As
      filed with the
      Securities and Exchange Commission on October 31, 2005.





**SECURITIES
        AND EXCHANGE COMMISSION**
 WASHINGTON,
        D.C.
        20549
  **FORM
        20-F/A**
    ̈ REGISTRATION
        STATEMENT PURSUANT TO SECTION 12(b) or (g)
 OF
        THE SECURITIES
        EXCHANGE ACT OF 1934; or
  **x** ANNUAL REPORT
        PURSUANT TO SECTION 13 OR 15(d) OF
 THE
        SECURITIES
        EXCHANGE ACT OF 1934
 For
        the fiscal year
        ended December 31, 2001
   ̈ TRANSITION REPORT
        PURSUANT TO SECTION 13 OR 15(d) OF
 THE
        SECURITIES
        EXCHANGE ACT OF 1934
 For
        the transition
        period ___________ to ___________
  Commission
        File No.
        001-15196
  **PROVIDENT
        ENERGY TRUST**
 (Exact
        name of
        registrant as specified in its charter)
  **Not
        applicable.**
 (Translation
        of
        Registrant’s name into English)
  **Alberta,
        Canada**
 (Jurisdiction
        of
        Incorporation or organization)
  **Suite
        700,
        112 - 4** **th** **Avenue
        S.W.**
 **Calgary,
        Alberta T2P 0H3**
 **(403)
        296-2233**
 (Address,
        including
        zip code and telephone number, including area code, or registrant’s principal
        executive offices)
  Securities
        registered or to be registered pursuant to Section 12(b) of the
        Act:
 Trust
        Units
  Securities
        registered or to be registered pursuant to Section 12(g) of the Act:
 None
 
 Securities
        for
        which there is a reporting obligation pursuant to Section 15(d) of
        the
        Act:
 None
  As
        of December 31,
        2004, the registrant had 142,226,248 Trust
        Units outstanding.
  Indicate
        by check
        mark whether the registrant: (1) has filed all reports required to be filed
        by
        Section 13 or 15(d) of the Securities Exchange Act of 1934 during
        the
        preceding 12 months (or for such shorter period that the registrant was required
        to file such reports), and (2) has been subject to such filing requirements
        for
        the past 90 days.
 Yes **x** No  ̈
  Indicate
        by check
        mark which financial statement item the registrant has elected to
        follow:
 Item
        17 **x** Item 18  ̈
  
 **EXPLANATORY
          NOTE**
  Provident
          Energy
          Trust hereby amends its Annual Report on Form 20-F for the fiscal year
          ended
          December 31, 2001 as follows. Part I is amended by deleting each of its
          Items in
          their entirety and replacing them with the Items set forth in this amendment.
          Items in the original filing, as previously amended, not expressly changed
          by
          this amendment shall be as set forth in the original filing. This Form
          20-F/A
          does not reflect events occurring after the filing of the original filing
          or
          modify or update disclosures, including the exhibits to the original filing,
          affected by subsequent events.
  **DEFINITIONS**
  **“ABCA”** means the *Business
          Corporations Act* (Alberta, Canada),
          S.A. 1981, c. B-15, as amended, including the regulations promulgated
          thereunder;
  **“Acquired
          Properties”** means the oil and
          gas properties located in southeast Alberta, Canada acquired by the Trust
          effective May 1, 2002 from Devon and Devon ARL pursuant to an agreement
          of
          purchase and sale dated March 25, 2002;
  **“Acquired
          Properties Purchase Agreement”** means the
          agreement dated March 25, 2002 between Provident, Devon and Devon
          ARL;
  **“Acquisition
          Notes”** means the
          unsecured, subordinated, demand notes issued by Provident under the Maxx
          Arrangement and issued pursuant to the Maxx Note Indenture;
  **“AECO”** means Alberta
          Energy Company;
  **“Affiliate”** or **“Associate”** when used to
          indicate a relationship with a person or company, means the same as set
          forth in
          the *Securities
          Act* (Alberta);
  **“AMEX”** means the American
          Stock Exchange;
  **“ARTC”** means credits or
          rebates in respect of Crown royalties which are paid or credited by the
          Crown,
          including those paid or credited under the *Alberta
          Corporate Tax Act* which are commonly
          known as “Alberta Royalty Tax Credits”;
  **“Citicorp”** means Citicorp
          Capital Investors Ltd., a corporation formed under the federal laws of
          Canada;
  **“Coast
          Pacific”** means Coast
          Pacific RLP-97 Exploration Inc.;
  **“Court”** means the Court of
          Queen’s Bench of Alberta;
  **“crude
          oil”** or **“oil”** means a mixture,
          consisting mainly of pentanes and heavier hydrocarbons that may contain
          sulfur
          compounds, that is liquid at the conditions under which its volume is measured
          or estimated, but excluding such liquids obtained from the processing of
          natural
          gas;
  **“Debenture”** means the
          $15,000,000 7.5% subordinated secured convertible redeemable debenture
          due
          June 2004 issued by Founders to Citicorp which was converted and
          redeemed
          as part of the Founders Arrangement;
  **“Devon”** means Devon
          Canada;
  ii
  **“Devon
          ARL”** means Devon ARL
          Corporation;
  **“Distributable
          Cash”** means all amounts
          distributed or to be distributed during any applicable period to Trust
          Unitholders;
  **“Distribution
          Record Date”** means the last day
          of each calendar month or such other date as may be determined from time
          to time
          by the Trustee, except that December 31 shall in all cases be a
          Distribution Record Date;
  **“Founders”** means Founders
          Energy Ltd., a predecessor of Provident;
  **“Founders
          Amalgamation”** means the
          amalgamation of Founders and Provident pursuant to the Founders
          Arrangement;
  **“Founders
          Arrangement”** means the
          arrangement effective March 6, 2001 under Section 186 of
          the ABCA
          involving, among other things, the exchange of Founders Shares for the
          Initial
          Notes, the exchange of the Initial Notes for Trust Units and the Founders
          Amalgamation;
  **“Founders
          Note Indenture”** means the note
          indenture providing for the issuance of the Initial Notes and made between
          Provident and Montreal Trust Company of Canada, as trustee;
  **“Founders
          Shares”** means the common
          shares in the capital of Founders;
  **“Initial
          Notes”** means the
          unsecured, $14.70 subordinated notes issued by Provident under the Founders
          Arrangement and issued pursuant to the Founders Note Indenture;
  **“Initial
          Royalty”** means the royalty,
          commencing January 1, 2002, entitling the Trust to 13.5% of Provident’s
          working interest in Petroleum Substances within, upon or under the oil
          and gas
          properties of Provident as at March 6, 2001 to the extent such Petroleum
          Substances are produced and saved (including Petroleum Substances allocated
          to
          such properties in accordance with any pooling or unitization
          scheme);
  **“Internal
          Rate of Return”** means the discount
          rate (expressed as an annual percentage rate, and adjusted appropriately
          should
          the Return Period be less than a full calendar year, based on monthly
          compounding) which equates the distributions in respect of a Trust Unit
          during a
          Return Period and the Unit Market Price at the end of a Return Period with
          the
          Unit Market Price at the beginning of such Return Period, taking into account
          the dates on which distributions were made;
  **“Management
          Agreement”** means the
          management agreement dated as of March 6, 2001 among Provident,
          ManagementCo and the Trustee on behalf of the Trust;
  **“ManagementCo”** or the **“Manager”** means
          Provident
          Management Corporation, a corporation incorporated under the ABCA;
  **“Market
          Capitalization”** means an amount
          equal to the weighted average number of Trust Units outstanding for the
          Return
          Period times the Unit Market Price at the beginning of the Return
          Period;
  **“Maxx”** means Maxx
          Petroleum Ltd.;
  **“Maxx
          Amalgamation”** means the
          amalgamation of Maxx and Provident pursuant to the Maxx
          Arrangement;
  iii
  **“Maxx
          Arrangement”** means the
          arrangement under Section 186 of the ABCA involving, among other
          things,
          the exchange of Maxx Shares for Acquisition Notes, the exchange of such
          Acquisition Notes for cash and/or Trust Units and the Maxx
          Amalgamation;
  **“Maxx
          Arrangement Agreement”** means the
          agreement dated March 26, 2001 between Maxx, Provident and the Trust
          pursuant to which such parties have implemented the Maxx
          Arrangement;
  **“Maxx
          Note
          Indenture”** means the note
          indenture providing for the issuance of the Acquisition Notes and made
          between
          Provident and Montreal Trust Company of Canada, as trustee;
  **“Maxx
          Shares”** means the common
          shares in the capital of Maxx;
  **“McDaniel”** means McDaniel
& Associates Consultants Ltd., independent oil and gas reservoir engineers
          of Calgary, Alberta;
  **“McDaniel
          Acquired Properties Report”** means the
          independent engineering evaluation of the Acquired Properties prepared
          by
          McDaniel dated March 21, 2002 effective January 1, 2002;
  **“McDaniel
          Report”** means the
          independent engineering evaluations of Provident’s oil, NGL and natural gas
          interests prepared by McDaniel dated February 15, 2002 and
          February 28, 2002 both effective January 1, 2002;
  **“McDaniel
          Richland Report”** means the
          independent engineering evaluation of Richland’s oil, NGL and natural gas
          interests prepared by McDaniel effective January 1, 2002;
  **“natural
          gas”** means the lighter
          hydrocarbons and associated non-hydrocarbon substances occurring naturally
          in an
          underground reservoir, which under atmospheric conditions is essentially
          gas,
          but which may contain liquids. The natural gas reserve estimates are reported
          on
          a marketable basis, that is the gas which is available to a transmission
          line
          after removal of certain hydrocarbons and non-hydrocarbon compounds present
          in
          the raw natural gas and which meets specifications for use as a domestic,
          commercial or industrial fuel;
  **“natural
          gas liquids”** or **“NGLs”** means those
          hydrocarbon components recovered from raw natural gas as liquids by processing
          through extraction plants or recovered from field separators, scrubbers
          or other
          gathering facilities. These liquids include the hydrocarbon components
          ethane,
          propane, butanes and pentanes plus, or a combination thereof;
  **“Non-Resident”** means a
          non-resident of Canada within the meaning of the Tax Act;
  **“Note
          Trustee”** means Montreal
          Trust Company of Canada, or its successor as trustee under the Founders
          Note
          Indenture and the Maxx Note Indenture, as the case may be;
  **“Operating
          Cash Flow”** means in respect
          of any period for which Operating Cash Flow is calculated: (i) the amount
          received or receivable by Provident, (on a consolidated basis), in respect
          of
          its interest in the sale of all Petroleum Substances collected from its
          oil and
          gas properties and any oil and gas revenue received in such period including
          any
          commodity hedging gains and ARTC but not including proceeds of the sale
          of its
          oil and gas properties; less (ii) expenditures paid or payable by or on
          behalf
          of Provident, (on a consolidated basis), in respect of operating its oil
          and gas
          properties including, without limitation, the costs of gathering, compressing,
          processing, transporting and marketing all Petroleum Substances produced
          therefrom, commodity hedging losses and all other amounts paid to third
          parties
          which are calculated with reference to production from Provident’s oil and gas
          properties including, without limitation, crown royalties, gross overriding
          royalties and lessors’ royalties, but for certainty not including the Initial
          Royalty or the Subsequent Royalty;
  iv
  **“Permitted
          Investments”** means: (i)
          obligations issued or guaranteed by the government of Canada or any province
          of
          Canada or any agency or instrumentality thereof; (ii) term deposits, guaranteed
          investment certificates, certificates of deposit or bankers’ acceptances of or
          guaranteed by any Canadian chartered bank or other financial institutions
          (including the Trustee and any affiliate of the Trustee) the short-term
          debt or
          deposits of which have been rated at least A or the equivalent by
          Standard & Poor’s Corporation, Moody’s Investors Service, Inc.,
          Canadian Bond Rating Service Inc. or Dominion Bond Rating Service Limited;
          and
          (iii) commercial paper rated at least A or the equivalent by Canadian Bond
          Rating Service Inc. or Dominion Bond Rating Service Limited, in each case
          maturing within 180 days after the date of acquisition;
  **“Petroleum
          Substances”** means petroleum,
          natural gas and related hydrocarbons (except coal) including, without
          limitation, all liquid hydrocarbons, and all other substances, including
          sulfur,
          whether gaseous, liquid or solid and whether hydrocarbon or not, produced
          in
          association with such petroleum, natural gas or related
          hydrocarbons;
  **“PFIC”** means a passive
          foreign investment company;
  “ **Pro
          Rata
          Share**”
          of any particular
          amount in respect of a holder of a Trust Unit at any time shall be the
          product
          obtained by multiplying the number of Trust Units that are owned by that
          Trust
          Unitholder at that time by the quotient obtained when the particular amount
          is
          divided by the total number of all Trust Units that are issued and outstanding
          at that time;
  **“Provident”** or
          the **“Corporation”** means Provident
          Energy Ltd., the corporation resulting from the Founders Amalgamation and
          which
          is wholly-owned by the Trust;
  **“Provident
          Royalties”** means the Initial
          Royalty and the Subsequent Royalty, collectively;
  **“Provident
          Shares”** means the common
          shares in the capital of Provident;
  **“Provident
          Special Resolution”** means a resolution
          proposed to be passed as a special resolution at a meeting of Trust Unitholders
          (including an adjourned meeting) duly convened for the purpose and held
          in
          accordance with the provisions of the Trust Indenture at which two or more
          holders of at least 5% of the aggregate number of Trust Units then outstanding
          are present in person or by proxy and passed by the affirmative votes of
          the
          holders of not less than 66 2/3% of the Trust Units represented at the
          meeting
          and voted on a poll upon such resolution;
  **“Qualification
          Rights Agreement”** means the
          qualification rights agreement dated as of January 25, 2001 between
          Citicorp and Provident;
  **“Return
          Period”** means the period
          for which the fee under the Management Agreement is being calculated; which
          period shall be a calendar year, except for the first year of the term
          in which
          case the Return Period shall commence on March 6, 2001 and terminate
          on
          December 31, 2001 and except for any year in which the Management
          Agreement
          is terminated, in which case the return period shall commence at the start
          of
          such year and end on the date of such termination;
  **“Richland”** means Richland
          Petroleum Corporation;
  v
  **“Richland
          Amalgamation”** means the
          amalgamation of Richland and Provident pursuant to the Richland
          Arrangement;
  **“Richland
          Arrangement”** means the
          arrangement under Section 186 of the ABCA involving, among other
          things,
          the exchange of Richland Shares for Richland Notes, the exchange of such
          Richland Notes for Trust Units and the Richland Amalgamation;
  **“Richland
          Arrangement Agreement”** means the
          agreement dated December 14, 2001 between Richland, Provident and
          the Trust
          pursuant to which such parties have implemented the Richland
          Arrangement;
  **“Richland
          Note Indenture”** means the note
          indenture providing for the issuance of the Richland Notes and made between
          Provident and Computershare Trust Company of Canada, as trustee;
  **“Richland
          Notes”** means the
          unsecured, subordinated, demand notes issued by Provident under the plan
          of
          arrangement involving the Trust, Provident and Richland effective
          January 16, 2002 and issued pursuant to the Richland Note
          Indenture;
  **“Richland
          Shares”** means the common
          shares in the capital of Richland;
  **“Seaton
          Jordan”** means Seaton
          Jordan & Associates Ltd., independent land appraisers of Calgary,
          Alberta;
  **“Seaton
          Jordan Report”** means the
          independent valuation of Provident’s undeveloped land as prepared by Seaton
          Jordan dated April 5, 2002 and effective December 31,
          2001;
  **“Special
          Voting Units”** means a special
          voting unit of Provident Energy Trust, which shall be entitled to such
          number of
          votes at meetings of Trust Unitholders equal to such number of votes and
          any
          other rights or limitations to be prescribed by the board of directors
          of
          Provident in the resolution issuing any such Special Voting Units;
  **“Sproule”** means Sproule
          Associates Limited, independent oil and gas reservoir engineers of Calgary,
          Alberta;
  **“Sproule
          Report”** means the
          independent engineering evaluations of Founders’ oil, NGL and natural gas
          interest prepared by Sproule dated January 12, 2001 and January 17,
          2001 both effective January 1, 2001;
  **“Subsequent
          Investment”** means those
          investments which the Trust is permitted to make pursuant to
          Sections 4.1(c) and (d) of the Trust Indenture, namely royalties
          in respect
          of Provident’s oil and gas properties and securities of Provident or any other
          subsidiary of the Trust to fund the acquisition, development, exploitation
          and
          disposition of all types of petroleum and natural gas and energy related
          assets,
          including without limitation, facilities of any kind, oil sands interests,
          electricity or power generating assets, and pipeline, gathering, processing
          and
          transportation assets and whether effected through an acquisition of assets
          or
          an acquisition of shares or other form of ownership interest in any entity
          the
          substantial majority of the assets of which are comprised of like
          assets;
  **“Subsequent
          Royalty”** means the royalty,
          commencing May 1, 2001, entitling the Trust to approximately 99%
          of the net
          cash flow generated from the present and future oil and gas interest and
          related
          tangibles owned by Provident (including the properties subject to the Initial
          Royalty) after certain costs, expenditures and deductions;
  vi
  **“Subsidiary”** means, when used
          to indicate a relationship with another body corporate:
  (a)  body
          corporate
          which is controlled by (i) that other, or (ii) that other and one or more
          bodies
          corporate, each of which is controlled by that other, or (iii) two or more
          bodies corporate each of which is controlled by that other, or
  (b)  a
          subsidiary of a
          body corporate that is the other’s subsidiary; and in the case of the Trust,
          includes Provident;
  **“Tax
          Act”** means the *Income
          Tax
          Act* (Canada), R.S.C.
          1985, c.1, 5th Supplement, as amended;
  **“Tax
          Regulations”** means the
          regulations enacted under the Tax Act;
  **“Terraquest”** means 961982
          Alberta Ltd.;
  **“Terraquest
          Assets”** means those assets
          of Richland sold to Terraquest;
  **“Terraquest
          Shares”** means common
          shares of Terraquest;
  **“Total
          Return Amount”** means in respect
          of any Return Period an amount equal to the Total Return Percentage minus
          8.0%
          if the Return Period is a full calendar year and adjusted appropriately
          should
          the Return Period be less than a full calendar year, multiplied by the
          Market
          Capitalization for that Return Period;
  **“Total
          Return Percentage”** means the Internal
          Rate of Return to a holder of a Trust Unit for a particular Return Period.
          For
          the purposes of the Total Return Percentage in the 2001 calendar year the
          Unit
          Market Price at the beginning of the Return Period shall be deemed to be
          $9.90
          per Trust Unit;
  **“Trust”** means Provident
          Energy Trust, a trust settled pursuant to the laws of Alberta;
  **“Trust
          Indenture”** means the amended
          and restated trust indenture dated as of January 25, 2001, as
          amended from
          time to time, between
          Computershare Trust Company of Canada and Founders;
  **“Trust
          Unit”** or **“Unit”** means a unit of
          the Trust, each unit representing an equal undivided beneficial interest
          therein;
  **“Trust
          Unitholders,”**  **“Provident
          Unitholders”** or **“Unitholders”** means the holders
          from time to time of the Trust Units;
  **“Trust
          Unitholder Rights Plan”** or **“Unitholder
          Rights Plan”** means the trust
          unitholders rights plan adopted by the Trust pursuant to a trust unitholder
          rights plan agreement dated March 6, 2001 between the Trust and
          Computershare Trust Company of Canada;
  **“Trustee”** means
          Computershare Trust Company of Canada, the initial trustee of the Trust,
          or such
          other trustee, from time to time, of Provident Energy Trust;
  **“TSX”** means the Toronto
          Stock Exchange;
  **“Unanimous
          Shareholders Agreement”** means the
          unanimous shareholders agreement entered into as of March 6, 2001
          between
          Provident and the Trustee, as trustee for and on behalf of Provident Energy
          Trust;
  vii
  **“Unit
          Market Price”** of the Trust Units
          at any date means the weighted average of the trading price per Trust Unit
          for
          such Trust Units for the ten (10) consecutive trading days immediately
          preceding
          such date and the ten (10) consecutive trading days from and including
          such
          date, on the TSX or, if on such date the Trust Units are not listed on
          the TSX,
          on the principal stock exchange upon which such Trust Units are listed,
          or, if
          such Trust Units are not listed on any stock exchange then on such
          over-the-counter market as may be selected for such purposes by the board
          of
          directors of Provident;
  **“Unitholder
          Rights Plan Agreement”** means the
          agreement dated March 6, 2001 between the Trust and Montreal Trust
          Company
          of Canada pursuant to which the Trust adopted the Trust Unitholder Rights
          Plan;
          and
  **“U.S.
          person”** has the meaning
          ascribed to it in Rule 902 (k) of the U.S. Securities Act of 1933.
  **IN
          THIS
          FORM 20-F, UNLESS OTHERWISE SPECIFIED, FINANCIAL INFORMATION IS EXPRESSED
          IN
          CANADIAN DOLLARS.**
  **ABBREVIATIONS,
          TERMS AND CONVERSIONS**
  **Oil
                    and Natural Gas Liquids**
                **Natural
                    Gas**Bbls
                Barrels
                Mcf
                thousand
                    cubic feetMbbls
                Thousand
                    barrels
                Mmcf
                million
                    cubic
                    feetBOPD
                Barrels
                    of
                    oil per day
                Bcf
                billion
                    cubic
                    feetBbls/d
                Barrels
                    of
                    oil per day
                Mcf/d
                thousand
                    cubic feet per dayMmbbls
                Million
                    barrels
                Mmcf/d
                million
                    cubic
                    feet per dayNGLs
                Natural
                    gas
                    liquids
                m3
                cubic
                    metresSTB
                Stock
                    tank
                    barrel of oil
                MMBTU
                million
                    British Thermal UnitsMstb
                Thousand
                    stock tank barrels of oil
                GJ
                gigajouleBOE/d
                Barrels
                    of
                    oil equivalent per day
                GJ/d
                gigajoule
                    per
                    dayBpd
                Barrels
                    of
                    production per day
 
