EXHIBIT 1
                                                         Annual Information Form
                                            for the year ended December 31, 2003





                             PETROFUND ENERGY TRUST


                         RENEWAL ANNUAL INFORMATION FORM




                      FOR THE YEAR ENDED DECEMBER 31, 2003

                                 March 15, 2004




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                                TABLE OF CONTENTS

INFORMATION PREPARED BY PETROFUND CORP......................................1

FORWARD-LOOKING STATEMENTS..................................................1

DOLLAR AMOUNTS..............................................................1

GLOSSARY OF TERMS...........................................................2

         The Trust..........................................................6

         Management of the Trust............................................7

         Strategy...........................................................9

         Acquisition Criteria...............................................9

         Key Factors for Success...........................................10

GENERAL DEVELOPMENT OF THE BUSINESS OF THE TRUST...........................10

         Financings........................................................10

BUSINESS AND PROPERTIES....................................................13

REPORT OF MANAGEMENT AND DIRECTORS ON RESERVES DATA AND OTHER INFORMATION..18

REPORT ON RESERVES DATA BY INDEPENDENT QUALIFIED RESERVES EVALUATOR OR
AUDITOR....................................................................20

INDEPENDENT QUALIFIED RESERVES.............................................20

EVALUATOR OR AUDITOR.......................................................20

STATEMENT OF RESERVES DATA AND OTHER OIL AND GAS INFORMATION...............22

         Disclosure of Reserves Data.......................................22

         Reserves Data (Constant Prices and Costs).........................22

         Reserves Data (Forecast Prices and Costs).........................24

         Definitions and Other Notes.......................................26

         Pricing Assumptions...............................................31

         Reconciliations of Changes in Reserves and Future Net Revenue.....31

         Additional Information Relating to Reserves Data..................33


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         Undeveloped Reserves..............................................33

         Significant Factors or Uncertainties..............................33

         Future Development Costs..........................................34

         Other Oil and Gas Information.....................................35

         Oil And Gas Wells.................................................35

         Properties with no Attributable Reserves..........................35

         Additional Information Concerning Abandonment and
         Reclamation Costs.................................................35

         Forward Contracts.................................................35

         Tax Horizon.......................................................36

         Capital Expenditures..............................................36

         Exploration and Development Activities............................36

         Production Estimates..............................................37

         Production History................................................37

SELECTED FINANCIAL AND OPERATING INFORMATION...............................37

         Consolidated Financial Information................................37

         Sensitivity Analysis..............................................38

         Distribution Policy...............................................39

         Distributions.....................................................39

         Credit Facility...................................................40

         Outlook for Next Year.............................................41

ENVIRONMENT, HEALTH AND SAFETY.............................................42

         Managing Liabilities..............................................42

         Stewardship.......................................................43

         Corporate Citizenship.............................................43

CORPORATE GOVERNANCE.......................................................43


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         Independence of the Board.........................................44

         Committees........................................................44

         Governance Committee..............................................45

         Human Resources and Compensation Committee........................45

         Reserves Audit Committee..........................................45

         Audit Committee...................................................45

Management's Discussion and Analysis.......................................48

RISK FACTORS...............................................................48

         Oil and Natural Gas Prices........................................49

         Foreign Currency Exchange Rates and Interest Rates................49

         Operations........................................................50

         Competition.......................................................50

         Environmental Concerns............................................50

         Reserves..........................................................51

         Depletion of Reserves.............................................51

         Marketability of Production.......................................52

         Assessments of Value of Acquisitions..............................52

         Reliance on Third Party Operators.................................52

         Enforcement of Operating Agreements...............................53

         Borrowing.........................................................53

         Delays in Distributions...........................................53

         Unforeseen Title Defects..........................................54

         Accounting Write-Downs as a Result of GAAP........................54

         Nature of Trust Units.............................................54

         Trading Price of Trust Units......................................55


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         Reliance on Petrofund Corp. and Others............................55

         Unitholder Limited Liability......................................55

         Retraction Right..................................................56

         Future Dilution...................................................56

         Changes in Legislation............................................56

         Changes in the Trust's Status under Tax Laws......................56

GOVERNANCE OF THE TRUST AND PC.............................................57

         Trust Indenture...................................................57

         PC Unanimous Shareholder Agreement................................61

         Royalty Agreement.................................................62

         Management Agreement..............................................63

UNITHOLDER PROTECTION RIGHTS PLAN..........................................63

DISTRIBUTION REINVESTMENT AND UNIT PURCHASE PLAN...........................65

DIRECTORS AND OFFICERS.....................................................66

         Ownership of Trust Units by Directors and Officers................68

ESCROWED SECURITIES........................................................68

MARKET FOR SECURITIES......................................................68

CONFLICTS OF INTEREST......................................................68

ADDITIONAL INFORMATION.....................................................69



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                     INFORMATION PREPARED BY PETROFUND CORP.

     The information contained in this annual information form has been prepared
by Petrofund Corp., who manages the Trust.

                           FORWARD-LOOKING STATEMENTS

     Some of the statements contained herein including, without limitation,
financial and business prospects and financial outlooks, may be forward-looking
statements which reflect management's expectations regarding future plans and
intentions, growth, results of operations, performance and business prospects
and opportunities. Words such as "may", "will" "should", "could", "anticipate",
"believe", "expect", "intend", "plan", "potential", "continue" and similar
expressions have been used to identify these forward-looking statements. These
statements reflect management's current beliefs and are based on information
currently available to management. Forward-looking statements involve
significant risk and uncertainties. A number of factors could cause actual
results to differ materially from the results discussed in the forward-looking
statements including, but not limited to, changes in general economic and market
conditions and other risk factors. Although the forward-looking statements
contained herein are based upon what management believes to be reasonable
assumptions, we cannot assure that actual results will be consistent with these
forward looking statements. Investors should not place undue reliance on
forward-looking statements. These forward-looking statements are made as of the
date hereof and we assume no obligation to update or revise them to reflect new
events or circumstances.

     Forward-looking statements and other information contained herein
concerning the oil and gas industry and our general expectations concerning this
industry is based on estimates prepared by us using data from publicly available
industry sources as well as from reserve reports, market research and industry
analysis and on assumptions based on data and knowledge of this industry which
we believe to be reasonable. However, this data is inherently imprecise,
although generally indicative of relative market positions, market shares and
performance characteristics. While we are not aware of any misstatements
regarding any industry data presented herein, the industry involves risks and
uncertainties and is subject to change based on various factors.

                                 DOLLAR AMOUNTS

     Unless otherwise specified, all dollar amounts set out in this annual
information form are in Canadian dollars.








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                                GLOSSARY OF TERMS

The following terms used herein have the meanings set out below:


AECO:                         The regional pricing hub for natural gas located
                              at the storage facilities of Alberta Energy
                              Company near Medicine Hat, Alberta.

Aggregate Equivalent Vote
Amount:                       With respect to any matter, proposition or
                              question on which Unitholders are entitled to
                              vote, consent or otherwise act, the number of
                              votes that the holder of a Special Voting Unit
                              would be entitled to had the holder exchanged all
                              of the Exchangeable Shares held by the holder for
                              Petrofund Units immediately prior to the record
                              date set for any such meeting.

bbl:                          Barrel.

bcf:                          Billions of cubic feet.

Board or Board of Directors:  The board of directors of PC.

boe:                          Barrels of oil equivalent, using a conversion
                              factor of 6 mcf of gas being equivalent to one bbl
                              of oil and one bbl of NGLs being equivalent to one
                              bbl of oil.

boepd:                        Barrels of oil equivalent per day.

bpd:                          Barrels of oil or NGLs per day.

Cash Retraction Notice:       A notice to redeem PC Exchangeable Shares
                              exercisable for a period of 5 business days from
                              the date of expiry of the subject Dividend Period.

Current Market Price:         In respect of a Unit on any date, the weighted
                              average trading price of a Unit on the TSX for the
                              10 trading days preceding that date.

Distribution Payment Date:    Each date from and after the effective date on
                              which a distribution is paid to Unitholders.

Distribution Record Date:     In respect of any distribution, the day on which
                              Unitholders are identified for purposes of
                              determining entitlement to such distribution.

Dividend Period:              A period within two business days of a
                              Distribution Payment Date.

Drip Price:                   In respect of a Unit on any Valuation Date,
                              the most recently applicable price at which a
                              holder of a Unit is entitled to purchase a Unit in
                              respect of the Distribution to which the subject
                              Valuation Date relates pursuant to any
                              distribution re-investment plan which Petrofund
                              may have in effect on such Valuation Date and
                              which is available to the holders of Units
                              generally.

Established Reserves:         Company interest reserves (proved plus 50%
                              probable) prior to royalties that conform to
                              National Policy Statement 2-B.

Exchange Ratio:               At any time and in respect of each PC Exchangeable
                              Share, shall initially be equal to one, and
                              provided that PC shall not have declared a
                              dividend in respect of the subject Dividend
                              Period, shall be cumulatively increased on the
                              expiry date of each Dividend

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                              Period by an amount equal to the (i) fraction
                              having as its numerator the Per Share Dividend
                              Amount relating to the subject expired Dividend
                              Period, and having as its denominator the Current
                              Market Price on the Valuation Date, or (ii) in the
                              event that: (a) as at the subject Valuation Date,
                              the Trust has in place a distribution
                              re-investment plan which is available to the
                              holders of Units generally, and (b) the holder has
                              not delivered a Cash Retraction Notice in respect
                              of the Distribution to which the expired Dividend
                              Period relates within the time period provided
                              for, the fraction having as its numerator the Per
                              Share Dividend Amount relating to the subject
                              expired Dividend Period, and having as its
                              denominator the Drip Price in effect as at the
                              Valuation Date.

gj:                           Gigajoule.

GLJ:                          Gilbert Laustsen Jung Associates Ltd., independent
                              oil and gas reservoir engineers of Calgary,
                              Alberta.

GLJ                           Report: The report prepared by GLJ dated February
                              17, 2004 with respect to the petroleum, natural
                              gas and NGL reserves of PC effective as at
                              December 31, 2003.

Internalization Transaction:  The transaction approved at the annual and special
                              meeting of Unitholders held on April 16, 2003
                              under which management of the Trust was
                              internalized through the acquisition by PC of all
                              of the issued and outstanding shares of NCEP
                              Management and the consequent elimination of all
                              management, acquisition and disposition fees
                              payable to NCEP Management.

Management Agreement:         The amended and restated management, advisory and
                              administration agreement made as of January 1,
                              2002 among PC, the Trust and NCEP Management.

mbbls:                        Thousands of barrels.

mboe:                         Thousands of barrels of oil equivalent.

mcf:                          Thousands of cubic feet.

mcfe:                         Thousands of cubic feet of natural gas equivalent,
                              using a conversion factor of one barrel of oil and
                              one barrel of NGL's being equivalent to 6 mcf of
                              gas.

mcfepd:                       Thousands of cubic feet of natural gas equivalent
                              per day.

mcfpd:                        Thousands of cubic feet per day.

mlt:                          Thousand long tons.

mmboe:                        Millions of barrels of oil equivalent.

MMBtu:                        Millions of British Thermal Units.

mmcf:                         Millions of cubic feet.

mmcfpd:                       Millions of cubic feet per day.

M$:                           Thousands of dollars.

MM$:                          Millions of dollars.


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NCEP Management:              NCE Petrofund Management Corp., the previous
                              manager.

NCE Services or NMSI:         NCE Management Services Inc.

netback:                      The amount received from the sale of a barrel of
                              oil or barrel of oil equivalent after deduction of
                              operating costs and royalty payments.

NGL or NGLs:                  Natural gas liquids.

PC:                           Petrofund Corp.

PC Exchangeable Share         The rights, privileges and conditions attaching to
Provisions:                   the PC Exchangeable Shares set forth in the
                              Articles of PC.

PC Exchangeable Shares:       Non voting exchangeable shares in the capital of
                              PC.

PC Support Voting and         The agreement dated April 29, 2003 between PC, the
Exchange Agreement:           Trust, 1518274 Ontario Limited ("Exchangeco."),
                              and Petro Assets Inc. ("Petro Assets") whereby PC
                              will take certain actions and make certain
                              payments and deliveries necessary to ensure that
                              the Trust and Exchangeco. will be able to make
                              certain payments and to deliver or cause to be
                              delivered Units in satisfaction of the obligations
                              of the Trust and Exchangeco under the PC
                              Exchangeable Share Provisions and the Unanimous
                              Shareholders Agreement.

Per Share Dividend Amount:    A distribution relating to the subject
                              Distribution Payment Date multiplied by the
                              Exchange Ratio.

Petro Assets:                 Petro Assets Inc.

Petrofund or the Trust:       Petrofund Energy Trust.

Properties:                   The interests, including working interests and
                              unit interests, in petroleum and natural gas
                              rights held by PC.

Redemption Date:              The date which is 60 days after the date of
                              delivery of a Redemption Notice.

Redemption Price:             A price per PC Exchangeable Share equal to the
                              amount determined by multiplying the Exchange
                              Ratio on the last business day prior to the
                              applicable Redemption Date by the current market
                              price on the last Business Day prior to such
                              Redemption Date.

Retracted Shares:             Means the number of Exchangeable Shares redeemed
                              in accordance with a Cash Retraction Notice.

Retraction Date:              The date that is 5 Business days after the date on
                              which PC receives a retraction request in respect
                              of the Retracted Shares.

Royalty Agreement:            The amended and restated royalty agreement dated
                              as of April 16, 2003 between PC and the Trust.

Special Resolution:           A resolution approved in writing by Unitholders
                              holding not less than 66 2/3% of the outstanding
                              Trust Units or passed by a majority of not less
                              than 66 2/3% of the votes cast, either in person
                              or by proxy, at a meeting of the Unitholders
                              called for the purpose of approving such
                              resolution.

Tax Act:                      Income Tax Act (Canada), as amended.

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TSX:                          Toronto Stock Exchange.

Trustee:                      Computershare Trust Company of Canada, as trustee
                              of the Trust.

Trust Indenture:              The amended and restated trust indenture made as
                              of April 16, 2003 between PC and the Trustee.

Trust Unit or Unit:           A trust unit created pursuant to the Trust
                              Indenture and representing a fractional undivided
                              interest in the Trust.

Unanimous Shareholder         The unanimous shareholder agreement made as of
Agreement:                    November 1, 2000 among PC, the Trust and NCEP
                              Management.

Unitholder:                   A holder from time to time of Trust Units.

Valuation Date:               The first Business Day following the Distribution
                              Record Date in respect of the Distribution to
                              which the expired Dividend Period relates.

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<PAGE>


                            PETROFUND ENERGY TRUST
                         RENEWAL ANNUAL INFORMATION FORM
                      FOR THE YEAR ENDED DECEMBER 31, 2003
                              DATED March 15, 2004

                             PETROFUND ENERGY TRUST

The Trust

     The Trust is an open-ended investment trust created under the laws of the
Province of Ontario on December 18, 1988 under the name "NCE Petrofund I".
Active operations commenced March 3, 1989. On July 4, 1996, the name of the
Trust was changed to "NCE Petrofund" and on November 1, 2003 the name was
changed to its present name of "Petrofund Energy Trust". Effective September 7,
2001, the Trustee became the trustee of the Trust. The Trust is currently
governed by the Trust Indenture.

     The executive office was relocated from 130 King Street West, Suite 2850,
Toronto, Ontario, M5X 1A4 in conjunction with the internalization of management.
The executive office, head office and operations of the Trust are now located at
Suite 600, 444 - 7th Avenue S.W., Calgary, Alberta, T2P 0X8.

     The Trust's primary source of income is from 99% net royalty interests
granted by PC, its wholly-owned subsidiary. PC is a corporation incorporated
under the laws of Alberta. PC acquires, manages and disposes of petroleum and
natural gas rights and royalties and related property rights and interests
located primarily in western Canada. In addition, PC may acquire royalties or
other property interests or securities of other resource issuers. The Trust may
also purchase directly or indirectly securities of oil and gas companies, oil
and gas properties and other related assets.

     The following chart shows the structure of the Trust at the date hereof:



                                GRAPHIC OMITTED











     Each Trust Unit represents an equal undivided beneficial interest in the
assets of the Trust. Historically, the Trust's activities have been focused on
the acquisition of net


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royalties from PC. For each property for which a net royalty is granted by PC,
the Trust receives 99% of the revenue generated by the property net of operating
costs, management fees (prior to 2003), debt service charges, general and
administrative costs and certain other taxes and charges. The Trust distributes
to its Unitholders a majority of its cash flow in the form of monthly
distributions, part of which is on a tax-advantaged basis. Cash flow includes
royalty income and may include cash flow generated by properties and interests
not currently subject to the Trust's net royalty interests.

     The Trust was initially formed as a closed-end royalty trust for the
purposes of acquiring royalty interests from PC. Effective February 2, 1999, the
Trust was converted to an open-ended investment trust. The Trust Indenture,
Royalty Agreement and related agreements were amended to: (i) permit the Trust
and PC to acquire, directly or indirectly, interests in resource issuers and/or
resource properties and other related assets; (ii) remove certain financing
restrictions applicable to the Trust and PC to permit the Trust and PC, subject
to certain limitations, to raise or issue capital in connection with, or to
finance, such acquisitions, either through the issuance of Trust Units or other
equity or debt securities of the Trust or PC or through borrowing; and (iii)
provide that Unitholders have the right to cause the Trust to redeem their Trust
Units in certain circumstances.

     Effective November 1, 2000, the Trust acquired all of the issued and
outstanding shares of PC from a subsidiary of NCEP Management for nominal
consideration, resulting in PC becoming a wholly-owned direct subsidiary of the
Trust. This change simplified the structure of the Trust and related entities
and allows the Trust to present consolidated financial statements which fully
reflect the assets and liabilities of the Trust and PC.

     In conjunction with PC becoming a wholly-owned subsidiary of the Trust, the
corporate governance of the Trust was changed so that the stewardship of the
Trust and PC was undertaken by the Board of Directors of PC.

Management of the Trust

     On January 1, 1990 PC entered into the Management Agreement, under which it
retained the services of NCEP Management to identify, assess and assist in the
acquisition, disposition and ongoing management of the Trust's properties and to
administer its net royalties and other assets. Management of the Trust is now
carried out directly by directors, officers and other employees of PC, see
"Governance of the Trust and PC - Management Agreement" and "Internalization of
Management".

Employees and Consultants

     As at December 31, 2003 PC had 90 office employees and 18 full time
consultants. PC also has 31 direct field employees and a number of contractors
to manage its field operations.

Internalization of Management

     On March 10, 2003, the Trust entered into an agreement to internalize its
management structure such that NCEP Management, the then manager of the Trust,
became a wholly owned subsidiary of PC. Unitholder and regulatory approval of
the Internalization Transaction was received at the annual and special meeting
of Unitholders held on April 16, 2003. As a result of the Internalization
Transaction, all management, acquisition and disposition fees payable to NCEP
Management were eliminated effective January 1, 2003. The cost of the
Internalization Transaction was $30.9 million including $2.5 million of

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transaction costs, all of which was expensed to the income statement. The
transaction was effected in the following manner:

     o    Prior to the closing, NCEP Management acquired NMSI (which employed
          all of the Calgary-based personnel who provided services to the Trust
          and PC on behalf of NCEP Management).

     o    At the closing, PC purchased all of the issued shares of NCEP
          Management from Petro Assets Inc. for $21.7 million. Petro Assets Inc.
          is owned by the Driscoll Family Trust (a trust established for the
          family of John F. Driscoll). John Driscoll was Chairman and Chief
          Executive Officer of PC at closing.

     o    The purchase price for the shares of NCEP Management was satisfied by
          the issuance of 1,939,147 PC Exchangeable Shares, plus a cash amount
          per PC Exchangeable Share equal to the distributions paid or payable
          per Trust Unit by the Trust to Unitholders of record from and after
          January 1, 2003 up to and including the closing date. Initially each
          PC 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. Each PC Exchangeable
          Share was initially ascribed a value of $12.1703, representing the
          weighted average trading price of the Trust Units over the 10 trading
          days, ending on March 4, 2003 on the TSX. For accounting purposes the
          PC 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.

     o    At closing, PC paid $3.4 million in cash to fund the repayment of
          indebtedness owing by NCEP Management. In addition, as part of the
          Internalization Transaction NMSI paid certain senior executives of
          NCEP Management $780,000 in cash and issued 100,244 Trust Units plus
          an amount per Trust Unit equal to the distributions per Trust Unit
          paid to holders of record of Trust Units during the period commencing
          on January 1, 2003 and ending on the closing date.

