shares (Note 10)		(2,792)		-		-
Net income		85,804		24,379		53,988
Distributions accruing to Unitholders (Note 12)		(150,712)		(97,444)		(110,646)
Balance, end of year	$	649,240	$	480,097	$	398,702

Consolidated Statement of Cash Flows
(unaudited) (thousands of dollars)

For the years ended December 31,		2003		2002		2001
Cash provided by (used in):
Operating activities
Net income	$	85,804	$	24,379	$	53,988
Add items not affecting cash:
Depletion and depreciation		113,899		98,777		68,453
Provision for reclamation and abandonment		6,199		5,856		3,680
Future income taxes		(44,516)		(14,252)		(15,561)
Actual abandonment costs incurred (Note 7)		(4,651)		(2,190)		(384)
Internalization of management contract (Note 9)		30,850		-		-
Cash flow from operating activities		187,585		112,570		110,176
Net change in non-cash operating working capital balances		6,410		(30,938)		18,334
Cash provided by operating activities		193,995		81,632		128,510
Financing activities
Bank loan		(102,546)		83,470		14,216
Distributions paid		(127,325)		(85,218)		(126,883)
Redemption of exchangeable shares		(2,792)		-		-
Capital lease repayments		(9,305)		(11,366)		(2,629)
Issuance of trust units (Note 8)		214,002		55,821		161,409
Advances to affiliates (Note 4)		-		948		-
Cash provided by (used in) financing activities		(27,966)		43,655		46,113
Investing activities
Reclamation and abandonment reserve (Note 7)		(776)		(706)		(447)
Acquisition of property interests		(186,956)		(158,516)		(177,729)
Proceeds on disposition of properties		33,466		30,019		3,736
Cash acquired on acquisition (Note 3b)		-		427		-
Internalization of management contract (Note 9)		(8,009)		-		-
Cash used in investing activities		(162,275)		(128,776)		(174,440)

Net change in cash		3,754		(3,489)		183
Cash (bank overdraft), beginning of year		(1,572)		1,917		1,734
Cash (bank overdraft), end of year	$	2,182	$	(1,572)	$	1,917
Interest paid during the year	$	8,885	$	8,016	$	7,806
Income taxes paid during the year	$	842	$	1,281	$	1,065

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

Notes to consolidated financial statements

December 31, 2003, 2002 and 2001 (Unaudited)

1. ORGANIZATION

Petrofund Energy Trust ("Petrofund" or the "Trust") is an open-ended investment trust created under the laws of the Province of Ontario pursuant to a trust indenture, as amended from time to time (the "Trust Indenture"), between Petrofund Corp. ("PC") and Computershare Trust Company of Canada (the "Trustee"). Active operations commenced March 3, 1989. The beneficiaries of the Trust are the holders of the trust units ("Unitholders").

PC, a wholly-owned subsidiary of the Trust, acquires oil and gas properties for its own account and sells a royalty interest (the "Royalty") to the Trust. The Royalty acquired from PC effectively transfers substantially all of the economic interest in the oil and gas properties to the Trust. The Trust is entitled to 99% of the production revenue from properties purchased by PC, less operating costs, general and administrative expenses, management fees (prior to 2003), debt service charges (including principal and interest) and taxes payable by PC.

2. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

The consolidated financial statements have been prepared by the management of PC following Canadian generally accepted accounting principles. The preparation of financial statements requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosures of contingencies at the date of the financial statements and the reported amounts of revenues and expenses during the reporting period. Actual results could differ from those estimated. The following significant accounting policies are presented to assist the reader in evaluating these consolidated financial statements.

(a) Basis of consolidation

The consolidated financial statements include the accounts of the Trust and its wholly-owned subsidiaries, PC, 1518274 Ontario Ltd., NCE Management Services Inc. ("NMSI"), which employed all of the personnel who provided services to the Trust, and NCE Petrofund Management Corp. ("NCEP Management", the "Previous Manager") collectively, the "Subsidiaries". NMSI and NCEP Management were acquired to effect the internalization of management and the shares of 1518274 Ontario Limited are exchangeable into trust units. (See Notes 9 and 10)

(b) Oil and gas royalty and property interests

Oil and gas royalty and property interests are accounted for using the full cost method of accounting whereby all costs of acquiring oil and gas royalty and property interests and equipment are capitalized. General and administrative costs and interest are not capitalized.

The provision for depletion and depreciation and the provision for site reclamation and abandonment costs are computed using the unit-of-production method based on the estimated gross proved oil and gas reserves. Proceeds on sale or disposition of oil and gas royalty and property interests are credited to oil and gas royalty and property interests, unless this results in a change in the depletion and depreciation rate by 20% or more, in which case a gain or loss is recognized in the consolidated statement of operations. The provision for reclamation and abandonment costs is accumulated as a long-term liability, which is reduced as actual expenditures are made.

The carrying value of the oil and gas royalty and property interests, net of accumulated depletion and depreciation, accrued reclamation and abandonment costs and future income taxes is limited to an amount equal to the estimated future net revenue, net of production-related general and administrative costs, reclamation and abandonment costs, and income taxes. Future net revenue was calculated using yearend oil and gas prices and costs.