 **Other**BOE
                means
                    barrel
                    of oil equivalent, using the conversion factor of 6:1 Mcf of
                    natural gas
                    being equivalent to one Bbl of oil, unless otherwise specified.
                    The
                    conversion factor used to convert natural gas to oil equivalent
                    is not
                    necessarily based upon either energy or price equivalents at
                    this
                    time.MBOE
                means
                    thousand barrels of oil equivalent.MMBOE
                means
                    million
                    barrels of oil equivalent.WTI
                means
                    West
                    Texas Intermediate.API
                means
                    the
                    measure of the density or gravity of liquid petroleum products
                    derived
                    from a specific gravity.OPEC
                means
                    Organization of the Petroleum Exporting Countries.
 
  viii
  **CONVERSION**
  The
          following table
          sets forth some conversions between Standard Imperial Units and the
          International System of Units (or metric units).
  **To
                    Convert From**
                **To**
                **Multiply
                    By**Mcf
                cubic
                    metres
                28.174cubic
                    metres
                cubic
                    feet
                35.494Bbls
                cubic
                    metres
                0.159cubic
                    metres
                Bbls
                6.289Feet
                Metres
                0.305Metres
                Feet
                3.281Miles
                Kilometres
                1.609Kilometres
                Miles
                0.621Acres
                Hectares
                0.405Hectares
                Acres
                2.471Gigajoules
                Mmbtu
                0.950
  For
          the purposes of
          this Form 20-F, unless otherwise specifically stated, all conversions
          of
          natural gas (Mcf) to barrels of oil equivalent (BOE) are on the basis of
          6:1 Mcf
          to 1 BOE.
 ix


**FORWARD-LOOKING
      STATEMENTS**




Some
      statements
      contained in this Form 20-F are “forward looking statements” and are
      prospective. These forward looking statements are subject to risks,
      uncertainties and other factors, some of which are beyond the Trust’s control,
      including: impact of general economic conditions in Canada; industry conditions,
      including fluctuations in the price of oil and natural gas, royalties payable
      in
      respect of the Trust’s oil and gas production, and governmental regulation of
      the oil and gas industry, including environmental regulation; the Trust’s
      ability to integrate successfully the businesses it has acquired and will
      acquire in the future; fluctuations in foreign exchange or interest rates;
      stock
      market volatility and market valuations; and the need to obtain required
      approvals from regulatory authorities; and the risk factors discussed below
      under “Key Information - Risk Factors.” The Trust’s actual results, performance
      or achievement could differ materially from those expressed in, or implied
      by,
      these forward looking statements and accordingly, no assurance can be given
      that
      any of the events anticipated by the forward looking statements will transpire
      or occur, or if any of them do so, what benefits, including the amount of
      proceeds, the Trust will derive from them. Neither the Trust nor Provident
      undertakes any obligations to publicly revise these forward-looking statements
      to reflect subsequent events or circumstances.




x


**PART
        I**
  **Item
        1.**  **Identity
        of
        Directors, Senior Management and Advisors**
  Not
        applicable.
   **Item
                  2.**
              **Offer
                  Statistics and Expected
                  Timetable**
  Not
        applicable.
   **Item
                  3.**
              **Key
                  Information**
  **A.**
              **Selected
                  Historical Financial Data**
  The
        following table
        sets forth historic information with respect to the Trust and Founders for
        the
        periods indicated. Founders is the Predecessor to the Trust.
  The
        consolidated
        financial statements of the Trust and Founders are prepared in accordance
        with
        Canadian GAAP, which differs in certain respects from U.S. GAAP (“US GAAP”). For
        a description of the material differences between Canadian GAAP and US GAAP
        in
        regard to the consolidated financial statements of the Trust and Founders,
        see
        Note 14 to the consolidated financial statements of the Trust. The
        historical results below are not necessarily indicative of the results to
        be
        expected for any future period.
  (stated
                  in
                  Cdn $000s, except per unit and per share data)**The
                  Trust(1)**
              
              **Founders
                  (1)****Amounts
                  in accordance with Canadian GAAP**
              
              
              **For
                  the period March 6, 2001 to December 31, 2001**
              
              
              **For
                  the year**
                **ended
                  December 31, 2000**
              
              
              **For
                  the year**
                **ended
                  December 31, 1999**
              
              **For
                  the year**
                **ended
                  December**
                **31,
                  1998**Gross
                  production revenue
              
              $
              78,311
              
              $
              49,226
              
              $
              30,805
              
              $14,496Net
                  earnings
                  (loss)
              
              $
              (46,855
              )
              $
              6,597
              
              $
              (3,654
              )
              $625Per
                  trust
                  unit or common share(2)
              
              $
              (3.39
              )
              $
              0.44
              
              $
              (0.25
              )
              $0.07Per
                  fully
                  diluted trust unit or common share(2)
              
              $
              (3.39
              )
              $
              0.34
              
              $
              (0.25
              )
              $0.07**Amounts
                  in accordance with US GAAP**
                Net
                  earnings
                  (loss)
              
              $
              (57,598
              )
              $
              6,133
              
              $
              (3,287
              )
              $(11,256)Per
                  Unit
              
              $
              (4.17
              )
              
              n/a
              
              
              n/a
              
              n/aPer
                  common
                  share (2)
              
              
              n/a
              
              $
              0.41
              
              $
              (0.23
              )
              $(1.32)Per
                  fully
                  diluted Unit
              
              $
              (4.17
              )
              
              n/a
              
              
              n/a
              
              n/aPer
                  fully
                  diluted common share (2)
              
              $
              n/a
              
              $
              0.40
              
              $
              (0.23
              )
              $(1.32)
  
  (1)
              The
                  Trust
                  commenced operations on March 6, 2001, when Founders converted
                  from an
                  exploration and production company into a cash-distributing energy
                  trust.
                  Founders is the Predecessor to the Trust. For further details on
                  this
                  conversion and its impact on the financial statement presentation
                  in this
                  Form 20-F, see “Operating and Financial Review and
                  Prospects.”
   (2)
              The
                  Founders
                  per common share numbers have been restated to reflect the impact
                  of the
                  one for four share consolidation on January 27,
                  2000.
   
  **Selected
        Balance Sheet Information**
 
 **The
                  Trust**
              **Founders**(stated
                  in
                  Cdn $000s)
              
              **As
                  of
                  December 31,****2001**
              **As
                  of
                  December 31,****2000**
              **As
                  of
                  December 31,****1999**
              **As
                  of
                  December 31,****1998****Canadian**
                **GAAP**
              
              
              **US****GAAP**
              
              
              **Canadian**
                **GAAP**
              
              
              **US****GAAP**
              
              
              **Canadian**
                **GAAP**
              
              
              **US****GAAP**
              
              
              **Canadian**
                **GAAP**
              
              
              **US****GAAP**Assets
                Property,
                  plant and equipment
              
              $
              171,808
              
              $
              146,072
              
              $
              88,803
              
              $
              88,204
              
              $
              72,711
              
              $
              71,932
              
              $
              93,413
              
              $
              86,763Deferred
                  charges
              
              $
              —
              
              $
              —
              
              $
              1,195
              
              $
              495
              
              $
              640
              
              $
              640
              
              $
              —
              
              $
              —Liabilities
                  and Unitholders/ Shareholders’ EquityFuture
                  income
                  taxes
              
              $
              23,252
              
              $
              11,752
              
              $
              16,641
              
              $
              16,293
              
              $
              2,662
              
              $
              10,899
              
              $
              2,526
              
              $
              7,742Demand
                  loan
              
              $
              —
              
              $
              35,600
              
              $
              —
              
              $
              26,100
              
              $
              —
              
              $
              35,640
              
              $
              —
              
              $
              45,000Long
                  term
                  debt
              
              $
              35,600
              
              $
              —
              
              $
              26,100
              
              $
              —
              
              $
              35,640
              
              $
              —
              
              $
              45,000
              
              $
              —Subordinated
                  convertible debenture (1)
              
              $
              —
              
              $
              —
              
              **$**
              14,187
              
              $
              15,000
              
              **$**
              13,949
              
              **$**
              15,000
              
              $
              —
              
              $
              —Equity
                  component - subordinated convertible debenture(1)
              
              $
              —
              
              $
              —
              
              $
              1,190
              
              $
              —
              
              $
              1,190
              
              $
              —
              
              $
              —
              
              $
              —Capital
                  contributions
              
              $
              187,331
              
              $
              191,314
              
              $
              —
              
              $
              —
              
              $
              —
              
              $
              —
              
              $
              —
              
              $
              —Share
                  capital
              
              $
              —
              
              $
              —
              
              $
              29,318
              
              $
              32,257
              
              $
              29,224
              
              $
              32,163
              
              $
              28,538
              
              $
              28,859Net
                  Assets
              
              $
              104,455
              
              $
              93,490
              
              $
              28,665
              
              $
              27,203
              
              $
              30,740
              
              $
              20,976
              
              $
              32,519
              
              $
              20,175Distributions
              
              $
              36,880
              
              $
              36,880
              
              $
              —
              
              $
              —
              
              $
              —
              
              $
              —
              
              $
              —
              
              $
              —Units/shares
                outstanding
              
              
              21,022,321
              
              
              21,022,321
              
              
              15,100,652
              
              
              15,100,652
              
              
              15,047,909
              
              
              15,047,909
              
              
              13,582,020
              
              
              13,582,020Accumulated
                  (loss)
              
              $
              (45,996
              )
              $
              (60,944
              )
              $
              —
              
              $
              —
              
              $
              —
              
              $
              —
              
              $
              —
              
              $
              —(Deficit)
                  retained earnings
              
              $
              —
              
              $
              —
              
              $
              (1,843
              )
              $
              (5,054
              )
              $
              327
              
              $
              (11,187
              )
              $
              3,981
              
              $
              (8,684
              )
 
 (1)
        2000 and 1999
        include a convertible debenture carried at $14,186 (1999 - $13,948). As part
        of
        the Founders Agreement, Citicorp agreed to the early conversion and redemption
        of the Debenture.
  **I.**  **Exchange
        Rate of Canadian and U.S. Dollars**
  On
        June 26, 2002, the exchange rate for one Canadian dollar expressed
        in U.S.
        dollars based on the noon buying rate of the Federal Reserve Bank of New
        York
        was 0.6574.
  For
        each period,
        the following table provides the high and low exchange rates for one Canadian
        dollar expressed in U.S. dollars, and the average of these exchange rates
        on the
        last day of each month during the period, based upon the noon buying rate
        in New
        York City for cable transfers in Canadian dollars, as certified for customer
        purposes by the Federal Reserve Bank of New York:
  **Year
                  ended December 31,****May**
                **2002**
              **April**
                **2002**
              **Mar.**
                **2002**
              **Feb.**
                **2002**
              **Jan.**
                **2002**
              **Dec.**
                **2001**
              **2001**
              **2000**
              **1999**
              **1998**
              **1997**High
              0.6367
              0.6252
              0.6269
              0.6207
              0.6199
              0.6267
              0.6279
              0.6512
              0.6535
              0.6341
              0.7235Low
              0.6547
              0.6397
              0.6342
              0.6295
              0.6290
              0.6397
              0.6667
              0.6894
              0.6925
              0.7105
              0.7487Average
              0.6453
              0.6324
              0.6301
              0.6266
              0.6249
              0.6339
              0.6446
              0.6724
              0.6744
              0.6748
              0.7333
 
