EXHIBIT 2
                                             Managements Discussion for Analysis
                                           for the year ended  December 31, 2003

MANAGEMENT'S DISCUSSION AND 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 audited 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"). Reserve 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


<PAGE>

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").


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 assess 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.

                                       2
<PAGE>

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 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 consists 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.

                                       3
<PAGE>

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

                                       4
<PAGE>

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
Natural 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 AND 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

                                       5
<PAGE>

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


<TABLE>
<CAPTION>
Average prices for the year ended December 31,                                      2003         2002          2001
-------------------------------------------------------------------------------------------------------------------

<S> <C>                                                                        <C>          <C>          <C>
Oil (1)                                                                        $   37.91    $   34.68    $    34.37
Natural 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 natural gas price was decreased per mcf due to hedging                 $   (0.11)   $       -    $    (0.13)

Production Revenue (millions)                                                       2003         2002     2001
-------------------------------------------------------------------------------------------------------------------
Oil                                                                            $   172.3    $   141.3    $    102.3
Natural gas                                                                        194.2        110.7         125.0
Natural gas liquids                                                                 26.6         18.7          17.2
-------------------------------------------------------------------------------------------------------------------

Total                                                                          $   393.1    $   270.7    $    244.5
-------------------------------------------------------------------------------------------------------------------
</TABLE>

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

                                       6
<PAGE>

$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, 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


                                       7
<PAGE>

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 AND 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.


                                       8
<PAGE>

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

<TABLE>
<CAPTION>
($millions, except                          Net Oil and                Net              Net income per Unit (2)
per Unit amounts)                       Natural Gas Sales (1)          Income             Basic            Diluted
------------------------------------------------------------------------------------------------------------------

<C>                                     <S>                        <S>                <S>               <S>
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

                                       9

<PAGE>

   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
=================================================================================================================
</TABLE>

(1)  Net after royalties
(2)  Net income per unit numbers are calculated quarterly and annually 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 Canada Customs and Revenue Agency (CCRA) 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")

                                       10
<PAGE>

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 and 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 boe/d of production at an average cost of
$28,600 per boe/d 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, three oil
wells and five 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 interests 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. The
properties sold are expected to reduce 2004 production by approximately 1,500
boe/d.


                                       11
<PAGE>



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       $    332.2
Property dispositions                  (33.5)             (30.0)           (3.7)
--------------------------------------------------------------------------------
Net acquisitions                         82.1             188.5            328.5
--------------------------------------------------------------------------------
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          $  355.4
================================================================================

(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.


                                       12
<PAGE>



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


<TABLE>
<CAPTION>
($ thousands, except per unit and percent amounts)                        2003              2002             2001
-----------------------------------------------------------------------------------------------------------------

<S>                                                             <C>                <C>              <C>
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
-----------------------------------------------------------------------------------------------------------------
</TABLE>

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.


                                       13
<PAGE>

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.

                                       14

<PAGE>

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 boe/d. These sensitivities are
approximations only and are not necessarily valid at other price and production
levels. As well, hedging activities can significantly affect these
sensitivities.

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
U.S. /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/d        1,131        $ 0.015
Gas production volumes*                   1 mmcf/d        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 - U.S. dollar exchange rate and the Trust's ability to add reserves and
production in a cost effective manner. Both product prices and the exchange rate
showed 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

                                       15
<PAGE>

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

For details on contractual obligations refer to note 17 of the Consolidated
Financial Statements.


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 Canadian Institute of Chartered Accountants (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 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

                                       16
<PAGE>

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 - 15 (e) and 15d - 15(e)) the end of the period
covered by 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

                                       17
<PAGE>

information relating to the Trust and its subsidiaries would be made known to
them by others within those entities.

Changes in internal control over financial reporting. There was no change in the
Trust's internal control over financial reporting that occurred during the
period covered by this annual report that has materially affected, or is
reasonably likely to materially affect, the Trust's internal control over
financial reporting.


STATEMENT OF CORPORATE GOVERNANCE


Petrofund adheres to all required regulatory and securities commissions'
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 the
annual report and within Petrofund's Annual Information Form.

The President and Chief Executive Officer and Senior Vice-President, Finance and
Chief Financial Officer have signed a code of ethics which is posted on the
Trust's website.



                                       18