Effective January 1, 2004, the carrying value of the oil and gas royalty and property interests is limited to their fair value determined by the expected discounted future revenue from the properties.

Distributions payable to Unitholders

Distributions payable to Unitholders are equal to amounts received or receivable by the Trust on the cash distribution date. Income earned, but not received, is distributed on the cash distribution date following receipt.

(c) Future income taxes

The Trust follows the liability method of accounting for income taxes. Under this method, income tax liabilities and assets are recognized for the estimated tax consequences attributable to differences between the amounts reported in the financial statements of the Subsidiaries and their respective tax bases, using enacted income tax rates. The effect of a change in income tax rates on future tax liabilities and assets is recognized in income in the period in which the change occurs. Temporary differences arising on acquisitions result in future income tax assets or liabilities.

The Trust is a taxable entity under the Income Tax Act (Canada) and is taxable only on income that is not distributed or distributable to the Unitholders. As the Trust distributes all of its taxable

income to the Unitholders and meets the requirements of the Income Tax Act (Canada) applicable to the Trust, no provision for future income taxes in the Trust has been made.

(d) Net income per trust unit

Basic net income per trust unit is computed by dividing net income by the weighted average number of trust units outstanding for the period. Diluted per unit amounts reflect the potential dilution that would occur if options to issue trust units were exercised and trust units were issued. The treasury stock method is used to determine the effect of dilutive instruments.

(e) Hedging activity

The Trust uses derivative instruments to reduce its exposure to commodity price fluctuations. Gains and losses on contracts, all of which constitute effective hedges, are deferred and recognized as a component of the price of the related transaction.

(g) Trust unit incentive plan

A Trust Unit Incentive Plan (the "Unit Incentive Plan") was established authorizing the issuance of options to acquire Trust units to directors, senior officers, employees and consultants of NCEP, Management, NCE Petrofund Advisory Corp., NMSI and certain other related parties, all of whom are deemed to be employees of the Trust. No options have been issued since 2002.

The Trust has elected to prospectively adopt amendments to the recommendations of the CICA on accounting for stock based compensation in accordance with the transitional provisions contained therein. Under the amended recommendations, the Trust must account for compensation expense based on the fair value of the options at the grant date. As the Trust has not granted any options since December 31, 2002, this change in accounting policy has no impact on the consolidated financial statements. For options granted in 2002 the Trust elected to continue accounting for compensation expense based on the intrinsic value of the options at the grant date and disclose pro forma net income and pro forma net income per Trust unit as if the fair value method had been adopted retroactively. The exercise price of options granted under the Unit Incentive Plan may be reduced in future periods in accordance with the terms of the Unit Incentive Plan. The amount of the reduction cannot be reasonably determined as it is dependent upon a number of factors including, but not limited to, future prices received on the sale of oil and natural gas, future production of oil and gas, and the determination of the amount to be withheld from future distributions to fund capital expenditures. Therefore, it is not possible to determine a fair value for the options granted under the Unit Incentive Plan and compensation expense has been determined based on the excess of the unit price over the reduced exercise price at the date of the financial statements and recognized in income over the vesting period of the options with a corresponding increase or decrease in contributed surplus. After the options have vested, compensation expense is recognized in income in the period in which a change in the market price of the Trust units or the exercise of the options occurs. The compensation expense under this method in 2003 for the options issued in 2002 is $ 2 million. Net income would have been reduced by this amount and net income per Trust unit would have decreased by $0.03. For 2002, net income would have been reduced by $60,000 with negligible impact on net income per Trust unit.

Consideration paid upon the exercise of the options together with any amount previously recognized in contributed surplus is recorded as an increase in unitholders' capital.

3. ACQUISITIONS

(a) Solaris Oil & Gas Inc.

On February 7, 2003, PC acquired 100% of the outstanding common shares of Solaris Oil & Gas Inc. for $7.4 million in cash and assumed $1.2 million of debt including negative working capital and the outstanding bank loan.

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

		$000's
Working capital	$	(813)
Oil and gas properties		13,219
Bank loan		(370)
Future income taxes		(4,676)
	$	7,360

(b) NCE Energy Trust

On May 30, 2002, Petrofund Energy Trust acquired NCE Energy Trust for 0.2325 of a Trust unit for each Trust unit on a tax-free rollover basis. The value assigned to the Trust units of $13.024 per unit issued on the acquisition was based on the average market value of the Trust units five days before and after the acquisition was announced.

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

	$000's
Working capital	$ (39,518)
Oil and gas properties	165,254
Future income taxes	(27,097)
	$ 98,639

Prior to the acquisition, Petrofund advanced $37.3 million to NCE Energy Trust to pay down the bank debt of NCE Energy Trust.

(c) Magin Energy Inc. ("Magin")

On June 25, 2001, PC acquired 93.6% of the outstanding common shares of Magin and on July 3, 2001 acquired the remaining shares. Magin was amalgamated into PC on July 3, 2001.

In total, PC acquired 38,338,535 Magin common shares for $58.6 million in cash, 8.5 million trust units with a deemed value of $18.56 per unit and the assumption of $43.7 million of debt including negative working capital, the outstanding bank loan and capital leases. In addition, other transaction costs of $11.8 million were incurred.