 On
        June 26, 2002, the exchange rate for one U.S. dollar expressed in
        Canadian
        dollars based on the noon spot rate of the Bank of Canada was
        1.5211.
  For
        each period,
        the following table provides the high and low exchange rates for one U.S.
        dollar
        expressed in Canadian dollars, and the average of these exchange rates on
        the
        last day of each month during the period, based upon the noon spot rate of
        the
        Bank of Canada:
  **Year
                  ended December 31,****May**
                **2002**
              **April**
                **2002**
              **Mar.**
                **2002**
              **Feb.**
                **2002**
              **Jan.**
                **2002**
              **Dec.**
                **2001**
              **2001**
              **2000**
              **1999**
              **1998**
              **1997**High
              1.5705
              1.5994
              1.5952
              1.6110
              1.6132
              1.5956
              1.5926
              1.5356
              1.5298
              1.5765
              1.4392Low
              1.5275
              1.5632
              1.5767
              1.5885
              1.5897
              1.5633
              1.5000
              1.4488
              1.4433
              1.4075
              1.3353Average
              1.5497
              1.5814
              1.5870
              1.5958
              1.6003
              1.5775
              1.5513
              1.4868
              1.4826
              1.4836
              1.3849
  2
  In
        this Form 20-F, unless otherwise specified, all monetary amounts are expressed
        in Canadian dollars.
  **B.**
              **Capitalization
                  and Indebtedness**
  Not
        applicable.
  **C.**
              **Reasons
                  for the Offer and Use of
                  Proceeds**
  Not
        applicable.
  **D.**
              **Risk
                  Factors**
  The
        Trust Units do
        not represent a traditional investment in the oil and natural gas industry.
        Prospective purchasers of the Trust Units should carefully consider the
        information set forth below and the other information set forth herein before
        deciding to invest in the Trust Units.
  The
        Trust is a
        limited purpose trust which will be entirely dependent upon the operations
        and
        assets of Provident through its ownership directly and indirectly, of the
        Provident Shares, the Initial Notes, the Acquisition Notes, the Richland
        Notes
        and other notes that the Trust may issue from time to time, the Initial Royalty
        and the Subsequent Royalty. Accordingly, the Trust is dependent upon the
        ability
        of Provident to meet its interest and principal repayment obligations under
        the
        Initial Notes and its principal repayment obligations under the Acquisition
        Notes, the Richland Notes and other notes that the Trust may issue from time
        to
        time, and to pay the Initial Royalty and the Subsequent Royalty. Provident’s
        income will be received from the production of oil and natural gas from
        Provident’s existing Canadian resource properties and will be susceptible to the
        risks and uncertainties associated with the oil and natural gas industry
        generally. If the oil and natural gas reserves associated with Provident’s
        Canadian resource properties are not supplemented through additional development
        or the acquisition of additional oil and natural gas properties, the ability
        of
        Provident to meet its obligations to the Trust may be adversely affected.
        Unitholders should consider carefully the information contained in this annual
        report and, in particular, the following risk factors:
  ***Risks
        Related to Provident’s Operations***
  **Provident’s
        exploitation and development activities depend on imperfect scientific
        methods.**
  Exploitation
        and
        development risks are due to the uncertain results of searching for and
        producing oil and natural gas using imperfect scientific methods. Provident’s
        exploitation and development activities expose it to inherent drilling risks,
        including the risk that it will not find any economically productive oil
        or
        natural gas reservoirs. The costs of drilling, completing and operating wells
        are often uncertain, and numerous factors beyond Provident’s control may cause
        drilling operations to be curtailed, delayed or canceled. In addition,
        Provident’s future drilling, exploitation and development activities may not be
        successful. If these activities were unsuccessful, this would have an adverse
        effect on Provident’s future operating results and financial condition, and
        could reduce or eliminate the amount of income available for distribution
        to
        Trust Unitholders.
  **Provident’s
        development and drilling activities are subject to operational risks and
        hazards.**
  Provident’s
        operations will be subject to all of the risks normally incident to the
        operation and development of oil and natural gas properties and the drilling
        of
        oil and natural gas wells, including encountering unexpected formations or
        pressures, blowouts, craterings and fires, all of which could result in personal
        injuries, loss of life and damage to property of Provident and others. Provident
        is not fully insured against all of these risks, nor are all of these risks
        insurable. The nature of these risks is such that liabilities could exceed
        the
        policy limits of Provident’s liability insurance. In this event, significant
        costs could be incurred that could have an adverse effect upon Provident’s
        financial condition, and which could reduce or eliminate the amount of income
        available for distribution to Trust Unitholders.
  3
  **Provident’s
        production may be affected by the ability of property
        operators.**
  Continuing
        production from a property, and to some extent the marketing of production
        therefrom, are largely dependent upon the ability of the operator of the
        property. To the extent the operator fails to perform its functions properly,
        revenue may be reduced. Payments from production generally flow through the
        operator and there is a risk of delay and additional expense in receiving
        such
        revenues if the operator becomes insolvent.
  **A
        defect in
        the chain of title may result in a reduction in Provident’s
        income.**
  Title
        reviews are
        generally conducted in accordance with industry standards; however, such
        reviews
        do not guarantee or certify that a defect in the chain of title may not arise
        to
        defeat the claim of Provident to certain of its oil and gas properties. A
        reduction of the income from the Provident Royalties could result in
        such circumstances.
  **Volatility
        of oil and natural gas prices could adversely affect Provident’s operating
        results and financial condition.**
  Provident’s
        financial condition, operating results and future growth are dependent on
        the
        prevailing prices for oil and natural gas. Historically, the markets for
        oil and
        natural gas have been volatile and those markets are likely to continue to
        be
        volatile in the future. Prices for oil and natural gas are subject to large
        fluctuations in response to a variety of factors beyond Provident’s control.
        Such fluctuations will have a positive or negative effect on Provident’s
        revenue. Such fluctuations will also have an effect on the acquisition costs
        of
        any future oil and natural gas properties that Provident may acquire. Cash
        distributions from the Trust will be highly sensitive to the prevailing prices
        of oil and natural gas. Any substantial decline in the prices of oil and
        natural
        gas may have a material adverse effect on Provident’s operating results and
        financial condition, and may reduce or eliminate the amount of income available
        for distribution to Trust Unitholders.
  **Fluctuations
        in the marketability of oil and natural gas may adversely affect Provident’s
        operating results and financial condition.**
  The
        marketability
        and price of oil and natural gas that may be acquired or discovered by Provident
        will be affected by numerous factors beyond Provident’s control. These factors
        include demand for oil and natural gas, market fluctuations, the proximity
        and
        capacity of oil and natural gas pipelines and processing equipment, and
        government regulations, including regulations relating to environmental
        protection, royalties, allowable production, pricing, importing and exporting
        of
        oil and natural gas. A reduction in the demand for oil and natural gas or
        in the
        proximity and capacity of pipelines and processing equipment, or a change
        to
        government regulations could have an adverse effect on Provident’s operating
        results and financial condition, and could reduce or eliminate the amount
        of
        income available for distribution to Trust Unitholders.
  4
  **Provident
        could incur significant liability or suffer material adverse effects under
        environmental laws.**
  The
        oil and natural
        gas industry is subject to a variety of local, provincial and federal laws
        and
        regulations, including laws and regulations relating to the protection of
        the
        environment. A breach of these laws and regulations may result in the imposition
        of fines or the issuance of clean-up orders in respect of Provident or its
        oil
        and gas properties. These laws and regulations may be changed in the future
        to
        impose higher standards and potentially more costly obligations on Provident.
        Provident may not be able to meet these standards and obligations. In addition,
        Provident’s reclamation fund may not be able to satisfy its future environmental
        and reclamation obligations. In this event, significant costs could be incurred
        that could have an adverse effect upon Provident’s financial condition, and
        which could reduce or eliminate the amount of income available for distribution
        to Trust Unitholders.
  **Payment
        delays may adversely affect Provident’s operating results and financial
        condition.**
  In
        addition to the usual delays in payment by purchasers of oil and natural
        gas to
        the operators of oil and gas properties, and by the operator to ManagementCo
        or
        Provident, payments between any of such 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, recovery by the operator of expenses incurred in the operation
        of oil
        and gas properties or the establishment by the operator of reserves for
        such expenses. These delays may have an adverse effect upon Provident’s
        operating results and financial condition, and may reduce or eliminate the
        amount of income available for distribution to Trust Unitholders.
  **Provident’s
        operating results and financial condition depend on its success in exploiting
        existing reserves and acquiring new reserves.**
  The
        Trust has
        certain unique attributes that differentiate it from other oil and gas industry
        participants. Distributions of Distributable Cash in respect of Provident’s oil
        and gas properties, absent commodity price increases or cost effective
        acquisition and development activities, will decline over time in a manner
        consistent with declining production from typical oil, natural gas and natural
        gas liquids reserves. Provident will not be reinvesting cash flow in the
        same
        manner as other industry participants. Accordingly, absent capital injections,
        Provident’s initial production levels and reserves will decline.
  Provident’s
        future
        oil and natural gas reserves and production, and therefore its cash flows,
        will
        be highly dependent on Provident’s success in exploiting its reserve base and
        acquiring additional reserves. Without reserve additions through acquisition
        or
        development activities, Provident’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, Provident’s ability to
        make the necessary capital investments to maintain or expand its oil and
        natural
        gas reserves will be impaired. To the extent that Provident is required to
        use
        cash flow to finance capital expenditures or property acquisitions, the level
        of
        Distributable Cash will be reduced.
  ManagementCo,
        on
        behalf of Provident, may not be successful in developing or acquiring additional
        reserves on terms that meet the Trust’s investment objectives. This failure to
        develop or acquire additional reserves would have an adverse effect upon
        Provident’s operating results and financial condition, and could reduce or
        eliminate the amount of income available for distribution to Trust
        Unitholders.
  5
  **Provident
        operates in a highly competitive industry.**
  The
        Trust actively
        competes with a substantial number of other oil and gas trusts and companies
        for
        reserve acquisitions, exploration leases, licenses and concessions, and skilled
        industry personnel, and in the marketing of oil and natural gas. Many of
        these
        competitors have significantly greater financial and personnel resources
        than
        the Trust. The Trust’s competitors include major integrated oil and natural gas
        companies and numerous other independent oil and natural gas companies and
        individual producers and operators. The Trust may not possess the resources
        to
        effectively compete against these companies to achieve its business
        objectives.
  Provident’s
        future
        oil and natural gas reserves and production will depend not only on its ability
        to exploit its reserve base, but also on its ability to select and acquire
        suitable additional reserves or prospects for exploratory drilling. Competitive
        factors in the distribution and marketing of oil include price, methods and
        reliability of delivery, and availability of imported products. In addition,
        the
        competition for qualified personnel in the oil and natural gas industry is
        intense and the Trust may not be able to continue to attract and retain all
        personnel necessary for the development and operation of its business. Increased
        competition would have an adverse effect on Provident’s future operating results
        and financial condition, and could reduce or eliminate the amount of income
        available for distribution to Trust Unitholders.
  ***Risks
        Related to the Trust Units***
  **Distributions
        to Trust Unitholders depend on levels of capital
        investment.**
  The
        timing and
        amount of capital expenditures will directly affect the amount of income
        for
        distribution to Trust Unitholders. Distributions to Trust Unitholders may
        be
        reduced, or even eliminated, at times when significant capital or other
        expenditures are made by the Trust’s operating subsidiaries. While the Trust
        does not budget capital expenditures a year in advance, see “Business Overview —
        Business Overview of Provident and the Trust — Capital Expenditures” for
        management’s estimate of future capital expenditures related to planned or
        existing drilling.
  **Provident
        may not be able to meet its debt service obligations or borrow additional
        funds
        from alternative sources.**
  Provident
        currently
        has a $135 million credit facility. Variations in interest rates and scheduled
        principal repayments could result in significant changes in the amount required
        to be applied to debt service before payment of any amounts to the Trust.
        In
        addition, the amount of Provident’s bank line of credit may not be adequate for
        the financial obligations of Provident, and Provident may not be able to
        obtain
        additional funds through other sources. This could have a material adverse
        effect upon Provident’s financial condition, and could reduce or eliminate the
        amount of income available for distribution to Trust Unitholders.
  The
        lender under
        Provident’s credit facility has been provided with security over substantially
        all of the assets of Provident. If Provident becomes unable to pay its debt
        service charges or otherwise commits an event of default under its credit
        facility such as bankruptcy, the lender may foreclose on or sell Provident’s oil
        and gas properties free from or together with the Provident Royalties. In
        this
        event, distributions to Trust Unitholders may be reduced or
        eliminated.
  6
  **The
        oil and
        natural gas reserves included in this annual report are only estimates, and
        may
        prove to be inaccurate; declines in Provident’s reserves may reduce the value of
        Trust Units to Trust Unitholders.**
  The
        oil and natural
        gas reserve figures included in this annual report represent estimates only.
        Actual production, revenues, expenditures and future cash flow with respect
        to
        Provident’s reserves will probably vary from these estimates, and those
        variances may be material. Many of the factors, assumptions and variable
        involved in estimating reserves are beyond Provident’s control and, over time,
        may prove to be incorrect. Declines in the reserves of Provident which are
        not
        offset by the acquisition or development of additional reserves may reduce
        the
        underlying value of Trust Units to Trust Unitholders. Trust Units will have
        no
        value once all of the oil and natural gas reserves of Provident have been
        produced.
  **Changes
        in
        legislation may adversely affect Trust Unitholders.**
  If,
        for any reason,
        the Trust ceases to qualify as a “mutual fund trust” under the Tax Act, the
        Trust Units will cease to be qualified investments for registered retirement
        savings plans, deferred profit sharing plans and registered retirement income
        funds. This may result in an adverse effect for some Trust Unitholders,
        including a reduction in after-tax returns on the Trust Units.
  **The
        Trust
        Units may not remain qualified or eligible investments under the Tax
        Act.**
  The
        Trust Units may
        not always remain qualified investments for registered retirement savings
        plans,
        deferred profit sharing plans and registered retirement income funds. The
        Tax
        Act imposes penalties for the acquisition or holding of non-qualified or
        ineligible investments, and Provident may not adhere to the conditions
        prescribed for qualified or eligible investments at any particular time.
        This
        may result in an adverse effect for some Trust Unitholders, including a
        reduction in after-tax returns on the Trust Units.
  **United
        States holders of Trust Units may be subject to PFIC
        rules.**
  If
        Provident and/or the Trust were treated as a passive foreign investment company
        for United States federal income tax purposes, a special, adverse tax regime
        (see “Additional
        Information — Taxation” )
        generally would
        apply to certain distributions with respect to, and gains upon dispositions
        of,
        the Trust Units held by United States persons. Because PFIC status is
        fundamentally factual in nature and is determined annually, the Trust may
        become
        a PFIC for either the current taxable year or for any subsequent taxable
        year.
        This factor may reduce the liquidity and trading prices of the Trust
        Units.
  **The
        Trust
        Units are not a traditional investment in the oil and natural gas
        sector.**
  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 Provident. The Trust Units
        represent a fractional interest in the Trust. The Trust Units will not represent
        a direct investment in Provident’s business. As holders of Trust Units, Trust
        Unitholders will 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.
  The
        Trust’s primary
        assets will be the Initial Notes, the Acquisition Notes, the Richland Notes
        and
        any other notes that the Trust may issue from time to time, the Provident
        Royalties and the Provident Shares. The price per Trust Unit is a function
        of
        the anticipated Distributable Cash, the oil and gas properties of Provident
        and
        ManagementCo’s 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.
  7
  **The
        Trust
        Units are not “deposits” within the meaning of the** ***Canada
        Deposit Insurance Corporation Act*** **(Canada)
        and are not insured under the provisions of that Act or any other legislation.
        Furthermore the Trust is not a trust company and, accordingly, it is not
        registered under any trust and loan company legislation as it does not carry
        on
        or intend to carry on the business of a trust company.**
  **Mechanisms
        for Trust Unitholders to liquidate their investments may be subject to
        limitations.**
  It
        is anticipated that the redemption right will not be the primary mechanism
        for
        Trust Unitholders to liquidate their investments. Initial Notes or Redemption
        Notes which may be distributed *in
        specie* to Trust
        Unitholders in connection with a redemption will not be listed on any stock
        exchange and no established market is expected to develop for such Initial
        Notes
        or Redemption Notes. Cash redemptions are subject to limitations. These factors
        may reduce the liquidity and trading prices of the Trust Units.
  **Trust
        Unitholders could potentially be liable for certain claims against the
        Trust.**
  The
        Trust Indenture
        provides that no Trust Unitholder will be subject to any liability in connection
        with the Trust or its assets or obligations and, in the event that a court
        determines that Trust Unitholders are subject to any such liabilities, the
        liabilities will be enforceable only against, and will be satisfied only
        out of,
        the Trust Unitholder’s share of the Trust’s assets.
  The
        Trust Indenture
        provides that all written instruments signed by or on behalf of the Trust
        must
        contain a provision to the effect that such obligation will not be binding
        upon
        Trust Unitholders personally. Personal liability may also arise in respect
        of
        claims against the Trust that do not arise under contracts, including claims
        in
        tort, claims for taxes and possibly certain other statutory
        liabilities.
  The
        operations of
        the Trust will be conducted, upon the advice of counsel, in such a way and
        in
        such jurisdictions as to avoid as far as possible any material risk of liability
        on the Trust Unitholders for claims against the Trust. Nevertheless, Trust
        Unitholders may potentially be liable for claims against the Trust.
  **The
        Trust
        is dependent on the operations and assets of Provident.**
  The
        Trust is an
        open-ended energy trust that will be entirely dependent upon the operations
        and
        assets of Provident through the ownership of the Provident Shares, the Initial
        Notes, the Acquisition Notes and the Provident Royalties. Accordingly, the
        cash
        distributions to the Trust Unitholders will be dependent upon the ability
        of
        Provident to pay its interest obligations under the Initial Notes, to declare
        and pay dividends on the Provident Shares and to make payments under the
        Provident Royalties.
  **Trust
        Unitholders are dependent on the management of Provident Management
        Corporation.**
  Trust
        Unitholders
        are dependent on the management of the Manager in respect of the administration
        and management of all matters relating to Provident’s oil and gas properties,
        the Provident Royalties, the Trust and the Trust Units. The ability of the
        Trust
        to distribute income to Trust Unitholders will depend upon the success of
        the
        Manager’s acquisition, disposition and management strategies.
  8
  **The
        directors and officers of Provident and the Manager may become subject to
        conflicts of interest.**
  The
        directors,
        officers and employees of Provident and the Manager, and some of the consultants
        retained by the Manager from time to time, are engaged in and will continue
        to
        engage in other activities in the oil and natural gas industry, including
        being
        directors and officers of other companies. As a result of these and other
        activities, the directors and officers of Provident and the Manager may become
        subject to conflicts of interest. These conflicts of interest may have an
        adverse effect upon Provident’s operating results and financial condition, and
        may reduce or eliminate the amount of income available for distribution to
        Trust
        Unitholders.
  The
        ABCA provides
        that in the event that a director has an interest in a contract or proposed
        contract or agreement, the director shall disclose his interest in such contract
        or agreement and shall refrain from voting on any matter in respect of such
        contract or agreement unless otherwise provided under the ABCA. To the extent
        that conflicts of interest arise, the conflicts will be resolved in accordance
        with the provisions of the ABCA.
  **U.S.
        investors may be adversely affected by the fact that the Trust and Provident
        are
        governed by the laws of the Province of Alberta.**
  The
        Trust and
        Provident are governed by the laws of the Province of Alberta. Most of their
        directors, controlling persons and officers, as well as some of the experts
        named in this Form 20-F, are residents of Canada or other jurisdictions outside
        of the United States and all or a substantial portion of the Trust’s and
        Provident’s assets and their assets are located outside of the United States. As
        a result, it may be difficult for Trust Unitholders to effect service of
        process
        upon the Trust or Provident or such persons within the United States or to
        enforce against the Trust or Provident in the United States, judgments of
        courts
        of the United States predicated upon the civil liability provisions of the
        U.S.
        federal securities laws or other laws of the United States. In addition,
        the
        Trust and Provident have been advised by their Canadian counsel that there
        is
        doubt as to the enforceability in Canada of liabilities predicated solely
        upon
        U.S. federal securities law against them, or directors, controlling persons
        and
        officers and the experts named in this Form 20-F who are not residents of
        the
        United States, in original actions or in actions for enforcement of judgments
        of
        U.S. courts.
   **Item
                  4.**
              **Information
                  on the****Trust**
  **A.**
              **History
                  and Development**
  **I.**  **The
        Trust**
   Provident
        Energy
        Trust is an open-end unincorporated investment trust governed by the laws
        of the
        Province of Alberta and created pursuant to the Trust Indenture. The head
        and
        principal offices of Provident Energy Trust are located at 900, 606 -
        4 th Street S.W.,
        Calgary, Alberta T2P 1T1. The telephone number is (403) 296-2233. The registered
        office of the Trust is 3700, 400 - 3 rd Avenue S.W.,
        Calgary, Alberta T2P 4H2.
  The
        Trust was
        formed as of January 25, 2001 pursuant to the Trust Indenture. In
        accordance with the Founders Arrangement effective as of March 6,
        2001
        involving the Trust, Founders and Provident, all of the issued and outstanding
        Founders Shares were exchanged for the Initial Notes of Provident on the
        basis
        of one Initial Note for every three Founders Shares. Each Initial Note was
        subsequently exchanged with the Trust for one Trust Unit, resulting in the
        acquisition by the Trust of all of the Initial Notes and the acquisition
        of
        Trust Units by the former shareholders of Founders.
  9
  Provident
        Energy
        Trust was established to acquire and hold, directly and indirectly, interests
        in
        petroleum and natural gas properties. Cash flow from the properties is flowed
        from Provident to the Trust by way of royalty payments on the Initial Royalty
        and Subsequent Royalty and interest payments and principal repayments on
        the
        Initial Notes and Acquisition Notes. Distributable Income generated by the
        royalties, interest and principal repayments is then distributed monthly
        to the
        Unitholders. Under the terms of the Trust Indenture the Trust is also entitled
        to:
  ·
              invest
                  in
                  securities of Provident from time to
                  time;
  ·
              acquire
                  the
                  Initial Royalty and other
                  royalties;
  ·
              temporarily
                  hold cash and Permitted Investments for the purposes of paying
                  the
                  expenses and liabilities of Provident Energy Trust and paying amounts
                  payable by Provident Energy Trust in connection with the redemption
                  of any
                  Trust Units and making distributions to Trust
                  Unitholders;
  ·
              acquire
                  or
                  invest in Subsequent Investments;
                  and
  ·
              pay
                  the
                  costs, fees and expenses associated with or incidental to the
                  foregoing.
  **II.**  **Provident**
   Provident
        Energy
        Ltd. is a corporation wholly owned by Provident Energy Trust. Provident was
        incorporated under the ABCA on January 19, 2001 and was amalgamated
        with
        Founders pursuant to the Founders Arrangement. The head and principal offices
        of
        Provident are located at 900, 606 - 4 th Street S.W.,
        Calgary, Alberta T2P 1T1. The telephone number is (403) 296-2233. The registered
        office of Provident is 3700, 400 - 3 rd Avenue S.W.,
        Calgary, Alberta T2P 4H2. Where the information in this Form 20-F
        is as of
        a date prior to March 6, 2001, the terms “Provident” or “Provident Energy
        Ltd.” shall refer to Founders Energy Ltd.
  **III.**  **Provident
        Holdings Trust**
  Provident
        Holdings
        Trust is an open-end unincorporated commercial trust. Provident Holdings
        Trust
        was formed pursuant to a trust agreement dated April 25, 2002. This
        trust
        is wholly owned by Provident Energy Trust. The asset of Provident Holdings
        Trust
        is a 99% interest in the limited partnership, Provident Acquisitions L.P.
        The
        head and principal office of Provident Holdings Trust is located at 900,
        606 -
        4 th Street S.W.
        Calgary, Alberta T2P 1T1. The telephone number is (403) 296-2233. The registered
        office of Provident Holdings Trust is 3700, 400 - 3 rd Avenue S.W.
        Calgary, Alberta T2P 4H2.
  **IV.**  **Provident
        Acquisitions L.P.**
  Provident
        Acquisitions L.P. is a limited partnership registered in the Province of
        Alberta. Provident Acquisitions L.P. was formed pursuant to a trust agreement
        dated April 25, 2002. Provident Energy Ltd. is the general partner
        with a
        1% interest in the partnership and Provident Holdings Trust is the limited
        partner with a 99% interest in the partnership. The head and principal office
        of
        Provident Acquisitions L.P. is located at 900, 606 - 4 th Street S.W.
        Calgary, Alberta T2P 1T1. The telephone number is (403) 296-2233. The registered
        office of Provident Acquisitions L.P. is 3700, 400 - 3 rd Avenue S.W.
        Calgary, Alberta T2P 4H2.
  10
  **V.**  **The
        Manager**
  Provident
        Management Corporation was incorporated on January 17, 2001 under
        the ABCA.
        The head and principal offices of the Manager are located at 900,
        606 - 4 th Street S.W.,
        Calgary, Alberta T2P 1T1. The telephone number is (403) 296-2233.
        The
        registered office of the Manager is 3700, 400 - 3 rd Avenue
        S.W.,
        Calgary, Alberta T2P 4H2.
  Pursuant
        to the
        provisions of the Management Agreement, the Manager provides certain management,
        administrative and support services to Provident Energy Trust. The Manager
        was
        incorporated solely for the purpose of providing management, advisory and
        administration services to Provident and Provident Energy Trust.
  **VI.**  **General
        Development of the Business of the Trust and Provident**
  The
        business and
        history of Provident, and its predecessor Founders, are detailed in the
        following discussion. This information provides relevant background to the
        growth of Founders and the decision to convert Founders into a cash distributing
        energy trust.
  In
        1997, Founders achieved significant production growth through an aggressive
        horizontal drilling program that focussed on exploiting certain southeast
        Saskatchewan oil properties that were acquired in March 1996. The use of
        three-dimensional seismic and horizontal drilling techniques resulted in
        nine
        successful horizontal oil wells in the Founders operated areas of Hartaven
        and
        Weir Hill. Exploration drilling during 1997 resulted in two successful deep
        exploratory oil wells in the Hartaven area of southeast Saskatchewan. During
        1997, Founders also increased its undeveloped land position by 48,325 net
        acres
        to total 60,816 net acres. Production volumes for 1997 averaged 1,762
        BOE/d.
  In
        1998, Founders realized significant gains in crude oil and natural gas
        production and reserves as a result of a significant multi-zone natural gas
        discovery at Pouce Coupe in northwest Alberta and the December 22, 1998
        acquisition of Opal. Production volumes averaged 2,489 BOE/d and undeveloped
        land holdings increased by 99,452 net acres to total 160,268 net acres. The
        acquisition of Opal ranked as Founders’ largest transaction at the time and
        provided Founders with a new Saskatchewan heavy oil core area in close proximity
        to Lloydminster as well as a natural gas prone core area in West Central
        Alberta. On a proven reserve basis the Opal acquisition provided 8.2 million
        BOE
        of which 46% were natural gas. Opal was a value-driven acquisition that
        significantly enhanced Founders’ competitive position in the gas-prone area of
        West Central Alberta and provided Founders with a new core growth area for
        heavy
        oil in close proximity to Lloydminster.
  In
        1999, high debt levels, historically low crude oil prices and limited equity
        markets significantly impaired Founders’ growth objectives for the year. Early
        in 1999, management recognized the need to deal with Founders’ debt levels to
        improve Founders’ financial flexibility. Accordingly, to repay bank debt, a $15
        million subordinated convertible debenture financing was completed in June
        1999
        and Founders commenced a program of identifying and selling $28.8 million
        of
        non-core assets throughout the year. These successful initiatives, coupled
        with
        drilling success during the second half of 1999, significantly improved the
        balance sheet and created a more flexible financial structure to allow Founders
        to aggressively compete in its core growth areas. In addition, during the
        third
        quarter of 1999, an extensive review was undertaken by management and the
        board
        of directors to evaluate and recommend strategic alternatives to maximize
        Founders’ potential. As a result of this process, Founders refocused and
        simplified its business strategy to create consistent growth in shareholder
        value through efficient use of capital and technical resources. Daily 1999
        production volumes averaged 2,874 Bpd of crude oil and natural gas liquids
        and
        12.3 Mmcf/d of natural gas for a total oil equivalent production of 4,922
        BOE/d.
  11
  During
        2000,
        Founders focused its activities in the two core areas of West Central Alberta
        and Lloydminster. During the year, Founders participated in the drilling
        of a
        total of 31 (27.3 net) wells, resulting in 22 (20.3 net) crude oil wells,
        six
        (4.9 net) gas wells and three (2.1 net) dry holes for an overall success
        rate of
        90%. During 2000, a total of 18 wells were drilled in the Lloydminster heavy
        oil
        area with a 100% success rate. In the gas prone area of West Central Alberta,
        Founders drilled or participated in drilling nine (7.0 net) wells for an
        overall
        success rate of 67%. During 2000, daily production volumes averaged 2,440
        Bpd of
        crude oil and natural gas liquids and 10.6 Mmcf/d of natural gas for a total
        oil
        equivalent production of 4,208 BOE/d compared to an average daily production
        rate of 4,922 BOE/d in 1999. The reduction in daily production volumes for
        2000
        compared to 1999 is attributed to the sale of approximately 1,200 BOE/d of
        annualized non-core production throughout 1999.
  During
        2000,
        management believed that Founders, along with the vast majority of other
        junior
        exploration and production companies, was significantly undervalued by the
        market. As a result, Founders’ board of directors reviewed several options for
        the company with a view to increasing shareholder value. At this time, it
        was
        the collective view of the board of directors that the Western Canadian
        Sedimentary Basin had become largely a mature basin with an operating emphasis
        on exploitation. In reviewing appropriate structures for a maturing basin,
        management believed the trust structure was clearly the most suited structure
        for acquiring mid-life to mature assets and for harvesting and paying out
        the
        cash flow in a low risk, cost effective manner. The board of directors believed
        that a trust structure would maximize the financial return for the Founders’
        shareholders through the creation of a yield-based investment that could
        take
        maximum advantage of the strong commodity prices and market fundamentals
        currently prevailing in the oil and gas sector.
  On
        March 5, 2001, the shareholders of Founders approved the reorganization of
        Founders into Provident Energy Trust. The transaction, accomplished by way
        of a
        plan of arrangement resulted in the shareholders of Founders receiving one
        (1)
        Trust Unit in Provident in exchange for each three (3) common shares of
        Founders. As part of the transaction, Citicorp, the holder of the $15.0 million
        7.5% subordinated secured convertible debenture due June 30, 2004, agreed
        to the
        early conversion and redemption of the Debenture as part of the Founders
        Arrangement. The conversion of the Debenture significantly improved Provident’s
        financial flexibility allowing the Trust to actively pursue quality acquisition
        opportunities. See “Significant Acquisitions and Significant
        Dispositions.”
  On
        May 25, 2001, the Trust and Provident completed the acquisition of the Maxx
        Shares pursuant to the Maxx Arrangement. The acquisition of Maxx increased
        the
        total number of Trust Units outstanding to 14,586,821 Trust Units. See
“Significant Acquisitions and Significant Dispositions.”
  On
        August 29, 2001, the Trust completed a treasury and secondary offering of
        2,435,500 Trust Units for gross proceeds of $26.425 million. On December
        13,
        2001, in conjunction with the acquisition of Richland, the Trust completed
        a
        treasury offering of 4,000,000 Trust Units for gross proceeds of $35.0
        million.
  On
        January 15, 2002, the Trust and Provident completed the Richland Arrangement.
        The acquisition of Richland increased the total number of Trust Units
        outstanding as of that date to 32,179,546 Trust Units. See “Significant
        Acquisitions and Significant Dispositions.”
  On
        May 1, 2002, the Trust and Provident completed the acquisition of certain
        oil
        and gas properties located in southeast Alberta for a purchase price of $72.0
        million (subject to adjustment), payable in cash. See “Significant Acquisitions
        and Significant Dispositions.” In conjunction with the acquisition of the oil
        and gas properties, the Trust completed a concurrent treasury offering of
        3,900,000 Trust Units and $64.41 million principal amount of 10.5% convertible
        unsecured subordinated debentures for gross proceeds of $103.8
        million.
  12
  **VII.**  **Significant
        Acquisitions and Significant Dispositions**
  ***Founders
        Arrangement***
 From
        the end of
        1999 and throughout 2000, an extensive review was undertaken by management
        and
        the board of directors to evaluate Founders’ asset base and future growth
        prospects in relation to the current industry environment and to consider
        various strategic alternatives. As part of this review, it was determined
        that
        the Western Canadian Sedimentary Basin had become largely a mature basin
        with
        limited new growth potential. Finding costs have consistently trended upwards
        over the past few years indicating that large new quantities of oil and gas
        are
        becoming more difficult to find. Despite extremely strong commodity prices
        and
        fundamentals, the majority of junior Canadian exploration and production
        companies, including Founders, continued to trade at very low valuations
        making
        it difficult to acquire properties or companies or access growth capital
        without
        being extremely dilutive to shareholders. At the same time, the Canadian
        oil and
        gas trust sector was trading at much stronger valuations than the exploration
        and production sector and raised more than $700 million of new equity during
        2000. In addition, many Canadian oil and gas trusts used their trust units
        as
        currency in completing more than $2.0 billion of corporate and property
        acquisitions in 2000 by the sector. After an extensive review of Founders’ asset
        base and detailed production and cash flow modeling, the board of directors
        concluded that the best alternative for maximizing shareholder value would
        be to
        convert Founders into an oil and gas trust.
  The
        purpose of the
        Founders Arrangement was to convert Founders from a corporate entity
        concentrating on growth through the reinvestment of cash flow to a trust
        entity
        which will distribute a substantial portion of cash flow to Trust Unitholders.
        The Founders Arrangement resulted in Founders Shareholders receiving Trust
        Units
        of the Trust in exchange for their Founders Shares. The Founders Arrangement
        involved the following steps which were deemed to occur
        sequentially:
  ·
              Founders’
                  existing shareholder rights plan was terminated and all rights
                  issued
                  thereunder were extinguished;
  ·
              each
                  issued
                  and outstanding Founders Share was exchanged for Initial Notes,
                  on the
                  basis of one Initial Note for every three Founders Shares. In lieu
                  of
                  fractional Initial Notes, each holder of Founders Shares who would
                  otherwise have received such fractional Initial Notes was paid
                  an amount
                  of cash (rounded to the nearest whole cent), without interest,
                  equal to
                  the product of (a) such fraction multiplied by (b) the product
                  of (i)
                  three and (ii) the average closing sale price per share of the
                  Founders
                  Shares on the TSX as reported in The Financial Post over the ten
                  consecutive trading days ending on the third trading day prior
                  to the
                  effective date, resulting in the acquisition by Provident of all
                  of the
                  issued and outstanding Founders and the acquisition by holders
                  of Founders
                  Shares of Initial Notes;
  13
 ·
              each
                  Initial
                  Note was exchanged for one Trust Unit, resulting in the acquisition
                  by the
                  Trust of all of the issued and outstanding Initial Notes and the
                  acquisition by the former holders of Founders Shares of Trust
                  Units;
  ·
              Founders
                  and
                  Provident were amalgamated to form “Provident Energy Ltd.”;
                  and
  ·
              the
                  Trust
                  Unitholder Rights Plan became
                  effective.
  In
        connection with the Founders Arrangement, all stock options immediately vested
        and became exercisable prior to the Founders Arrangement becoming effective.
        Any
        stock options not exercised at such time were cancelled. Founders has made
        a
        loan available to any employee, officer or director exercising options
        (including Randall J. Findlay and Thomas W. Buchanan) for a maximum term
        of
        three months from the date of the Founders Arrangement taking effect at an
        interest rate equal to the average commercial bank lending rate available
        to
        Provident. Any distributions on the Trust Units made to an employee, officer
        or
        director during that period will be applied to the loan amount due. Principal
        and accrued interest on the loans will be due and payable in full on the
        earlier
        of the due date of the loans or at the time of termination of
        employment.
  Immediately
        following the Founders Arrangement, Provident granted the Initial Royalty
        to the
        Trust for consideration of $13.6 million, in exchange for a reduction of
        the
        principal amount owing by Provident under the Initial Notes.
  The
        Founders
        Arrangement resulted in each shareholder ultimately receiving one Trust Unit
        for
        every three Founders Shares held with a cash payment in respect of any
        fractional interests. The Founders Arrangement also resulted in the termination
        of the shareholder rights plan of Founders and the adoption of the Trust
        Unitholder Rights Plan containing substantially the same provisions as the
        shareholder rights plan.
  The
        board of
        directors of Founders received an opinion dated January 29, 2001 from Scotia
        Capital Inc., its independent financial advisor, stating that, in its opinion,
        as of the date of such opinion, the Founders Arrangement was fair from a
        financial point of view to the holders of Founders Shares.
  ***Maxx
        Arrangement***
 On
        March 26, 2001, Provident, Maxx and the Trust entered into the Maxx Arrangement
        Agreement, which provided for implementation of the Maxx Arrangement pursuant
        to
        Section 186 of the ABCA. The Maxx Arrangement became effective on May 25,
        2001.
        On May 25, 2001, each of the events below were deemed to occur in the following
        sequence without further act or formality:
  ·
              each
                  issued
                  and outstanding Maxx Share was exchanged with Provident for Acquisition
                  Notes on the basis of the Per Share Principal Amount of Acquisition
                  Notes
                  for every one Maxx Share;
  ·
              the
                  Acquisition Notes were exchanged with the Trust for Trust Units
                  and/or
                  cash, resulting in the acquisition by the Trust of all of the Acquisition
                  Notes and the acquisition by holders of Acquisition Notes of Trust
                  Units
                  and/or cash on the basis of:
  14
  ·
              $7.00
                  cash
                  for each Maxx Share for those Maxx shareholders that elected to
                  receive
                  all cash;
  ·
              $1.9745
                  cash
                  and 0.4523 of a Trust Unit for those Maxx shareholders that elected
                  to
                  receive all Units,
  resulting
        in a
        total of $35.4 million in cash and 7,475,000 Trust Units being issued to
        acquire
        all of the issued and outstanding shares of Maxx; and
  ·
              Maxx
                  and
                  Provident were amalgamated and continued as one corporation, under
                  the
                  name “Provident Energy Ltd.”
  In
        addition, Provident issued 19,600 Units to directors of Maxx holding share
        appreciation rights of Maxx pursuant to a letter agreement entered into between
        Provident and each such director.
  Upon
        completion of
        the Maxx Arrangement, the Trust became the holder of all of the issued and
        outstanding Acquisition Notes.
  Provident
        and Maxx
        each had three focused and matching core operating areas in the Lloydminster
        area of Alberta and Saskatchewan, south-east Saskatchewan and west central
        Alberta. The acquisition of Maxx resulted in financial and operational synergies
        due to the similar nature of operations and proximity of these properties.
        These
        synergies resulted in reduced general and administrative expenses, operational
        cost reduction opportunities and the ability to access capital investment
        opportunities. As a result of the acquisition of Maxx, Provident’s daily average
        production increased from 4,800 BOE/d to 12,500 BOE/d, including 6,300 barrels
        of conventional heavy crude oil, 1,700 Bpd of light crude oil, 800 barrels
        of
        natural gas liquids and 20.6 Mmcf/d of natural gas.
  ***Richland
        Arrangement***
 On
        November 26, 2001, Provident, Richland, Terraquest and the Trust entered
        into
        the Richland Arrangement Agreement, which provided for implementation of
        the
        Richland Arrangement pursuant to Section 186 of the ABCA. The Richland
        Arrangement became effective on January 16, 2002. Under the terms of the
        Richland Arrangement Agreement, Richland shareholders received 0.4 of a Trust
        Unit and one share of Terraquest for each issued and outstanding common share
        of
        Richland. Pursuant to the plan of arrangement, each issued and outstanding
        common share of Richland was exchanged by Richland shareholders for one newly
        created Class A Share and one Class B Share of Richland. As part of the Richland
        Arrangement, upon completion of the sale of the Terraquest Assets for Terraquest
        Shares, Richland redeemed all of the issued and outstanding Class B Shares
        held
        by Richland shareholders in consideration for the transfer of the Terraquest
        Shares held by Richland for the Class B Shares held by Richland shareholders.
        Each issued and outstanding Class A Share held by Richland shareholders was
        then
        exchanged for a note, which was immediately redeemed for 0.4 of a Trust
        Unit.
  The
        Terraquest
        Assets sold by Richland to Terraquest as part of the Richland Arrangement
        were
        comprised of certain producing properties of Richland located in southern
        and
        northwest Alberta which represented production as at September 30, 2001 of
        approximately 200 BOE/d, 426 MBOE of proved reserves and 88,000 net acres
        of
        undeveloped lands and associated seismic data. Pursuant to the Richland
        Arrangement Agreement, Provident received gross overriding royalties on industry
        standard terms on certain of the Terraquest properties.
  15
  The
        Richland
        Arrangement received the final order approving the plan from the Court on
        January 16, 2002 following the approval of the Richland shareholders
        at a
        special meeting held on January 15, 2002, and Provident and Richland were
        then
        amalgamated, continuing as “Provident Energy Ltd.”. A total of 11,157,225 Trust
        Units were issued by the Trust to acquire all of the issued and outstanding
        shares of Richland. As part of the acquisition of Richland, Provident assumed
        Richland’s debt, net of working capital, of approximately $83
        million.
  Upon
        completion of
        the Richland Arrangement, the Trust became the holder of all of the issued
        and
        outstanding Richland Notes.
  Following
        the
        Richland Arrangement, Provident’s daily average production increased to
        approximately 17,000 BOE/d comprising of 40% natural gas, 33% cold conventional
        heavy oil and 27% light crude oil and natural gas liquids. The assets of
        Richland have diversified Provident’s production mix, which, prior to the
        Richland Arrangement, was weighted 55% to heavy oil. The Richland assets
        complement Provident’s existing operations in west central Alberta and southeast
        Saskatchewan and provide a new core area in southern Alberta.
  For
        further
        information relating to Richland, please see “—Business Overview—Business
        Overview of Richland.”
  ***Southeast
        Alberta Property Acquisition***
  On
        March 26, 2002, Provident entered into an agreement of purchase and sale
        with
        Devon and Devon ARL providing for the acquisition by Provident of certain
        oil
        and gas properties for a purchase price of $72.0 million (subject to
        adjustment), payable in cash. The right to acquire the Acquired Properties
        was
        subsequently assigned to Provident Acquisitions L.P. The acquisition of the
        Acquired Properties closed on May 1, 2002.
  The
        Acquired
        Properties consist primarily of mature light oil and natural gas assets located
        in southeast Alberta producing approximately 3,600 BOE/d. The assets are
        comprised primarily of high working interest, operated properties with year
        round operating access. Provident believes that the assets offer additional
        low-risk development and optimization potential. The Acquired Properties
        met the
        Trust’s objectives of increasing cash available for distribution and net asset
        value on a per unit basis.
  For
        further
        information relating to the Acquired Properties, please see “—Business
        Overview—Business Overview of the Acquired Properties.”
  **B.**
              **Business
                  Overview**
  **I.**  **Business
        Overview of Provident and the Trust**
  **The
        following is a description of the business of Provident prior to the Richland
        Arrangement and the acquisition of the Acquired Properties, unless otherwise
        indicated. For a description of the business and properties of Richland prior
        to
        the Richland Arrangement, see “—Business Overview of Richland.” For a
        description of the Acquired Properties, see “—Business Overview of the Acquired
        Properties.”**
  The
        Trust acquires
        and holds, directly or indirectly, interests in crude oil and natural gas
        properties in Western Canada. Cash flow from the properties is flowed from
        Provident to the Trust by way of royalty payments on the Initial Royalty
        and
        Subsequent Royalty, interest and principal repayments on the Initial Notes
        and
        principal repayments on the Acquisition Notes, Richland Notes and other notes
        that Provident may issue from time to time. Distributable Income generated
        by
        the royalties, interest and principal repayments is then distributed monthly
        to
        Unitholders. The management and administration of the business and operations
        of
        Provident are performed by the Manager under the terms of the Management
        Agreement, and the Manager is responsible for providing the services of both
        the
        President and the Chief Executive Officer to Provident. The Trust has no
        employees, while Provident has 72 employees and consultants at its head office
        location and 58 employees and contract operators located in several field
        offices within the core areas of Lloydminster, west central Alberta and
        southeast Saskatchewan.
  16
  **(a)**  **Corporate
        Strategy**
  Provident’s
        strategy is focused on achieving a consistent level of monthly cash
        distributions to the Unitholders. To this end, Provident pursues a focused
        program of acquisition, development, exploitation, production and marketing
        of
        crude oil and natural gas in the Western Canadian Sedimentary Basin. Provident’s
        operations are currently located in three core areas of activity in west
        central
        Alberta, Lloydminster and southeast Saskatchewan. These areas generally offer
        low to medium risk development potential, a well-developed operational
        infrastructure and year-round access, all of which is ideally suited to a
        trust.
  Provident
        will
        focus its development activities primarily in the Lloydminster heavy oil
        area. A
        consistent, disciplined commodity price risk management strategy will be
        employed by Provident, focusing on stabilizing monthly cash distributions
        to
        Unitholders. To this end, Provident plans to use both financial and physical
        contracts to reduce the volatility of oil and gas prices.
  Provident
        will also
        pursue an aggressive acquisition strategy targeting both property and corporate
        acquisitions that are accretive to distributable cash flow and net asset
        value
        per Trust Unit. The Trust will pursue acquisitions that meet certain criteria
        including quality low-risk production with     
        year-round access and good operating infrastructure. This will minimize the
        risk
        of production downtime. Provident will pursue acquisitions that have a strong
        production component and where minimal capital is required to bring incremental
        production on stream. Where development potential exists, only those
        opportunities that are considered low risk will be undertaken by Provident,
        higher risk prospects or exploration opportunities will be either farmed
        out or
        sold.
  **(b)**  **Risk
        Management Strategy**
  Provident’s
        cash
        flow available for distribution to Unitholders could be substantially impacted
        by fluctuations in commodity prices for both crude oil and natural gas, quality
        differentials for both heavy and medium grade crude oil, the Canadian/U.S.
        dollar exchange rate and interest rates. In order to manage the volatility
        inherent in these variables, Provident’s Board of Directors has adopted a
        commodity price risk management program that is administered by a Risk
        Management Committee comprised of certain members of senior management of
        Provident in consultation with Provident’s primary commodity marketing
        advisors.
  The
        Risk Management
        Committee is responsible for the following:
  ·
              development
                  and communication of the commodity price risk management policies
                  and
                  procedures;
  ·
              development
                  of strategic commodity price risk management guidelines under which
                  physical or financial instruments are to be utilized and to strike
                  a
                  balance between risk exposure and the desired level of risk
                  tolerance;
  17
 ·
              development
                  of parameters for market risk transaction volumes and other
                  limits;
  ·
              authorization
                  of specific financial and physical commodity and derivative instruments
                  to
                  be traded; and
  ·
              development
                  of appropriate systems for recording, monitoring and reporting
                  the results
                  of the commodity risk management
                  activity.
  The
        risk management
        program is not intended to create incremental economic exposure to Provident.
        Instead, the program serves to reduce the economic exposure of Provident
        to
        adverse market movements thus providing more stability of cash distributions
        to
        Unitholders.
  Provident
        currently
        markets and distributes its crude oil production through various third party
        intermediate marketing companies and in some cases directly to refiners that
        also market and distribute their products. There are numerous markets available
        to transact competitively priced commodity contracts for crude oil, and
        Provident typically contracts on a month-to-month basis with companies in
        these
        markets. Provident’s natural gas is generally sold on both the spot market and
        to aggregators, with approximately 85% sold on the spot market and approximately
        15% sold to aggregators (typically pipeline companies). There are also numerous
        markets available to transact competitively priced commodity contracts for
        natural gas, and Provident frequently has longer-term contracts with companies
        in these markets. Provident is not dependent on any single customer or group
        of
        customers for the marketing or distribution of its crude oil and natural
        gas.
  In
        conjunction with the Founders Arrangement, the Maxx Arrangement and the Richland
        Arrangement, Provident has entered into several physical and financial hedge
        transactions for the balance of 2002 and for 2003. As of June 30, 2002,
        approximately 57% of Provident’s oil production was hedged for 2002 and
        approximately 55% of Provident’s gas production was hedged for 2002. The
        following table summarizes the Provident commodity price risk program as
        of
        March 31, 2002, including contracts that were transacted by Richland
        prior
        to January 16, 2002.
  **Year**
              **Product**
              **Volume**
              **Terms**
              **Effective Period**2002
              Light
                  Oil
              250
                  Bpd
              Costless
                  Collar WTI US $20.00 - US $22.90
              January 1
                  - December 31Light
                  Oil
              1,000
                  Bpd
              WTI
                  US
                  $24.30
              January 1
                  - December 31Heavy
                  Oil
              1,000
                  Bpd
              Costless
                  Collar WTI US $24.00 - US $27.00
              January 1
                  - December 31Heavy
                  Oil
              1,000
                  Bpd
              US
                  $8.25 per
                  Bbl Differential @ Hardisty
              January 1
                  - December 31Heavy
                  Oil
              4,000
                  Bpd
              Cdn
                  $18.93
                  per Bbl Wellhead
              January 1
                  - December 31Natural
                  Gas
              3,000
                  Mcf/d
              Cdn
                  $5.01 per
                  Mcf
              January 1
                  - December 31Natural
                  Gas
              11,500
                  Mcf/d
              Cdn
                  $5.34 per
                  Mcf
              January 1
                  - October 31Natural
                  Gas
              7,000
                  Mcf/d
              Cdn
                  $3.14 per
                  Mcf
              January 1
                  - September 30Natural
                  Gas
              5,000
                  Mcf/d
              Cdn
                  $4.42 per
                  Mcf
              November 1
                  - December 31Natural
                  Gas
              3,000
                  Mcf/d
              Costless
                  Collar Cdn $6.33 - Cdn $9.02 per Mcf
              January 1
                  - October 31Natural
                  Gas
              5,000
                  Mcf/d
              Costless
                  Collar Cdn $3.95 - Cdn $5.06 per Mcf
              January 1
                  - October 312003
              Light
                  Oil
              1,000
                  Bpd
              WTI
                  US
                  $23.18
              January 1
                  - December 31Heavy
                  Oil
              3,000
                  Bpd
              Cdn
                  $18.98
                  per Bbl Wellhead
              January 1
                  - December 31Natural
                  Gas
              5,000
                  Mcf/d
              Cdn
                  $5.22 per
                  Mcf
              January 1
                  - December 31Natural
                  Gas
              3,000
                  Mcf/d
              Cdn
                  $5.01 per
                  Mcf
              January 1
                  - October 31
  18
 