Subsequent to the closing of the Internalization Transaction, the Trust
proceeded to consolidate all activities in PC's offices in Calgary, Alberta. To
ensure an orderly transition of the services then provided by NCEP Management
through its office in Toronto, Ontario, Sentry Select Capital Corp. ("Sentry")
entered into an agreement on closing, which was effective January 1, 2003, with
the Trust, PC and NCEP Management to provide certain of these services to the
Trust and PC at Sentry's cost until December 31, 2003, subject to a maximum cost
of $2 million. After December 31, 2003, Sentry no longer provides any services.
At closing Sentry was an affiliate of NCEP Management and is a company in which
John F. Driscoll owns a controlling interest.

As part of the agreement, all management fees, acquisition and disposition fees
were eliminated retroactive to January 1, 2003.

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<PAGE>

Strategy

     The Trust's objective is to maximize cash flow for distribution to its
Unitholders. The Trust intends to execute its business strategy by:

     o    continuing to pursue selected acquisitions that meet its portfolio
          acquisition criteria;

     o    continuing to develop its existing properties to enhance production
          and increase reserves;

     o    maintaining a balanced portfolio of geographically and geologically
          diversified oil and gas properties;

     o    controlling costs through efficient operation of existing and acquired
          properties;

     o    maintaining a capital structure that provides flexibility in accessing
          debt and capital markets; and

     o    managing commodity price risk when appropriate through hedging
          agreements that will increase the level of predictability in prices
          for its oil and gas production.

Acquisition Criteria

     The Royalty Agreement requires PC to comply with the following criteria and
procedures before purchasing a property:

     o    Properties will be acquired with the objective of providing
          Unitholders with an average annual net yield after all costs but
          before income taxes of at least 15% over the first five years from the
          date of acquisition and at least a 15% internal rate of return over
          the life of the reserves after all costs but before income taxes.

     o    At least 70% of the purchase price of all gas and oil properties must
          be represented by proved reserves.

     o    At least 50% of the properties purchased will be estimated to be
          producing for 20 years following their acquisition, based on
          independent engineering reports.

     o    Generally accepted industry practices and procedures will be employed
          in investigating title to the properties.

     o    No property having an acquisition cost of $10 million or more will be
          acquired unless a report has been obtained from an independent
          engineering consultant.

     o    Where the acquisition price of a property has not been determined by
          arm's length negotiations, the price will be no greater than the fair
          market value of the property at the time of acquisition as determined
          by an independent engineering consultant.

     o    The amount of anticipated future capital expenditures for a property
          will not be significant and such expenditures will be of the type
          which are intended to maintain, realize or improve production from the
          properties.

     In addition to the above, the Trust's properties, in aggregate, must be
geographically and geologically diversified. Not more than 25% of the asset
value of all the Trust's properties may be attributable to a single reservoir.
The Trust's properties will be located primarily in western Canada (namely,
British Columbia, Alberta, Saskatchewan and Manitoba). At the time of each
acquisition, after

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<PAGE>

giving effect to the proposed acquisition, not more than 10% of the asset value
of the Trust's properties may be represented by properties located outside of
western Canada. All of the Trust's properties must be located in Canada. Asset
value is the fair market value of the property as estimated by the Board of
Directors based on the most recent independent engineering report respecting
such property. If there is a material change to such property, a new report will
be prepared and used to determine the fair market value of such property.

     The foregoing acquisition criteria apply only to the Trust's property
acquisitions. The foregoing criteria may only be amended by Special Resolution.
Although the Trust is not required to apply these criteria when it acquires oil
and gas companies, as a matter of policy, the Trust is generally guided by the
same criteria. In addition, the Trust Indenture requires that any such
acquisition will be subject to standard industry due diligence procedures and a
favourable valuation report.

     In the event of a sale of a property, the Board of Directors must make a
determination as to whether the proceeds of the sale will be reinvested in
additional properties or assets or will be distributed to the Unitholders, in
each case after repayment of such portion of the outstanding indebtedness as PC
may determine. A sale involving more than 35% of the asset value of all
properties requires the approval of the Unitholders by Special Resolution.

Key Factors for Success

     The success of the Trust in meeting its objectives lies in management's
ability to positively influence three main factors:

     1)   Identify, pursue and acquire oil and gas properties and/or companies
          at prices which meet the acquisition criteria previously mentioned and
          add value to the Trust;

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

     3)   Manage and contain costs.

     PC's ability to achieve these three factors depends mainly on the
experience, knowledge, and capability of the management team. In addition to the
factors over which management has influence, there are numerous other factors
beyond management's control which will influence the success of the
organization. These other potential risks are identified in the Risk Factors
section of this document.

                GENERAL DEVELOPMENT OF THE BUSINESS OF THE TRUST

Financings

     The Trust was established in 1988 to raise funds for the purposes of
acquiring royalties from PC. On July 6, 2001, the Trust Units were consolidated
on a one-for-three basis. All relevant figures, including Trust Units
outstanding, net income per Trust Unit and distributions per Trust Unit, have
been restated to reflect this consolidation.

     During the last three years, the Trust completed the following public
offerings of Trust Units:


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<PAGE>
<TABLE>
<CAPTION>

    Date                  Trust Units           Price       Gross Proceeds
<S>        <C>            <C>                <C>            <C>
    April, 2001           13,600,000*        $  5.50*       $    74,800,000*
    August, 2001           3,450,000           15.00             51,750,000
    November, 2001         3,200,000           12.75             40,800,000
    March, 2002            4,600,000           13.00             59,800,000
    May, 2003              9,200,000           10.60             97,520,000
    December, 2003         6,600,000         $ 16.20        $   106,920,000
</TABLE>

  *Prior to the 3 for 1 consolidation of the units on July 6, 2001.

Acquisitions

2001

Apache Properties

     Effective January 1, 2001, PC purchased a 50% interest in a diverse group
of oil and gas producing properties from a major oil and gas company for $23.8
million. The acquisition added 3.7 mmboe of Established Reserves, at a cost of
$6.40 per boe, and 702 boepd of production. The reserves and production were 57%
gas.

Strachan

     On March 6, 2001, PC closed the purchase of an interest in a gas producing
property in Strachan, Alberta from a major Canadian oil and gas producer. The
purchase price was $9.5 million. The acquisition added approximately 1.2 million
boe of Established Reserves and 270 boepd of production.

Magin Energy Inc.

     In July 2001, PC completed the acquisition of Magin Energy Inc., a company
listed on the TSX. The purchase price consisted of $58.6 million in cash and 8.5
million Trust Units. PC also assumed $43.7 million of debt, including negative
working capital, the outstanding bank loan and capital leases, and incurred
other transaction costs of $11.8 million (comprised principally of brokers'
fees, severance costs and an acquisition fee of $4.4 million paid to NCEP
Management) and received net stock option proceeds of $6.9 million. In
consideration for the delivery of such Trust Units, the Trust received
promissory notes of PC in the aggregate amount of $157.1 million. Magin Energy
was amalgamated into PC and a royalty was granted in the Magin Energy properties
in favour of the Trust. Cash flow from the Magin Energy properties is paid to
the Trust as royalty income and as payment on the promissory notes.

     Magin Energy was a Canadian oil and gas exploration and production company
whose principal areas of operation were Alberta and Saskatchewan. Prior to the
completion of the acquisition of Magin Energy, Magin Energy sold its interest in
a property known as the Copton property.

     As a result of the acquisition, PC acquired Established Reserves of 29
mmboe and production of 9,000 boepd at the time of the acquisition at an
effective purchase price of $9.17 per Established Reserves boe. The reserves and
production were 50% gas. The reserve life index for the Magin Energy properties
at December 31, 2000 was 7.5 years. Over 90% of the Magin Energy properties were


                                       11
<PAGE>

operated by Magin Energy, and are now operated by PC. The Magin Energy
properties are located in areas with year round road access and this, along with
the multiple geological zone potential, is expected to help keep development
costs at or below the average for the area. As a result of the Magin Energy
acquisition, PC also acquired undeveloped land of 345,080 net (460,287 gross)
acres.

Swan Hills

     Effective November 1, 2001, PC acquired a 1.2% interest in the Swan Hills
Unit #1 along with other minor interests in the Swan Hills area from a large
independent U.S. oil and gas company. The transaction closed on February 26,
2002. The purchase price was $12.3 million. The acquisition added approximately
2.5 million boe of Established Reserves and 400 boepd of production.

     On December 31, 2001, PC acquired a 1.4% interest in the Swan Hills Unit #1
in north central Alberta from a large independent U.S. oil and gas company for
$7.5 million. The acquisition added approximately 2.2 million boe of Established
Reserves and 300 boepd of production.

2002

     Central Alberta

     Effective March 2002, PC acquired two gas properties and two oil properties
in Central Alberta for $40.2 million. Three of the properties are unitized and
one is operated. Net Established Reserves acquired were estimated at 8.8 million
boe and net production at date of acquisition was approximately 1,800 boepd
consisting of 67% oil. The properties had a reserve life index in excess of 13
years.

     NCE Energy Trust

     On May 30, 2002, PC completed the acquisition of NCE Energy Trust, a
royalty trust listed on the TSX. The acquisition was completed through the
exchange of 0.2325 of a unit of PC for each unit of NCE Energy Trust. The total
price of the transaction was $140.1 million comprised of 7.6 million Trust Units
with an assigned value of $98.6 million, the assumption of $39.5 million of debt
and negative working capital, and transaction costs of $2.0 million. A non-cash
amount of $27.1 million was added to oil and gas properties to reflect the
difference between the cost and the tax basis of the properties acquired.

     As a result of the acquisition, PC acquired Established Reserves of 13.9
mmboe and production of 5,300 boepd at an effective purchase price of $10.08 per
boe and $26,400 per boepd. The reserves and production were approximately 50%
gas and the reserve life index for these properties was 7.2 years. The NCE
Energy Trust properties are located in British Columbia, Alberta and
Saskatchewan. Over 50% of the production was operated by NCE Energy Trust and is
now operated by PC. Approximately 30% of the production and reserves in NCE
Energy Trust were common with or adjacent to PC properties.

     The Trust and NCE Energy Trust were managed by affiliated management
companies. Although it was concluded that the acquisition was not a "related
party transaction" within the meaning of certain Canadian securities laws,
because of the fact that the Trust and NCE Energy Trust were managed by


                                       12
<PAGE>

management companies that were under common control, the acquisition was
effectively treated as a related party transaction. As such, certain valuation,
disclosure and minority approval requirements were complied with. A valuation of
each of the Trust and NCE Energy Trust was completed by Sayer Securities
Limited. The valuation report, dated April 19, 2002, concluded that a reasonable
range of the fair market value for the units of the Trust was a low of $11.39
and a high of $14.29 and that a reasonable range of the fair market value for
the units of NCE Energy Trust was a low of $2.59 and a high of $3.29. The
acquisition was negotiated on an arm's length basis on behalf of the Trust and
NCE Energy Trust by a special committee of the board responsible for each
respective entity.

     ATCO

     On December 31, 2002, PC acquired producing gas properties in the Fort
Saskatchewan, Alberta area from ATCO Gas for $31.5 million. PC now operates the
properties and holds an average 95% working interest. Production net to PC was
approximately 6 mmcfpd and the Established Reserves acquired were approximately
19 bcf.

2003

     Solaris

     Effective January 1, 2003, PC acquired 100% of the outstanding common share
of Solaris Oil & Gas Inc. ("Solaris"), and on February 7, 2003, amalgamated
Solaris in 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 boepd of production.

     Property Package

     In the second quarter of 2003, PC closed the acquisition of a diverse group
of oil and gas properties for $61.7 million after adjustment. The purchase was
accretive to distributable cash flow, production from the properties was
approximately 2,300 boepd of which 42% was gas. Production and cash flow for the
month of June has been included in this report. Net revenue of $4.3 million from
the effective date to May 31, 2003 was applied against the purchase price. The
properties contain a large percentage of unit production, and have an RLI of
11.6 years.

     Swan Hills

     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 the
Trust's interest in the Unit, bringing the Trust's total interest in the Unit to
9.87%. This acquisition added 8.5 mmboe of Established Reserves and
approximately 1,100 boepd of production. The property's RLI was over 20 years.

                             BUSINESS AND PROPERTIES

     PC acquires, manages and disposes of petroleum and natural gas property
rights and interests. As of December 31, 2003, PC's principal properties were
located in Alberta, British Columbia, Manitoba and Saskatchewan. PC primarily
produces light and medium oil, natural gas and natural gas liquids. As at
December 31, 2003, PC's asset base included proved plus probable reserves
(before deduction of

                                       13
<PAGE>

royalties) of 53.4 mbbls of oil, 248.7 bcf of natural gas and 7.2 mbbls of
natural gas liquids based on forecast prices and cost assumptions, and an
inventory of undeveloped land totalling 534,589 gross acres and 250,509 net
acres. See "Statement of Reserves Data and Other Oil and Gas Information -
Disclosure of Reserves Data" and "Statement of Reserves Data and Other Oil and
Gas Information - Properties With No Attributed Reserves".

     One of PC's ongoing objectives is to enhance reserves and production
through acquisitions. With respect to acquisitions, PC operates in a competitive
environment with both large and small competitors.

     In 2003, PC acquired new properties for a total purchase price of $58.4
million and expended approximately $57.2 million to increase interests in
existing properties. PC disposed of properties for total proceeds of $33.5
million. In addition, PC incurred approximately $71.4 million mainly for
drilling, well equipment and facility costs.

     The following is a summary of PC's properties as at December 31, 2003.
Unless otherwise specified, gross and net acres and well count information are
as at December 31, 2003. Reserve amounts are stated, before deduction of
royalties, as at December 31, 2003 based forecast costs and price assumptions as
evaluated in the GLJ Report. The estimates of reserves and future net reserve
for individual properties may not reflect the same confidence level as estimates
of reserves and future net reserve for all properties, due to the effects of
aggregation.

<TABLE>
<CAPTION>
-------------------------- --------------------------------- -------------- ------------------ --------------- ----------------
                                                                                                 2003 Average      Proved Plus
                                                                Average                            Production         Probable
                                                                Working                               (boepd)  Reserves (mboe)
      Property Name                    Operator                Interest       Major Product
-------------------------- --------------------------------- -------------- ------------------ --------------- ----------------

-------------------------- --------------------------------- -------------- ------------------ --------------- ----------------
<S>                        <C>                               <C>            <C>                <C>             <C>
Swan Hills                 Various                                                 Oil                  2,300           14,424
-------------------------- --------------------------------- -------------- ------------------ --------------- ----------------
Weyburn                    PanCanadian                                9.3%         Oil                  2,000           14,012
-------------------------- --------------------------------- -------------- ------------------ --------------- ----------------
Pembina                    Various                                              Oil & Gas               1,200            8,815
-------------------------- --------------------------------- -------------- ------------------ --------------- ----------------
Hatton                     Apache                                    95.0%         Gas                  1,100            4,100
-------------------------- --------------------------------- -------------- ------------------ --------------- ----------------
Strachan                   Various                                              Oil & Gas               1,225            3,963
-------------------------- --------------------------------- -------------- ------------------ --------------- ----------------
Ring Border                Burlington Resources                       9.4%         Gas                    750            3,941
-------------------------- --------------------------------- -------------- ------------------ --------------- ----------------
July Lake                  Canadian Natural Resources                35.0%         Gas                  1,200            3,175
-------------------------- --------------------------------- -------------- ------------------ --------------- ----------------
Fort St. John              Petrofund and Others                                 Oil & Gas                 775            3,031
-------------------------- --------------------------------- -------------- ------------------ --------------- ----------------
Fort Saskatchewan          Petrofund                                 97.0%         Gas                    850            3,015
-------------------------- --------------------------------- -------------- ------------------ --------------- ----------------
Minehead                   Shiningbank Energy                        35.0%         Gas                    500            2,838
-------------------------- --------------------------------- -------------- ------------------ --------------- ----------------
Others                     Various                                 Various      Oil & Gas              16,518           40,716
-------------------------- --------------------------------- -------------- ------------------ --------------- ----------------
                                                                                                       28,418          102,030
-------------------------- --------------------------------- -------------- ------------------ =============== ================
</TABLE>


     Weyburn, Saskatchewan

     The Weyburn Unit, operated by EnCana Oil & Gas Partnership, is located 30
kilometres south of the city of Weyburn in southeastern Saskatchewan. Petrofund
owns a 9.3% interest in the Weyburn Unit

                                       14
<PAGE>

following the acquisition of an additional 2.3% unit interest in 2003. This unit
has an especially long reserves life index (20+ years) due to ongoing enhanced
recovery operations by water and CO2 flooding. The unit's 2003 performance
exceeded budget expectations. 2003 development activity included further
expansion of the CO2 flood, horizontal drilling (10 producers within the
waterflood area and 2 injectors within the CO2 flood area) and the commencement
of pre-engineering work on Phase 4 of the CO2 flood. Petrofund's unit working
interest production averaged 2,000 boepd in 2003. Petrofund's total proved plus
probable reserves as of December 31, 2003, amounted to 14,012 mboe consisting of
13,655 mbbl of oil and 357 mbbl of NGL.

     Swan Hills, Alberta

     Petrofund's Swan Hills (including Swan Hills North) property is located
approximately 200 kilometres northwest of Edmonton, Alberta and includes
significant ownership in such major oil units as Swan Hills Unit #1, Judy Creek
West Beaverhill Lake Unit, South Swan Hills Unit and House Mountain Unit #1.
Each of these units has long life reserves due to enhanced recovery through
water flooding and/or miscible hydrocarbon flooding. Early in 2003, Petrofund
significantly increased its Swan Hills Unit #1 ownership from 2.6% to 9.9%
through an acquisition. In addition, 6 horizontal wells were drilled in House
Mountain Unit #1 and 2 verticals wells in Swan Hills Unit #1. The Swan Hills
Unit #1 owners agreed to implement a pilot CO2 enhanced recovery project that's
expected to start up in early 2004. At yearend, Petrofund's working interest
Swan Hills production was 2,300 boepd. Petrofund's total proved plus probable
reserves as of December 31, 2003, totaled 14,424 mboe, consisting of 12,654 mbbl
of oil, 4.2 bcf of gas and 1,074 mbbl of NGL.

     Pembina, Alberta

     Petrofund's extensive Pembina holdings are situated 100 kilometres
southwest of Edmonton, Alberta. Petrofund operates several Pembina properties,
including Alder Flats, Cynthia, Lodgepole, Pembina, Rose Creek and Warburg.
Partner operated properties include North Pembina Cardium Unit, Berrymoor
Cardium Unit, Pembina Cardium Unit #7, Pembina Easyford Cardium Unit #1,
Lobstick Cardium Unit and Pembina Knobhill Belly River Unit #2. Development
activity in 2003 included the drilling of approximately 40 gross wells and
continued optimization/reactivation of several unit waterfloods. Petrofund
anticipates a similar number of wells being drilled on its properties next year.
Petrofund's working interest Pembina averaged 1,200 boepd during 2003.
Petrofund's total proved plus probable reserves as of December 31, 2003, totaled
8,815 mboe, comprising of 6,753 mbbl of oil, 8.9 bcf of gas and 576 mbbl of NGL.

     Hatton, Saskatchewan

     Petrofund's Hatton gas property is located approximately 140 kilometres
west of Swift Current, Saskatchewan. Petrofund operates 265 shallow gas wells,
including 74 new 100% working interest wells drilled in late 2003. Petrofund's
production originates from the shallow (500 metres) commingled Medicine Hat and
Milk River sand zones. At yearend, Petrofund's working interest production was
1,100 boepd. Petrofund's total proved plus probable reserves as of December 31,
2003, were 4,100 mboe, comprising of 24.6 bcf of gas.

                                       15

<PAGE>



     Strachan-Caroline, Alberta

     Petrofund's Strachan-Caroline property is located approximately 160
kilometres northwest of Calgary and consists of a combination of operated and
non-operated producing entities. Petrofund operates approximately 85% of its
Strachan-Caroline production. This area is well-known for its multiple targets
as evidenced by Petrofund's production coming from a variety of zones such as
the Leduc, Beaverhill Lake, Cardium, Viking, Ostracod, Glauconite and Lower
Mannville. In 2003, Petrofund successfully completed, equipped and tied in 2
operated gas wells that had been drilled in late 2002. Petrofund's working
interest production averaged 1,225 boepd in 2003. Petrofund's total proved plus
probable reserves as of December 31, 2003, were 3,963 mboe, made up of 67 mbbl
of oil, 17.8 bcf of gas and 924 mbbl of NGL.