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

		$000's
Working capital	$	(4,749)
Oil and gas properties		381,043
Bank loan		(21,569)
Capital leases		(17,359)
Future income taxes		(109,790)
	$	227,576

4. RELATED PARTY TRANSACTIONS

(a) Management, advisory and administration agreement

PC, NCEP Management, the Previous Manager, and the Trust had entered into an agreement which was amended from time to time, whereby the Previous Manager was to provide management, advisory and administrative services to PC and the Trust. During 2002 the Previous Manager was paid a management fee equal to 3.25% of net operating income plus Alberta Royalty Credit (2001-3.75%). In addition the Previous Manager received an investment fee of 1.5% (1.75% prior to January 1, 2002) of the purchase cost of all properties purchased by PC other than replacement properties, and a disposition fee equal to 1.25% (1.5% prior to January 1, 2002) of the sale price of properties sold. During 2002, the Previous Manager received a management fee from PC of $4.7 million (2001 - $5.3 million). In addition, the Previous Manager received investment fees of $1.3 million (2001 - - $5.2 million), which were capitalized as part of the acquisitions, and disposition fees of $116,000 (2001 - $3,000), which reduced the proceeds of disposition. No management fees have been charged directly to the Trust.

Due to the internalization of management, no fees were payable in 2003. (See Note 9)

Under the terms of the agreement, the Previous Manager was entitled to be reimbursed by PC for general and administrative expenses. In any year, PC was to reimburse the Previous Manager no less than $240,000 and no more than 5% of gross production revenue for general and administrative expenses. To the extent that general and administrative expenses exceed 5% of gross production revenue, PC was entitled to set off and deduct the excess from its liability to pay management fees to the Previous Manager.

(b) Management agreement

The Previous Manager had entered into an agreement with NMSI to provide oil and gas investment, consulting, administrative and management services to PC. An officer and director of the Previous Manager is the sole beneficial shareholder of NMSI. During 2002 PC paid NMSI $11.7 million (2001 - $9.3 million) for accounting and administrative services, which is included in general and administrative expenses and $838,000 (2001 - $1.4 million) for project sourcing and evaluation services, which have been capitalized to oil and gas properties. In addition, PC reimbursed NMSI $300,000 (2001 - $600,000) for marketing and other related equity issue costs. No amounts for these services have been charged directly to the Trust. The amounts for general and administrative expenses paid to NMSI are subject to the same limitations noted for the Previous Manager in (a) above.

5. LONG-TERM DEBT

Under the loan agreements, PC has a revolving working capital operating facility of $25 million and a syndicated facility of $240 million. Interest on the working capital loan is at prime and interest on the syndicated facility varies with PC's debt to cash flow ratio from prime to prime plus 75 basis points or, at the Trust's option, banker's acceptances rates plus stamping fees. As at December 31, 2003, there was no amount outstanding under the working capital facility and $110 million outstanding under the syndicated facility.

The revolving period on the syndicated facility ends on May 28, 2004, 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, Petrofund 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 in the amount of $350 million pursuant to which a Canadian chartered bank (the "Lender"), as principal and as agent for the other lender, 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 Bankers' Acceptances, resulting in a reduction in the stated bank loan interest rates.

6. CAPITAL LEASE OBLIGATIONS

The future minimum lease payments under the capital leases are as follows:

		$000's
2004	$	423
2005		621
Total minimum lease payments		1,044
Less imputed interest at rates ranging from 7.37% to 8.425%		(80)
Obligation under capital leases		964
Current portion		(356)
Long-term portion	$	608

7. RECLAMATION AND ABANDONMENT RESERVE

PC maintains a cash reserve to finance large and unusual oil and gas property reclamation and abandonment costs by withholding distributions accruing to Unitholders. At December 31, 2003, the cash reserve was $3.8 million (2002 - $3.0 million, 2001 - $2.1 million). In 2003, PC increased the cash reserve by withholding $776,000 (2002 - $706,000, 2001 - $447,000) from distributions accruing to Unitholders.

In addition, routine ongoing reclamation and abandonment costs of $4.7 million in 2003 (2002 - $2.2 million, 2001 - $384,000) were incurred and deducted from distributions accruing to Unitholders.

8. TRUST UNITS

	Number
Authorized: unlimited number of trust units	of Units		$000's
Issued
December 31, 2000	21,914,079	$	321,344
Issued for cash	11,183,334		167,350
Issued for Magin acquisition	8,464,399		157,139
Commissions and issue costs	-		(11,781)
Options exercised	341,305		5,620
Unit purchase plan	13,279		220
December 31, 2001	41,916,396		639,892
Issued for cash	4,600,000		59,800
Issued for NCE Energy acquisition	7,573,874		98,639
Commissions and issue costs	-		(4,190)
Options exercised	7,966		85
Unit purchase plan	10,184		126
December 31, 2002	54,108,420		794,352
Issued for cash	15,800,000		204,440
Issued for internalization of management contact	100,244		1,123
Exchangeable shares converted	1,000,000		11,200
Commissions and issue costs	-		(11,001)
Options exercised	1,673,404		20,474
Unit purchase plan	6,509		89
December 31, 2003	72,688,577	$	1,020,677

The Trust has a Distribution Reinvestment and Unit Purchase Plan (the "Plan") for Canadian residents. Under the terms of the Plan, Unitholders can elect, firstly, to reinvest their cash distributions and obtain either newly issued units of the Trust directly from the Trust or previously issued units of the Trust purchased in the open market and, secondly, to purchase for cash newly issued units directly from the Trust.