 **(c)**  **Principal
        Properties** **of
        Provident**
  The
        following are
        descriptions of Provident’s principal producing properties prior to the Richland
        Arrangement and prior to the acquisition of the Acquired Properties, both
        of
        which closed in 2002, located in west central Alberta, east central Alberta
        and
        west central Saskatchewan (the “Lloydminster Core Area”), and southeast
        Saskatchewan. All conversions of gas to oil are on a 6:1 basis.
  ***1.***  ***West
        Central Alberta Core Area***
  ***Carrot
        Creek, Alberta***
  Provident
        has a
        17.7% working interest in six producing liquids-rich gas wells, and one oil
        well
        with solution gas in the area. For the period March 6, 2001 to
        December 31, 2001, production from this area was 835 Mcf/d of natural
        gas
        and 52 Bpd of oil and natural gas liquids. Currently, Carrot Creek is producing
        200 BOE/d, net to Provident. Based on the McDaniel Report, Provident has
        been
        assigned a total of 651 Mmcf of proven natural gas reserves. Crude oil and
        natural gas liquids reserves of 58 Mbbls proved have also been assigned to
        the
        area. Provident also has undeveloped land holdings of 391 net acres in the
        area.
  ***Clive,
        Alberta***
  The
        Clive area is
        located approximately 60 kilometres east of Red Deer in central Alberta.
        Provident operates twelve natural gas wells (net 10 wells), a seven million
        cubic feet per day natural gas plant, a seven Mmcf/d compressor station,
        three
        wellhead compressors and a gathering system in the area. Clive is a natural
        gas-prone area with many of the same multi-zone targets found at Gilby. For
        the
        period from March 6, 2001 to December 31, 2001, Provident’s net share
        of production from the Clive area averaged 1.2 Mmcf/d of natural gas and
        15 Bpd of oil and natural gas liquids. Current net production is
        approximately 265 BOE/d from the area. Based on the McDaniel Report,
        Provident has been assigned 2.0 Bcf of proven natural gas reserves. Proved
        crude
        oil and natural gas liquids reserves of 25 Mbbls proved have also
        been
        assigned to the area. Provident also has undeveloped land holdings of 3,954
        net
        acres in the area.
  ***Cow
        Lake, Alberta***
  Provident
        operates
        six natural gas wells (net 3.3 wells) and gathering and compression facilities
        in this area. For the period from March 6, 2001 to December 31,
        2001,
        the property produced approximately 2.9 Mmcf/d of natural gas and 150 Bpd
        of natural gas liquids. Current net production is approximately 560 BOE/d
        from the area. Based on the McDaniel Report, Provident has been assigned
        5.6 Bcf
        of proven natural gas reserves. Proved natural gas liquids reserves of
        309 Mbbls have also been assigned to the area. Provident also has
        undeveloped land holdings of 420 net acres in the area.
  ***Gilby,
        Alberta***
  The
        Gilby area is
        located approximately 35 kilometers northwest of Red Deer in central Alberta.
        Provident has an interest in 52 gas wells (net 38.2 wells), an eight million
        cubic feet per day natural gas plant, a five million cubic feet per day
        compressor station and an extensive gathering system. Provident established
        Gilby as a core area due to its attractive multi-zone, liquids-rich and
        gas-prone nature. Hydrocarbon reservoirs range from very shallow to deep.
        For
        the period March 6, 2001 to December 31, 2001, Provident’s share of production
        from the Gilby area averaged 8.6 Mmcf/d of natural gas and 334 Bpd of oil
        and
        natural gas liquids. Current net production is approximately 1,600 BOE/d.
        Based
        on the McDaniel Report, Provident has been assigned a total of 16.5 Bcf of
        proven natural gas reserves. Crude oil and natural gas liquids reserves of
        766
        Mbbls proved have also been assigned to the area. Provident also has undeveloped
        land holdings of 21,352 net acres in the area.
  19
  ***Westward
        Ho, Alberta***
  Provident
        operates
        21 oil and natural gas wells (net 8.8 wells) and gathering and compression
        facilities in the area. For
        the period
        March 6, 2001 to December 31, 2001, t he
        property
        produced approximately 0.6 Mmcf/d of natural gas and 82 Bpd of oil
        and
        natural gas liquids. Current net production is approximately 310 BOE/d
        from
        the area. Based on the McDaniel Report, Provident has been assigned 1.9 Bcf
        of
        proven natural gas reserves. Crude oil and natural gas liquids reserves of
        192 Mbbls proved have also been assigned to the area. Provident also
        has
        undeveloped land holdings of 472 net acres in the area.
  ***Willesden
        Green, Alberta***
  Provident
        has an
        interest in 14 oil and natural gas wells (net 5.2 wells) and gathering and
        compression facilities in this area. For
        the period
        March 6, 2001 to December 31, 2001, t he
        property
        produced approximately 0.8 Mmcf/d of natural gas and 62 Bpd of oil
        and
        natural gas liquids. Current net production is approximately 340 BOE/d
        from
        the area. Based on the McDaniel Report, Provident has been assigned 2.4 Bcf
        of
        proven natural gas reserves. Crude oil and natural gas liquids reserves of
        151 Mbbls proved have also been assigned to the area. Provident also
        has
        undeveloped land holdings of 5,625 net acres in the area.
  ***2.***  ***Lloydminster
        Core Area***
  Provident
        established the Lloydminster area of Saskatchewan as a second core growth
        area,
        following Founders’ acquisition of Opal in late 1998. With the acquisition of
        Maxx in May 2001, this area was expanded to include heavy oil properties
        in
        Alberta. Provident currently operates 307 wells and three processing
        facilities at its seven properties at Epping, Freemont, Islay, Lashburn,
        Lloydminster, Meridian and Wildmere. All of the pools are on conventional
        primary cold production and in aggregate, currently capable of producing
        approximately 6,000 Bpd of 15 degree API heavy oil.
  ***Epping,
        Saskatchewan***
  The
        Epping area is
        located approximately 31 kilometers southeast of Lloydminster. Provident
        has a
        100% working interest and operates 35 heavy oil wells, which produce oil
        from
        the Sparky Formation. Production for the period March 6, 2001 to December
        31,
        2001 averaged 923 Bpd of 15 degree API heavy oil. Oil produced from the area
        is
        trucked to Provident’s pipeline connected Neilburg and Dulwich facilities. In
        1999, Provident discovered a new pool to the north of its existing production.
        Two and three-dimensional seismic programs were shot in late 1999 to better
        delineate the two Epping pools and define further infill locations on the
        established pool and step-outs to the new discovery. In 2000, 15 wells were
        drilled adding approximately 450 Bpd of production. In 2001, an additional
        10
        wells were drilled adding approximately 200 Bpd of production. Current
        production is approximately 950 Bpd. Based on the McDaniel Report, Provident
        has
        been assigned 816 Mbbls of proved crude oil reserves. Provident also
        has
        undeveloped land holdings of 1,351 net acres in the area.
  ***Freemont,
        Saskatchewan***
  The
        Freemont area
        is located approximately 74 kilometres southeast of Lloydminster. Provident
        operates and has an average 91% working interest in 32 (29.0 net) producing
        heavy oil wells which produce from the thick, very porous and permeable Waseca
        channel sandstone, the regional Waseca sandstone and the Sparky Formation.
        Oil
        produced from the area is trucked to Provident’s Neilburg facility or directly
        to sales terminals. For the period March 6, 2001 to December 31, 2001,
        Provident’s net share of production averaged 320 Bpd of 15 degree API heavy oil.
        Current production is approximately 180 Bpd. Based on the McDaniel Report,
        Provident has been assigned 372 Mbbls of proved crude oil reserves.
        Provident also has undeveloped land holdings of 2,025 net acres in the
        area.
  20
  ***Lashburn,
        Saskatchewan***
  Lashburn
        is located
        in close proximity to Provident’s existing properties in the Lloydminster area.
        Using existing two dimensional and newly acquired proprietary three dimensional
        seismic, Provident drilled three wells at Lashburn in late 2000, seven wells
        in
        2001 and six wells in the first quarter of 2002, all of which are 100% owned
        by
        Provident. The 16 Lashburn wells are currently producing at a combined rate
        of
        approximately 940 Bpd of 15 degree API heavy oil. For the period March
        6,
        2001 to December 31, 2001, Provident’s net share of production was 287 Bpd.
        Provident has been assigned 1,442 Mbbls of proved crude oil reserves
        for
        the area. At December 31, 2001, Provident has undeveloped land holdings of
        3,726
        net acres in this growth area.
  ***Dulwich
        and Neilburg, Saskatchewan***
  Provident
        operates
        a treating facility at Dulwich and another at Neilburg, both of which are
        owned
        100%. Most of the production from the Trust’s Saskatchewan heavy oil area is
        treated at one of these facilities and subsequently sold via the Husky or
        Manitou pipelines. The facilities at Dulwich and Neilburg have treating
        capacities of 1,100 Bpd and 2,700 Bpd of clean oil, respectively. There are
        also
        opportunities to process third-party volumes at both of the
        facilities.
  ***Islay,
        Alberta***
  The
        Islay area was
        acquired as part of the Maxx Arrangement and produces 15 degree API heavy
        oil.
        The 26, 100% working interest wells, produced 271 Bpd in the March 6, 2001
        to
        December 31, 2001 period. Currently, the field is producing 330 Bpd, net
        to
        Provident. Provident has been assigned 559 Mbbls of proved crude oil
        reserves for the area. At December 31, 2001, Provident has undeveloped land
        holdings of 1,107 net acres in this area.
  ***Lloydminster
        and Meridian, Alberta***
  The
        Lloydminster
        and Meridian fields were acquired as part of the Maxx Arrangement and produce
        15
        degree API heavy oil from 170 wells (169 net). The fields produced 2,503
        Bpd in
        the March 6, 2001 to December 31, 2001 period. Currently, the fields are
        producing 2,845 Bpd, net to Provident. Provident has been assigned
        7,411 Mbbls of proved crude oil reserves for the area. At December
        31,
        2001, Provident has undeveloped land holdings of 11,007 net acres in this
        area.
  ***Wildmere,
        Alberta***
  The
        Wildmere area
        was acquired as part of the Maxx Arrangement and produces 15 degree API heavy
        oil. The 34, 100% owned wells, produced 385 Bpd in the March 6, 2001 to December
        31, 2001 period. Currently, the field is producing 450 Bpd, net to Provident.
        In
        addition to the producing wells, Provident owns a treating facility in the
        area
        that processes most of Provident’s Alberta heavy oil production. This facility
        is capable of treating 2,500 Bpd of clean oil. Provident has been assigned
        819 Mbbls of proved crude oil reserves for the area. At December 31,
        2001,
        Provident has undeveloped land holdings of 968 net acres in this
        area.
  21
  ***3.***  ***Southeast
        Saskatchewan***
  ***Hartaven,
        Saskatchewan***
 The
        Hartaven area
        is located approximately 35 kilometres northeast of Weyburn. Provident operates
        and has an average 90% working interest in 29 light/medium oil wells, two
        disposal wells, a gathering system and two batteries, with an average working
        interest of 80%. Provident’s net share of production from the area for the
        period March 6, 2001 to December 31, 2001 averaged approximately 465 Bpd
        of
        light and medium oil. Current production is approximately 370 Bpd.
        Based on
        the McDaniel Report, Provident has been assigned 958 Mbbls of proved
        crude
        oil reserves for the area.
  ***Ingoldsby,
        Saskatchewan***
 The
        Ingoldsby area
        was acquired as part of the Maxx Arrangement and has 33 wells with an average
        working interest of 74%. Provident’s net share of production from the area for
        the period March 6, 2001 to December 31, 2001 averaged approximately
        230
        Bpd of light oil. Current production is approximately 370 Bpd. Based
        on the
        McDaniel Report, Provident has been assigned 764 Mbbls of proved crude
        oil
        reserves for the area.
  ***Silverton,
        Saskatchewan***
 Provident
        operates
        38 wells (35.4 net) in the Silverton area that was acquired as part of the
        Maxx
        Arrangement. Provident’s net share of production from the area for the period
        March 6, 2001 to December 31, 2001 averaged approximately 298 Bpd of light
        oil.
        Current production is approximately 320 Bpd. Based on the McDaniel
        Report,
        Provident has been assigned 701 Mbbls of proved crude oil reserves
        for the
        area.
  **(d)**  **Reserves**
  The
        oil, natural
        gas and NGL reserves of Provident as of January 1, 2002 have been
        evaluated
        by McDaniel utilizing McDaniel January 1, 2002 pricing as set forth
        in the
        McDaniel Report. McDaniel conducted evaluations based on constant price
        assumptions of Provident’s oil, gas and NGL reserves and present worth of future
        cash flows associated with such reserves. The results of the evaluations
        of
        McDaniel, contained in the McDaniel Report, are summarized in the tables
        below **.
        The
        present worth of estimated future cash flows contained in the following tables
        may not be representative of the fair market values of the
        reserves** .
        Assumptions
        relating to costs, prices for future production and other matters are summarized
        in the notes following the tables. There is no assurance that such prices
        and
        cost assumptions will be attained and variances could be material. All estimated
        future cash flows set forth in the following tables are stated prior to
        provision for income taxes, indirect costs, and future site restoration costs,
        and after deduction of operating costs, royalties and estimated future capital
        expenditures. The McDaniel Report is based on certain factual data including
        operating costs, property descriptions, details of interests held, well data,
        future development plans and future capital estimates supplied by Provident
        and
        on McDaniel’s opinion of reasonable practice in the industry.
  22
  **Oil
        and
        Natural Gas Reserves and Present Value of Estimated Future Cash
        Flows**
 **in
        Respect
        of Provident Based on Constant Price Assumptions**
 