     Border Bluesky, British Columbia

     Petrofund's Border Bluesky gas property is located 190 kilometres northeast
of Fort St. John in northeastern British Columbia and is operated by Burlington
Resources Canada. Petrofund owns a 9.4% interest in the Border
Bluesky-Gething-Montney Unit "B" and a similar interest in certain surrounding
non-unit lands. Petrofund also has ownership in the Border gas plant. Sixteen
unit and non-unit wells were drilled and equipped in early 2003. A similar
infill drilling program is planned for early 2004 (winter access only).
Petrofund's 2003 working interest production averaged 750 boepd. Petrofund's
total proved plus probable reserves as of December 31, 2003, were 3,941 mboe,
comprising of 20.9 bcf of gas and 450 mbbl of NGL.

     July Lake, British Columbia

     Petrofund's July Lake property is situated approximately 160 kilometres
northeast of Fort Nelson in northeastern British Columbia. Petrofund holds an
average 34% working interest in 19 producing gas wells, several of which are
horizontals, within a Production Sharing Area operated by Canadian Natural
Resources Limited. Petrofund also owns 100% working interest in nine additional
gas wells. All gas production comes from the Jean Marie formation and is
processed at Duke's Fort Nelson gas plant. No wells were drilled on Petrofund
lands in 2003 but as many as 8 wells could be drilled in 2004. Petrofund's
working interest production averaged 1,200 boepd during 2003. Petrofund's total
proved plus probable reserves as of December 31, 2003, were 3,175 mboe,
consisting of 19.0 bcf of gas and 8 mbbl of NGL.

     Fort St. John, British Columbia

     Petrofund's Fort St. John property is located close by the city of the Fort
St. John in northeastern British Columbia. Petrofund's operated entities include
Boundary Lake, Cecil Lake, Fort St. John and Wilder, while non-operated entities
include West Eagle and Stoddart. During 2003, Petrofund successfully drilled 2
operated Boundary Lake wells, plus completed, equipped and tied in 2 operated
Cecil Lake oil wells that had been drilled late in 2002. Petrofund is moving
ahead with plans to waterflood its Cecil Lake property in 2004. Petrofund is
also contemplating follow-up drilling on its Boundary Lake and Cecil Lake oil
properties in 2004. Petrofund's working interest production from this property
averaged 775 boepd during 2003. Petrofund's total proved plus probable reserves
as of December 31, 2003, totaled 3,031 mboe, containing 1,417 mbbl of oil, 8.1
bcf of gas and 267 mbbl of NGL.

                                       16
<PAGE>

     Minehead, Alberta

     Minehead is a gas property located approximately 120 kilometres southwest
of Edmonton, Alberta. Shiningbank Energy and Calpine Canada operate Petrofund's
Minehead production. Petrofund's working interests vary from 27.8 per cent to 40
per cent. Producing zones include the Cardium and Belly River. Cardium
production is characterized by low decline and high NGL recovery. During 2003,
Petrofund participated for its 40% working interest in drilling 2 successful
Cardium gas wells which came on stream in the 4th quarter. Petrofund anticipates
as many as 8 gross wells being drilled on its Minehead acreage in 2004.
Petrofund's working interest production from this property averaged 500 boepd in
2003. Petrofund's total proved plus probable reserves as of December 31, 2003,
were 2,838 mboe, comprising of 12.8 bcf of gas and 712 mbbl of NGL.

     Fort Saskatchewan, Alberta

     Petrofund operates its Fort Saskatchewan gas property located immediately
east of Edmonton, Alberta. Petrofund's Fort Saskatchewan property includes the
Beaverhill Lake Viking Gas Unit #1 along with the nearby Partridge Hill and
Bremner producing fields. Petrofund's average working interest for this area is
nearly 100%. Besides the wells, Petrofund owns and operates 3 associated
compression-dehydration facilities. Production is predominantly gas from the
Viking zone. During 2003, Petrofund aggressively recompleted and reactivated
several wells with mixed success. In 2004, Petrofund will continue to evaluate
its lands and wells for development opportunities. Petrofund's working interest
production averaged 850 boepd during 2003. Petrofund's total proved plus
probable reserves as of December 31, 2003, amounted to 3,015 mboe, consisting of
18.1 bcf of gas.

     The above 10 properties account for about 60% of PC's total proved plus
probable reserves as at December 31, 2003.

Other Properties

     PC has various interests in numerous other properties located in Alberta,
British Columbia, Manitoba and Saskatchewan. PC's proved plus probable reserves
for these other properties as at December 31, 2003 amounted to approximately
40,700 mboe. In total, these properties represent approximately 40% of PC's
proved plus probable reserves as at December 31, 2003.


                                       17
<PAGE>


     A map which illustrates the approximate locations of PC's principal
properties is set out below:

[GRAPHIC OMITTED]



    Report of Management and Directors on Reserves Data and Other Information

Management of Petrofund Corp. (the "Company") are responsible for the
preparation and disclosure of information with respect to the Company's oil and
gas activities in accordance with securities regulatory requirements. This
information includes reserves data, which consist of the following:

     (a)  (i)  proved and proved plus probable oil and gas reserves estimated as
               at December 31, 2003 using forecast prices and costs; and

         (ii)  the related estimated future net revenue; and

     (b)  (i)  proved oil and gas reserves estimated as at December 31, 2003
               using constant prices and costs; and

         (ii)  the related estimated future net revenue.

An independent qualified reserves evaluator has evaluated the Company's reserves
data. The report of the independent qualified reserves evaluator is presented
below.

The Reserves Committee of the board of directors of the Company has:

                                       18
<PAGE>

     (a)  reviewed the Company's procedures for providing information to the
          independent qualified reserves evaluator;

     (b)  met with the independent qualified reserves evaluator to determine
          whether any restrictions affected the ability of the independent
          qualified reserves evaluator to report without reservation; and

     (c)  reviewed the reserves data with management and the independent
          qualified reserves evaluator.

The Reserves Committee of the board of directors has reviewed the Company's
procedures for assembling and reporting other information associated with oil
and gas activities and has reviewed that information with management. The board
of directors has, on the recommendation of the Audit Committee, approved:

     (a)  the content and filing with securities regulatory authorities of the
          reserves data and other oil and gas information;

     (b)  the filing of the report of the independent qualified reserves
          evaluator on the reserves data; and

     (c)  the content and filing of this report.

Because the reserves data are based on judgments regarding future events, actual
results will vary and the variations may be material.


(signed) "Jeffery E. Errico"                        (signed) "Glen C. Fischer"
Jeffery E. Errico                                   Glen C. Fischer
President and Chief Executive Officer               Senior Vice President,
                                                    Operations

(signed) "Wayne M. Newhouse"                        (signed) "James E. Allard"
Wayne M. Newhouse                                   James E. Allard
Director and Chairman of the Reserves Audit         Director and Member of the
Committee                                           Reserves Audit Committee

March 1, 2004


                                       19
<PAGE>



                           REPORT ON RESERVES DATA BY
                         INDEPENDENT QUALIFIED RESERVES
                              EVALUATOR OR AUDITOR


To the board of directors of Petrofund Corp. (the "Company"):

1.   We have evaluated the Company's reserves data as at February 17, 2004. The
     reserves data consist of the following:

     (a)  (i) proved and proved plus probable oil and gas reserves estimated as
              at December 31, 2003 using forecast prices and costs; and

         (ii) the related estimated future net revenue; and

     (b)  (i) proved oil and gas reserves estimated as at December 31, 2003
              using constant prices and costs; and

         (ii) the related estimated future net revenue.

               o    The reserves data are the responsibility of the Company's
                    management. Our responsibility is to express an opinion on
                    the reserves data based on our evaluation.

     We carried out our evaluation in accordance with standards set out in the
     Canadian Oil and Gas Evaluation Handbook (the "COGE Handbook") prepared
     jointly by the Society of Petroleum Evaluation Engineers (Calgary Chapter)
     and the Canadian Institute of Mining, Metallurgy & Petroleum (Petroleum
     Society).

               o    Those standards require that we plan and perform an
                    evaluation to obtain reasonable assurance as to whether the
                    reserves data are free of material misstatement. An
                    evaluation also includes assessing whether the reserves data
                    are in accordance with principles and definitions presented
                    in the COGE Handbook.

               o    The following table sets forth the estimated future net
                    revenue (before deduction of income taxes) attributed to
                    proved plus probable reserves, estimated using forecast
                    prices and costs and calculated using a discount rate of 10
                    percent, included in the reserves data of the Company
                    evaluated by us for the year ended December 31, 2003, and
                    identifies the respective portions thereof that we have
                    audited, evaluated and reviewed and reported on to the
                    Company's board of directors:


                                       20
<PAGE>

<TABLE>
<CAPTION>
                                Location of
                                  Reserves
                                 (County or               Net Present Value of Future Net Revenue
            Description and       Foreign                (M$ before income taxes, 10% discount rate)
          Preparation Date of    Geographic        ----------------------------------------------------------------
                 Report             Area)         Audited         Evaluated          Reviewed           Total
        ---------------------   -----------       -------         ---------         ----------         --------
<S>                              <C>              <C>             <C>               <C>               <C>
          February 4, 2004        Canada            nil            678,788             nil             678,788

</TABLE>


               o    In our opinion, the reserves data respectively evaluated by
                    us have, in all material respects, been determined and are
                    in accordance with the COGE Handbook.

               o    We have no responsibility to update this evaluation for
                    events and circumstances occurring after the preparation
                    date.

               o    Because the reserves data are based on judgements regarding
                    future events, actual results will vary and the variations
                    may be material.


(signed) "Wayne Chow, P.Eng"
Vice President
Gilbert Laustsen Jung Associates Ltd.

Calgary, Alberta
February 17, 2004



                                       21
<PAGE>

          STATEMENT OF RESERVES DATA AND OTHER OIL AND GAS INFORMATION


      The statement of reserves data and other oil and gas information set
  forth below (the "Statement") is dated February 17, 2004. The effective date
        of the Statement is December 31, 2003 and the preparation date of
                       the Statement is February 4, 2004.

Disclosure of Reserves Data

     The reserves data set forth below (the "Reserves Data") is based upon an
evaluation by GLJ with an effective date of December 31, 2003 contained in the
GLJ Report dated February 17, 2004. The Reserves Data summarizes the oil,
liquids and natural gas reserves of PC and the net present values of future net
revenue for these reserves using constant prices and costs and forecast prices
and costs. The Reserves Data conforms with the requirements of National
Instrument 51-101 Standards of Disclosure for Oil and Gas Activities ("NI
51-101"). Additional information not required by NI 51-101 has been presented to
provide continuity and additional information which we believe is important to
the readers of this information. PC engaged GLJ to provide an evaluation of
proved and proved plus probable reserves and no attempt was made to evaluate
possible reserves.

     All of PC's reserves are in Canada and, specifically, in the provinces of
Alberta, British Columbia, Manitoba and Saskatchewan.

     PC is not taxable under the existing trust structure. The Alberta
Securities Commission has advised that PC will be exempt from disclosing after
tax future net revenues from its reserves.

Reserves Data (Constant Prices and Costs)



                         SUMMARY OF OIL AND GAS RESERVES
                  AND NET PRESENT VALUES OF FUTURE NET REVENUE
                             as of December 31, 2003
                            CONSTANT PRICES AND COSTS

<TABLE>
<CAPTION>
                                                                     RESERVES
                              ---------------------------------------------------------------------------------------
                              LIGHT AND MEDIUM OIL       HEAVY OIL             NATURAL GAS       NATURAL GAS LIQUIDS
                              --------------------   ----------------      ------------------    --------------------
                                Gross       Net       Gross       Net       Gross       Net        Gross       Net
RESERVES CATEGORY              (mbbl)     (mbbl)     (mbbl)     (mbbl)     (mmcf)      (mmcf)     (mbbl)     (mbbl)
-----------------             --------   ---------   -------   -------     --------    -------    --------   --------
<S>                           <C>        <C>         <C>        <C>        <C>         <C>        <C>        <C>
PROVED
   Developed Producing           33,914     29,686        853        750    196,898     155,614      5,213      3,674
   Developed Non-Producing          310        292          0          0      5,903       4,488        148        107
   Undeveloped                    8,671      7,815          0          0      5,402       4,170        376        255
                               --------   ---------   -------   --------   --------    --------    --------   --------
TOTAL PROVED                     42,895     37,793        853        750    208,203     164,271      5,738      4,036

PROBABLE                         11,240      9,677        205        183     45,680      36,115      1,584      1,211
                               --------   ---------   -------   --------   --------    --------    --------   --------
TOTAL PROVED PLUS PROBABLE       54,135     47,471      1,058        933    253,883     200,386      7,323      5,247
                               ========   =========   =======   ========   ========    ========    ========   ========
</TABLE>

                                       22
<PAGE>

<TABLE>
<CAPTION>
                                             NET PRESENT VALUES OF FUTURE NET REVENUE
                                            BEFORE INCOME TAXES DISCOUNTED AT (%/year)
-----------------------------------------------------------------------------------------------------------------------------
                                                    0             5             10            12            15            20
RESERVES CATEGORY                                 (MM$)         (MM$)          (MM$)         (MM$)         (MM$)         (MM$)
-----------------------------------------     -----------    ----------      ----------    ---------      -------     --------

<S>                                            <C>             <C>           <C>           <C>           <C>           <C>
PROVED
   Developed Producing                            1,214           902           728           678           616           538
   Developed Non-Producing                           32            24            19            18            16            14
   Undeveloped                                      174           105            67            57            44            30
                                                -------         -----         -----         -----         -----         ------
TOTAL PROVED                                      1,419         1,031           814           753           677           582

PROBABLE                                            429           239           155           134           110            83
                                                -------         -----         -----         -----         -----         ------
TOTAL PROVED PLUS PROBABLE                        1,848         1,270           970           887           787           664
                                                =======         =====         =====         =====         =====         ======
</TABLE>


<TABLE>
<CAPTION>
                                                 TOTAL FUTURE NET REVENUE
                                                       (UNDISCOUNTED)
                                                 as of December 31, 2003
                                                 CONSTANT PRICES AND COSTS

                                                                                                                       FUTURE NET
                                                                                                                         REVENUE
                                                                                                         WELL             BEFORE
                                                               OPERATING                               ABANDONMENT        INCOME
                                  REVENUE      ROYALTIES        COSTS         DEVELOPMENT COSTS          COSTS             TAXES
      RESERVES CATEGORY             (M$)          (M$)           (M$)                (M$)                 (M$)             (M$)
--------------------------     -----------  -------------     -----------     -----------------       ------------      --------
<S>                            <C>              <C>            <C>                <C>                  <C>            <C>
Proved Reserves                  3,122,731        591,013        942,158            116,124              54,124         1,419,313

Proved Plus Probable
Reserves                         3,886,979        730,689      1,105,367            147,279              55,609         1,848,034
</TABLE>

                                       23
<PAGE>


                                                     FUTURE NET REVENUE
                                                     BY PRODUCTION GROUP
                                                   as of December 31, 2003
                                                  CONSTANT PRICES AND COSTS

<TABLE>
<CAPTION>
                                                                                          FUTURE NET REVENUE BEFORE
                                                                                         INCOME TAXES (discounted at
                                                                                                  10%/year)
      RESERVES CATEGORY                            PRODUCTION GROUP                                  (M$)
----------------------------  ------------------------------------------------------------  -------------------------

<S>                            <C>                                                           <C>
Proved Reserves                Light and Medium Crude Oil (including solution gas and
                               other by-products)                                                   394,007
                               Heavy Oil (including solution gas and other by-products)               9,108
                               Natural Gas (including by-products but excluding
                               solution gas from oil wells)                                         411,312

Proved Plus Probable           Light and Medium Crude Oil (including solution gas and
Reserves                       other by-products)                                                   487,656
                               Heavy Oil (including solution gas and other by-products)              10,563
                               Natural Gas (including by-products but excluding
                               solution gas from oil wells)                                         471,389
</TABLE>


Reserves Data (Forecast Prices and Costs)


                                       SUMMARY OF OIL AND GAS RESERVES
                               AND NET PRESENT VALUES OF FUTURE NET REVENUE
                                            as of December 31, 2003
                                          FORECAST PRICES AND COSTS

<TABLE>
<CAPTION>
                                                                     RESERVES
                             ----------------------------------------------------------------------------------------
                             LIGHT AND MEDIUM OIL        HEAVY OIL             NATURAL GAS       NATURAL GAS LIQUIDS
                            ------------------------  ----------------     ------------------    ---------------------
                               Gross        Net        Gross       Net       Gross       Net        Gross       Net
RESERVES CATEGORY             (mbbl)       (mbbl)     (mbbl)     (mbbl)     (mmcf)      (mmcf)     (mbbl)     (mbbl)
----------------------      ----------    ---------   ---------  -------    ----------  -------    ---------  ---------
<S>                             <C>         <C>           <C>        <C>    <C>         <C>          <C>        <C>
PROVED
   Developed Producing          32,512      28,565        848        750    191,682     151,527      5,060      3,577
   Developed Non-
    Producing                      276         260          -          -      6,071       4,616        154        112
   Undeveloped                   8,675       8,196          -          -      5,408       4,177        377        258
                               -------      ------      ------     -----   --------    --------     ------     -------
TOTAL PROVED                    41,463      37,021        848        750    203,161     160,320      5,591      3,947

PROBABLE                        10,889       9,458        203        182     45,605      36,114      1,575      1,208
                               -------      ------      ------     -----   --------    --------     ------     -------
TOTAL PROVED PLUS PROBABLE      52,352      46,479      1,051        932    248,766     196,434      7,166      5,155
                               =======      ======      ======     =====   =========   ========     =======

</TABLE>
                                       24
<PAGE>

<TABLE>
<CAPTION>

                                     NET PRESENT VALUES OF FUTURE NET REVENUE
                                     BEFORE INCOME TAXES DISCOUNTED AT (%/year)

                                                        0             5           10           12          15            20
RESERVES CATEGORY                                     (MM$)         (MM$)        (MM$)        (MM$)       (MM$)         (MM$)
---------------------------------------             -------        -------      --------    ---------     ------      --------
<S>                                                  <C>          <C>           <C>        <C>          <C>           <C>
PROVED
   Developed Producing                                  790          615           513        483          446           397
   Developed Non-Producing                               24           18            15         14           12            11
   Undeveloped                                          111           63            37         30           21            12
                                                     ------        ------       -------     ------         ----
TOTAL PROVED                                            925          696           565        527          479           419

PROBABLE                                                320          177           114         98           81            60
                                                     ------        ------       -------     ------         ----          ----
TOTAL PROVED PLUS PROBABLE                            1,245          873           679        625          560           480
                                                     ======        ======       =======     ======         ====          ====
</TABLE>

<TABLE>
<CAPTION>
                                           TOTAL FUTURE NET REVENUE
                                                (UNDISCOUNTED)
                                            as of December 31, 2003
                                           FORECAST PRICES AND COSTS

                                                                                                    WELL           FUTURE NET
                                                               OPERATING       DEVELOPMENT       ABANDONMENT     REVENUE BEFORE
                             REVENUE         ROYALTIES           COSTS             COSTS            COSTS         INCOME TAXES
RESERVES CATEGORY             (M$)             (M$)              (M$)              (M$)             (M$)              (M$)
                          -----------       -----------      ------------        ---------       -----------       ------------
<S>                        <C>                <C>             <C>                 <C>               <C>              <C>
Proved Reserves            2,590,205          473,795         1,003,268           123,226           64,581           925,335

Proved Plus
Probable Reserves          3,267,061          589,762         1,206,744           156,876           68,834         1,244,846
</TABLE>


                                             FUTURE NET REVENUE
                                             BY PRODUCTION GROUP
                                            as of December 31, 2003
                                           FORECAST PRICES AND COSTS

<TABLE>
<CAPTION>
                                                                                         FUTURE NET REVENUE BEFORE
                                                                                        INCOME TAXES (discounted at
                                                                                                 10%/year)
     RESERVES CATEGORY                            PRODUCTION GROUP                                  (M$)
---------------------------  --------------------------------------------------------   ----------------------------


<S>                          <C>                                                            <C>
Proved Reserves               Light and Medium Crude Oil (including solution gas and
                              other by-products)                                                   241,996
                              Heavy Oil (including solution gas and other by-products)               6,674
                              Natural Gas (including by-products but excluding
                              solution gas from oil wells)                                         316,033

Proved Plus Probable          Light and Medium Crude Oil (including solution gas and
Reserves                      other by-products)                                                   309,328
                              Heavy Oil (including solution gas and other by-products)               7,797
                              Natural Gas (including by-products but excluding
                              solution gas from oil wells)                                         361,663

</TABLE>

                                       25
<PAGE>

Definitions and Other Notes

     In the tables set forth above in "Disclosure of Reserves Data" and
elsewhere in this Annual Information Form the following definitions and other
notes are applicable:

               o    "Gross" means:

in relation to PC's interest in production and reserves, its "PC gross
reserves", which are PC's interest (operating and non-operating) share before
deduction of royalties and without including any royalty interest of PC;

in relation to wells, the total number of wells in which PC has an interest; and

in relation to properties, the total area of properties in which PC has an
interest.

               o    "Net" means:

     (a)  in relation to PC's interest in production and reserves, its "PC net
          reserves", which are PC's interest (operating and non-operating) share
          after deduction of royalties obligations, plus PC's royalty interest
          in production or reserves.