For the years ended December 31,		2003		2002		2001
Distributions reinvested to acquire
previously issued units (000's)	$	4,095	$	3,387	$	6,979
Price per unit	$	13.20	$	12.15	$	16.61
Number of units acquired		310,276		278,797		420,100
Distributions reinvested
to acquire newly issued units	$	89	$	126	$	220
Price per unit	$	13.65	$	12.36	$	16.59
Number of units acquired		6,509		10,184		13,279

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

For the twelve months ended December 31,	2003	2002	2001
Basic	61,010,105	49,921,523	31,593,378
Diluted	61,153,027	49,967,648	31,635,976

Trust units/exchangeable shares:

For the years ended December 31,	2003	2002	2001
Trust units outstanding	72,688,577	54,108,420	41,916,396
Trust units issuable on exchangeable shares (Note 10)	939,147	-	-
	73,627,724	54,108,420	41,916,396

9. INTERNALIZATION OF MANAGEMENT

On April 29, 2003, PC purchased 100% of the outstanding shares of NCEP Management, and NMSI. As a result of these transactions, all management acquisition and disposition fees payable to the Previous Manager were eliminated retroactive to January 1, 2003.

The total consideration paid was $30.9 million as detailed below.

Total Consideration	$000's
Issuance of 1,939,147 exchangeable shares to the shareholder of the Previous Manager	$ 21,718
Cash payment to Trust for the repayment of indebtedness owing by the Previous Manager	3,400
Issuance of 100,244 units to executive management	1,123
Cash payment to executive management	780
Cash payment for distributions on exchangeable shares and trust units from
January 1 to April 30, 2003,	1,326
Transaction costs	2,503
Total Purchase Price	$ 30,850

To ensure an orderly transition of the services that were provided by the Previous Manager through its offices in Toronto, PC entered into an agreement with Sentry Select Capital Corp. ("Sentry") to provide certain services to the Trust and PC until December 31, 2003, for a maximum cost of $2 million. The amount incurred decreased from $1 million in the first quarter of 2003 to $500,000 in the second quarter and to $250,000 in each of the third and fourth quarters. As of December 31, 2003, Sentry no longer provides any services to Petrofund or to any of its subsidiaries. Sentry is a company in which John Driscoll, the Chairman of the Board of Directors of PC, owns a controlling interest.

Prior to the acquisition, the Previous Manager was paid a management fee equal to 3.25% of net operating income plus Alberta Royalty Credit, an investment fee equal to 1.50% of the purchase price of all properties purchased by PC and a disposition fee of 1.25% of properties sold, except replacement properties.

10. EXCHANGEABLE SHARES

The number of Exchangeable Shares to be issued in connection with the internalization of the management contract was determined based on a negotiated value of $12.17 per share as set out

in the Information Circular dated March 10, 2003. For accounting purposes, the 1,939,147 Exchangeable Shares were deemed to be issued at a value of $11.20 per share, being the average trading value of the Trust units for the last ten days prior to the closing date. Initially, each Exchangeable Share was exchangeable into one Trust Unit. The exchange ratio is adjusted from time to time to reflect the per unit distributions paid to unitholders after the closing date. Under the terms of the Exchangeable Share Agreement, the holder of the Exchangeable Shares is entitled to redeem for cash the number of shares equal to the cash distributions that would have been received had the Exchangeable Shares been converted to Trust units. As a result of the redemption feature, the number of Trust units issuable upon conversion is expected to remain constant over time. As the substance of this feature is to allow the holder of the Exchangeable Shares to receive cash distributions, the redemption has been accounted for as a distribution of earnings rather than a return of capital. In 2003, 181,041 Exchangeable Shares were redeemed for $2.8 million in cash.

On December 17, 2003, 906,635 Exchangeable Shares were converted to 1,000,000 Trust units at a rate of 1.10298. At December 31, 2003, 851,471 Exchangeable Shares were outstanding, at an exchange ratio of 1.10298 per Trust Unit.

Issued and Outstanding	Number of Shares		$000's
Issued for internalization of Management Contract	1,939,147	$	21,718
Redemption of Shares	(181,041)		-
Exchanged for Trust Units	(906,635)		(11,200)
Balance, December 31, 2003	851,471		10,518
Exchange ratio, end of period	1.10298		-
Trust Units issuable upon conversion	939,147	$	10,518

11. UNIT INCENTIVE PLAN

A total of 5,200,000 units have been reserved for issuance under the Unit Incentive Plan of which 2,254,100 have been issued as at December 31, 2003.