 **Company
                  Gross Reserves**(1)
              **Company
                  Net Reserves**(2)
              **Present
                  Worth Value Discounted at**(3)(4)**Oil**
              **Natural
                  Gas Liquids**
              **Natural
                  Gas**
              **Oil**
              **Natural
                  Gas Liquids**
              **Natural
                  Gas**
              **0%**
              **10%**
              **12%**
              **15%**
              **20%****Constant
                  Prices**
              **(Mbbls)**
              **(Mbbls)**
              **(Mmcf)**
              **(Mbbls)**
              **(Mbbls)**
              **(Mmcf)**
              **($000s)**Proved
                  Reserves(5)Producing(6)
              9,696
              876
              28,009
              8,544
              599
              20,616
              130,189
              101,260
              97,469
              92,477
              85,559Non-Producing(7)
              872
              50
              1,767
              821
              34
              1,291
              5,119
              3,855
              3,656
              3,386
              2,999Undeveloped(8)
              1,224
              75
              2,423
              1,107
              59
              2,009
              8,918
              4,742
              4,238
              3,599
              2,770Total
                  Proved
              11,792
              1,001
              32,199
              10,472
              692
              23,916
              144,226
              109,857
              105,363
              99,462
              91,328
  (1)
              Gross
                  Reserves are the aggregate of Provident’s working interest and royalty
                  interest reserves before deductions of royalties payable to
                  others.
  (2)
              Company
                  Net
                  Reserves are the Gross Reserves less all royalties payable to
                  others.
  (3)
              Present
                  worth
                  values have been calculated before deduction of income tax. The
                  present
                  worth values are not to be construed as fair market value of the
                  reserves.
  (4)
              Reserves
                  and
                  present worth values may not add due to
                  rounding.
  (5)
              Proven
                  Reserves are those quantities of crude oil, natural gas, and natural
                  gas
                  by-products, which, upon analysis of geologic and engineering data,
                  appear
                  with a high degree of certainty to be recoverable at commercial
                  rates in
                  the future from known oil and gas reservoirs under presently anticipated
                  economic and operating conditions. There is relatively little risk
                  with
                  these reserves.
  (6)
              Proven
                  Developed Producing Reserves are proven reserves that can be expected
                  to
                  be recovered through existing wells with existing equipment and
                  operating
                  methods that are presently being produced from completion intervals
                  open
                  for production in existing wells.
  (7)
              Proven
                  Developed Non-Producing Reserves are proven reserves that are currently
                  not being produced but do exist in completed but not producing,
                  intervals
                  in existing wells, behind casing in existing wells or at minor
                  depths
                  below the present bottom of existing wells. These proven reserves
                  are
                  expected to be produced through the existing wells in the predictable
                  future. These reserves are classified as proven developed because
                  the cost
                  of making such reserves available for production is relatively
                  small,
                  compared to the cost of a new well.
  (8)
              Proven
                  Undeveloped Reserves are proven reserves that are expected to be
                  recovered
                  from new wells on undrilled acreage, or from existing wells where
                  relatively major expenditures are required for completion installation
                  of
                  processing and gathering facilities prior to the production of
                  the
                  reserves. Reserves on undrilled acreage are limited to those drilling
                  units offsetting productive wells, where there is reasonable certainty
                  of
                  production.
   **Constant
        Price Summary Schedule (at December 31, 2001)**
  West
                  Texas
                  Intermediate ($US/Bbl)(1)
              19.78Corporate
                  Avg
                  Light Oil ($CDN/Bbl)(2)
              25.46Corporate
                  Avg
                  Heavy Oil ($CDN/Bbl)(2)
              13.69Corporate
                  Avg
                  Gas ($CDN/Mcf)(2)
              3.68Corporate
                  Avg
                  NGL ($CDN/Bbl)(2)
              22.20
  (1)
              December
                  31,
                  2001 NYMEX close.
  (2)
              Provident
                  estimate of corporate average price received on December 31,
                  2001.
   The
        extent and
        character of ownership and all information related to revenues and expenses,
        forecast expenditures and other data were accepted by McDaniel as provided
        by
        Provident. Only direct field expenditures and incomes have been evaluated
        in the
        McDaniel Report. General and administrative expenses and incomes are not
        reported. McDaniel did not consider it necessary to complete a field
        inspection.
  **(e)**  **Reserve
        Reconciliation**
  **Proved
                  Crude Oil & Liquids**
              **Proved
                  Natural Gas**
              **Proved
                  Oil Equivalent****(Mbbl)**
              **(Bcf)**
              **(MBOE)**As
                  of March
                  6, 2001
              6,466
              23.2
              10,333Additions
              681
              1.2
              881Acquisition
                  of Maxx
              13,592
              17.9
              16,575Revisions
              (5,793)
              (5.4)
              (6,673)Dispositions
              (5)
              -
              (5)Production
              (2,149)
              (4.7)
              (2,932)As
                  of January
                  1, 2002
              12,792
              32.2
              18,159Change
                  (%)
              98
              39
              76
 