     (b)  in relation to wells, the number of wells obtained by aggregating PC's
          working interest in each of its gross wells; and

     (c)  in relation to PC's interest in a property, the total area in which PC
          has an interest multiplied by the working interest owned by PC.

3.   Definitions used for reserve categories are as follows:

     Reserve Categories

     Reserves are estimated remaining quantities of oil and natural gas and
     related substances anticipated to be recoverable from known accumulations,
     from a given date forward, based on

     o    analysis of drilling, geological, geophysical and engineering data;

     o    the use of established technology; and

     o    specified economic conditions (see the discussion of "Economic
          Assumptions" below).

     Reserves are classified according to the degree of certainty associated
     with the estimates.

     (a)  Proved reserves are those reserves that can be estimated with a high
          degree of certainty to be recoverable. It is likely that the actual
          remaining quantities recovered will exceed the estimated proved
          reserves.

     (b)  Probable reserves are those additional reserves that are less certain
          to be recovered than proved reserves. It is equally likely that the
          actual remaining


                                    26
<PAGE>

          quantities recovered will be greater or less than the sum of the
          estimated proved plus probable reserves.

     "Economic Assumptions" will be the prices and costs used in the estimate,
namely:

     o    constant prices and costs as at the last day of PC's financial year

     o    forecast prices and costs

     Development and Production Status

     Each of the reserve categories (proved and probable) may be divided into
     developed and undeveloped categories:

     (a)  Developed reserves are those reserves that are expected to be
          recovered from existing wells and installed facilities or, if
          facilities have not been installed, that would involve a low
          expenditure (for example, when compared to the cost of drilling a
          well) to put the reserves on production. The developed category may be
          subdivided into producing and non-producing.

          (i)  Developed producing reserves are those reserves that are expected
               to be recovered from completion intervals open at the time of the
               estimate. These reserves may be currently producing or, if
               shut-in, they must have previously been on production, and the
               date of resumption of production must be known with reasonable
               certainly.

          (ii) Developed non-producing reserves are those reserves that either
               have not been on production, or have previously been on
               production, but are shut-in, and the date of resumption of
               production is unknown.

     (b)  Undeveloped reserves are those reserves expected to be recovered from
          known accumulations where a significant expenditure (for example, when
          compared to the cost of drilling a well) is required to render them
          capable of production. They must fully meet the requirements of the
          reserves classification (proved, probable) to which they are assigned.

     In multi-well pools it may be appropriate to allocate total pool reserves
     between the developed and undeveloped categories or to subdivide the
     developed reserves for the pool between developed producing and developed
     non-producing. This allocation should be based on the estimator's
     assessment as to the reserves that will be recovered from specific wells,
     facilities and completion intervals in the pool and their respective
     development and production status.

     Levels of Certainty for Reported Reserves

     The qualitative certainty levels referred to in the definitions above are
     applicable to individual reserve entities (which refers to the lowest level
     at which reserves calculations are performed) and to reported reserves
     (which refers to the highest level sum of

                                       27
<PAGE>

     individual entity estimates for which reserves are presented). Reported
     reserves should target the following levels of certainty under a specific
     set of economic conditions:

     o    At least a 90 percent probability that the quantities actually
          recovered will equal or exceed the estimated proved reserves;

     o    At least a 50 percent probability that the quantities actually
          recovered will equal or exceed the sum of the estimated proved plus
          probable reserves.

     A qualitative measure of the certainty levels pertaining to estimates
     prepared for the various reserves categories is desirable to provide a
     clearer understanding of the associated risks and uncertainties. However,
     the majority of reserves estimates will be prepared using deterministic
     methods that do not provide a mathematically derived quantitative measure
     of probability. In principle, there should be no difference between
     estimates prepared using probabilistic or deterministic methods.

4.   Forecast prices and costs

     Future prices and costs that are:

     (a)  Generally acceptable as being a reasonable outlook of the future; and

     (b)  If and only to the extent that, there are fixed or presently
          determinable future prices or costs to which PC is legally bound by a
          contractual or other obligation to supply a physical product,
          including those for an extension period of a contract that is likely
          to be extended, those prices or costs rather than the prices and costs
          referred to in paragraph (a).

     The forecast summary table under "Pricing Assumptions" identifies benchmark
     reference pricing that apply to PC.

5.   Constant prices and costs

     Prices and costs used in an estimate that are:

     (a)  PC's prices and costs as at the effective date of the estimation, held
          constant throughout the estimated lives of the properties to which the
          estimate applies; and

     (b)  If, and only to the extent that, there are fixed or presently
          determinable future prices or costs to which PC is legally bound by a
          contractual or other obligation to supply a physical product,
          including those for an extension period of a contract that is likely
          to be extended, those prices or costs rather than the prices and costs
          referred to in paragraph (a).

     For the purposes of paragraph (a), PC prices are the posted prices for oil
     and the spot price for gas, after historical adjustments for
     transportation, gravity and other factors.

6.   The Alberta royalty tax credit ("ARTC") is included in the cumulative cash
     flow amounts. ARTC is based on the program announced November 1989 by the
     Alberta

                                       28
<PAGE>

     government with modifications effective January 1, 1995. PC qualifies for
     the maximum ARTC.

7.   Future income tax expense

     Future income tax expenses estimate:

     (a)  Making appropriate allocations of estimated unclaimed costs and losses
          carried forward for tax purposes;

     (b)  Without deducting estimated future costs that are not deductible in
          computing taxable income;

     (c)  Taking into account estimated tax credits and allowances; and

     (d)  Applying to the future pre-tax net cash flows relating to PC's oil and
          gas activities the appropriate year-end statutory rates, taking into
          account future tax rates already legislated.

8.   "Development well" means a well drilled inside the established limits of an
     oil and gas reservoir, or in close proximity to the edge of the reservoir,
     to the depth of a stratigraphic horizon known to be productive.

9.   "Development costs" means costs incurred to obtain access to reserves and
     to provide facilities for extracting, treating, gathering and storing the
     oil and gas from reserves. More specifically, development costs, including
     applicable operating costs of support equipment and facilities and other
     costs of development activities, are costs incurred to:

     (a)  Gain access to and prepare well locations for drilling, including
          surveying well locations for the purpose of determining specific
          development drilling sites, clearing ground draining, road building,
          and relocating public roads, gas lines and power lines, pumping
          equipment and wellhead assembly;

     (b)  Drill and equip development wells, development type stratigraphic test
          wells and service wells, including the costs of platforms and of well
          equipment such as casing, tubing, pumping equipment and wellhead
          assembly;

     (c)  Acquire, construct and install production facilities such as flow
          lines, separators, treaters, heaters, manifolds, measuring devices and
          production storage tanks, natural gas cycling and processing plants,
          and central utility and waste disposal systems; and

     (d)  Provide improved recovery systems.

10.  "Exploration well" means a well that is not a development well, a service
     well or a stratigraphic test well.

                                       29
<PAGE>

11.  "Exploration costs" means costs incurred in identifying areas that may
     warrant examination and in examining specific areas that are considered to
     have prospects that may contain oil and gas reserves, including costs of
     drilling exploratory wells and exploratory type stratigraphic test wells.
     Exploration costs may be incurred both before acquiring the related
     property and after acquiring the property. Exploration costs, which include
     applicable operating costs of support equipment and facilities and other
     costs of exploration activities, are:

     (a)  Costs of topographical, geochemical, geological and geophysical
          studies, rights of access to properties to conduct those studies, and
          salaries and other expenses of geologists, geophysical crews and
          others conducting those studies;

     (b)  Costs of carrying and retaining unproved properties, such as delay
          rentals, taxes (other than income and capital taxes) on properties,
          legal costs for title defence, and the maintenance of land and lease
          records;

     (c)  Dry hole contributions and bottom hole contributions;

     (d)  Costs of drilling and equipping exploratory wells; and (e) Costs of
          drilling exploratory type stratigraphic test wells.

12.  "Service well" means a well drilled or completed for the purpose of
     supporting production in an existing field. Wells in this class are drilled
     for the following specific purposes: gas injection (natural gas, propane,
     butane or flue gas), water injection, steam injection, air injection, salt
     water disposal, water supply for injection, observation or injection for
     combustion.

13.  Numbers may not add due to rounding.

14.  The estimates of future net revenue presented in the tables above do not
     represent fair market value.

15.  Disclosure provided herein in respect of boes may be misleading,
     particularly if used in isolation. A boe conversion ratio of 6 mcf : 1 bbls
     is based on an energy equivalency conversion method primarily applicable at
     the burner tip and does not represent a value equivalency at the wellhead.

16.  Estimated further abandonment and reclamation costs related to a property
     have been taken into account by GLJ in determining reserves that should be
     attributable to a property and in determining the aggregate future net
     revenue there from, there was deducted the reasonable estimated further
     well abandonment costs.

17.  Both the constant and forecast price and cost assumptions assume the
     continuance of current laws and regulations.

18.  The extended character of all factual data supplied to GLJ were accepted by
     GLJ as represented. No field inspection was conducted.

                                       30
<PAGE>

Pricing Assumptions

The following sets out the benchmark reference prices, as at December 31, 2003,
reflected in the Reserves Data. These price assumptions were provided to PC by
GLJ, PC's independent qualified evaluator.



                                          SUMMARY OF PRICING ASSUMPTIONS
                                             as of December 31, 2003
                                            CONSTANT PRICES AND COSTS
<TABLE>
<CAPTION>

                                     OIL
              -------------------------------------------------------
                  WTI      Edmonton    Hardisty                                                                Edmonton
                Cushing    Par Price     Heavy          Cromer Medium     NATURAL GAS    Edmonton   Edmonton   Pentanes   EXCHANGE
               Oklahoma 40(degree)API 12(degree) API  29.3(degree)API  AECO Gas Price    Propane     Butane      Plus       RATE(1)
     Year      ($US/bbl)   ($Cdn/bbl)  ($Cdn/bbl)        ($Cdn/bbl)      ($Cdn/MMBtu)  ($Cdn/bbl)  ($Cdn/bbl) ($Cdn/bbl)  ($US/$Cdn)
 ------------ ----------  -----------  -------------  ---------------  --------------   ---------   ---------  ---------   ---------
Historical
<S>            <C>          <C>          <C>              <C>            <C>             <C>         <C>       <C>         <C>

As at December   32.52       40.81         23.31          34.81            6.09            29.81      31.81      41.31       0.7738
31, 2003

</TABLE>
Notes:

(21) The exchange rate used to generate the benchmark reference prices in this
     table.


                             SUMMARY OF PRICING AND INFLATION RATE ASSUMPTIONS
                                          as of December 31, 2003
                                         FORECAST PRICES AND COSTS

<TABLE>
<CAPTION>
                                     OIL
              ------------------------------------------------
                  WTI      Edmonton    Hardisty
                Cushing    Par Price     Heavy          Cromer Medium     NATURAL GAS    Edmonton
               Oklahoma 40(degree)API 12(degree) API  29.3(degree)API  AECO Gas Price    Propane
     Year      ($US/bbl)   ($Cdn/bbl)  ($Cdn/bbl)        ($Cdn/bbl)      ($Cdn/MMBtu)  ($Cdn/bbl)
 ------------ ----------  -----------  -------------  ---------------  --------------   ---------

<S>            <C>        <C>          <C>             <C>             <C>              <C>
Forecast:
      2004     29.00      37.75        20.25                31.75            5.85          26.75
      2005     26.00      33.75        20.25                28.75            5.15          21.75
      2006     25.00      32.50        21.00                28.50            5.00          20.50
      2007     25.00      32.50        21.00                28.50            5.00          20.50
      2008     25.00      32.50        21.00                28.50            5.00          20.50




<CAPTION>


                          Edmonton
               Edmonton   Pentanes   INFLATION     EXCHANGE
                Butane      Plus      RATES(1)     RATE(1)
     Year    ($Cdn/bbl) ($Cdn/bbl)    %/Year     ($US/$Cdn)
 ------------ ---------  ---------   ----------  ---------

Forecast:
<S>   <C>        <C>       <C>           <C>         <C>
      2004       28.75     38.25         1.5         0.750
      2005       23.75     34.25         1.5         0.750
      2006       22.50     33.00         1.5         0.750
      2007       22.50     33.00         1.5         0.750
      2008       22.50     33.00         1.5         0.750

</TABLE>


Notes:
(1)  Inflation rates for forecasting prices and costs.
(2)  Exchange rates used to generate the benchmark reference prices in this
     table.

PC's weighted average prices received in 2003 after transportation and quality
differentials were $37.91/bbl for oil, $6.30/mcf for natural gas and $34.66/bbl
for natural gas liquids.

Reconciliations of Changes in Reserves and Future Net Revenue

                                       31
<PAGE>

                                                 RECONCILIATION OF
                                                COMPANY NET RESERVES
                                               BY PRINCIPAL PRODUCT TYPE
                                                CONSTANT PRICES AND COSTS

<TABLE>
<CAPTION>
                                                                                             ASSOCIATED AND NON-
                              LIGHT AND MEDIUM OIL                   HEAVY OIL                 ASSOCIATED GAS
                        ----------------------------------  ------------------------------  -------------------------------
                                                 Net                               Net                               Net
                                                Proved                            Proved                            Proved
                           Net        Net        Plus        Net        Net        Plus        Net        Net        Plus
                         Proved    Probable    Probable    Proved     Probable   Probable    Proved     Probable   Probable
FACTORS                  (mbbl)     (mbbl)      (mbbl)     (mbbl)      (mbbl)     (mbbl)      (bcf)      (bcf)       (bcf)
---------------------   --------   ---------  ----------   ----------  --------  ---------  ---------   ---------  ---------
<S>                     <C>        <C>         <C>        <C>          <C>        <C>       <C>        <C>         <C>
   December 31 2002(1)   34,834      6,758      41,592       553         -40        593        181         32         213

            Extensions      159         23         182         -          -           -          1         -            1
     Improved Recovery      681       (492)        189         -          -           -         -          -            0
   Technical Revisions   (1,303)     2,478       1,175       318         143        461         (8)         3          (6)
           Discoveries       79         21         100         -          -           -         -          -            0
          Acquisitions    9,319      2,348      11,667         -          -           -         15          2          17
          Dispositions   (2,186)    (1,520)     (3,705)        -          -           -         (2)        (1)         (3)
      Economic Factors     (102)        62                     -          -           -          1          1           1
                                                  (39)
            Production   (3,689)                            (121)                  (121)       (23)                   (23)
                                                (3,689)
                        ---------- ---------- ----------- ---------- ----------- ---------- ---------- ----------- ----------
     December 31, 2003   37,793      9,678      47,471       750         183        933        164         36         200
                        ========== ========== =========== ========== =========== ========== ========== =========== ==========

</TABLE>

<TABLE>
<CAPTION>
                              NATURAL GAS LIQUIDS             BARRELS OF OIL EQUIVALENT
                        -------------------------------   -----------------------------------
                                                Net
                                               Proved                             Net Proved
                           Net       Net        Plus        Net        Net          Plus
                         Proved    Probable    Probable    Proved     Probable    Probable
FACTORS                  (mbbl)     (mbbl)     (mbbl)      (mboe)      (mboe)      (mboe)
----------------------  ---------  ---------   ---------  --------   ----------  -------------
<S>         <C>           <C>         <C>      <C>         <C>         <C>         <C>
   December 31 2002(1)    4,175       762      4,937       69,753      12,850      82,602


            Extensions       30         4         34          332          53         385
     Improved Recovery       11         1         13          757        (478)        280
   Technical Revisions   (1,007)      294       (713)      (3,391)      3,365         (27)
           Discoveries       -          0          -           79          21         100
          Acquisitions    1,367       129      1,496       13,201       2,820      16,020
          Dispositions      (13)       (8)       (22)      (2,537)     (1,750)     (4,287)
      Economic Factors       17        29         45           11         211         222
            Production     (545)                (545)      (8,248)                 (8,248)
                        ---------- ---------- ----------- ---------- ----------- ------------
     December 31, 2003     4,036    1,211      5,247       69,957      17,091      87,048
                        ========== ========== =========== ========== =========== ============
</TABLE>

Note:
(1)  The evaluation as at December 31, 2002 was prepared using National Policy
     Statement 2-B reserves definitions. Under those definitions, probable
     reserves were adjusted by a factor to account for the risk associated with
     their recovery. PC 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 above reconciliation reflects current probable reserves
     versus previous risk adjusted (50%) probable reserves reported by PC.

                                       32

<PAGE>


                                    RECONCILIATION OF CHANGES IN
                                 NET PRESENT VALUES OF FUTURE NET REVENUE
                                     DISCOUNTED AT 10% PER YEAR
                                          PROVED RESERVES
                                       CONSTANT PRICES AND COSTS

<TABLE>
<CAPTION>
                                                                                                      2003
PERIOD AND FACTOR                                                                                     (M$)
------------------------------------------------------------------------------------------------------------------
<S>                                                                                                <C>
Estimated Net Present Value Before Tax at Beginning of Year                                         1,027,930

     Oil and Gas Sales During the Period(1)                                                          (217,054)
     Changes due to Prices, Production Costs and Royalties Related to Forecast Production(2)         (151,647)
     Development Costs During the Period(3)                                                           (71,400)
     Changes in Forecast Development Costs(4)                                                          15,421
     Changes Resulting from Extensions and Improved Recovery(5)                                        12,665
     Changes Resulting from Discoveries(5)                                                                989
     Changes Resulting from Acquisitions of Reserves(5)                                               156,038
     Changes Resulting from Dispositions of Reserves(5)                                               (28,991)
     Accretion of Discount(6)                                                                         102,793
     Net Change in Income Taxes(7)                                                                        N/A
                                                                                                 ----------------
     Changes Resulting from Technical Reserves Revisions Plus All Other Changes                       (32,317)
                                                                                                 ----------------
Estimated Net Present Value Before Tax at End of Period                                               814,427
                                                                                                 ================

</TABLE>
               Notes:
               (1)  Net of production costs and royalties, before income taxes
               (2)  The impact of changes in prices and other economic factors
                    on future net revenue
               (3)  Actual capital expenditures relating to the exploration and
                    development and production of oil and gas reserves
               (4)  Includes the difference between actual and forecast
                    development costs during the period
               (5)  Production and capital costs associated with recovery of the
                    related reserves are included in this category
               (6)  10% of after adjustments for dispositions
               (7)  Includes the difference between actual and forecast income
                    taxes during the period


Additional Information Relating to Reserves Data

Undeveloped Reserves

     Proved and probable undeveloped reserves have been estimated in accordance
with procedures and standards contained in the COGE Handbook. In general,
undeveloped reserves are scheduled to be developed within the next two years of
the effective date. Capital expenditures to develop proved undeveloped reserves
are estimated at $15.8 million in 2004 and $11.4 million in 2005.

Significant Factors or Uncertainties

     For details of important economic factors or significant uncertainties that
affect particular components of the Reserves Data, see "Management's Discussion
and Analysis - Risk Factors - Business-Related Risks".

                                       33
<PAGE>

Future Development Costs

     The following table sets forth development costs deducted in the estimation
of PC's future net revenue attributable to the reserve categories noted below.

<TABLE>
<CAPTION>
                                                                        Constant Prices and
                                 Forecast Prices and Costs (M$)            Costs (M$)
                                --------------------------------------  --------------------
                                                      Proved Plus
Year                              Proved Reserves   Probable Reserves      Proved Reserves
                                ------------------ -------------------   -------------------
<C>                              <C>                 <C>                    <C>
2004                                   24,634              29,548                 24,634
2005                                   17,535              24,829                 17,446
2006                                   14,504              18,473                 14,209
2007                                   13,975              16,194                 13,487
2008                                    7,383              12,280                  7,049
Remainder                              45,195              55,552                 39,299
Total Undiscounted                    123,226             156,876                116,124
                                ------------------ -------------------   -------------------
Total Discounted at 10%                83,033             106,285                 80,566
                                ================== ===================   ====================

</TABLE>

     The source of funding for future development costs will be internally
generated cash flow, debt or a combination of both. Disclosed reserves and
future net revenue will not be materially affected by the costs of funding the
future development expenditures.