A summary of the status of the Unit Incentive Plan as of December 31, 2003, 2002 and 2001, and changes during the years then ended is presented below:

For the years ended December 31,				2003			2002		2001
			Weighted			Weighted			Weighted
				Average			Average		Average
				Exercise			Exercise		Exercise
	Units			Price	Units		Price	Units	Price
Options outstanding,
beginning of year	3,028,280			$ 13.21	1,840,190		$ 15.92	941,278	$ 16.71
Issued	-			-	1,468,100		10.65	1,477,800	17.65
Forfeited	(555,754)			16.82	(272,044)		16.66	(237,583)	18.38
Exercised	(1,673,404)			12.88	(7,966)		10.65	(341,305)	16.47
Options outstanding before
reduction of exercise price		799,122		$ 14.74	3,028,280		$ 13.31	1,840,190	$ 17.29
Reduction of exercise price	-			(1.81)	-		(0.10)	-	(1.37)
Options outstanding,
end of year	799,122			$ 12.93	3,028,280		$ 13.21	1,840,190	$ 15.92
Options exercisable,
end of year	440,656			$ 15.36	1,593,681		$ 14.10	745,565	$ 16.08

The options granted in 2002 and 2001 are exercisable at the original option prices, which were the market prices of the units on the date of the grants, or if so elected by the participant, at reduced prices as described below. The option prices are reduced for each calendar quarter ending after the date of the grant by the positive amount, if any, equal to the amount by which the aggregate distributions made by the Trust in any calendar quarter ending after the date of the grant exceed 2.5% of the oil and gas royalty and property interests on the Trust's consolidated balance sheet at the beginning of the applicable calendar quarter divided by the issued and outstanding units at the beginning of the applicable quarter.

The following table summarizes the options outstanding at December 31, 2003:

Number	Exercise	Reduced Exercise
of Units	Price		Price	Expiry Date
4,689	$ 15.00		N/A	May 8, 2005
280,666	$ 19.35	$	16.23	January 30, 2006
109,067	$ 17.25	$	14.78	April 4, 2006
21,800	$ 14.71	$	13.31	July 20, 2006
382,900	$ 10.65	$	9.93	July 25, 2007

12. DISTRIBUTIONS ACCRUING TO UNITHOLDERS

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

For the period ended	Cash Distribution Date		2003		2002		2001
November 30	January 31	$	0.15	$	0.15	$	0.42
December 31	February 28		0.16		0.15		0.42
January 31	March 31		0.17		0.13		0.42
February 28	April 30		0.17		0.13		0.42
March 31	May 31		0.18		0.14		0.45
April 30	June 30		0.18		0.14		0.45
May 31	July 31		0.18		0.14		0.36
June 30	August 31		0.18		0.14		0.32
July 31	September 30		0.18		0.14		0.25
August 31	October 31		0.18		0.15		0.25
September 30	November 30		0.18		0.15		0.25
October 31	December 31		0.18		0.15		0.23
Cash Distributions per Trust unit		$	2.09	$	1.71	$	4.24

Reconciliation of Distributions Accruing to Unitholders
(thousands of dollars except per unit amounts)

For the years ended December 31,		2003		2002		2001
Distributions payable, beginning of year	$	30,065	$	12,188	$	28,425
Distributions accruing during the year
Cash flow from operating activities		187,585		112,570		110,176
Redemption of exchangeable shares		(2,792)		-		-
Proceeds on disposition of property interests		-		946		3,546
Reclamation and abandonment reserve		(776)		(706)		(447)
Less capital lease repayment (2) (3)		(3,305)		(5,366)		(2,629)
Capital expenditures		(30,000)		(10,000)		-
Total distributions accruing during the year		150,712		97,444		110,646
NCE Energy Trust cash flow (1)		-		5,651		-
Total distributable income for the year		150,712		103,095		110,646
Distributions paid		(127,325)		(85,218)	(126,883)
Distributions payable, end of year (4)	$	53,452	$	30,065	$	12,188
Distributions accruing to Unitholders per Trust unit
Basic	$	2.47	$	2.07	$	3.50
Diluted	$	2.46	$	2.06	$	3.49

(1) Remaining undistributed cash flow of NCE Energy Trust on May 30, 2002 (see Note 3b).
⁽²⁾ Net of $6 million refinanced by increased bank loan in 2002
⁽³⁾ Net of $6 million refinanced by increased bank loan in 2003.
⁽⁴⁾ It is expected that a portion of this amount will be used to fund capital expenditures.

13. FINANCIAL INSTRUMENTS

The Trust's financial instruments consist of cash, accounts receivable and payable, long-term debt, capital lease obligations and derivative instruments. As at December 31, 2003, the carrying value of the cash and accounts receivable and payable approximated their fair value due to their short-term nature. The carrying value of the long-term debt approximated its fair value due to the floating rate of interest charged under the facilities. The carrying value of the capital lease obligations is not significantly different from their fair values.

The derivative instruments have no carrying value (see Note 14). The derivative instruments at December 31, 2003, had a negative fair value of $6.8 million based on quotes provided by brokers. This fair value represents an approximation of amounts that would be paid to counterparties to settle these instruments at the balance sheet date. The Trust plans to hold all derivative instruments outstanding at December 31, 2003, to maturity.