 23
  The
        2001 year-end
        reserve estimates are prepared using applicable industry standard engineering
        practices that are consistent with prior years. Reserve revisions for 2001
        are
        primarily attributed to a change in reserve estimates based on a longer period
        of production history or changes in well performance and are not a result
        of
        changes in methodology, and are also due to low year-end prices making some
        reserves uneconomical.
  **(f)**  **Capital
        Program Efficiency Ratios and Finding Costs**
  The
        following table
        summarizes Provident’s capital spending efficiencies and finding costs. For the
        years ended 1999 and 2000, the data is from Founders, while 2001 represents
        the
        period March 6, 2001 to December 31, 2001 for Provident. Finding and development
        costs presented in the following table are based on reserve additions
        only.
  **Finding
        and
        On-stream Costs**
  **The
                  Trust**                             
                                  
                      **Founders****For
                  the period March 6, 2001 to December31, 
                  2001**
              
              
              **For
                  the year ended**
                **December
                  31, 2000**
              
              
              **For
                  the year ended December 31, 1999**Capital
                  expenditures ($millions) (1)
              
              
              158.3
              
              
              28.1
              
              
              23.1Proved
                  reserve additions (MBOE)
              
              
              17,456
              
              
              4,554
              
              
              3,491
   **2001**
              
              
              **2000**
              
              
              **1999**Proved
                  finding and on-stream costs ($/BOE)
              
              
              9.07
              
              
              6.16
              
              
              6.62**Notes:**(1)Includes
                  all
                  capital expenditures, property acquisitions and corporate
                  acquisitions.(2)Based
                  on
                  aggregate reserve additions, less revisions.
 
 **(g)**  **Efficiency
        Ratios and Statistics**
  **The
                  Trust**
              **Founders****For
                  the period**
                **March
                  6, 2001 to**
                **December
                  31, 2001**
              **For
                  the year ended**
                **December 31,
                  2000**
              **For
                  the year ended**
                **December 31,
                  1999**Production
                  (MBOE)
              3,932
              1,542
              1,796Field
                  netbacks ($/BOE)
              $15.27
              $19.20
              $8.68Proved
                  reserve replacement ratio (1)
              4.4
              3.0
              1.9Proved
                  recycle ratio (2)
              1.7
              3.1
              1.3Proved
                  reserve life index (years) (3)-Oil
                  equivalent
              6.2
              6.9
              6.0**Notes:**(1)Represents
                  the ratio of proved reserve additions to annual
                  production.(2)Represents
                  the ratio of field netbacks to proved finding and on-stream
                  costs.(3)Based
                  on
                  average production rates for the year
 
 24
  **(h)**  **Drilling
        History**
  Provident
        drilled
        or participated in the drilling of the following wells for the following
        periods:
  **The
                  Trust**
              
              **Founders****For
                  the period March 6, 2001 to December 31, 2001**
              
              **For
                  the year ended**
                **December
                  31, 2000**
              
              **For
                  the year ended**
                **December
                  31, 1999****Gross**
              
              **Net**
              
              **Gross**
              
              **Net**
              
              **Gross**
              
              **Net**Oil
              19
              
              18.1
              
              22
              
              20.3
              
              11
              
              10.0Gas
              4
              
              0.7
              
              6
              
              4.9
              
              7
              
              5.1Abandoned
              -
              
              -
              
              3
              
              2.1
              
              5
              
              3.6Total
              23
              
              18.8
              
              31
              
              27.3
              
              23
              
              18.7
 
 **(i)**  **Oil
        and
        Natural Gas Wells**
  The
        following table
        summarizes, as of December 31, 2001, Provident’s interests in producing
        wells and in non-producing wells, which Provident believes are capable of
        commercial production of oil or natural gas. The stated interests are subject
        to
        landowners and other royalties, where applicable, in addition to usual Crown
        royalties and mineral taxes.
  **Producing
                  Wells**
              **Non-Producing
                  Wells(1)****Oil**
              **Natural
                  Gas**
              **Oil**
              **Natural
                  Gas****Gross(2)**
              **Net(3)**
              **Gross(2)**
              **Net(3)**
              **Gross(2)**
              **Net(3)**
              **Gross(2)**
              **Net(3)****Alberta**Carrot
                  Creek
              1
              0.2
              7
              1.2
              -
              -
              -
              -Clive
              1
              0.5
              11
              9.4
              2
              2.0
              6
              4.0Cow
                  Lake
              -
              -
              5
              2.3
              -
              -
              1
              1.0Gilby
              7
              4.1
              35
              24.9
              -
              -
              10
              9.2Islay
              13
              13.0
              -
              -
              13
              13.0
              -
              -Lloydminster
              78
              77.5
              -
              -
              75
              75.0
              -
              -Meridian
              13
              13.0
              -
              -
              4
              4.0
              -
              -Westward
                  Ho
              16
              6.9
              3
              1.5
              -
              -
              2
              0.4Wildmere
              19
              19.0
              -
              -
              15
              15.0
              -
              -Willesden
                  Green
              4
              2.0
              4
              1.8
              2
              1.0
              4
              0.4**Saskatchewan**Epping
              27
              27.0
              -
              -
              8
              8.0
              -
              -Freemont
              9
              8.0
              -
              -
              23
              21.0
              -
              -Lashburn
              7
              7.0
              -
              -
              3
              3.0
              -
              -Hartaven
              28
              25.0
              -
              -
              1
              1.0
              -
              -Ingoldsby
              31
              22.1
              -
              -
              3
              2.3
              -
              -Silverton
              34
              31.7
              -
              -
              4
              3.7
              -
              -Other
                  minor
                  properties
              68
              50.8
              25
              6.3
              29
              27.4
              13
              2.6**Total**
              356
              307.8
              90
              47.4
              182
              176.4
              36
              17.6
  **Notes:**
  (1)
              Non-producing
                  wells are wells, which are capable of economic production or which
                  Provident considers capable of production but which, for a variety
                  of
                  reasons, are not placed on production at the present time. All
                  non-producing wells are located within 2.5 kilometers of
                  facilities.
  (2)
              Gross
                  wells
                  mean the number of wells in which Provident has an
                  interest.
  (3)
              Net
                  wells
                  means the aggregate numbers obtained by multiplying each gross
                  well by
                  Provident’s percentage interest in the
                  well.
  **(j)**  **Production
        History**
  The
        following table
        sets forth Provident’s working interest production of oil and natural gas,
        before deduction of royalties, for the following periods:
  25
  **The
                  Trust**
              
              **Founders****For
                  the Period**
                **March 6,
                  2001 to**
                **December
                  31, 2001**
              
              **For
                  the Year Ended**
                **December
                  31, 2000**
              
              **For
                  the Year Ended**
                **December
                  31, 1999**Crude
                  Oil and
                  NGLTotal
                  net
                  production (Bbls)
              
              2,148,586
              
              893,040
              
              1,048,725Per
                  day
                  (Bpd)
              
              7,139
              
              2,440
              
              2,873Natural
                  GasTotal
                  net
                  production (Mcf)
              
              4,747,364
              
              3,892,776
              
              4,484,527Per
                  day
                  (Mcf/d)
              
              15,772
              
              10,636
              
              12,286Oil
                  equivalentTotal
                  net
                  production (BOE)
              
              2,939,813
              
              1,541,836
              
              1,796,146Per
                  day
                  (BOE/d)
              
              9,767
              
              4,212
              
              4,921
 
 **(k)**  **Land
        Holdings**
  The
        following table
        sets out Provident’s undeveloped and developed land holdings as of January 1,
        2002.
  **Undeveloped****(1)**
              
              **Gross
                  Acres(2)**
              
              **Net
                  Acres(3)**Alberta
              
              167,960
              
              89,924Saskatchewan
              
              71,287
              
              64,310British
                  Columbia
              
              7,228
              
              2,822Total
              
              246,475
              
              157,056**Developed**Alberta
              
              111,688
              
              42,921Saskatchewan
              
              24,616
              
              18,288British
                  Columbia
              
              658
              
              12Total
              
              136,962
              
              61,221**Notes:**(1)Undeveloped
                  land holdings refers to those lands in which Provident has an interest
                  and
                  which have not been assigned reserves.(2)Gross
                  acres
                  refers to the number of acres in which Provident has an
                  interest.(3)Net
                  acres
                  refers to the aggregate of the numbers obtained by multiplying
                  each gross
                  acre by Provident’s percentage interest in the acre.
 
 Seaton
        Jordan,
        independent land consultants, evaluated Provident’s existing undeveloped land as
        of January 1, 2002 in the Seaton Jordan Report. The Seaton Jordan Report
        estimated the market value of these land holdings at $18.7 million.
  Market
        value is
        defined as the price which Seaton Jordan, as independent consultants, given
        the
        conditions existing at January 1, 2002, believe could reasonably be expected
        to
        be received for these properties in a sale. In order to determine the market
        value, Seaton Jordan analyzed the most current prices paid at land sales
        for
        properties in the immediate vicinity. In addition, recognition was given
        to the
        remaining terms of the oil and gas leases as well as any particular burdens
        such
        as overriding royalties.
  **(l)**  **Capital
        Expenditures**
  The
        following table
        summarizes Provident’s capital expenditures for the following
        periods:
  **The
                  Trust**
              
              **Founders****For
                  the period**
                **March
                  6, 2001 to December 31, 2001**
              
              **For
                  the year ended December 31, 2000**
              
              **For
                  the year ended December 31, 1999**Land
                  Acquisitions
              $
              359
              $
              4,799
              $
              1,131Seismic
              
              327
              
              1,377
              
              2,524Drilling
                  and
                  Completions
              
              5,696
              
              15,649
              
              11,822Production
                  Facilities
              
              4,471
              
              1,383
              
              3,432Other
              
              126
              
              295
              
              140Capital
                  Expenditures, excluding
                Acquisitions
              
              10,979
              
              23,503
              
              19,049Acquisitions
              
              147,369
              
              4,571
              
              4,054Total
                  Capital
                  Expenditures
              $
              158,348
              $
              28,074
              $
              23,103
  26
  Capital
        expenditures are not budgeted a year in advance, but capital expenditures
        on
        wells are determined in conjunction with property or corporate acquisitions.
        No
        firm capital commitments were in place as of December 31, 2001. As of June
        30,
        2002, Provident had estimated capital expenditures for 2002 of $20 million
        related to planned or existing drilling at approximately 30 locations. Provident
        intends to finance these capital expenditures with borrowings under its credit
        facility.
  ***1.***  ***Production
        History, Prices Received and Capital Expenditures***
  The
        following table
        sets forth production data, production prices received and expenditures made
        by
        Founders for each quarter for the year ended December 31, 2000 and for Provident
        for the period March 6, 2001 to March, 31, 2001 and the quarters ended June
        30,
        2001, September 30, 2001 and December 31, 2001.
 **The
                    Trust**
                
                **Founders**
                
                **The
                    Trust**
                
                
                **Founders**
                
                
                **The
                    Trust**
                
                
                **Founders**
                
                
                **The
                    Trust**
                
                
                **Founders****For
                    the period March 6, 2001 to March 31,**
                
                **Three
                    months ended**
                  **March
                    31,**
                
                **Three
                    month ended**
                  **June
                    30,**
                
                **Three
                    months ended September 30,**
                
                **Three
                    months ended December 31,****2001**
                
                **2000**
                
                **2001**
                
                
                **2000**
                
                
                **2001**
                
                
                **2000**
                
                
                **2001**
                
                
                **2000**Average
                    Daily
                    Production (before deductionof
                    royalties)Crude
                    oil
                    (Bpd)
                
                2,937
                
                2,130
                
                4,769
                
                
                1,811
                
                
                8,399
                
                
                2,382
                
                
                7,744
                
                
                2,590Natural
                    gas
                    (Mcf/d)
                
                11,155
                
                12,418
                
                14,914
                
                
                11,408
                
                
                18,324
                
                
                9,446
                
                
                15,373
                
                
                9,300NGLs
                    (Bpd)
                
                235
                
                233
                
                479
                
                
                233
                
                
                639
                
                
                218
                
                
                485
                
                
                156Combined
                    (BOE/d)
                
                5,031
                
                4,432
                
                7,733
                
                
                3,946
                
                
                12,093
                
                
                4,175
                
                
                10,792
                
                
                4,296Average
                    Net
                    Prices ReceivedCrude
                    Oil
                    ($/Bbl)
                
                25.36
                
                32.96
                
                26.18
                
                
                32.39
                
                
                26.89
                
                
                35.86
                
                
                19.79
                
                
                27.74Natural
                    gas
                    ($/Mcf)
                
                9.45
                
                3.35
                
                6.07
                
                
                4.29
                
                
                4.61
                
                
                5.84
                
                
                4.65
                
                
                8.03NGLs
                    ($/Bbl)
                
                44.12
                
                29.29
                
                38.24
                
                
                31.54
                
                
                31.24
                
                
                35.53
                
                
                23.18
                
                
                58.8Equivalent
                    ($/BOE)
                
                37.81
                
                26.77
                
                30.23
                
                
                29.14
                
                
                27.32
                
                
                35.53
                
                
                26.64
                
                
                36.23Royalties
                    ($/BOE)(1)
                
                6.2
                
                7.49
                
                5.34
                
                
                6.98
                
                
                4.84
                
                
                8.17
                
                
                3.1
                
                
                8.22Operating
                    Expenses ($/BOE)(2)
                
                7.62
                
                6.09
                
                6.79
                
                
                5.63
                
                
                7.04
                
                
                6.94
                
                
                6.86
                
                
                7.03Cash
                    Field
                    Netback Received ($/BOE)
                
                23.99
                
                15.3
                
                18.1
                
                
                17.6
                
                
                15.44
                
                
                22.43
                
                
                11.9
                
                
                21.51Capital
                    Expenditures ($000s)(3)
                