                                       34
<PAGE>

Other Oil and Gas Information

Oil And Gas Wells

     The following table sets forth the number and status of wells in which PC
has a working interest as at December 31, 2003.

<TABLE>
<CAPTION>
                                           Oil Wells                                  Natural Gas Wells
                         ----------------------------------------------   -------------------------------------------
                                Producing            Non-Producing            Producing             Non-Producing
                         -----------------------  ---------------------   --------------------   --------------------
                             Gross        Net        Gross        Net       Gross        Net       Gross         Net
                         -----------  ----------  ----------  ---------   ---------   --------   ---------    --------
<S>                        <C>         <C>           <C>      <C>           <C>       <C>          <C>       <C>
Alberta                       2,618       392.4         762      172.5         845       256.1        187       105.5
British Columbia                 88        23.2          69       11.0         244        37.8         71        13.6
Manitoba                        121       114.8          51       49.1           -           -          -           -
Saskatchewan                  1,592       525.1         237       34.2         341       298.5         16         9.3
                         -----------  ----------  ----------  ---------   ---------   --------   ---------    --------
Total                         4,419     1,055.5       1,119      266.8       1,430       592.4        274       128.4
                         ===========  ==========  ==========  =========   ==========  =========  ==========   ========
</TABLE>


Properties with no Attributable Reserves

     The following table sets out PC's undeveloped land holdings as at December
31, 2003.

                                   Undeveloped Acres
                            ------------------------------
                                Gross             Net
                            --------------   -------------
Alberta                        311,218          150,319
British Columbia               132,701           44,346
Manitoba                         1,201            1,181
Saskatchewan                    89,469           54,663
                            --------------   -------------

Total                          534,589          250,509
                            ==============   =============

     There are no material work commitments on the undeveloped land holdings.

     PC expects that rights to explore, develop and exploit 48,680 net acres of
its undeveloped land holdings will expire by December 31, 2004.

Additional Information Concerning Abandonment and Reclamation Costs

     Future abandonment and reclamation costs have been estimated based on
actual costs incurred to date by PC for abandonment and reclamation activities.
Costs to abandon and reclaim approximately 2,040 net wells totalling $61.6
million net of salvage value ($26.0 million discounted at 10%) are included in
the estimate of future net revenue. Facility abandonment costs of $20.7 million
($3.1 million discounted at 10%) are not included in the estimate of future net
revenue. Abandonment and reclamation costs estimated for the next three years
are $4.3 million in 2004, $4.1 million in 2005 and $3.3 million in 2006.

Forward Contracts

     For details of material commitments to sell natural gas and crude oil which
were outstanding at December 31, 2003, see Note 14 to the Trust's audited
consolidated financial

                                       35
<PAGE>

statement for the year ended December 31, 2003, which Note is incorporated
herein by reference.

Tax Horizon

     Under its existing trust structure, PC does not pay income tax because the
tax liability is transferred to the individual Unitholders.

Capital Expenditures

     The following tables summarize capital expenditures (net of incentives and
net of certain proceeds and including capitalized general and administrative
expenses) related to PC's activities for the year ended December 31, 2003:

                                          (M$)
                                     ----------------
Property acquisition costs
   Proved properties                      $82,100
   Undeveloped properties                   1,700
Exploration costs                           5,700
Development costs                          64,000
                                     ----------------
Total                                    $153,500
                                     ================

Exploration and Development Activities

     The following tables sets forth the gross and net exploratory and
development wells in which PC participated during the year ended December 31,
2003:

     Working Interest Wells

                       Development Wells               Exploration Wells
                   -------------------------        --------------------------
                     Gross            Net             Gross            Net
                   -----------    ----------        -----------     ----------
Oil                    74             7.9               6              1.5
Gas                   110             80.2              5              1.9
Service                 4             2.2                -               -
Dry                     7             1.5               8              3.7
                   -----------    ----------        -----------     ----------
Total:                195             91.8             19              7.1
                   ===========    ==========        ===========     ==========



     Farm-out Wells

                              Development     Exploration
                                 Wells           Wells
                             --------------- ---------------

Oil                                 2              1
Gas                                10              22
Service                             -               -
Dry                                 1              4
                             --------------- ---------------
Total:                             13              27
                             =============== ===============


                                       36

<PAGE>

     PC's most important current and likely exploration and development
activities are described under "Business and Properties".

o        Production Estimates

         The following table sets out the gross volume of PC's production
estimated for the year ended December 31, 2004 which is reflected in the
estimate of future net revenue disclosed in the tables contained under
"Disclosure of Reserves Data" using constant prices and costs.

<TABLE>
<CAPTION>
                          Light and Medium                                            Natural Gas
                                 Oil            Heavy Oil         Natural Gas           Liquids             BOE
                                (bpd)             (bpd)             (mcfpd)              (bpd)             (boepd)
                          ----------------     -----------       -------------       --------------       ---------
<S>                        <C>                 <C>               <C>                 <C>               <C>
Proved Producing               10,381              333               74,091              2,020             25,083
Total Proved                   10,745              333               76,739              1,899             25,767
Proved plus Probable           11,088              340               78,077              1,921             26,361
</TABLE>


Production History

     The following tables summarize certain information in respect of
production, product prices received, royalties paid, operating expenses and
resulting netbacks of PC for the periods indicated below:

                                                   Quarter Ended
                                    --------------------------------------------
                                                        2003
                                    --------------------------------------------
                                     Dec. 31    Sept. 30    June 30     Mar. 31
                                   ------------ ---------- ---------- ---------
                     Oil Wells(1)

 Average Daily Production (boepd)       15,111     14,297     13,005    12,847

                  Revenue ($/boe)        33.72      36.50      37.32     44.04
                Royalties ($/boe)         5.87       6.62       6.55      8.36
         Production Costs ($/boe)        11.06      12.85      12.22     10.49
                                   ------------ ---------- ---------- ---------
                  Netback ($/boe)        16.79      17.03      18.55     25.19
                                   ============ ========== ========== =========

                     Gas Wells(1)

Average Daily Production (mcfepd)       85,660     85,099     84,866    87,384

                 Revenue ($/mcfe)         5.63       5.77       6.26      7.46
               Royalties ($/mcfe)         1.33       1.37       1.51      1.91
        Production Costs ($/mcfe)         0.91       1.10       0.97      0.89
                                   ------------ ---------- ---------- ---------
                 Netback ($/mcfe)         3.39       3.30       3.78      4.66
                                   ============ ========== ========== =========

         Note:
          (1)  Principal product type attributable to the wells.


                  SELECTED FINANCIAL AND OPERATING INFORMATION

Consolidated Financial Information

     The following is a summary of selected consolidated financial information
of the Trust for the years indicated.

                                       37

<PAGE>





<TABLE>
<CAPTION>
-------------------------------------------------- --------------- ----------------------- --------------------

December 31,                                           2003                 2002                 2001(2)
-------------------------------------------------- ----------------------------------------------------------------
                                                                  (MM$, except per unit amounts)
-------------------------------------------------- ---------------- ----------------------- --------------------
<S>                                                <C>                 <C>                   <C>
Total revenues                                        $ 393.1             $ 270.7               $ 244.5
-------------------------------------------------- ---------------- ----------------------- --------------------
Royalties, net of incentives                           $ 84.8              $ 50.4                $ 54.8
-------------------------------------------------- ---------------- ----------------------- --------------------
Lease operating costs                                  $ 91.3              $ 74.8                $ 48.2
-------------------------------------------------- ---------------- ----------------------- --------------------
Proceeds on disposition of property interests          $ 33.5              $ 30.0                 $ 3.7
-------------------------------------------------- ---------------- ----------------------- --------------------
Cash flow from operations                             $ 187.6             $ 112.6               $ 110.2
-------------------------------------------------- ---------------- ----------------------- --------------------
Cash flow available for distribution                  $ 150.7             $ 103.1               $ 110.6
-------------------------------------------------- ---------------- ----------------------- --------------------
         per Unit - basic                              $ 2.47              $ 2.07                $ 3.50
-------------------------------------------------- ---------------- ----------------------- --------------------
         per Unit - diluted                            $ 2.46              $ 2.06                $ 3.49
-------------------------------------------------- ---------------- ----------------------- --------------------
Net income                                             $ 85.8              $ 24.4                $ 54.0
-------------------------------------------------- ---------------- ----------------------- --------------------
         Per Unit - basic                              $ 1.41              $ 0.49                $ 1.71
-------------------------------------------------- ---------------- ----------------------- --------------------
         Per Unit - diluted                            $ 1.40              $ 0.49                $ 1.71
-------------------------------------------------- ---------------- ----------------------- --------------------
Working Capital (deficit)                              $(30.0)            $  (6.9)              $ (20.6)
-------------------------------------------------- ---------------- ----------------------- --------------------
Total assets                                          $ 943.9             $ 890.6               $ 699.3
-------------------------------------------------- ---------------- ----------------------- --------------------
Total long-term debt(1)                               $ 110.3             $ 219.2               $ 145.0
-------------------------------------------------- ---------------- ----------------------- --------------------
Unitholders' equity                                   $ 649.2             $ 480.1               $ 398.7
-------------------------------------------------- ---------------- ----------------------- --------------------
Weighted average number of Units outstanding
-------------------------------------------------- ---------------- ----------------------- --------------------
         Basic                                           61.0                49.9                  31.6
-------------------------------------------------- ---------------- ----------------------- --------------------
         Diluted                                         61.2                49.9                  31.6
-------------------------------------------------- ---------------- ----------------------- --------------------
</TABLE>

Note:

(1)  Although the Trust does not have any long term indebtedness, PC does have
     long term indebtedness, which is secured against 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 of the Trust have no direct liability to PC's lenders or to PC
     should the assets securing the loan generate insufficient cash flow to
     repay the obligations.

(2)  On July 6, 2001, the Trust Units were consolidated on a one-for-three
     basis. All relevant figures, including Trust Units, outstanding net income
     per Trust Unit and distributions per Trust Unit have been restated to
     reflect this consolidation.

Sensitivity Analysis

     In 2003, PC's cash flow from operating activities was $187.6 million, and
net income was $85.8 million. The sensitivity of PC's cash flow and net income
before income taxes to oil price, gas price, $US/$CAN exchange rate, and the
prime interest rate is listed below.

     The table below 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.



<TABLE>
<CAPTION>
        ---------------------------------------------- ---------------- ------------------- --------------
                                                                                                   $/unit
                                                                Change                  M$       per year
        ---------------------------------------------- ---------------- ------------------- --------------

        <S>                                              <C>                     <C>            <C>
        Price per barrel of oil                             $1.00 U.S.              $5,331         $0.072

                                       38

<PAGE>

        ---------------------------------------------- ---------------- ------------------- --------------
        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 bpd               1,131         $0.015
        ---------------------------------------------- ---------------- ------------------- --------------
        Gas production volumes -                              1 mmcfpd               1,784         $0.024
        ---------------------------------------------- ---------------- ------------------- --------------
        *After adjustment for estimated royalties
        ---------------------------------------------- ---------------- ------------------- --------------
</TABLE>

Distribution Policy

     A major objective of the Trust's distribution policy is to provide
unitholders with relatively stable and predictable monthly distributions despite
potentially significant variations in product prices. A second objective is to
retain a portion of cash flow to fund ongoing development and optimization
projects designed to enhance the sustainability of cash flow.

     The percentage of cash flow from operations paid to unitholders each
quarter will vary according to a number of factors assessed by management
including:

     o    Fluctuations in oil and gas prices

     o    Changes in the $Canadian/$US exchange rate

     o    The size of the development drilling programs and the portion funded
          from cash flow

     o    The level of debt within PC.

     Although the payout ratio will vary significantly from quarter to quarter,
the objective is to pay to unitholders 80% of cash flow over the long term. The
payout ratio was 70% in 2003 and 75% in 2002. The payout ratio in 2003 ranged
between 45% in the first quarter to 92% in the third quarter.

Distributions

     The following cash distributions per Trust Unit in respect of the quarters
indicated have been made to Unitholders since 2001:

                                       Cash Distributions
                          ----------------------------------------------
                               2003            2002            2001
                              -------        -------          ------
First Quarter                 $0.48          $0.43            $1.26
Second Quarter                 0.53            0.41            1.32
Third Quarter                  0.54            0.42            0.93
Fourth Quarter                 0.54            0.45            0.73
                              -------        -------          ------

Total Annual                  $2.09          $1.71           $4.24
                              =======        =======         =======

Product Marketing

     Petrofund markets its products to a diverse group of buyers with a variety
of contract terms and lengths as a way to help stabilize distributions and
mitigate the effect of price fluctuations. Forward selling instruments such as
swaps, collars, and floors are used for up to 50

                                       39
<PAGE>

percent of its production, with the remainder subject to market prices. This
marketing strategy is not intended to make money as a speculation on future
commodity prices. The goal of this hedging program is to improve financial
protection and help sustain cash flow should prices drop. During 2003, product
prices were impacted by commodity price fluctuations and the rising value of the
Canadian dollar. Crude oil prices were robust throughout 2003 with West Texas
Intermediate (WTI) averaging US$ 31.04/bbl in the fourth quarter, up US$
2.89/bbl from the same period in 2002. WTI for the year returned the highest
average annual price of US$ 31.04/bbl since 1982. So far in 2004, product prices
have exceeded those realized in the fourth quarter 2003 levels and are following
early 2003 levels in the mid-thirty dollar per barrel range.

     Market fundamentals remain strong as US commercial crude inventories
decreased in 2003 to 29-year lows, while the US remains committed to filling the
US Strategic Petroleum Reserve by 2005. Supply additions from OPEC and non-OPEC
were strong in 2003 but incremental demand from the US and China offset the new
supply. Petrofund expects supply growth from non-OPEC and Iraq arising late in
2004 will exceed demand although it should be noted that re-building crude
inventories takes several years to complete. Strong oil prices are also broadly
supported by long-term geopolitical risks that can affect supply and demand.

     Petrofund continues to believe that OPEC and other large crude suppliers
will manage supplies to meet demand and that the low inventory levels actually
provide a substantial cushion for any overproduction that might occur in the
short run.

     AECO spot natural gas prices were also at record high levels, ending the
year on a strong note closely following US natural gas prices. For the year,
AECO prices averaged $6.70/mcf, up 65 percent from 2002. AECO prices were
strongest early in the year but fourth quarter 2003 prices averaging $5.59/mcf
still exceeded fourth quarter 2002 levels by $.34/mcf, or 6.5 percent. December
2003 AECO gas prices were markedly higher than October and November, and natural
gas prices are tracking rising oil prices in the first quarter of 2004. Basis
differentials between AECO and the Henry Hub widened by $0.05/mcf, to
approximately $0.70/mcf over the year. This level is expected to remain constant
over 2004.

     Petrofund believes the fundamentals underpinning natural gas markets will
continue to support attractive price levels for the commodity in North America.
Gas-directed drilling recovered in 2003 as rig counts rose 34 percent in the US
year-over-year to 959 rigs. Canadian gas directed rig counts were only up 20
percent over the same period. The increased drilling will increase supplies
after the first quarter of 2004; however, growth in the US economy and natural
production declines are expected to absorb the new supply. Liquefied Natural Gas
(LNG) imports to the US increased by upwards of one bcf/d in 2003, but large
scale increases in imports with the potential to impact prices are not expected
until 2005-2007.

Credit Facility

     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 depends on PC's debt to cash flow
ratio and varies from prime to prime plus 75 basis points or, at the Trust's
option, bankers acceptance plus a stamping fee. Substantially all

                                       40
<PAGE>

of the credit facility is financed with banker's acceptances, resulting in an
average reduction in interest rates of 0.50% per annum.

     The limit of the syndicated facility is subject to adjustment from time to
time to reflect changes in PC's asset base. PC had long-term debt outstanding of
$110 million at December 31, 2003, compared to $212 million at the end of the
prior year.

     The revolving period on the syndicated facility ends on May 28, 2004,
unless extended for a further 364 day period. There are no principal repayments
required during the revolving period. PC may request the facility be extended no
earlier than 90 days and no later than 60 days prior to the end of the revolving
period at which time lenders may extend the facility for an additional one year
period. If the revolving period is not extended, the loan will convert to a one
year term with payments due in three consecutive quarterly amounts equal to
one-twentieth of the loan amount with an additional payment due on the last day
of the term period equal to the remaining balance outstanding. In the event that
the revolving period is not extended, the Trust will prepay the required
quarterly instalments into a reserve account.

     The credit facility is secured by a debenture in the amount of $350 million
under which a Canadian chartered bank, as principal and as agent for the other
lenders, received a first ranking security interest on all of PC's assets. The
loan is the legal obligation of PC. Unitholders have no direct liability to the
lenders or to PC should the assets securing the loan generate insufficient cash
flow to repay the obligation.

Outlook for Next Year

     The level of cash flow for 2004 will be affected by oil and gas prices, the
$US/$CAN 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 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

                                       41
<PAGE>

enters into fixed price transactions when commodity prices approach historic
highs. To date, the Trust has not entered into any currency related
transactions.


                         ENVIRONMENT, HEALTH AND SAFETY

     Petrofund recognizes that our efforts to protect the environment and the
health and safety of our workers and the public are essential to our continuing
success. The Environment, Health and Safety program is designed to meet four
objectives:

     o    Provide our workers with the tools and training needed to complete
          work assignments safely and effectively;
     o    Identify and manage environmental, health and safety risks as an
          integral part of every business activity;
     o    Monitor performance to ensure that Petrofund operations comply with
          our legal obligations and the standards we set for ourselves, and;
     o    Identify and manage environmental liabilities associated with our
          existing asset base and potential acquisitions.

     All employees of Petrofund are responsible and accountable for ensuring
that we manage environmental protection and health and safety responsibilities
properly. Senior Management ensures work places are healthy and safe and workers
know and understand Petrofund's environment, health and safety operating
standards and expectations. Supervisors ensure that activities at our workplaces
meet or exceed our standards and regulatory requirements. Each employee is
responsible for working safely, maintaining a healthy workplace and conducting
their activities with respect for other people and the environment.
Collectively, we strive to continually improve our performance and reduce the
potential risks of our operations to people and the environment.

Managing Liabilities


     Liability management is a cornerstone of Petrofund's environmental
protection and restoration activities. We closely monitor our site abandonment
and reclamation liabilities. We have taken steps to properly abandon well sites
and facilities and restore the land at locations that have reached the end of
their economic life. In 2003, Petrofund abandoned 70 wells and continued
restoration work at over 350 sites across Western Canada. By the end of 2003,
Petrofund successfully completed restoration work at over 80 sites and began the
process of submitting the necessary documentation to our regulators to obtain
reclamation certificates. In order to eliminate the environmental and financial
liabilities of non-producing assets, Petrofund actively manages its abandonment
and site restoration program. The goal is to minimize the cycle time between the
initial abandonment and the final restoration.

     Petrofund is also committed to fully assessing potential environmental
liabilities associated with wells and facilities that may be candidates for
acquisition. We review records held by governments and owners, and conduct
inspections of the assets to assure ourselves that we are aware of the
conditions at each site and the costs to restore these locations to meet
government imposed environmental standards. The objective is to provide a
realistic assessment

                                       42
<PAGE>

of the liabilities associated with potential asset acquisition candidates and
provide management with a factual basis to negotiate purchase terms and
conditions. In 2003, Petrofund conducted 2 major and 2 minor reviews of
potential acquisition opportunities as part of our due diligence process.

Stewardship

     In 2003, Petrofund initiated a formal third party environmental compliance
and best practices audit program to assure management and unitholders that our
field operations meet or exceed regulatory requirements and our internal
operating standards. We will conduct formal assessments of compliance with
regulations and operating standards at our major properties every three years.
Assessments were completed at 85 active sites in 13 producing fields in Alberta
this past year. Our insurer conducts a safety audit/risk survey of our
operations and a cross section of our field facilities each year. In 2003, seven
facilities in three fields in Alberta were included in the safety audit program.

     The results of these audits have confirmed that our facilities are operated
and maintained at or above industry standards and that our field staff are
knowledgeable and give workplace health and safety, and environmental protection
a high priority in their operations. The audit findings have been incorporated
into our on-going environment, health and safety program planning to better
manage potential risks to people and the environment.

     These external audits complement Petrofund's long standing site inspection
program where field operating staff formally inspect each producing well and
facility twice per year. These inspections not only identify real or potential
environmental and safety risks at each location but they also serve to remind
workers of the importance placed on these aspects of our business.