14. DERIVATIVE FINANCIAL INSTRUMENTS AND PHYSICAL CONTRACTS

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

The outstanding derivative financial instruments, all of which constitute effective hedges, and the related unrealized gains or losses, and physical contracts as at December 31, 2003, are

					Unrealized
		Volume	Price	Delivery	Gain (Loss)
Natural Gas	Term	mcf/d	$/mcf	Point	$000's
Collar	November 1, 2003 to	9,475	$6.23-$8.34	AECO	$	118
	March 31, 2004
Collar	November 1, 2003 to	9,475	$5.80-$10.98	AECO		164
	March 31, 2004
Fixed	January 1, 2004 to	4,737	$6.07	AECO		(316)
	March 31, 2004
Fixed	January 1, 2004 to	4,737	$6.23	AECO		(246)
	March 31, 2004
Fixed	January 1, 2004 to	4,737	$6.81	AECO		18
	March 31, 2004
Fixed	January 1, 2004 to	4,737	$7.39	AECO		255
	March 31, 2004
Collar	April 1, 2004 to	9,475	$5.17-$7.28	AECO		268
	October 31, 2004
Collar	April 1, 2004 to	9,475	$5.07-$6.81	AECO		(66)
	October 31, 2004
Collar	April 1, 2004 to	1,895	$5.28-$7.39	AECO		56
	October 31, 2004
Fixed	April 1, 2004 to	4,737	$5.33	AECO		(550)
	October 31, 2004

Collar	November 1, 2004 to	9,475	*(1)	AECO		54
	March 31, 2005
Total					$	(245)

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

					Unrealized
		Volume	Price	Delivery	Gain (Loss)
Oil	Term	bbl/d	$/bbl	Point		$000's
Fixed Price	January 1, 2004 to	1,995	$38.59	Edmonton	$	(897)
	June 30, 2004
Fixed Price	July 1, 2004 to	668	$36.41	Edmonton		(186)
	December 31, 2004
Collar	January 1, 2004 to	2,000	$31.12-$35.98	Edmonton		(999)
	March 31, 2004
Three Way Collar	January 1, 2004 to	2,000	*(1)	Edmonton		(1,478)
	June 30, 2004
Collar	April 1, 2004 to	2,000	$31.12-$36.56	Edmonton		(768)
	June 30, 2004
Three Way Collar	July 1, 2004 to	2,000	*(2)	Edmonton		(892)
	December 31, 2004
Collar	July 1, 2004 to	2,000	$31.12-$36.30	Edmonton		(591)
	September 30, 2004
Collar	October 1, 2004 to	2,000	$31.12-$36.30	Edmonton		(505)
	December 31, 2004
Three Way Collar	January 1, 2005 to	1,000	*(3)	Edmonton		(516)
	December 31, 2005
Total					$	(6,832)

*(1) At Prices above $37.27 Petrofund receives $37.27/bbl.
      At Prices between $31.12 and $37.27/bbl Petrofund receives the market price.
      At Prices below $27.55 Petrofund receives a premium of $3.89/bbl.

*(2) At Prices above $37.60 Petrofund receives $37.60/bbl.
      At Prices between $31.45 and $37.60/bbl Petrofund receives the market price.
      At Prices below $27.87 Petrofund receives a premium of $3.89/bbl.

*(3) At Prices above $37.60 Petrofund receives $37.60/bbl.
      At Prices between $31.12 and $37.60/bbl Petrofund receives the market price.
      At Prices below $25.93 Petrofund receives a premium of $5.19/bbl.

All the oil hedges are at U.S. WTI prices and have been converted to Canadian dollars at the year end exchange rate of $1.2965 C$:US$.

					Unrealized
		Volume	Price	Delivery	Gain (Loss)
Electricity	Term	MW/h	$/MWh	Point	$000's
Fixed Price	January 1, 2004 to	3.0	$ 44.50	Alberta Power	$ 303
	December 31, 2005			Pool

The gains or losses are recognized on a monthly basis over the terms of the contracts and adjust the prices received.

Derivative financial instruments and physical hedge contracts involve a degree of credit risk, which the Trust controls through the use of financially sound counterparties. Market risk relating to changes in value or settlement cost of the Trust's derivative financial instruments is essentially offset by gains or losses on the underlying physical sales.

15. INCOME TAXES
(thousands of dollars except per unit amounts)

The future income tax liability (asset) includes the following temporary differences:

As at December 31,		2003	2002	2001
Oil and gas properties	$	77,005	$ 119,825	$ 106,961
Resource allowance		-	(2,980)	(2,961)
	$	77,005	$ 116,845	$ 104,000

The provision for current and future income taxes differs from the result which would be obtained by applying the combined federal and provincial statutory tax rates to income before income taxes. This difference results from the following:

For the years ended December 31,		2003		2002		2001
Income before income tax provision	$	41,857	$	10,165	$	40,128
Income tax provision computed at statutory rates	$	17,052	$	4,294	$	17,304
Effect on income tax of:
Income attributed to the Trust		(41,468)		(24,435)		(32,665)
Internalization of management contract		12,568		-		-
Non-deductible crown charges,
net of Alberta Royalty Credit		24,190		17,055		19,276
Resource allowance		(20,730)		(15,045)		(16,661)
Capital taxes		1,000		831		1,130
Income tax rate reductions on opening balances		(36,688)		-		(329)
Temporary differences in resource allowance		-		(19)		(2,427)
Other		129		3,105		512
Provision for (recovery of) income taxes	$	(43,947)	$	(14,214)	$	(13,860)

The petroleum and natural gas properties and facilities owned by the Subsidiaries have a tax basis of $232.7 million ($212 million - 2002, $153.3 million - 2001) available for future use as deductions from taxable income. Included in this tax basis are non-capital loss carry forwards of $43.6 million ($34.0 million - 2002, $33.6 million - 2001), which could expire in various years through 2010.