                2,206
                
                2,807
                
                207,488
                
                
                10,085
                
                
                2,793
                
                
                5,919
                
                
                5,246
                
                
                8,335(1)
                    Royalties
                    are net of ARTC.(2)
                    This
                    figure includes all field operating expenses.(3)
                    Capital
                    expenditures include acquisitions, net of dispositions.
  27
  **(m)**  **Canadian
        Government Regulation**
  The
        Trust and
        Provident, and the Canadian oil and natural gas industry in general, are
        subject
        to extensive controls and regulations imposed by various levels of the Canadian
        government. Outlined below are some of the more significant aspects of the
        relevant legislation and regulations.
  ***1.***  ***Pricing
        and Marketing - Oil***
  Producers
        of oil
        negotiate sales contracts directly with oil purchasers, with the result that
        the
        market determines the price of oil. The price depends in part on oil quality,
        price of competing oils, distance to market and the value of refined products.
        Oil exporters are also entitled to enter into export contracts and export
        oil
        provided that, for contracts which do not exceed one year in the case of
        light
        crude oil and two years in the case of heavy crude oil, an export order must
        be
        obtained from the National Energy Board prior to the export. Any export pursuant
        to a contract of longer duration must be made pursuant to a National Energy
        Board export license and Governor in Council approval.
  ***2.***  ***Pricing
        and Marketing - Natural Gas***
  The
        price of
        natural gas sold in intra-provincial and inter-provincial trade is determined
        by
        negotiation between buyers and sellers. Natural gas exported from Canada
        is
        subject to regulation by the National Energy Board and the government of
        Canada.
        The price received by Provident depends, in part, on the prices of competing
        natural gas and other substitute fuels, access to downstream transportation,
        distance to markets, length of the contract term, weather conditions, the
        supply
        and demand balance and other contractual terms. Exporters are free to negotiate
        prices with purchasers, provided that the export contracts must continue
        to meet
        certain criteria prescribed by the National Energy Board and the government
        of
        Canada. As in the case with oil, natural gas exports for a term of less than
        two
        years must be made pursuant to a National Energy Board order and, in the
        case of
        exports for a longer duration, pursuant to a National Energy Board license
        and
        Governor in Council approval.
  The
        government of
        Alberta also regulates the volume of natural gas which may be removed from
        the
        province for consumption elsewhere.
  ***3.***  ***The
        North American Free Trade Agreement***
  On
        January 1, 1994 the North American Free Trade Agreement (“NAFTA”) among the
        governments of Canada, the United States and Mexico became effective. NAFTA
        carries forward most of the material energy terms contained in the Canada-U.S.
        Free Trade Agreement. In the context of energy resources, Canada continues
        to
        remain free to determine whether exports to the U.S. or Mexico will be allowed
        provided that the restrictions are otherwise justified under certain provisions
        of the General Agreement on Tariffs and Trade and then only if any export
        restrictions do not: (i) reduce the proportion of the energy resource exported
        relative to the total supply of energy resource (based upon the proportions
        prevailing in the most recent 36 months); (ii) impose an export price
        higher than the domestic price; or (iii) disrupt normal channels of supply.
        All
        three countries are prohibited from imposing minimum export or import price
        requirements.
  NAFTA
        contemplates
        the reduction of Mexican restrictive trade practices in the energy sector
        and
        prohibits discriminatory border restrictions and export taxes. The agreement
        also contemplates clearer disciplines on regulators to avoid discriminatory
        actions and to minimize disruption of contractual arrangements.
 28
  ***4.***  ***Provincial
        Royalties and Incentives***
  In
        addition to federal regulation, each province has legislation and regulations
        which govern land tenure, royalties, production rates, environmental protection
        and other matters. The royalty regime is a significant factor in the
        profitability of oil and natural gas production. Royalties payable on production
        from lands other than Crown lands are determined by negotiations between
        the
        mineral owner and the lessee. Crown royalties are determined by governmental
        regulation and are generally calculated as a percentage of the value of the
        gross production, and the rate of royalties payable generally depends in
        part on
        well productivity, geographical location, field discovery data and the type
        or
        quality of the petroleum product produced.
  From
        time to time the
        governments of Canada and Alberta have established incentive programs which
        have
        included royalty rate reductions, royalty holidays and tax credits for the
        purpose of encouraging oil and natural gas production and enhanced production
        projects.
  ***5.***  ***Alberta***
  In
        Alberta, a producer of oil or natural gas is entitled to a credit against
        the
        royalties payable to the Crown by virtue of the ARTC program. The ARTC rate
        is
        based on a price-sensitive formula and varies between 75% for prices at or
        below
        the royalty tax credit reference price of $100 per m 3 decreasing to 25%
        for prices above the royalty tax credit reference price of $210 per
        m 3 .
        The ARTC rate
        will be applied to a maximum annual amount of $2,000,000 of Alberta Crown
        royalties payable for each producer or associated group of producers. Crown
        royalties on production from producing properties acquired from corporations
        claiming maximum entitlements to ARTC will generally not be eligible for
        ARTC.
        The rate is established quarterly based on the average par price, as determined
        by the Alberta Department of Energy.
  On
        October 13, 1992, the Alberta government announced major changes to
        its
        royalty structure and permanent incentives for exploring and developing oil
        and
        gas reserves. The significant changes announced which remain in force include
        the following: (i) the first wells drilled in new oil pools discovered
        on
        or after October 1, 1992 will have a permanent one year oil royalty
        holiday, subject to a $1,000,000 cap and a reduced royalty rate thereafter;
        (ii) reduction of royalties on pre-October 1, 1992 production
        of oil
        and gas; (iii) incentives by way of royalty holidays and reduced royalties
        on reactivated, low productivity and horizontal re-entry of vertical oil
        wells;
        (iv) introduction of separate par pricing for light, medium and heavy
        oil;
        and (v) modification of the royalty formula structure to provide for
        sensitivity to price fluctuations.
  ***6.***  ***Environmental
        Regulation***
  The
        oil and natural
        gas industry is currently subject to environmental regulations pursuant to
        provincial and federal legislation. Environmental legislation provides for
        restrictions and prohibitions on releases or emissions of various substances
        produced in association with certain oil and gas industry operations. In
        addition, legislation requires that well and facility sites be abandoned
        and
        reclaimed to the satisfaction of provincial authorities. A breach of such
        legislation may result in the imposition of fines and penalties, the suspension
        or revocation of necessary licenses and civil liability. Environmental
        legislation in Alberta has been consolidated into the Environmental Protection
        and Enhancement Act (Alberta) which took effect on September 1, 1993.
        The
        Environmental Protection and Enhancement Act (Alberta) imposes stricter
        environmental standards, requires more stringent compliance and reporting
        and
        significantly increases penalties for non-compliance.
 29
  In
        1994, the United Nations’ Framework Convention on Climate Change came into force
        and three years later led to the Kyoto Protocol which will require, upon
        ratification, nations to reduce their emissions of carbon dioxide and other
        greenhouse gases. Canada has not ratified the Kyoto Protocol, but should
        it do
        so, reductions in greenhouse gases from oil and gas operations may be required
        which could result in increased capital expenditures and reductions in
        production of oil and gas. It is expected that other changes in environmental
        legislation may also require, among other things, reductions in emissions
        to the
        air from oil and gas operations and result in increased capital expenditures.
        Although it is not expected that future changes in environmental legislation
        will result in materially increased costs, such changes could occur and result
        in stricter standards and enforcement, larger fines and liability, and increased
        capital expenditures and operating costs, which could have a material adverse
        effect on the Trust’s financial condition or results of operations.
  ***7.***  ***Exports
        from Canada***
  In
        order to export oil or natural gas from Canada, certain approvals are required
        from the National Energy Board and the Government of Canada. The approval(s)
        required are dependent on the hydrocarbon substance being exported and the
        length of the proposed export arrangement.
  **II.**  **Business
        Overview of Richland**
  On
        January 15, 2002, subsequent to the 2001 year-end discussed in this
        annual
        report, the Trust and Provident completed the Richland Arrangement. The
        following is a description of the business and properties of Richland prior
        to
        the Richland Arrangement.
  **(a)**  **Principal
        Oil and Gas Properties**
  The
        following sets
        out the principal properties of Richland and operational information related
        to
        them.
  ***Paddle
        River/Heldar, Alberta***
  The
        Paddle
        River/Heldar area, 60 miles northwest of Edmonton, had been Richland’s primary
        growth area for natural gas in 1999 and 2000. During 2001, gas production
        declined 48% and oil and liquids production declined 55%, primarily due to
        increasing water production at a significant well. As at December 31,
        2001,
        Richland had an interest in 30,900 gross (26,100 net) acres of undeveloped
        land
        in the area. Production for the year ended December 31, 2001 averaged
        7.8
        Mmcf/d of natural gas and 308 Bpd of oil and liquids. The McDaniel
        Report
        assigned 3.2 MMBOE of proved reserves to this interest.
  ***Whitecourt,
        Alberta***
  Located
        15 miles
        northwest of Paddle River, Richland acquired an interest in 76,000 gross
        acres
        (32,600 net acres) of undeveloped land, a 45% ownership in a 65 Mmcf/d gas
        plant
        with substantial unused capacity, and approximately 40 Bpd of oil and liquids
        and 6.1 Mmcf/d of natural gas production in the Whitecourt area effective
        January 1, 2001. This is a multi-zone area targeting natural gas with
        liquids, which has significant exploitation upside. Richland drilled 13 gross
        (6
        net) wells in the area in 2001. As of December 31, 2001, Richland
        had an
        interest in 78,000 gross (34,200 net) acres of undeveloped land in the area.
        Production for the year ended December 31, 2001 averaged 56 Bpd of
        oil and
        liquids and 7.3 Mmcf/d of natural gas. The McDaniel Report assigned proved
        reserves of 3.4 MMBOE to this interest.
  On
        February 2, 2001, Richland announced that it had completed the purchase of
        a 50%
        interest in a significant natural gas property in the Whitecourt area for
        $32.9
        million. At that time, net production form Richland’s share of the property was
        approximately 650 BOE/d (94% natural gas). Richland also acquired a 45% working
        interest in a 65 Mmcf/d processing/facility as well as between 41% and 50%
        in
        six compressors.
  30
  ***Southern
        Alberta***
  Southern
        Alberta
        was Richland’s most active area in 2001, with 34 gross (28 net) wells drilled.
        The area is primarily a multi-zone shallow gas play, with year-round access.
        At
        December 31, 2001, Richland had an interest in 88,200 gross (66,700
        net)
        acres of undeveloped land in the area. Production in 2001 averaged 9.0 Mmcf/d
        of
        natural gas and 553 Bpd of oil and liquids. The McDaniel Report assigned
        3.7
        MMBOE of proved reserves to this interest.
  ***Southeast
        Saskatchewan***
  Southeast
        Saskatchewan is Richland’s primary oil producing area. At December 31,
        2001, Richland had an interest in 35,400 gross (28,500 net) acres of undeveloped
        land in the area. Production in 2001 averaged 1,573 BOE/d, consisting primarily
        of crude oil. The McDaniel Report assigned 3.5 MMBOE of proved reserves to
        this
        interest.
  ***East
        Lost Hills, California***
  At
        December 31, 2001, Richland’s U.S. subsidiary had a 4.13% working interest
        in approximately 32,000 gross (1,300 net) acres of exploratory land in the
        San
        Joaquin basin of California. Exploration at East Lost Hills targets the Temblor
        formation at depths greater than 16,000 feet. To date, the East Lost Hills
        consortium has drilled four wells into the feature. Two additional wells
        are
        currently being drilled at depths in excess of 17,000 feet. The consortium
        has
        shot a large (165 sq. mile) 3D seismic program to assist in the optimization
        of
        this gas discovery.
  The
        first well into
        the feature blew out at a depth of 16,700 feet. A relief well was sidetracked
        after killing the blowout and was completed, pending the testing of other
        wells.
        The third well, Berkley East Lost Hills #1, was drilled to a total depth
        of
        19,742 feet and was tied into existing facilities in the area. Production
        from
        this well, which was placed on-stream in February, has been limited to less
        than
        2.0 Mmcf/d pending the installation of water disposal facilities in
        2002.
  Net
        production in
        2001 averaged 0.1 Mmcf/d of natural gas and 8 Bpd of liquids. The McDaniel
        Report assigned 0.4 MMBOE of proved reserves to this interest.
  **(b)**  **Acquisition
        of Coast Pacific**
  On
        April 23, 2001, Richland announced that it had completed the acquisitions
        of all
        of the issued and outstanding shares of Coast Pacific by way of a take-over
        bid.
        Pursuant to the take-over bid, a total of 180,000 Richland Shares were issued
        to
        Coast Pacific shareholders, representing .0206 Richland Shares for every
        Coast
        Pacific common share and .02 Richland Share for every Coast Pacific preferred
        share. Coast Pacific subsequently became a wholly-owned subsidiary of
        Richland.
  **(c)**  **Oil
        and
        Natural Gas Reserves**
  The
        following is a
        summary, as of January 1, 2002, of the McDaniel Richland Report’s estimate
        of Richland’s crude oil, NGLs and natural gas reserves attributable to the
        properties and the present worth value of the estimated future net cash flows
        associated with these reserves, based on constant price and cost assumptions.
        The table summarizes the data contained in the evaluations and as a result
        may
        contain slightly different numbers than the evaluations due to rounding.
        All
        future cash flows are stated prior to provision for income taxes, interest,
        general and administrative expenses and indirect costs and after deduction
        of
        royalties and estimated future capital expenditures. It should not be assumed
        that the present worth of estimated future cash flows shown below is
        representative of the fair market value of the reserves. There is no assurance
        that these price and cost assumptions will be attained and variances could
        be
        material. The recovery and reserve estimates of Richland’s crude oil, NGLs and
        natural gas reserves provided in this summary are estimates only and there
        is no
        guarantee that the estimated reserves will be recovered. Actual reserves
        may be
        greater than or less than the estimates provided here.
  31
  **Oil
        and
        Natural Gas Reserves and Present Value of Estimated Future**
  **Cash
        Flows
        of Richland** **Based
        on
        Constant Price Assumptions**
  **Gross
                  Reserves (1)**
              
              **Net
                  Reserves**
              
              **Present
                  Worth Value Discounted at (6)****Oil**
              **NGLs**
              **Natural
                  Gas**
              
              **Oil**
              **NGLs**
              **Natural
                  Gas**
              
              **0%**
              **10%**
              **15%**
              **20%****(Mbbls)**
              **(Mbbls)**
              **(Mmcf)**
              
              **(Mbbls)**
              **(Mbbls)**
              **(Mmcf)**
              
              **($000s)**Proved
                  Reserves (2)Producing
                  (3)
              3,966
              644
              43,967
              
              3,392
              437
              33,383
              
              130,570
              95,870
              85,362
              77,311Non-Producing
                  (4)
              240
              55
              8,297
              
              195
              39
              6,017
              
              16,880
              9,644
              8,107
              7,042Undeveloped
                  (5)
              344
              75
              2,150
              
              284
              59
              1,657
              
              6,043
              3,867
              3,133
              2,552**TOTAL**
              4,549
              775
              54,414
              
              3,870
              535
              41,057
              
              153,492
              109,381
              96,603
              86,904
  
 (1)
              “Gross”
                  means
                  Richland’s working interests and/or royalty interests share of reserves
                  before deducting royalties owned by others. “Net” means Richland’s working
                  interests and/or royalty interests share of reserves after deducting
                  the
                  amounts attributable to the royalties owned by others. In order
                  to
                  estimate reserves after giving effect to the deduction of provincial
                  royalties, certain assumptions must be made including forecasts
                  of future
                  prices and production. The net reserves are based on forecasts
                  prepared by
                  McDaniel of these and other factors necessary to estimate provincial
                  and
                  other royalties.
  (2)
              “Proved
                  reserves” means those reserves estimated as recoverable under current
                  technology and existing economic conditions, from that portion
                  of a
                  reservoir which can be reasonably evaluated as economically productive
                  on
                  the basis of analysis of drilling, geological, geophysical and
                  engineering
                  data, including the reserves to be obtained by enhanced recovery
                  processes
                  demonstrated to be economic and technically successful in the subject
                  reservoir. Reserves assigned to non-producing zones in producing
                  wells
                  were classified as producing if the reserve quantities were estimated
                  to
                  be minor relative to Richland’s reserves in the
                  area.
  (3)
              “Proved
                  producing reserves” means those proved reserves that are actually on
                  production, or if not producing, that could be recovered from existing
                  wells or facilities and where the reasons for the current non-producing
                  status is the choice of the owner. An illustration of such a situation
                  is
                  where a well or zone is capable but is shut-in because its deliverability
                  is not required to meet contract commitments. Reserves assigned
                  to
                  non-producing zones in producing wells were classified as producing
                  if the
                  reserve quantities were estimated to be minor relative to Richland’s
                  reserves in the area.
  (4)
              “Proved
                  non-producing reserves” are those non-producing proved reserves from
                  existing wells that require relatively minor capital expenditures
                  to
                  produce.
  (5)
              “Proved
                  undeveloped reserves” are those reserves expected to be recovered from new
                  wells on undrilled acreage, or from existing wells where a relatively
                  major expenditure will be required.
  (6)
              The
                  constant
                  price assumptions assume the continuance of current laws, regulations
                  and
                  productions costs in effect on the date of the McDaniel Report.
                  The
                  constant oil and gas price assumptions are based on December 31,
                  2001
                  corporate average prices of Cdn $21.96 per barrel of oil, Cdn $22.90
                  per
                  barrel of NGL, and Cdn $2.41 per thousand cubic feet of natural
                  gas.
                  Prices, production and capital costs have not been adjusted for
                  the
                  effects of inflation.
 32
 **Reserve
        Reconciliation**
  **Crude
                  Oil**
                **(Mbbls)**
              
              **NGLs**
                **(Mbbls)**
              
              **Natural
                  Gas**
                **(Mmcf)**
              
              **BOE
                  at 6:1**
                **(000s)****Proved**
              
              **Proved**
              
              **Proved**
              
              **Proved**Reserves
                  at
                  December 31, 2000
              5,209
              
              1,088
              
              45,832
              
              13,936Discoveries
              178
              
              22
              
              7,620
              
              1,470Acquisitions
              80
              
              120
              
              19,940
              
              3,523Dispositions
              -
              
              -
              
              (114)
              
              (19)Revisions
              (66)
              
              (319)
              
              (9,303)
              
              (1,935)Production
              (845)
              
              (136)
              
              (9,585)
              
              (2,579)**Reserves
                  at December 31, 2001**
              4,556
              
              775
              
              54,391
              
              14,396
   **Reserve
        Life Index**
  **Oil**
              
              **NGLs**
              
              **Natural
                  Gas**
              
              **MBOE
                  at 6:1****Proved**
              
              **Proved**
              
              **Proved**
              
              **Proved**Reserves
                  at
                  December 31, 2001
              4,556
              
              775
              
              54,391
              
              14,3962001
                  Production
              845
              
              136
              
              9,585
              
              2,579**Reserve
                  Life Index in Years**
              5.4
              
              5.7
              
              5.7
              
              5.6
 
 **(d)**  **Land
        Holdings**
  The
        following table
        summarizes Richland’s land holdings as of December 31, 2001.
  **Undeveloped
                  Acres****Gross**
              
              **Net**Alberta
              377,184
              
              224,198Saskatchewan
              35,409
              
              28,451United
                  States
              32,000
              
              1,322**Total**
              444,593
              
              253,971
 
 **(e)**  **Oil
        and
        Natural Gas Wells**
  The
        following table
        summarizes, as of December 31, 2001, Richland’s interests in producing and
        shut-in wells.
  **Producing
                  Wells**
              
              **Shut-In
                  Wells (1)****Oil**
              
              **Natural
                  Gas**
              
              **Oil**
              
              **Natural
                  Gas****Gross
                  (2)**
              
              **Net
                  (3)**
              
              **Gross
                  (2)**
              
              **Net
                  (3)**
              
              **Gross
                  (2)**
              
              **Net
                  (3)**
              
              **Gross
                  (2)**
              
              **Net
                  (3)**Alberta
              45
              
              17.1
              
              109
              
              61.9
              
              2
              
              0.5
              
              25
              
              13.6Saskatchewan
              188
              
              75.4
              
              0
              
              0
              
              25
              
              13.6
              
              0
              
              0Unites
                  States
              0
              
              0
              
              1
              
              0.1
              
              0
              
              0
              
              3
              
              0.1**Total**
              233
              
              92.5
              
              110
              
              62
              
              27
              
              14.1
              
              28
              
              13.7
  
 (1)
              “Shut-In”
                  wells means wells which are not producing but which may be capable
                  of
                  production. Shut-in wells in which Richland had an interest are
                  located no
                  further than 10 kilometres from gathering systems, pipelines or
                  other
                  means of transportation.
  (2)
              “Gross”
                  wells
                  are defined as the total number of wells in which Richland had
                  an
                  interest.
  (3)
              “Net”
                  wells
                  are defined as the aggregate of the numbers obtained by multiplying
                  each
                  gross well by Richland’s percentage working
                  interest.
  33
  **(f)**  **Drilling
        Activity**
  The
        following table
        summarizes the number of wells drilled by Richland during the years ended
        December 31, 2001 and 2000.
  **Year
                  ended December 31, 2001**
              