Corporate Citizenship

     In 2003, Petrofund embarked on major projects to identify the sources and
volumes of greenhouse gas emissions and other air contaminants from producing
facilities. These studies will be used to confirm compliance with provincial and
federal air quality guidelines, contaminant emission regulations, and possible
requirements to meet Canada's potential greenhouse gas emission reduction
commitments under the Kyoto protocol. These investigations will also assist us
in establishing priorities for planning upgrades to our facilities to improve
energy efficiency across operations.

     Petrofund continues to review environmental, health and safety programs and
commitments to ensure that we are positioned to address the increasing public
expectation of higher levels of performance. We understand and accept our
responsibility for developing and maintaining superior environment, health and
safety standards and performance levels to sustain public trust and the
confidence of regulators everywhere we operate.



                              CORPORATE GOVERNANCE

     The relationship between the Board and the management of Petrofund is
grounded in a mutual understanding of respective roles and the ability of the
Board to act independently while

                                       43

<PAGE>

fulfilling its responsibilities. Further, the Board's involvement in strategic
planning recognizes that the role of directors is not to manage but to guide
management. The board oversees and monitors systems for managing business risk
and regularly reviews strategic plans with management. Petrofund is in full
compliance with the corporate governance standards outlined by the TSX.

     Petrofund has actively sought men and women with a diversity of experience
and competencies to add value to boardroom deliberations. In 2003, the Board
increased in size by one directorship with a view to increase overall
effectiveness and improve decision making. In keeping with best practices, the
Board separated the role of Chairman and Chief Executive Officer in early 2003.
The Board acknowledges the critical role they must play in choosing the Chief
Executive Officer and in contributing to and continually assessing Petrofund's
strategic direction. All directors are elected by unitholders. Voting for
directors is conducted during Petrofund's annual general meeting.

     In addition to those matters which must be approved by the Board of
Directors by law, significant business activities and actions proposed to be
undertaken by Petrofund are subject to Board approval. The Board of Directors
approves appropriate corporate objectives and recommended courses of action
which have been brought forward by the Chief Executive Officer and management.

Independence of the Board

     The Board currently comprises seven members. Five of the seven are
unrelated directors within the context and meaning outlined within TSX
Guidelines. The responsibility for ensuring that individual directors are
unrelated rests with the Board of Directors. The Board will ensure that
Petrofund discloses on an annual basis the number of related and unrelated
directors.

     Petrofund has instituted a formal orientation program intended to further
assist new Board members in familiarizing themselves with Petrofund's field
operations, management, administration, policies and plans.

     All members of the Board of Directors, with the exception of Mr. Errico and
Mr. Driscoll, are unrelated. All Board committees consist entirely of unrelated
directors.

Committees

     The Board has four committees; the Governance Committee, the Human
Resources & Compensation Committee, the Reserves Audit Committee and the Audit
Committee. The committees have formal written mandates based on the council of
outside advisors and approved by the Board of Directors. These mandates reflect
current `best practices' concerning committee mandates. The committees review
these mandates and work processes at least annually; taking into account changes
in regulatory and other appropriate requirements or practices, and propose
changes as appropriate to the Board of Directors for its approval. All
committees have the right to retain independent advisors at the expense of
Petrofund.

                                       44
<PAGE>

Governance Committee


     The Governance Committee comprises Sandra S. Cowan (Chairman), Frank Potter
and Peter N. Thomson. The Committee has the responsibility of reviewing the
Board's size, composition and working processes and proposing changes to the
Board for its consideration. It has the responsibility for assessing the
performance of the Board, its committees, and individual directors. It
recommends to the Board at least annually and at such other times as it sees
fit, the composition of board committees and the chairmanship of such
committees. A component of the Committee's mandate is the responsibility for
considering and proposing nominations to the Board, should such nominations be
required. It reviews director compensation at least annually, and recommends
changes as it sees fit to the Board for its approval.

Human Resources and Compensation Committee

     The Human Resources and Compensation Committee comprises Frank Potter
(Chairman), Sandra S. Cowan and Wayne M. Newhouse. The Committee is responsible
to the Board for overseeing the development and administration of competitive
policies designed to attract, develop and retain employees of the highest
standards at all levels. It recommends to the Board appropriate policies dealing
with recruitment, compensation, benefits and training, and oversees the
administration of succession planning. It is responsible for recommending to the
Board the compensation arrangements for individual senior officers, in
consultation with the Chief Executive Officer.

Reserves Audit Committee


     The Reserves Audit Committee comprises Wayne M. Newhouse (Chairman), James
E. Allard and Peter N. Thomson. The Committee oversees the integrity of
Petrofund's reserve estimates. Contained within the Committee mandate is the
responsibility to ascertain those procedures and policies which minimize
environmental, occupational and safety risks to asset value thereby mitigating
any potential damage to or deterioration of asset value. It meets at least
annually, and such other times as it sees fit. It meets with Petrofund's
independent engineering consultants, and does so at least once per year. o Audit
Committee


     The Audit Committee comprises James E. Allard (Chairman), Frank Potter and
Peter N. Thomson. All listed committee members possess the requisite financial
skills necessary to qualify them as committee directors. Additionally, Mr.
Allard fulfills the requirement for financial sophistication, having served as
Chief Executive Officer and Chief Financial Officer for several private and
publicly traded companies throughout a lengthy career.


                                       45
<PAGE>

                               SHARE CAPITAL OF PC


     PC's authorized capital is comprised of an unlimited number of common
shares and an unlimited number of PC Exchangeable Shares.

Common Shares

     PC has authorized for issuance an unlimited number of common shares of
which, as at February 27, 2004, two common shares are issued and outstanding and
held by Computershare Trust Company of Canada, as trustee of the Trust. The
holders of common shares are entitled to notice of, to attend and to one vote
per share held at any meeting of the shareholders of PC (other than meetings of
a class or series of shares of PC other than the common shares as such). The
holders of common shares are entitled to receive dividends as and when declared
by the Board of Directors of PC on the common shares as a class, and subject to
prior satisfaction of all preferential rights to dividends attached to all
shares of other classes of shares of PC ranking in priority to the common shares
in respect of dividends, to share rateably, together with the shares of any
other class of shares of PC ranking equally with the common shares in respect of
dividends. The holders of common shares are entitled to in the event of any
liquidation, dissolution or winding up of PC, whether voluntary or involuntary,
or any other distribution of the assets of PC among its shareholders for the
purpose of winding up its affairs, and subject to prior satisfaction of all
preferential rights to return of capital on dissolution attached to all shares
of other classes of shares of PC ranking in priority to the common shares in
respect of return of capital on dissolution, to share rateably, together with
the shares of any other class of shares of PC ranking equally with the common
shares in respect of return of capital on dissolution, in such assets of PC as
are available for distribution.

Exchangeable Shares

     PC has authorized to issue an unlimited number of PC Exchangeable Shares,
of which, as at February 27, 2004, 851,471 PC Exchangeable Shares are issued and
outstanding. The PC Exchangeable Shares rank prior to the common shares of PC
and any other shares ranking junior to the PC Exchangeable Shares with respect
to the payment of dividends and the distribution of assets in the event of the
liquidation, dissolution or winding up of PC, whether voluntary or involuntary,
or any other distribution of the assets of PC among its shareholders for the
purpose of winding up its affairs. Provided that same is declared during the
Dividend Period, holders of PC Exchangeable Shares are entitled to receive, as
and when declared by the board of directors of PC in its sole discretion, from
time to time, non cumulative preferential cash dividends in an amount per share
equal to the amount of the Distribution relating to the subject Distribution
Payment Date multiplied by the Exchange Ratio as at the subject Distribution
Payment Date. It is not anticipated that dividends will be declared or paid on
the PC Exchangeable Shares; however, the board of directors of PC has the right
in its sole discretion to do so.

     PC will not, without obtaining the approval of the holders of the PC
Exchangeable Shares as set forth below:

pay any dividend on the common shares of PC or any other shares ranking junior
to the PC Exchangeable Shares, other than stock dividends payable in common
shares of PC or any such other shares ranking junior to the PC Exchangeable
Shares;

                                       46
<PAGE>

redeem, purchase or make any capital distribution in respect of the common share
of PC or any other shares ranking junior to the PC Exchangeable Shares;

redeem or purchase any other shares of PC ranking equally with the PC
Exchangeable Shares with respect to the payment of dividends or on any
liquidation distribution; or

issue any shares, other than PC Exchangeable Shares or common shares of PC,
which rank superior to the PC Exchangeable Shares with respect to the payment of
dividends or on any liquidation distribution.

     In the event that a dividend is not declared by PC prior to the expiry of a
Dividend Period, each holder of PC Exchangeable Shares shall have the right,
exercisable for a period of 5 business days from the date of expiry of the
subject Dividend Period, to redeem such number of PC Exchangeable Shares (the
"Cash Retracted Shares") as have a value (calculated as the amount equal to the
Exchange Ratio as at the date of delivery of the notice of the holder to retract
multiplied by the Current Market Price) equal to the aggregate amount of the
dividend which would have been paid to the holder had a dividend been declared
and paid in respect of the subject Dividend Period (the "Aggregate Dividend
Amount") for an amount in cash equal to the Aggregate Dividend Amount.

     A holder of PC Exchangeable Shares is entitled at any time to exchange each
PC Exchangeable Share into the number of Trust Units equal to the Exchange Ratio
then in effect.

     The PC Exchangeable Shares provide holders with a security having economic,
ownership and voting rights which are substantially equivalent to those of Trust
Units. The PC Exchangeable Shares are maintained economically equivalent to the
Trust Units by the progressive increase in the Exchange Ratio to reflect
distributions paid by the Trust to Unitholders. The PC Exchangeable Shares are
provided equivalent voting rights as unitholders through the PC Support Voting
and Exchange Agreement. Pursuant to the PC Support Voting and Exchange
Agreement, the Trust has issued a Special Voting Unit to Petro Assets, the
holder of the PC Exchangeable Shares. The Special Voting Unit entitles Petro
Assets to such number of votes, exercisable at any meeting at which unitholders
are entitled to vote, equal to the Aggregate Equivalent Vote Amount.

     At any time on or after April 29, 2010, or at any time on or after the date
when the aggregate number of issued and outstanding PC Exchangeable Shares is
less than 100,000, holders of PC Exchangeable Shares may be required by PC to
sell all of the then outstanding PC Exchangeable Shares in exchange for the
payment of either cash, PC Exchangeable Shares or that number of Trust Units
determined by multiplying the number of PC Exchangeable Shares by the Exchange
Ratio then in effect.

     The PC Exchangeable Shares are convertible, at the option of the holder
thereof, into common shares of PC, on a one for one basis (the "Conversion
Right"). Pursuant to the provisions of the Unanimous Shareholders Agreement,
Petro Assets has agreed never to exercise the Conversion Right in respect of any
PC Exchangeable Shares held thereby.

                                       47
<PAGE>

                      Management's Discussion and Analysis

     The Trust's Management's Discussion and Analysis, filed with the Trust's
audited consolidated financial statements for the year ended December 31, 2003,
is incorporated by reference herein.

                                  RISK FACTORS

     The following are certain risk factors relating to the business of the
Trust which prospective investors should carefully consider before deciding
whether to purchase Trust Units.


                                       48
<PAGE>



                             Industry-Related Risks

Oil and Natural Gas Prices

     The monthly cash distributions the Trust pays to Unitholders are highly
dependent on the prices received for PC's oil and natural gas production. Oil
and natural gas prices can fluctuate widely on a month-to-month basis in
response to a variety of factors that are beyond the control of the Trust and
PC. These factors include, among others:

     o    political conditions throughout the world;
     o    worldwide economic conditions;
     o    weather conditions;
     o    the supply and price of foreign oil and natural gas;
     o    the level of consumer demand;
     o    the price and availability of alternative fuels;
     o    the proximity to, and capacity of, transportation facilities;
     o    the effect of worldwide energy conservation measures; and
     o    government regulations.

     Declines in oil or natural gas prices will have an adverse effect on the
Trust's operations, financial condition, reserves and ultimately on its ability
to pay distributions to Unitholders.

     Oil prices were fairly strong throughout 2003 averaging US$31.04 WTI as
compared to and average of US$26.08 WTI in 2002. The only quarter in the last
two years that saw relatively low prices was the first quarter of 2002 when oil
prices averaged US$21.64 WTI.

     Monthly AECO prices averaged $6.71/mcf in 2003 as compared to $4.07/mcf in
2002, an increase of 65%. The AECO gas price was weak throughout the first nine
months of 2002 averaging $3.67/mcf; however, increased significantly to
$5.26/mcf in the fourth quarter. The monthly AECO price in 2003 ranged from a
high of $10.13/mcf in March to a low of $5.48/mcf in November.

Foreign Currency Exchange Rates and Interest Rates

     World oil prices are quoted in United States dollars and the price received
by Canadian producers is therefore affected by the $US/$CAN exchange rate that
may fluctuate over time. A material increase in the value of the Canadian
dollar, which occurred in 2003, negatively impacted PC's net production revenue
and may affect the future value of the Trust's reserves as determined by
independent evaluations at this time. The impact is reduced to the extent that
PC has engaged in, or in the future will engage in risk management activities
related to commodity prices and foreign exchange rates. PC will be subject to
unfavourable price changes and credit risks associated with the counterparties
with which it contracts. PC has not entered into any foreign exchange contracts
at this time.

     Variations in interest rates could result in a significant increase in the
amount the Trust pays to service debt which may result in a decrease in
distributions to Unitholders.

                                       49
<PAGE>

Operations

     PC's operations are subject to all of the risks normally associated with
drilling for and the production and transportation of oil and gas. Such risks
and hazards include encountering unexpected formations or pressures, blow-outs,
craterings and fires, all of which could result in personal injury, loss of
life, property damage and environmental damage. Although PC has safety and
environmental policies in place to protect operators and employees, as well as
to meet regulatory requirements, and although PC has liability insurance
policies in place, PC cannot fully insure against all such risks, nor are all
such risks insurable. PC may become liable for damages arising from such events
against which it cannot insure or against which we may elect not to insure
because of high premium costs or other reasons. Costs incurred to repair such
damage or pay such liabilities will reduce payments made by PC to the Trust.

Competition

     There is strong competition relating to all aspects of the oil and gas
industry. The Trust competes for capital, acquisitions of reserves, undeveloped
lands, skilled personnel, access to drilling rigs, service rigs and other
equipment, access to processing facilities, pipeline and refining capacity and
in many other respects with a substantial number of other organizations, many of
which may have greater technical and financial resources than the Trust. Some of
those organizations not only explore for, develop and produce oil and natural
gas but also carry on refining operations and market oil and other products on a
world wide basis and as such have greater and more diverse resources to draw on.

Environmental Concerns

     The oil and natural gas industry is subject to extensive environmental
regulation pursuant to local, provincial and federal legislation. A breach of
such legislation may result in the imposition of fines or issuance of clean up
orders. Such legislation may be changed to impose higher standards and
potentially more costly obligations. Although PC has established a reclamation
fund for the purpose of funding its estimated future environmental and
reclamation obligations based on its current knowledge, there can be no
assurance that PC will be able to satisfy its actual future environmental and
reclamation obligations.

     While PC has established a reserve for extraordinary and significant site
reclamation or abandonment costs, actual abandonment costs incurred in the
ordinary course of business during a specific period will reduce the amounts
available for distribution to Unitholders.

     Although PC maintains insurance coverage considered to be customary in the
industry, it is not fully insured against certain environmental risks, either
because such insurance is not available, or because of high premium costs. In
particular, insurance against risks from environmental pollution occurring over
time (compared to sudden and catastrophic damages) is not available.
Accordingly, PC's properties may be subject to liability due to hazards which
cannot be insured against, or have not been insured against due to prohibitive
premium costs or for other reasons. In such an event, these environmental
obligations will be funded out of PC's cash flow and could therefore reduce
distributable income payable to Unitholders.

                                       50
<PAGE>

                             Business-Related Risks

Reserves

     The value of the Trust Units will depend upon, among other things, the
reserves attributable to PC's properties. Estimating reserves is inherently
uncertain. Ultimately, actual production, revenues and expenditures for PC's
properties will vary from estimates and those variations could be material. The
reserve and cash flow information contained in this annual information form
represent estimates only. Reserves and estimated future net cash flow from PC's
properties have been independently evaluated at the dates indicated by
independent firms of oil and gas reservoir engineers. These firms consider a
number of factors and make assumptions when estimating reserves. These factors
and assumptions include, among others:

     o    historical production in the area compared with production rates from
          similar producing areas;

     o    the assumed effect of governmental regulation;

     o    assumptions about future commodity prices, production and development
          costs, severance and excise taxes, and capital expenditures;

     o    initial production rates;

     o    production decline rates;

     o    ultimate recovery of reserves;

     o    timing and amount of capital expenditures;

     o    marketability of production;

     o    future prices of oil and natural gas;

     o    operating costs and royalties; and

     o    other government levies that may be imposed over the producing life of
          reserves.

     These factors and assumptions were based on prices at the date the relevant
evaluations were prepared. If these factors and assumptions prove to be
inaccurate, the actual results may vary materially from the reserve estimates.
Many of these factors are subject to change and are beyond the Trust's control.
For example, evaluations are based in part on the assumed success of
exploitation activities intended to be undertaken in future years. Actual
reserves and estimated cash flows will be less than those contained in the
evaluations to the extent that such exploitation activities do not achieve the
level of success assumed in the evaluations. Furthermore, cash flows may differ
from those contained in the evaluations depending upon whether capital
expenditures and operating costs differ from those estimated in the evaluations.

Depletion of Reserves

     The Trust has certain unique attributes which differentiate it from other
oil and gas industry participants. Distributions by the Trust, absent commodity
price increases or cost effective acquisition and development activities, will
decline. The Trust will not be reinvesting cash flow in the same manner as other
industry participants. Accordingly, absent capital

                                       51
<PAGE>

injections and acquisition and development activities, the Trust's production
levels and reserves will decline.

     PC's reserves and production, and therefore its cash flows, will be highly
dependent upon its success in exploiting its reserve base and acquiring
additional reserves. Without reserve additions through acquisition or
development activities, PC's reserves and production will decline over time as
reserves are exploited.

     To the extent that external sources of capital, including the issuance of
additional Trust Units, become limited or unavailable, the Trust's ability to
make the necessary capital investments to maintain or expand reserves will be
impaired.

     Even if the Trust does obtain the necessary capital, there is no assurance
of success in developing or acquiring additional reserves on terms that meet the
Trust's investment objectives.

Marketability of Production

     The marketability of PC's production depends in part upon the availability,
proximity and capacity of gas gathering systems, pipelines and processing
facilities. Canadian federal and provincial, as well as U.S. federal and state,
regulation of oil and gas production and transportation, tax and energy
policies, general economic conditions, and changes in supply and demand all
could adversely affect PC's ability to produce and market oil and natural gas.
If market factors dramatically change, the financial impact on the Trust's
business could be substantial. The availability of markets is beyond PC's
control.

Assessments of Value of Acquisitions

     Acquisitions of resource issuers and resource assets will be based in large
part on engineering and economic assessments made by independent engineers.
These assessments will include a series of assumptions regarding such factors as
recoverability and marketability of oil and gas, future prices of oil and gas
and operating costs, future capital expenditures and royalties and other
government levies which will be imposed over the producing life of the reserves.
Many of these factors are subject to change and are beyond PC's control. In
particular, the prices of and markets for resource products may change from
those anticipated at the time of making such assessment. In addition, all such
assessments involve a measure of geologic and engineering uncertainty which
could result in lower production and reserves than anticipated. Initial
assessments of acquisitions may be based on reports by a firm of independent
engineers that are not the same as the firm that PC uses for its year end
reserve evaluations. Because each of these firms may have different evaluation
methods and approaches, these initial assessments may differ significantly from
the assessments of the firm used by PC. Any such instance may offset the return
on and value of the Trust Units.

Reliance on Third Party Operators

     Continuing production from a property and marketing of product produced
from the property are dependent to a large extent on the ability of the operator
of the property. PC currently operates properties that represent approximately
50% of its total daily production. To

                                       52
<PAGE>

the extent the operator fails to perform these functions properly or becomes
insolvent, revenue may be reduced.

Enforcement of Operating Agreements

     Operations of the wells on properties not operated by PC are generally
governed by operating agreements, which typically require the operator to
conduct operations in a good and workmanlike manner. Operating agreements
generally provide, however, that the operator will have no liability to the
other non-operating working interest owners for losses sustained or liabilities
incurred, except such as may result from gross negligence or wilful misconduct.
In addition, third-party operators are generally not fiduciaries with respect to
PC, the Trust or the Unitholders. PC, as owner of working interests in
properties not operated by it, will generally have a cause of action for damages
arising from a breach of such duty. Although not established by definitive legal
precedent, it is unlikely that the Trust or Unitholders would be entitled to
bring suit against third-party operators to enforce the terms of the operating
agreements; thus, Unitholders will be dependent on PC, as owner of the working
interest, to enforce such rights.