16. NET INCOME PER TRUST UNIT

Basic per unit calculations are based on the weighted average number of Trust units and exchangeable shares outstanding. Diluted calculations include additional Trust units for the dilutive impact of options. There were no adjustments to net income in calculating diluted per Trust unit amounts.

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

For the twelve months ended December 31,	2003	2002	2001
Basic	61,010,105	49,921,523	31,593,378
Diluted	61,153,027	49,967,648	31,635,976

NON-RESIDENT OWNERSHIP

As at January 30, 2004, based on information provided by our transfer agent, Petrofund estimates that non-resident ownership of the trust was approximately 64%.

RESERVES SUMMARY

Petrofund has received the results of an independent engineering evaluation of its oil and gas reserves conducted by Gilbert Laustsen Jung Associates Ltd. ("GLJ") effective December 31, 2003. This evaluation is prepared in accordance with National Instrument 51-101 Standards of Disclosure for Oil and Gas Activities (NI 51-101). This new instrument adopted by the Canadian Securities Administrators sets out standards of disclosure for oil and gas activities and mandates the application of evaluation standards defined in the Society of Petroleum Evaluation Engineers (SPEE) Canadian Oil and Gas Evaluation Handbook (COGEH). The information that follows has been derived from the GLJ evaluation.

In prior years the reserve category most often referenced was "Proved plus Risked Probable", also known as "Established". The new standard does not include this definition, however, the evaluation criteria in NI 51-101 make the new "Proved plus Probable" category reasonably comparable to the old Established category. Year over year comparisons will therefore be done using Established reserves from December 31, 2002 and Proved plus Probable reserves from December 31, 2003.

HIGHLIGHTS

These highlights are based on the forecast prices and costs evaluation.

• Proved plus Probable reserves are 102.7 million boe, an increase of 3% over last year.
• Acquisition and development activity added 20.3 million boe of company interest Proved plus Probable reserves replacing actual 2003 production 2 times.
• Disposition of non-core properties totaled 5 million boe of Company interest Proved plus Probable reserves.
• Technical revisions including adjustments for infill drilling reduced proved plus probable reserves by 1.3 million boe's, or approximately 1%.
• Reserve life index is 11.1 years.

RESERVE SUMMARY 2003

Summary of Oil and Gas Reserves
as of December 31, 2003
Based on Forecast Price and Costs
	Light and						Natural Gas
	Medium Oil		Heavy Oil		Natural Gas		Liquids		Total BOE's
	Gross	Net	Gross	Net	Gross	Net	Gross	Net	Gross	Net
	(mbbls)		(mbbls)		(mmcf)		(mbbls)		(mboes)
PROVED
Developed
Producing	32,512	28,565	848	750	191,682	151,527	5,060	3,577	70,367	58,146
Developed
Non-
producing	276	260	-	-	6,071	4,616	154	112	1,442	1,142
Undeveloped	8,675	8,196	-	-	5,408	4,177	377	258	9,953	9,150
TOTAL
PROVED	41,463	37,021	848	750	203,161	160,320	5,591	3,947	81,762	68,438
PROBABLE	10,889	9,458	203	182	45,605	36,114	1,575	1,208	20,268	16,867
TOTAL
PROVED
PLUS
PROBABLE	52,352	46,479	1,051	932	248,766	196,434	7,166	5,155	102,030	85,305

NET PRESENT VALUE SUMMARY 2003

Petrofund's reserves were evaluated using GLJ's price forecast effective January 1, 2004. The net present values shown below do not necessarily represent the fair market value of the reserves.

Net Present Value of Future Net Revenue Before Income Taxes
At of December 31, 2003
Based on Forecast Price and Costs

		Discounted at the Rate of
	Undiscounted	10%	12%	15%
	($millions)		($millions)
PROVED
Developed Producing	$ 790.0	$ 513.3	$ 483.3	$ 445.6
Developed Non-Producing	24.5	14.8	13.7	12.3
Undeveloped	110.9	36.6	29.6	21.4
TOTAL PROVED	925.3	564.7	526.5	479.3
PROBABLE	319.5	114.1	98.5	80.7
TOTAL PROVED PLUS
PROBABLE	$1,244.8	$ 678.8	$625.0	$ 560.0
GLJ January 1, 2004 Price Forecast

Summary of Pricing Assumptions as of December 31, 2003
Forecast Prices

	Oil	Oil	Natural Gas	Exchange
	WTI	Edmonton Par	AECO Spot	Rate	Inflation
Year	(US$/bbl)	(C$/bbl)	(C$/mmbtu)	($US/$Cdn)	(%)
2004	$ 29.00	$ 37.75	$ 5.85	0.75	1.5
2005	26.00	33.75	5.15	0.75	1.5
2006	25.00	32.50	5.00	0.75	1.5
2007	25.00	32.50	5.00	0.75	1.5
2008	25.00	32.50	5.00	0.75	1.5
2009	25.00	32.50	5.00	0.75	1.5
2010	25.00	32.50	5.00	0.75	1.5
2011	25.00	32.50	5.00	0.75	1.5
2012	25.00	32.50	5.00	0.75	1.5
2013	25.00	32.50	5.00	0.75	1.5
2014	25.00	32.50	5.00	0.75	1.5
Note: Prices escalate 1.5% in 2015 and thereafter