Borrowing

     PC has secured credit facilities with variable interest rates. Variations
in interest rates and scheduled principal repayments could result in significant
changes in the amount of PC's revenues required to be applied to its debt
service before payment of any amounts to the Trust. Certain covenants contained
in PC's agreements with its lenders may also limit the amounts paid to the Trust
and the distributions paid by the Trust to Unitholders.

     PC's lenders have been provided with security over substantially all of the
assets of PC. If PC becomes unable to pay its debt service charges or otherwise
commits an event of default, such as bankruptcy, these lenders may foreclose on
or sell PC's properties. The proceeds of any such sale would be applied to
satisfy amounts owed to PC's lenders and other creditors and only the remainder,
if any, would be available to the Trust.

     Although PC believes that the credit facilities are sufficient, there is no
assurance that the amounts available thereunder will be adequate for its future
obligations or that additional funds can be obtained. The syndicated facility is
available on a one year revolving basis. If the revolving period at which the
lenders may extend the facility is not renewed for an additional one year
period, the loan will convert to a one year term with payments due in three
consecutive quarterly amounts equal to one-twentieth of the loan amount with an
additional payment due on the last day of the term equal to the balance
outstanding. If this occurs, PC will have to arrange alternate financing. There
is no assurance that such financing will be available or be available on
favourable terms. Trust distributions may be materially reduced in these
circumstances and the failure to obtain suitable replacement financing may have
a material adverse effect on the Trust.

Delays in Distributions

     In addition to the usual delays in payment by purchasers of oil and natural
gas to the operators of PC's properties, and by those operators to PC, payments
between any of these parties may also be delayed by restrictions imposed by
lenders, delays in the sale or delivery of products, delays in the connection of
wells to a gathering system, blowouts or other accidents,

                                       53
<PAGE>

recovery by the operator of expenses incurred in the operation of the properties
or the establishment by the operator of reserves for such expenses. Any of these
delays could adversely affect Trust distributions.

Unforeseen Title Defects

     Although title reviews are conducted prior to any purchase of resource
issuers or resource assets, such reviews do not guarantee that an unforeseen
defect in the chain of title will not arise to defeat PC's title to certain
assets. A reduction of the distributable cash flow of the Trust and possible
reduction of capital could result from such defects.

Accounting Write-Downs as a Result of GAAP

     Canadian Generally Accepted Accounting Principles ("GAAP") requires that
management apply certain accounting policies and make certain estimates and
assumptions which affect reported amounts in the consolidated financial
statements of the trust. The accounting policies may result in non-cash charges
to net income and write-downs of net assets in the financial statements. Such
non-cash charges and write-downs may be viewed unfavourably by the market and
result in an inability to borrow funds and/or may result in a decline in the
trust unit price.

     Under GAAP, the net amounts at which petroleum and natural gas costs on a
property or project basis are carried are subject to a cost-recovery test which
is based in part upon estimated future net cash flow from reserves. If net
capitalized costs exceed the estimated recoverable amounts, PC will have to
charge the amounts of the excess to earnings. A decline in the net value of oil
and natural gas properties could cause capitalized costs to exceed the cost
ceiling, resulting in a charge against earnings.

     Emerging GAAP surrounding hedge accounting may result in non-cash charges
against net income as a result of changes in the fair market value of hedging
instruments. A decrease in the fair market value of the hedging instruments as
the result of fluctuations in commodity prices and foreign exchange rates may
result in a write-down of net assets and a non-cash charge against net income.
Such write-downs and non-cash charges may be temporary in nature if the fair
market value subsequently increases.

    Risks Related to the Securities Markets and the Ownership of Trust Units

Nature of Trust Units

     The Trust Units do not represent a traditional investment in the oil and
natural gas sector and should not be viewed by investors as shares in PC. The
Trust Units are also dissimilar to conventional debt instruments in that there
is no principal amount owing directly to Unitholders. The Trust Units represent
a fractional interest in the Trust. As holders of Trust Units, Unitholders do
not have the statutory rights normally associated with ownership of shares of a
corporation including, for example, the right to bring "oppression" or
"derivative" actions.

                                       54
<PAGE>

Trading Price of Trust Units

     The price per Trust Unit is a function of anticipated Trust Unit
distributions, the properties acquired by the Trust and its ability to effect
long-term growth in the value of the Trust. The market price of the Trust Units
will be sensitive to a variety of market conditions including, but not limited
to, interest rates and the ability of the Trust to acquire suitable oil and
natural gas properties. Changes in market conditions may adversely affect the
trading price of the Trust Units.

     Trust Units will have no value when reserves from the properties can no
longer be economically produced or marketed and, as a result, cash distributions
do not represent a "yield" in the traditional sense as they represent both
return of capital and return on investment. Investors in Trust Units will have
to obtain the return of capital invested out of cash flow derived from their
investments in the Trust Units during the period when reserves can be
economically recovered. Accordingly, there is no assurance that the
distributions Unitholders receive over the life of their investment will meet or
exceed their initial capital investment.

Reliance on Petrofund Corp. and Others

     Unitholders are entirely dependent on the management of PC with respect to
the acquisition of oil and gas properties and assets, the development and
acquisition of additional reserves, the management and administration of all
matters relating to properties and the administration of the Trust. The loss of
the services of key individuals who currently comprise the management team of PC
could have a detrimental effect on the Trust. PC currently operates properties
that represent approximately 50% of its total daily production. Investors who
are not willing to rely on the management of PC should not invest in the Trust
Units.

Unitholder Limited Liability

     Because of uncertainties in the law relating to investment trusts there is
a risk that a Unitholder could be held personally liable for obligations of the
Trust (to the extent that claims are not satisfied by the Trust) in respect of
contracts or undertakings which the Trust enters into and for certain
liabilities arising otherwise than out of contract including claims in tort,
claims for taxes and possibly certain other statutory liabilities. The Trust
Indenture requires that the operations of the Trust be conducted in such a way
as to minimize any such risk and, in particular, where feasible, every written
contract or commitment of the Trust must contain an express disavowal of
liability upon the Unitholders and a limitation of liability to Trust property.
Notwithstanding the terms of the Trust Indenture, Unitholders may not be
protected from liabilities of the Trust to the same extent as a shareholder is
protected from the liabilities of a corporation. It is unlikely, however, that
personal liability will attach in Canada to the holders of Trust Units for
claims arising out of any agreement or contract containing such a disavowal and
limitation of liability. It is also considered unlikely that personal liability
will attach in Canada to the holders of Trust Units for claims in tort, claims
for taxes and possibly certain other statutory liabilities. In the event that a
Unitholder is required to satisfy any obligation of the Trust, such Unitholder
will be entitled to reimbursement from any available assets in the Trust.

                                       55
<PAGE>

Retraction Right

     Cash payments for Trust Units surrendered for retraction are subject to
limitations and any notes issued in lieu of a cash payment will not be listed on
any stock exchange and no market is expected to develop for such notes.

Future Dilution

     An objective of the Trust is to continually add to its reserves through
acquisitions and through development, and because the Trust does not reinvest
its cash flow, the success of the Trust is in part dependent on its ability to
raise capital from time to time. Holders of Trust Units may also suffer dilution
in connection with future issuances of Trust Units, whether issued pursuant to a
financing or acquisition or otherwise.

Changes in Legislation

     There can be no assurance that income tax laws, other laws or government
incentive programs relating to the oil and gas industry, such as the status of
mutual fund trusts and resource allowance, will not be changed in a manner which
will adversely affect the Trust and Unitholders. There can be no assurance that
tax authorities having jurisdiction will agree with how the Trust calculates its
income for tax purposes or that such tax authorities will not change their
administrative practices to the detriment of the Trust or the Unitholders.

Changes in the Trust's Status under Tax Laws

     Legislative or regulatory changes remain an ongoing risk associated with
the trust units and there can be no assurance that the provisions of the Tax Act
relating to the qualification of the trust as a mutual fund trust will be
maintained in their current form or if changes are implemented how the new
provisions may affect the trust.

     Under the trust indenture of the Trust, PC may require declarations as to
the jurisdictions in which beneficial holders of trust units are resident. It
may also make a public announcement advising that it will not accept a
subscription for trust units from, or issue or register a transfer of trust
units to, a person unless the person provides a declaration that the person is a
not a non-resident of Canada. If, notwithstanding the foregoing, PC determines
that a majority of the trust units are held by non-residents, PC may send a
notice to non-resident holders of trust units, chosen in inverse order to the
order of acquisition or registration or in such other manner as PC may consider
equitable and practicable, requiring them to sell their trust units or a
specified portion thereof within a specified period of not less than 60 days. If
the unitholders receiving such notice have not sold the specified number of
trust units or provided PC with satisfactory evidence that they are not
non-residents within such period, PC may on behalf of such unitholders sell such
trust units and in the interim, may suspend the voting and distribution rights
attached to such trust units. Any such sale shall be made on any stock exchange
on which the trust units are listed and, upon such sale, the affected holders
shall cease to be holders of trust units and their rights shall be limited to
receiving the net proceeds of sale upon surrender of the certificates
representing such trust units.

                                       56
<PAGE>

     Should the status of the trust as a mutual fund trust be lost, certain
adverse consequences may arise. The material consequences of losing mutual fund
status are as follows: (1) trust units would not constitute qualified
investments for Exempt Plans upon the trust ceasing to be a mutual fund trust.
Where at the end of any month an Exempt Plan holds trust units that are not
qualified investments, the Exempt Plan must, in respect of that month, pay a tax
under Part XI.1 of the tax Act equal to 1% of the fair market value of the trust
units at the time such trust units were acquired by the Exempt Plan. An RRSP or
RRIF holding trust units that are not qualified investments would become taxable
on the income attributable to the trust units while they are not qualified
investments. RESPs which hold trust units that are not qualified investments may
have their registration revoked by the Canada Customs and Revenue Agency; (2)
the trust would be required to pay a tax under Part XII.2 of the Tax Act in
respect of amounts distributed to non-resident persons if it ceases to be a
mutual fund trust. The payment of Part XII.2 tax by the trust may have adverse
income tax consequences for certain unitholders, since the amount of cash
available for distribution would be reduced by the amount of the tax; (3) the
trust would cease being eligible for the capital gains refund mechanism
available under the tax Act upon ceasing to be a mutual fund trust; (4) units
held by unitholders that are not residents of Canada would become taxable
Canadian property upon the trust ceasing to be a mutual fund trust. Such holders
would be subject to Canadian income tax on any gains realized on a disposition
of units constituting taxable Canadian property; and (5) the trust would be
subject to alternative minimum tax under Part 1 of the Tax Act.

                         GOVERNANCE OF THE TRUST AND PC

Trust Indenture

General

     The Trust is an investment trust created pursuant to the Trust Indenture
and governed by the laws of the Province of Ontario. The Trust has been
established for the purpose of holding royalties granted by PC and acquiring,
directly and indirectly, securities and royalties of oil and gas companies, oil
and gas properties and other related assets.

     An unlimited number of Trust Units are issuable pursuant to the Trust
Indenture. As at December 31, 2003, 73.6 million Trust Units and Trust Units
issuable for PC Exchangeable Shares were issued and outstanding. Each Trust Unit
represents an equal undivided beneficial interest in the assets of the Trust.
Each outstanding Trust Unit is entitled to an equal share of distributions by
the Trust and, in the event of termination of the Trust, the net assets of the
Trust. All Trust Units rank equally. Each Trust Unit entitles the holder thereof
to one vote at all meetings of Unitholders.

     An unlimited number of Special Voting Units are also issuable pursuant to
the Trust Indenture. Special Voting Units may only be issued by the Trust in
conjunction with the issuance by the Corporation or an affiliate of exchangeable
shares. Each holder of a Special Voting Unit of record is entitled to vote at
all meetings of Unitholders. The maximum number of votes attached to each
Special Voting Unit shall be that number of Trust Units into which the
exchangeable shares issued in conjunction with the Special Voting Unit and at
that time outstanding are then exchangeable. The holders of Trust Units and the
holder of Special Voting

                                       57
<PAGE>

Units vote together as a single class on all matters. Special Voting Units have
the foregoing rights in respect of voting at all meetings of unitholders but
have no other rights and, for greater certainty, Special Voting Units do not
represent a beneficial interest in the Trust. In the event that exchangeable
shares issued in conjunction with a Special Voting Unit cease to be outstanding,
such Special Voting Unit shall be deemed to be cancelled.

     A Special Voting Unit was issued in connection with the Internalization
Transaction to Petro Assets, which company was issued PC Exchangeable Shares
pursuant to the Internalization Transaction.

Trustee

     The Trust Indenture provides that the Trustee is required to exercise its
powers and carry out its functions thereunder as trustee honestly, in good faith
and in the best interests of the Trust and the Unitholders and, in connection
therewith, will exercise that degree of care, diligence and skill that a
reasonably prudent trustee would exercise in comparable circumstances.

     The Trustee, where it has met its standard of care, will be indemnified out
of the assets of the Trust for any actions, suits or proceedings commenced
against the Trustee in respect of the Trust and for costs, taxes and other
liabilities incurred by the Trustee in respect of the administration or
termination of the Trust but will have no additional recourse against
Unitholders. In addition, the Trust Indenture contains other customary
provisions limiting the liability of the Trustee.

Issuance of Trust Units

     The Trust Indenture provides that Trust Units may be issued whether fully
paid or in the context of an offering, on an instalment basis, subject to the
approval of the PC Board of Directors, for the purposes of, among other things,
acquiring, or raising capital to acquire, net royalty interests, securities of
oil and gas companies and oil and gas properties and related assets. The Trust
Indenture also provides that the PC Board of Directors may also authorize the
creation and issuance from time to time of rights, warrants or options to
subscribe for Trust Units or other securities convertible or exchangeable into
Trust Units.

Distributions

     The Trust makes monthly cash distributions of the distributable cash flow
received by the Trust in each month. Distributions are made on the last business
day of each month to Unitholders of record as at the close of business on the
tenth business day preceding each such distribution date.

Retraction Right in Respect of Trust Units

     Trust Units are retractable at any time on demand by the holders thereof
upon delivery to the Trust of the certificate or certificates representing such
Trust Units, accompanied by a duly completed and properly executed notice
requesting retraction. Upon receipt of the retraction request by the Trust, all
rights to and under the Trust Units tendered for retraction shall be surrendered
and the holder thereof shall be entitled to receive a price per Trust Unit (the


                                       58
<PAGE>

"Retraction Price") equal to the lesser of: (i) 85% of the "market price" of the
Trust Units on the principal market on which the Trust Units are quoted for
trading during the 10 trading day period commencing immediately after the date
on which the Trust Units were surrendered for retraction (the "Retraction
Date"); and (ii) the "closing market price" on the principal market on which the
Trust Units are quoted for trading on the Retraction Date.

     The aggregate Retraction Price payable by the Trust in respect of any Trust
Units surrendered for retraction during any calendar month shall be satisfied by
way of a cash payment on the last day of the following month; provided that the
entitlement of Unitholders to receive cash upon the retraction of their Trust
Units is subject to the limitations that: (i) the total amount payable by the
Trust in respect of such Trust Units and all other Trust Units tendered for
retraction in the same calendar month shall not exceed $100,000 (provided that
such limitation may be waived in the discretion of the Trustee; (ii) at the time
such Trust Units are tendered for retraction the outstanding Trust Units shall
be listed for trading on a Canadian exchange or traded or quoted on any other
market which the Trustee considers, in its sole discretion, provides
representative fair market value prices for the Trust Units; and (iii) the
normal trading of Trust Units is not suspended or halted on any stock exchange
on which the Trust Units are listed (or, if not listed on a stock exchange, on
any market on which the Trust Units are quoted for trading) on the Retraction
Date or for more than five trading days during the 10 day trading period
commencing immediately after the Retraction Date.

     If a Unitholder is not entitled to receive cash upon the retraction of
Trust Units as a result of the foregoing limitations, then the Retraction Price
shall, subject to any applicable regulatory approvals, be paid and satisfied by
way of a distribution in specie of debt securities of PC then held by the Trust
(the "PC Notes") having a rate of interest which is no less than the highest
rate of interest charged by the Trust to PC. If the Trust does not hold PC Notes
having a sufficient principal amount outstanding to effect such payment, the
Trust will be entitled to create and, subject to any applicable regulatory
approvals, issue in satisfaction of the Retraction Price its own debt securities
(the "Trust Retraction Notes") having such terms and conditions as the Trustee
may determine and with recourse of the holder limited to the assets of the
Trust.

     The retraction right described above will not be the primary mechanism for
holders of Trust Units to dispose of their Trust Units. The PC Notes, Trust
Retraction Notes or other assets which may be distributed in specie to
Unitholders in connection with a retraction will not be listed on any stock
exchange and no market is expected to develop in such PC Notes or Trust
Retraction Notes.

Meetings of Unitholders

     The Trust Indenture provides that the following must be approved by Special
Resolution: (i) removing or appointing the Trustee (subject to exceptions such
as the Trustee failing to qualify to act as trustee and insolvency-related
events); (ii) amendments to the Trust Indenture (except as described under
"Governance of the Trust and PC - Trust Indenture - Amendments to the Trust
Indenture"); (iii) amendments to the Royalty Agreement; (iv) subdivisions or
consolidations of Trust Units; (v) the termination of the Trust; (vi) any matter
required to be approved by Special Resolution under the Royalty Agreement, (vii)
the sale of the property of the Trust as an entirety or substantially as an
entirety; (viii) directing the Trustee to exercise, or

                                       59
<PAGE>

refrain from exercising, any power under the Trust Indenture; (ix) directing the
Trustee with respect to legal proceedings in connection with the Trust; and (x)
approving the disposition of properties having a value in excess of 35% of the
asset value of the properties of the Trust.

     The Trust holds meetings of Unitholders on an annual basis for the purposes
of electing the directors of PC.

     A meeting of Unitholders may be convened at any time and for any purpose by
the Trustee and must be convened if requested by the holders of not less than
25% of the Trust Units then outstanding by a written requisition. A requisition
must specify the purpose for which the meeting is to be called.

Amendments to the Trust Indenture

     Except as specifically provided otherwise, the Trust Indenture may only be
amended by Special Resolution.

     The Trustee is entitled to make certain amendments to the Trust Indenture
without the approval of the Unitholders. These include amendments for the
purposes of ensuring compliance with applicable laws, ensuring the Trust
satisfies the requirements of the Tax Act to be a unit trust and mutual fund
trust, providing additional protection for Unitholders, removing conflicts or
inconsistencies (if such amendment is not detrimental to the interests of the
Unitholders) and correcting ambiguities or errors (provided the rights of the
Trustee and the Unitholders are not prejudiced thereby).

Limitation of Non-Resident Ownership

     Under the Trust Indenture, PC may require declarations as to the
jurisdictions in which beneficial holders of Trust Units are resident. It may
also make a public announcement advising that it will not accept a subscription
for Trust Units from, or issue or register a transfer of Trust Units to, a
person unless the person provides a declaration that the person is not a non
resident of Canada. If, notwithstanding the foregoing, PC determines that a
majority of the Trust Units are held by non residents, PC may send a notice to
non resident holders of Trust Units, chosen in inverse order to the order of
acquisition or registration or in such other manner as PC may consider equitable
and practicable, requiring them to sell their Trust Units or a specified portion
thereof within a specified period of not less than 60 days. If the Unitholders
receiving such notice have not sold the specified number of Trust Units or
provided PC with satisfactory evidence that they are non residents within such
period, PC may on behalf of such Unitholders sell such Trust Units and in the
interim, may suspend the voting and distribution rights attached to such Trust
Units. Any such sale shall be made on any stock exchange on which the Trust
Units are listed and, upon such sale, the affected holders shall cease to be
holders of Trust Units and their rights shall be limited to receiving the net
proceeds of sale upon surrender of the certificates representing such Trust
Units.

Termination of the Trust

     Unless the Trust is terminated earlier, the Trustee will commence to wind
up the affairs of the Trust on December 31, 2066. If, in the opinion of the
Board of Directors of PC, it would

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<PAGE>

be in the best interests of the Unitholders to wind up the Trust, the Trust will
be wound up. In addition, the Unitholders may, by Special Resolution, decide to
terminate the Trust. Upon a decision to terminate the Trust, the Trustee will
sell the assets of the Trust and distribute the net proceeds to Unitholders, or
wind up the Trust as otherwise directed by the Unitholders or the Board of
Directors.