RESERVE RECONCILIATION

Reconciliation of Company Net Reserves
Constant Prices and Costs

				Natural	Barrels of
	Light and			Gas	Oil
	Medium Oil	Heavy Oil	Natural Gas	Liquids	Equivalent
	Net Proved	Net Proved	Net Proved	Net Proved	Net Proved
	(mbbls)	(mbbls)	(bcf)	(mbbls)	(mboe)
December 31, 2002	34,834	553	181	4,175	69,753
Extensions	159	-	1	30	332
Improved Recovery	681	-	-	11	757
Technical Revisions	(1,303)	318	(8)	(1,007)	(3,391)
Discoveries	79	-	-	-	79
Acquisitions	9,319	-	15	1,367	13,201
Dispositions	(2,186)	-	(2)	(13)	(2,537)
Economic Factors	(102)	-	1	17	11
Production	(3,689)	(121)	(23)	(545)	(8,248)
December 31, 2003	37,793	750	164	4,036	69,957
				Natural	Barrels of
	Light and			Gas	Oil
	Medium Oil	Heavy Oil	Natural Gas	Liquids	Equivalent
	Net Proved	Net Proved	Net Proved	Net Proved	Net Proved
	plus	plus	plus	plus	plus
	Probable	Probable	Probable	Probable	Probable
	(mbbls)	(mbbls)	(bcf)	(mbbls)	(mboe)
December 31, 2002	41,592	593	213	4,937	82,602
Extensions	182	-	1	34	385
Improved Recovery	189	-	-	13	280
Technical Revisions	1,175	461	(6)	(713)	(27)
Discoveries	100	-	-	-	100
Acquisitions	11,667	-	17	1,496	16,020
Dispositions	(3,705)	-	(3)	(22)	(4,287)
Economic Factors	(39)	-	1	45	222
Production	(3,689)	(121)	(23)	(545)	(8,248)
December 31, 2003	47,471	933	200	5,247	87,048

Reconciliation of Total Company Interest Reserves
Forecast Prices and Escalated Costs

	Light and			Natural
	Medium		Natural	Gas	Barrels of Oil
	Oil	Heavy Oil	Gas	Liquids	Equivalent
	Proved	Proved	Proved	Proved	Proved
	(mbbls)	(mbbls)	(bcf)	(mbbls)	(mboe)
December 31, 2002	38,014	826	233	5,925	83,633
Extensions	181	-	1	43	407
Improved Recovery	775	-	1	16	875
Technical Revisions	(1,062)	180	(15)	(1,567)	(4,918)
Discoveries	90	-	-	1	91
Acquisitions	10,636	-	19	2,002	15,771
Dispositions	(2,488)	-	(3)	(19)	(2,940)
Economic Factors	(168)	-	-	(6)	(240)
Production	(4,402)	(144)	(30)	(759)	(10,371)
December 31, 2003	41,577	861	205	5,637	82,309
	Light and			Natural
	Medium		Natural	Gas	Barrels of Oil
	Oil	Heavy Oil	Gas	Liquids	Equivalent
	Proved	Proved	Proved	Proved	Proved
	plus	plus	plus	plus	plus
	Probable	Probable	Probable	Probable	Probable
	(mbbls)	(mbbls)	(bcf)	(mbbls)	(mboe)
December 31, 2002	45,689	1,012	274	6,998	99,399
Extensions	208	-	1	48	473
Improved Recovery	216	-	1	18	334
Technical Revisions	1,480	200	(11)	(1,208)	(1,325)
Discoveries	114	-	-	1	115
Acquisitions	13,614	-	22	2,166	19,363
Dispositions	(4,236)	-	(4)	(30)	(4,983)
Economic Factors	(195)	-	(1)	(11)	(306)
Production	(4,402)	(144)	(30)	(759)	(10,371)
December 31, 2003	52,487	1,068	252	7,223	102,698
Note: Company interest reserves includes royalty interest and working interest

Additional details regarding Petrofund's reserves information will be included in our Annual Information Form, which is anticipated to available on our website and SEDAR by the end of March.

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

This news release may include statements about expected future events and/or financial results that are forward-looking in nature and subject to risks and uncertainties. For those statements, we claim the protection of the safe harbor for forward-looking statements provisions contained in the U.S. Private Securities Litigation Reform Act of 1995. Petrofund Energy Trust cautions that actual performance will be affected by a number of factors, many of which are beyond its control. Future events and results may vary substantially from what Petrofund Energy Trust currently foresees. Discussion of the various factors that may affect future results is contained in Petrofund Energy Trust's recent filings with the Securities and Exchange Commission and Canadian securities regulatory authorities.

PETROFUND ENERGY TRUST

Jeffery E. Errico
President and Chief Executive Officer

For Petrofund Investor Relations:

Phone: (403) 218-4736
Fax: (403) 539-4300
Toll Free: 1-866-318-1767
E-mail: info@petrofund.ca
Website: www.petrofund.ca

For information regarding this press release:

Chris Dutcher
Director, Business Development
Phone: (403) 218-8625

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