Borrowing

     The Trust and PC may finance the acquisition of securities and royalties of
oil and gas companies, oil and gas properties and related assets and capital
expenditures in respect thereof through the issuance of equity or debt
securities.

     The Trust and PC are also permitted to borrow funds and to grant security
in respect of their assets, in priority to the royalty granted by PC, for the
purposes of financing the purchase of oil and gas properties and related assets,
capital expenditures in respect thereof or the purchase of securities and
royalties of oil and gas companies or to facilitate the repurchase of Trust
Units.

     The maximum amount which may be borrowed for such purposes shall not exceed
40% of the aggregate Asset Value of all properties and other resource assets
(including, where applicable, those being acquired) held by Petrofund, PC and
their subsidiaries and 40% of the net asset value of non-reserve based assets.
"Asset Value" is defined as the present worth of all of the estimated pre-tax
net cash flow from the proved reserves and 50% of the estimated pre-tax net cash
flow from the probable reserves shown in the most recent engineering report
relating thereto, discounted at an annual rate equal to the then current annual
yield of long term (10 year) Government of Canada bonds plus 400 basis points,
subject to a maximum rate of 10% and using escalating price and cost
assumptions.

     In calculating the 40% borrowing restriction, amounts borrowed by the Trust
or PC which the Trust or PC has the right to effectively repay or cause to be
repaid through the issuance of Trust Units will not form part of the 40%
borrowing restriction provided the Trust or PC, as applicable, has agreed to
cause payment of such indebtedness to be made through the issuance of Trust
Units prior to the maturity of such indebtedness to the extent necessary to
ensure that the aggregate borrowings of the Trust and PC do not then exceed the
40% borrowing restriction.

PC Unanimous Shareholder Agreement

     On the completion of the Internalization Transaction, the Unanimous
Shareholder Agreement was terminated. As a result of such termination the
Unitholders now have the right to designate all of the nominees to be elected to
the Board of Directors of PC.

     The Trust is to hold meetings on an annual basis for the purposes of
implementing the appointment of such directors.

     The Unanimous Shareholder Agreement provided for the establishment of the
Executive Committee of the Board of Directors of PC comprised of three members,
two of whom will be directors of PC nominated by Unitholders and one of whom
will be a director nominated by

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<PAGE>

NCEP Management. Any decision with respect to the following matters were to be
approved by the Board of Directors and the Executive Committee to be effective:

any acquisition or disposition of oil and gas properties or other assets by the
Trust or PC in excess of $10 million;

any borrowing of funds or granting of security in oil and gas properties or
other assets held by the Trust or PC; and

any related party transaction proposed to be entered into by the Trust or PC,
including any amendment to or other matter involving the Management Agreement.

     On the completion of the Internalization Transaction, the Executive
Committee was terminated and the above matters have to be approved by the board
of Directors.

Royalty Agreement

     Under the Royalty Agreement, PC grants net royalties to the Trust of 99% of
the revenue received in respect of each property held by PC net of certain
related costs and expenses.

     The net royalty consists of a 99% share of the royalty income from PC's
properties. Net royalty income is gross production revenue less the following
amounts:

          o    operating costs;
          o    debt service charges;
          o    general and administrative costs;
          o    management fees;
          o    taxes or other charges payable by PC; and
          o    amounts paid into the cash reserve established by PC to fund the
               payment of operating costs, capital expenditures, reclamation
               obligations, general and administrative costs, management fees
               and debt service charges.

     Gross production revenues essentially consist of cash proceeds from the
sale of oil, natural gas and other substances produced from PC's properties, any
drilling credits resulting from any expenditures made on the properties (other
than drilling credits applied to capital expenditures), amounts arising out of
"take or pay" contracts for oil, gas and other products and any other
consideration received by PC as a result of its ownership of the properties with
the exception of revenues from the rental, sale or exchange of tangible assets
and the proceeds from any unitization or pooling equalization payments relating
to tangible assets and excluding the proceeds from the sale of any properties.

     Operating costs are all expenditures from or allocated to a property made
in connection with the maintenance of a property or any activities related to
producing, gathering, treating, storing, compressing, processing and
transporting oil, gas and other substances including, without limitation,
overriding royalties and lessors' royalties.

     PC is required to pay the royalty on the last business day of each month.

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<PAGE>

     The properties in respect of which the Trust has net royalties may be
encumbered by security granted by PC to secure its loan obligations. The
obligations of PC to pay net royalties to the Trust are not secured. Borrowings
are subject to the 40% borrowing restriction referred to under "Governance of
the Trust and PC - Trust Indenture - Borrowing".

     The Royalty Agreement provides that the sale of a property and the royalty
thereto shall be approved by the PC Board of Directors, if the sale proceeds
exceed $10,000,000.

Management Agreement

     The Unitholders approved the Internalization Transaction at the annual and
special meeting held on April 16, 2003, and in connection with the
Internalization Transaction, PC acquired all of the shares of NCEP Management
and the external management contract of Petrofund as described below and all
related fees were eliminated.

     Pursuant to the Management Agreement, NCEP Management was compensated for
providing services to PC and Petrofund. As a result of the completion of the
Internalization Transaction, no fees were payable to the NCEP Management under
the Management Agreement in respect of the period commencing on January 1, 2003
to the closing date, April 29, 2003. The NCEP Management received a quarterly
fee paid on the last business day of each quarter of each year equal to 3.25%
(reduced from 3.75%, effective January 1, 2002) of the sum of net production
revenue less Crown royalties and other Crown charges attributable to PC's
properties for the applicable quarterly period. In addition the NCEP Management
received acquisition fees equal to 1.5% (reduced from 1.75%, effective January
1, 2002) of the purchase costs of all oil and gas properties, oil and gas
companies and other related assets acquired by PC, other than replacement
properties. In the event that PC properties were sold, NCEP Management also
received disposition fees of 1.25% (reduced from 1.5%, effective January 1,
2002) of the sale price of the properties sold.

     PC is entitled to a residual 1% interest in the properties. The management
fee and investment fee were paid in part, firstly, by applying any income
received by PC in respect of its residual interest in the properties and,
secondly, by applying any interest income of PC relating to the proceeds or
revenue from the properties.

     NCEP Management was also entitled to be reimbursed by PC for general and
administrative costs and by Petrofund for trust expenses. PC was not responsible
for the payment in any fiscal year of Petrofund of general and administrative
costs in excess of the greater of (a) 5% of the gross production revenue for
such fiscal year and (b) $240,000. To the extent that general and administrative
costs paid by PC for any fiscal year of Petrofund exceed such maximum amount, PC
was entitled to set off and deduct such excess amount from its liability to pay
management fees to NCEP Management.

                        UNITHOLDER PROTECTION RIGHTS PLAN

     The Trust has entered into an agreement with Computershare Trust Company of
Canada dated May 14, 1999 creating a unitholder protection rights plan (the
"Rights Plan"). The Rights Plan was approved by the Unitholders at a meeting
held on November 12, 1999.

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<PAGE>

     The Rights Plan utilizes the mechanism of the Permitted Bid (as hereinafter
described), to ensure that a person seeking control of the Trust gives the Trust
sufficient time in which to evaluate the bid, negotiate with the initial bidder
and encourage competing bids to emerge. The purpose of the Rights Plan is to
protect Unitholders by requiring all potential bidders to comply with the
conditions specified in the Permitted Bid provisions failing which such bidders
will become subject to the dilutive features of the Rights Plan.

     Generally, to qualify as a Permitted Bid, a bid must be made to all of the
Unitholders of the Trust and must be open for 60 days after the bid is made. If
more than 50% of the Units held by Independent Unitholders (being Unitholders
other than the bidder, its affiliates and persons acting jointly or in concert
with it) are deposited or tendered to the bid and not withdrawn, the bidder may
take up and pay for such Units. The take-over bid must then be extended for a
further period of 10 business days on the same terms to allow those Unitholders
who did not initially tender their Units to tender to the take-over bid if they
so choose. Thus, there is no coercion to tender during the initial 60-day period
because the bid must be open for acceptance for at least 10 days after the
expiry of the initial tender period.

     The term of the Rights Plan is May 14, 2004, which date is five years from
the date of the Rights Plan, May 14, 1999, at which time the right to exercise a
right will terminate, unless it is previously terminated in accordance with the
terms of the Rights Plan.

     On May 14, 1999, one right (a "Right") was issued for each Unit outstanding
which is, until the Separation Time (as defined below), evidenced by a legend
imprinted on a certificate for the Units. One Right will also attach to any
subsequently issued Units. The initial exercise price of the Rights is $60.00
per Unit (the "Exercise Price"), subject to appropriate anti-dilution
adjustments.

     The Rights will separate from the Units to which they are respectively
attached and will become exercisable at the time (the "Separation Time") which
is 10 days after the earlier of (i) the announcement that a person has become
the beneficial owner of 20% or more of the Units, other than by an acquisition
pursuant to a Permitted Bid, or (ii) the commencement or announcement date, or
such later date as may be determined by the directors of NCEP Management in
respect of a take-over bid to acquire 20% or more of the Units, other than by an
acquisition pursuant to a Permitted Bid. After the Separation Time and prior to
the occurrence of a Flip-in Event (as defined below), each Right will entitle
the holder thereof to purchase, upon payment of the Exercise Price, one Unit,
subject to anti-dilution adjustments.

     The acquisition by a person (an "Acquiring Person"), including others
acting in concert, of 20% or more of the Units, other than by way of a Permitted
Bid, is referred to as a "Flip-in Event". Any Rights held by an Acquiring Person
on or after the earlier of the Separation Time or the first date of public
announcement by the Trust or an Acquiring Person that an Acquiring Person has
become such, will become void upon the occurrence of a Flip-in Event. Ten
trading days after the occurrence of the Flip-in Event, the Rights (other than
those held by the Acquiring Person) will permit the holder to purchase, upon
payment of the Exercise Price of $60.00, Units with a total market value of
$120.00 (i.e., at a 50% discount).

                                       64
<PAGE>

     Until a Right is exercised, the holder of such Right, as such, will have no
rights as a Unitholder of the Trust.

                DISTRIBUTION REINVESTMENT AND UNIT PURCHASE PLAN

     The Trust has a distribution reinvestment and unit purchase plan (the
"Plan"). The Plan allows Unitholders resident in Canada to acquire additional
Trust Units by reinvesting their cash distributions or by making optional cash
payments. Only Unitholders who are resident in Canada and hold in excess of 100
Trust Units may participate in the Plan. The Plan is not available to
Unitholders who are residents of the United States or other foreign
jurisdictions.

     Under the Plan, Unitholders may direct the Trust to reinvest cash
distributions on the Trust Units to acquire, in the discretion of NCEP
Management, existing Trust Units through the facilities of the TSX or newly
issued Trust Units from treasury. In addition, Unitholders may purchase newly
issued Trust Units directly from the Trust by making cash payments to the Trust,
subject to a minimum of $100 and a maximum of $1,000 per calendar quarter.

     Cash distributions will be applied to the purchase of Trust Units on the
TSX at prevailing market prices for a period of 10 trading days following the
distribution date. The cost of such Trust Units to participants will be the
average cost of the Trust Units purchased. If insufficient Trust Units are
purchased during the said 10 trading day period, the uninvested portion will be
applied to purchase Trust Units from treasury.

     Optional cash payments will be applied to the purchase of newly-issued
Trust Units on the cash distribution date following receipt.

     In 2003, the Trust issued 316,785 Trust Units under the Plan.


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<PAGE>



                             DIRECTORS AND OFFICERS

Information concerning the directors and officers of PC as of the date hereof is
set out below:

<TABLE>
<CAPTION>
Name and Municipality of Residence            Position                      Director Since
----------------------------------            --------                      --------------
<S>                                         <C>                            <C>
John F. Driscoll                              Chairman and Director         July 15, 1988
Toronto, Ontario
Jeffery E. Errico                             President, Chief Executive    April 16, 2003
Calgary, Alberta                              Officer and Director
Glen C. Fischer                               Senior Vice-President,
Calgary, Alberta                              Operations
Vince P. Moyer                                Senior Vice-President,
Calgary, Alberta                              Finance and Chief Financial
                                              Officer
Jeffrey D. Newcommon                          Executive Vice President
Calgary, Alberta
Noel Cronin                                   Vice-President, Production
Calgary, Alberta
James E. Allard(1)(4)                         Director                      April 16, 2003
Calgary, Alberta
Sandra S. Cowan(2)(3)                         Director                      January 17, 2002
Toronto, Ontario
Wayne M. Newhouse(3)(4)                       Director                      April 16, 2003
Calgary, Alberta
Frank Potter(1)(2)(3)                         Director                      November 1, 2000
Toronto, Ontario
Peter N. Thomson(1)(2)(4)                     Director                      November 1, 2000
Nassau, Bahamas
</TABLE>

Notes:

(3)  Member of the Audit Committee.
(4)  Member of the Governance Committee.
(5)  Member of the Human Resources and Compensation Committee.
(6)  Member of the Reserves Audit Committee.

     Set forth below are the particulars of the principal occupations of each
director and officer of PC for the past several years.

     John F. Driscoll is the Chairman, President, Chief Executive Officer and a
director of Sentry Select Capital Corp. He also founded and has been Chairman of
NCE Resources group since 1984 and Chairman of Petrofund since 1988. He has also
been Chairman of Inter Pipeline Fund and strategic Energy Fund since October
2002 and May 2002 respectively. He specializes in closed-end funds and mutual
funds and related advisory, management and consulting services. Mr. Driscoll
received his Bachelor of Science degree from the Boston College Business School
in 1964 and in 1967 attended the New York Institute of Finance. During the last
20 years, issuers of which Mr. Driscoll was responsible as an officer and/or
director or in respect of which he was an officer and/or director of their
managers have raised gross proceeds of approximately $4.0

                                       66
<PAGE>

billion. Mr. Driscoll also founded and has been President, since 1981, of J.F.
Driscoll Investment Corp., a company specializing in investment management.

     Jeffery E. Errico is a Professional Engineer who received a Bachelor of
Science degree in Chemical Engineering from the University of British Columbia
in 1973. He has over 20 years experience in the oil and gas industry, serving as
Vice-President, Operations of Deminex Canada Limited prior to joining NCE
Resources Group in April, 1995.

     Glen C. Fischer is a Professional Engineer who received a Degree in
Mechanical Engineering from the University of Calgary. He has over 20 years of
engineering and management experience in the oil and gas industry and from 1984
to 1996 was Manager, Engineering & Operations for ATCOR Ltd. and its successor
Canadian Forest Oil Ltd. Mr. Fischer joined the NCE Resources Group in July,
1996.

     Vince P. Moyer received his Chartered Accountant's designation in 1975 and
a Master of Business Administration degree in 1972 from the University of
Manitoba, majoring in finance. From 1981 to 1991 he held various positions with
Enron Oil Canada Ltd., including most recently as Vice-President, Finance and
Administration from 1986 to 1991. Mr. Moyer joined the NCE Resources Group in
June, 1991.

     Jeffrey D. Newcommon received his Bachelor of Arts degree in Finance and
Economics from the University of Western Ontario in 1983. From 1984 to 1995 he
held various positions with Canadian Hunter Exploration Ltd., including, most
recently, Land Manager. He joined the NCE Resources Group in April, 1995.

     Noel Cronin is a Professional Engineer with over 20 years of diversified
experience in the petroleum industry in western Canada, including reservoir
management/exploitation, economic evaluations, joint interests and production
operations. He has worked for various Calgary-based oil and gas producers during
his career and joined the NCE Resources Group as Production Manager in 1997.

     James E. Allard has focused his career in international finance and the
petroleum industry for the past 40 years serving as CEO, CFO and director of a
number of publicly traded and private companies during that period. During the
past five years he has continued to serve on the board of the Alberta Securities
Commission, act as the sole external trustee and advisor to a mid-sized pension
plan and serve as a director and advisor to several companies. From 1981 to
1995, he served as a senior executive officer of Amoco Corporation as well as a
director of Amoco Canada, then Canada's largest natural gas producer.

     Sandra S. Cowan is Partner and General Counsel of EdgeStone Capital
Partners, an independent private equity firm managing over $1 billion of private
capital. Prior to joining EdgeStone in 2001, Ms. Cowan practiced law for over 15
years, most recently as a senior partner of Goodman and Carr LLP. Her practice
specialized in private equity and corporate finance transactions, including fund
formation, mergers, acquisitions and divestitures, cross-border and public
market transaction. Ms. Cowan has an LLB from the University of Western Ontario
and serves on a number of private and public boards.

                                       67
<PAGE>

     Wayne M. Newhouse is a Professional Engineer and Oil and Gas Executive with
over 40 years of broad industry experience. Since 1995 Mr. Newhouse has served
as President of Newhouse Resources Management Ltd. and subsequently Morgas Ltd.,
both private oil and gas production companies, as well as being a director of
several publicly traded companies. From 1989 to 1994, Mr. Newhouse served as
Senior Vice President, Production and Senior Vice President, Exploration and
International Development with Norcen Energy Resources Ltd.

     Frank Potter has been the Chairman since 1995 of Emerging Markets Advisors,
Inc., a Toronto-based consultancy that assists corporations in making and
managing direct investments internationally. Prior thereto, Mr. Potter was
executive director of The World Bank Group in Washington, and was subsequently
senior advisor at the federal Department of Finance. Mr. Potter is a director of
a number of public and private corporations and public service organizations.

     Peter Nesbitt Thomson has been the Chairman of the Board of the West Indies
Power Corporation Limited for over 10 years. He attended Lower Canada College
and Sir George Williams College. He received an honorary Doctorate of Laws
Degree from St. Thomas University, Fredericton, New Brunswick. Beginning his
professional career in Montreal with investment dealer Nesbitt Thomson, he later
was Chairman, President and Chief Executive Officer of Power Corporation of
Canada. He has served as a director of numerous Canadian companies, including
Petrofina Canada Limited and Norcen Energy Resources Ltd.

Ownership of Trust Units by Directors and Officers

     As at December 31, 2003, the directors and executive officers of PC
beneficially owned, directly or indirectly, 596,166 Trust Units representing
less than 1% of the issued and outstanding Trust Units and 851,471 PC
Exchangeable Shares representing 100% of the issued and outstanding PC
Exchangeable Shares.

                               ESCROWED SECURITIES

     There are 85,244 Trust Units in escrow which were issued to executive
management in connection with the internalization of management. They are
released evenly each quarter to March 31, 2008. The escrow agent is Goodman and
Carr LLP.

                              MARKET FOR SECURITIES

     The Trust Units are listed and posted for trading on the TSX under the
symbol "PTF.UN" and the American Stock Exchange under the symbol "PTF".

                              CONFLICTS OF INTEREST

     Many of the directors and officers of PC are directors and officers of
other entities which may be in competition to the interests of PC and the Trust.
In the ordinary course of business, these other entities may acquire properties
or explore other business opportunities that may be suitable for Petrofund. No
assurances can be given that opportunities identified by such board members will
be provided to PC and the Trust.

                                       68

                             ADDITIONAL INFORMATION

     Additional financial information is available on Sedar at www.sedar.com and
on the Trust's website at www.petrofund.ca.

     The Trust will provide to any person, upon request to PC:

when the securities of the Trust are in the course of a distribution pursuant to
a short form prospectus or a preliminary short form prospectus has been filed in
respect of a distribution of its securities,

one copy of the annual information form of the Trust, together with one copy of
any document, or the pertinent pages of any document, incorporated by reference
therein,

one copy of the comparative financial statements of the Trust for its most
recently completed financial year together with the accompanying report of the
auditor and one copy of any interim financial statements of the Trust subsequent
to the financial statements for its most recently completed financial year,

one copy of the information circular of the Trust in respect of its most recent
annual meeting of Unitholders that involved the election of directors or one
copy of any annual filing prepared in lieu of that information circular, as
appropriate, and

one copy of any other documents that are incorporated by reference into the
preliminary short form prospectus or the short form prospectus and are not
required to be provided under (i) to (iii) above; or

at any other time, one copy of any other documents referred to in (a)(i), (ii)
and (iii) above, provided the Trust may require the payment of a reasonable
charge if the request is made by a person who is not a security holder of the
Trust.

     Additional information including directors' and officers' remuneration and
indebtedness, principal holders of the issuer's securities, options to purchase
securities and interests of insiders in material transactions, if applicable, is
contained in the issuer's information circular for its most recent annual
meeting of Unitholders that involved the election of directors, and additional
financial information is provided in the issuer's comparative financial
statements for its most recently completed financial year.

     For additional copies of this annual information form please contact:

         Petrofund Corp.
         444 - 7th Avenue, S.W.
         Suite 600
         Calgary, Alberta
         T2P 0X8

         Attention:  Investor Relations


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