              **Year
                  ended December 31, 2000****Gross
                  (1)**
              
              **Net
                  (2)**
              
              **Gross
                  (1)**
              
              **Net
                  (2)****Exploratory**Crude
                  Oil
              
              3
              
              2.0
              
              5
              
              1.8Natural
                  Gas
              
              10
              
              6.6
              
              20
              
              15.4Dry
                  and
                  Abandoned
              
              6
              
              4.3
              
              12
              
              8.9Total
                  Exploratory
              
              19
              
              12.9
              
              37
              
              26.1**Development**Crude
                  Oil
              
              7
              
              5.1
              
              8
              
              3.4Natural
                  Gas
              
              31
              
              21.6
              
              15
              
              10.5Dry
                  and
                  Abandoned
              
              8
              
              7.0
              
              3
              
              1.9Total
                  Development
              
              46
              
              33.7
              
              26
              
              15.8**Total**Crude
                  Oil
              
              10
              
              7.1
              
              13
              
              5.2Natural
                  Gas
              
              41
              
              28.2
              
              35
              
              25.9Dry
                  and
                  Abandoned
              
              14
              
              11.3
              
              15
              
              10.8**Total**
              
              **65**
              
              **46.6**
              
              **63**
              
              **41.9**
  
 (1)
              “Gross”
                  wells
                  refers to all wells in which the Corporation has either a working
                  interest
                  or a royalty interest.
  (2)
              “Net”
                  wells
                  refers to the aggregate of the percentage working interests of
                  the
                  Corporation in the gross wells before royalties and on a before
                  payout
                  basis, unless the wells have already paid
                  out.
  **(g)**  **Marketing**
  Richland
        sells its
        crude oil to major crude oil aggregators under short-term floating price
        crude
        oil sales contracts, with the majority of production pipeline-connected.
        Richland’s natural gas production is sold to natural gas aggregators at spot
        market prices. Richland has no significant long-term gas sales
        contracts.
  **(h)**  **Environmental
        Matters**
  All
        oil and gas
        operations are subject to federal, provincial and municipal legislation
        regarding environmental risks and hazards, including restrictions and
        prohibitions on spills, releases or emissions of various substances produced
        in
        connection with oil and gas operations. Environmental law also requires that
        well and facility sites be abandoned and reclaimed to the satisfaction of
        the
        relevant authorities. Any breach of this legislation may result in the
        imposition of fines and penalties.
  As
        these requirements apply to all operators in the Western Canadian oil and
        gas
        industry, it is unlikely that Richland’s competitive position within the
        industry will be affected by these regulations.
 34
 **(i)**  **Employees**
  Richland
        had 35
        full-time employees as of December 31, 2001.
  **(j)**  **Dividends**
  No
        dividends have been paid on any shares of Richland since the date of its
        incorporation and it is not anticipated that any dividends will be paid on
        the
        common shares in the immediate or foreseeable future. Richland’s demand
        revolving operating facility with a Canadian chartered bank provides that
        Richland may not declare a dividend without the prior approval of the
        bank.
  **III.**  **Business
        Overview of the Acquired Properties**
  On
        May 1, 2002, subsequent to the 2001 year-end discussed in this annual
        report, the Trust and Provident completed the acquisition of certain oil
        and gas
        properties located in southeast Alberta for a purchase price $72.0 million
        (subject to adjustment), payable in cash. The following is a description
        of the
        Acquired Properties.
  **(a)**  **Principal
        Oil and Gas Properties**
  The
        following is a
        description of the principal properties acquired by the Trust in connection
        with
        the acquisition of the Acquired Properties, effective January 1,
        2002.
  ***Princess,
        Alberta***
  The
        Princess area
        is located approximately 75 kilometres northwest of the City of Medicine
        Hat.
        Production in the area is obtained from the shallow gas formations of Medicine
        Hat, Milk River and Second White Specks. The Acquired Properties include
        working
        interests ranging from 25% to 99%. Average net natural gas production in
        2001
        was 2,100 Mcf/d. Current net natural gas production is 3,700 Mcf/d.
  McDaniel
        evaluated
        the reserves attributable to the Acquired Properties in the area in the McDaniel
        Acquired Properties Report and assigned 7.4 Bcf of proved reserves.
  Provident
        believes
        this property adds relatively stable and predictable long life reserves to
        the
        Trust.
  ***Retlaw
        Area, Alberta***
  The
        Retlaw area is
        located approximately 115 kilometres west of the City of Medicine Hat. The
        area
        is comprised of the Retlaw Unit, Retlaw Non Unit, Retlaw East/Vauxhall and
        the
        Retlaw V Unit. Both oil and gas are produced in the area, predominantly from
        the
        Mannville Group. The Acquired Properties include an operating interest in
        a
        large proportion of the production in this area. Average 2001 net natural
        gas
        production was 5,800 Mcf/d and average 2001 net oil production was 810 Bpd.
        Current net natural gas production is 5,100 Mcf/d and current net oil production
        is 940 Bpd.
  McDaniel
        evaluated
        the reserves attributable to the Acquired Properties in the area in the McDaniel
        Acquired Properties Report and assigned 1,339 Mbbls and 8.6 Bcf of proved
        reserves.
  Provident
        believes
        the properties offer immediate optimization and development opportunities
        including possible waterflood performance enhancement, reactivation of
        previously suspended waterflood operations, pump upgrades, compression
        optimization, recompletion opportunities and some drilling opportunities
        for oil
        downspacing and further gas development.
  35
  ***Craigmyle,
        Alberta***
  The
        Craigmyle area
        is located approximately 210 kilometres northwest of the City of Medicine
        Hat.
        Production in the area is obtained from the Mannville Group, along with
        shallower production from the Belly River Formation. The Acquired Properties
        include 100% working interests in a majority of the wells currently on
        production. Average net natural gas production in 2001 was 2,420 Mcf/d. Current
        net natural gas production is 2,040 Mcf/d.
  The
        Acquired
        Properties include a 100% working interest in the Craigmyle Compressor Station
        that has a capacity of 6.5 Mmcf/d of sweet gas utilizing one 500 hp unit
        and one
        900 hp unit.
  McDaniel
        evaluated
        the reserves attributable to the Acquired Properties in the area in the McDaniel
        Acquired Properties Report and assigned 5.8 Bcf of proved reserves.
  ***Long
        Coulee Area, Alberta***
 The
        Long Coulee
        area is located approximately 145 kilometres west of the City of Medicine
        Hat.
        The area is comprised of Long Coulee and Long Coulee Sunburst P pool.
        Gas
        production is obtained from the Sunburst, Glauconitic, Bow Island and Second
        White Specks formations. Oil production is obtained from the Sunburst P
        Pool. The Acquired Properties include 59% to 100% working interests in a
        majority of the wells currently on production. Average 2001 net natural gas
        production was 1,260 Mcf/d and average 2001 net oil production was 220 Bpd.
        Current net natural gas production is 1,180 Mcf/d and current net oil production
        is 190 Bpd.
  The
        Acquired
        Properties include a 100% working interest in the oil battery that has a
        capacity of 950 Bpd of sour oil and 950 Bpd of water. Water injection capacity
        is 2,200 Bpd. Solution gas is compressed at the battery and delivered to
        the
        Long Coulee Gas Plant.
  McDaniel
        evaluated
        the reserves attributable to the Acquired Properties in the area in the McDaniel
        Acquired Properties Report and assigned 2.8 Bcf and 266 Mbbls of proved
        reserves.
  Provident
        believes
        the Sunburst P Pool offers the possibility of initiating another waterflood
        recovery process beside an existing waterflood scheme in order to optimize
        the
        pool oil recovery. Additionally, there may be some infill drilling opportunities
        as a result of the new post waterflood implementation.
  ***Carmangay,
        Alberta***
  The
        Carmangay area
        is located approximately 155 kilometres west of the City of Medicine Hat.
        Oil
        and gas production is obtained from the Sunburst formation. The Acquired
        Properties include a 100% working interest in the area and a gross overriding
        royalty in the Second White Specks. Average 2001 net natural gas production
        was
        730 Mcf/d and average 2001 net oil production was 260 Bpd. Current net oil
        production is 190 Bpd and current net natural gas production is 500
        Mcf/d.
  The
        Acquired
        Properties include a 100% working interest in the oil battery that has a
        capacity of 1,260 Bpd of sour oil and 3,800 Bpd of water. Solution gas is
        compressed at the battery and delivered to the Long Coulee Gas
        Plant.
  36
  McDaniel
        evaluated the reserves
        attributable to the Acquired Properties in the area in the McDaniel Acquired
        Properties Report and assigned 235 Mbbls and 5.8 Bcf of proved
        reserves.
  Provident
        believes
        the Carmangay property offers the possibility of upgrading the existing gas
        compressor and some reactivation and stimulation candidates to optimize the
        existing production.
   **(b)**  **Oil
        and
        Natural Gas Wells**
  The
        following table
        summarizes, as of January 1, 2002, the producing and shut-in wells
        in
        respect of the Acquired Properties:
  **Producing
                  Wells**
              **Shut-in
                  Wells (1)****Oil**
              **Natural
                  Gas**
              **Oil**
              **Natural
                  Gas****Gross(2)**
              **Net(3)**
              **Gross(2)**
              **Net(3)**
              **Gross(2)**
              **Net(3)**
              **Gross(2)**
              **Net(3)****Total**
              196
              106
              277
              146
              132
              90
              74
              52
  
 (1)
              “Shut-in”
                  wells means wells which are not producing but which may be capable
                  of
                  production.
  (2)
              “Gross”
                  wells
                  are defined as the total number of wells in respect of the Acquired
                  Properties.
  (3)
              “Net”
                  wells
                  are defined as the aggregate of the numbers obtained by multiplying
                  each
                  gross well by the percentage working interest in the
                  well.
  **(c)**  **Production
        History**
  The
        following table
        summarizes the historical average daily production of the Acquired Properties
        during the periods indicated.
  **Year
                  Ended December 31,****2001**
              **2000**Crude
                  Oil
                  & NGLsTotal
                  production (Mbbls)
              653
              787Average
                  daily
                  production (Bpd)
              1,788
              2,151Natural
                  GasTotal
                  production (Mmcf)
              5,259
              5,598Average
                  daily
                  production (Mmcf/d)
              14
              15Total
                  ProductionTotal
                  production (MBOE)
              1,529
              1,720Average
                  daily
                  production (BOE/d)
              4,190
              4,700
 **(d)**  **Land
        Holdings**
  The
        following table
        summarizes the land holdings in respect of the Acquired Properties as at
        January 1, 2002:
  **Undeveloped**
              **Developed**
              **Total****Gross**
              **Net**
              **Gross**
              **Net**
              **Gross**
              **Net****Total
                  acres**
              101,664
              78,222
              122,339
              77,066
              224,063
              155,288
  **(e)**  **Oil
        and
        Natural Gas Reserves of the Acquired Properties**
  The
        oil, natural
        gas and NGL reserves of the Acquired Properties as of January 1, 2002
        have
        been evaluated by McDaniel utilizing McDaniel’s January 1, 2002 pricing as
        set forth in the McDaniel Acquired Properties Report. McDaniel conducted
        evaluations based on constant price assumptions of the vendor’s oil, gas and NGL
        reserves and present worth of future cash flows associated with these reserves.
        The results of the evaluations of McDaniel, contained in the McDaniel Acquired
        Properties Report, based on constant price assumptions as provided by McDaniel,
        are summarized in the tables below.
  37
  The
        present worth
        of estimated future cash flows contained in the following tables may not
        be
        representative of the fair market values of the reserves. Assumptions relating
        to costs, prices for future production and other matters are summarized in
        the
        notes following the tables. There is no assurance that these prices and cost
        assumptions will be attained and variances could be material. All estimated
        future cash flows set forth in the following tables are stated prior to
        provision for income taxes, indirect costs, and future site restoration costs,
        and after deduction of operating costs, royalties and estimated future capital
        expenditures. The McDaniel Acquired Properties Report is based on certain
        factual data including operating costs, property descriptions, details of
        interests held, well data, future development plans and future capital estimates
        supplied by the vendor in a data room, and on McDaniel’s opinion of reasonable
        practice in the industry.
  **Oil
        and
        Natural Gas Reserves and Present Value of Estimated Future Cash Flows**
  **in
        Respect
        of the Acquired Properties Based on Constant Price
        Assumptions**
  **Gross
                  Reserves (1)**
              **Net
                  Reserves (2)**
              **Present
                  Worth Value Discounted at****Oil**
              **NGLs**
              **Natural
                  Gas**
              **Oil**
              **NGLs**
              **Natural
                  Gas**
              **0
                  %**
              **10
                  %**
              **15
                  %**
              **20
                  %****(Mbbls)**
              **(Mbbls)**
              **(Mmcf)**
              **(Mbbls)**
              **(Mbbls)**
              **(Mmcf)**
              **(thousands
                  of dollars)**Proved
                  ReservesProducing
              2,361.0
              79.9
              28,708.1
              2,140.5
              53.3
              23,760.7
              54,873.0
              42,274.5
              37,986.4
              34,593.3Non-Producing
              1.5
              0.1
              4,960.9
              1.5
              0.0
              3,607.1
              7,648.9
              4,245.0
              3,308.1
              2,640.4Undeveloped
              47.8
              0.0
              1,525.6
              39.4
              0.0
              1,178.8
              1,637.9
              838.6
              622.3
              467.5**TOTAL**
              2,410.3
              79.9
              35,194.5
              2,181.4
              53.3
              28,546.7
              64,159.8
              47,358.1
              41,916.8
              37,701.3
 
  (1)
              “Gross
                  Reserves” are the aggregate of the Vendor’s working interest and royalty
                  interest reserves before deductions of royalties payable to
                  others.
  (2)
              “Net
                  Reserves” are the Gross Reserves less all royalties payable to
                  others.
  **Constant
        Price Summary Schedule (at December 31, 2001)**
  West
                  Texas
                  Intermediate ($US/Bbl)(1)
              19.78Edmonton
                  Light Crude ($Cdn/Bbl)(2)
              29.16Alberta
                  Average Natural Gas ($Cdn/Mmbtu)(3)
              3.26Propane
                  ($Cdn/Bbl)(4)
              18.85Butane
                  ($Cdn/Bbl)(4)
              18.60NGL
                  Mix
                  ($Cdn/Bbl)(4)
              21.00Natural
                  Gasolines & Condensate ($Cdn/Bbl)(4)
              29.16
  
 (1)
              December 31,
                  2001 NYMEX close.
  (2)
              December 31,
                  2001 average postings.
  (3)
              December 2001
                  estimate.
  (4)
              December 2001
                  Edmonton reference price.
 38
 **Estimated
        Future Annual Production Volumes for the Acquired
        Properties**
  **Proved
                  Producing**
              **Total
                  Proved****Year**
              **Oil**
              **NGLs**
              **Natural**
                **Gas**
              **Oil**
              **NGLs**
              **Natural**
                **Gas**(Mbbls)
              (Mbbls)
              (Mmcf)
              (Mbbls)
              (Mbbls)
              (Mmcf)2002
              576.5
              16.1
              4,886.1
              594.8
              16.2
              5,030.92003
              442.0
              12.5
              3,845.4
              457.9
              12.6
              4,244.02004
              343.8
              9.9
              3,134.1
              351.9
              9.9
              3,451.4
  
 **C.**
              **Organizational
                  Structure**
  The
        following
        diagram describes the flow of cash from the oil and gas properties to the
        Trust
        and from the Trust to the Unitholders as of June 30, 2002. Reference should
        be
        made to the appropriate sections of this Form 20-F for a complete
        description of the structure of the Trust.
  
  **D.**
              **Property,
                  Plant and Equipment**
  See
“Business
        Overview.”
 39
  **Item
                  5.**
              **Operating
                  and Financial Review and
                  Prospects**
  **Variations
        in Operating Results**
  The
        following is a
        summary of variations in Provident’s and Founders’ operating results for the
        fiscal periods indicated, which should be read in conjunction with the financial
        statements of Provident and Founders and the notes accompanying such financial
        statements.
  On
        January 27, 2000 the shareholders of Founders approved a consolidation
        of
        Founders’ common shares on a one for four basis. For the purposes of the
        following analysis, unless otherwise noted, the issued and outstanding and
        weighted average common share and corresponding per share information have
        been
        restated as if the share consolidation had taken effect at the beginning
        of the
        applicable reporting period.
  ***Inception
        of
        the Trust and the Requirement for the Forecast***
  Provident
        Energy
        Trust commenced operations on March 6, 2001 when Founders converted from
        an
        exploration and production company into a cash-distributing energy trust.
        This
        was accomplished through the Founders Arrangement approved by the shareholders
        of Founders. Normally, under Canadian GAAP the disclosure incorporated in
        the
        circular would include the historical activity of Founders and would form
        the
        basis for Founders’ shareholders to evaluate the Founders Arrangement. In this
        instance, the historical activity of Founders, an exploration and production
        company, did not accurately reflect the activity of Provident going forward
        as
        an energy trust. In these circumstances, a forecast was provided in the Founders
        Management Information Circular dated January 29, 2001, accompanied by an
        auditors’ report on the financial forecast.
  ***Forecast
        Summary***
  The
        forecast was
        based on Founders’ January 2001 production base adjusted for the planned
        activities, assuming the assets were managed as a trust. The forecast
        incorporated management’s judgement as of January 18, 2001 of the most probable
        set of economic conditions, which in turn, was based on information available
        at
        that time. The forecast was based on average daily production over the period
        of
        4,493 BOE/d. The commodity prices used in the forecast were based on an average
        crude oil price of US $25.00 per Bbl WTI, a natural gas price of Cdn $6.00
        per
        Mcf at AECO and a natural gas liquids price of Cdn $28.04 per barrel. The
        relevance of the forecast was diminished upon the closing of the Maxx
        Arrangement that combined the production base of Maxx with Provident effective
        May 25, 2001. The additional 7,800 BOE/d of production and the change in
        the
        production mix minimized the relevance of the forecast as a comparison for
        actual results.
  **Period
        from
        March 6, 2001 to December 31, 2001 compared to Forecast**
  The
        following
        analysis provides a detailed explanation of Provident’s operating results for
        the period March 6, 2001 to December 31, 2001, which should be read in
        conjunction with the audited consolidated financial statements of Provident.
        The
        forecast referenced in this annual report refers to the 2001 forecast, disclosed
        in the Founders Management Information Circular dated January 29, 2001. The
        following analysis compares the actual results to the forecast for this period.
        All amounts are reported in Canadian dollars, unless otherwise
        stated.
   40
  ***Operations***
  Operating
        results
        for the period March 6, 2001 to December 31, 2001 compared to the forecast
        were
        as follows.
  **Actual**
              
              **Forecast**
              
              **Percent
                  Change****Operating
                  Revenue ($000s)**Gross
                  production revenue
              $
              78,311
              $
              43,415
              
              80Royalties
                  (net of ARTC)
              
              (13,036)
              
              (7,871)
              
              66Net
                  operating
                  revenue
              
              (20,416)
              
              (7,528)
              
              171Net
                  operating
                  income
              $
              44,859
              $
              28,016
              
              60**Daily
                  average production**Crude
                  oil -
                  Light / Medium (Bpd)
              
              1,577
              
              732
              
              115-
                  Heavy
                  (15oAPI)
                  (Bpd)
              
              5,053
              
              1,877
              
              169Natural
                  gas
                  liquids (Bpd)
              
              509
              
              200
              
              155Natural
                  gas
                  (Mcf/d)
              
              15,772
              
              10,100
              
              56Oil
                  equivalent (BOE/d @ 6:1)(2)
              
              9,767
              
              4,493
              
              117Average
                  selling price (Cdn $)(1)Crude
                  oil -
                  Light / Medium ($/Bbl)
              $
              31.94
              $
              33.42
              
              (4)-
                  Heavy
                  (15oAPI)
                  ($/Bbl)
              $
              21.71
              $
              20.51
              
              6-
                  Corporate
                  blend ($/Bbl)
              $
              24.14
              $
              24.37
              
              -Natural
                  gas
                  liquids ($/Bbl)
              $
              31.40
              $
              28.04
              
              12Natural
                  gas
                  ($/Mcf)
              $
              5.33
              $
              7.49
              
              (29)Oil
                  equivalent ($/BOE @ 6:1)
              $
              26.64
              $
              32.10
              
              (17)Netback
                  ($/BOE @ 6:1)
              $
              15.27
              $
              20.72
              
              (26)**Notes:**(1)
              Average
                  selling prices include the impact of the commodity price risk management
                  program.(2)
              For
                  reporting
                  purposes, Provident reports oil equivalent production converting
                  natural
                  gas to oil on a 6:1 basis. For comparative purposes, the volumetric
                  data
                  previously disclosed in the forecast contained in the Founders’ Management
                  Information Circular on a 10:1 basis has been restated on a 6:1
                  basis.
  ***Production***
  For
        the period
        March 6, 2001 to December 31, 2001, total production of 9,767 BOE/d exceeded
        the
        forecast by 117% or 5,274 BOE/d. Heavy oil production increased, by 169%,
        to
        5,053 Bbls/d from the forecast production of 1,877 Bbls/d. The increase in
        heavy
        oil production volumes is almost entirely attributed to the Maxx-acquired
        heavy
        oil properties. Natural gas and natural gas liquids production averaged 15.8
        Mmcf/d and 509 Bbls/d respectively to total 3,138 BOE/d. The addition of
        the
        Maxx West Central Alberta gas properties and the continued strong performance
        of
        the liquids-rich Medicine River 13-27 well were the primary factors for natural
        gas production exceeding the forecast by 56% or 5.7 Mmcf/d and natural gas
        liquids exceeding the forecast by 155% or 309 Bbls/d. The addition of the
        Maxx
        properties and a Southeast Saskatchewan property acquisition, combined with
        positive results from a re-completion program in Southeast Saskatchewan,
        resulted in light/medium crude oil production averaging 1,577 Bbls/d, an
        increase of 115% or 845 Bbls/d above the forecast.
  ***Crude
        Oil Price***
  The
        WTI oil price
        averaged US $25.19 per barrel for the period March 6, 2001 to December 31,
        2001,
        compared to US $25.00 per barrel in the forecast. This slight increase in
        WTI,
        accompanied by both the gains related to the commodity price risk management
        program and the weak Canadian dollar, were offset by wider heavy oil
        differentials, and resulted in the Trust averaging Cdn $24.14 per barrel
        at the
        wellhead for all its crude oil, as compared to Cdn $24.37 per barrel in the
        forecast. Average prices include a gain of $4.4 million or $2.23 per barrel
        from
        the impact of the commodity price risk management program, compared to a
        gain of
        $0.2 million or $0.23 per barrel in the forecast.
  In
        the fourth quarter, the WTI crude oil price dropped significantly to average
        US
        $20.43 per barrel while heavy oil differentials remained wide. This resulted
        in
        a fourth quarter price for heavy oil that was extremely low by historical
        standards, resulting in very low operating netbacks on unhedged production.
        Accordingly, Provident did not reactivate or perform workovers on heavy oil
        wells that went down during the fourth quarter. In the first quarter of 2002,
        differentials narrowed significantly to reflect pricing that was closer to
        historical trends and as a result, operating netbacks improved substantially
        and
        most of the economical shut-in production was reactivated. Provident’s commodity
        price risk management program increased the heavy oil price received in the
        fourth quarter to Cdn $15.70 per barrel, compared to Cdn $17.27 per barrel
        in
        the forecast. The average fourth quarter blended oil price included a gain
        of
        $3.2 million or $4.53 per barrel achieved through the commodity price risk
        management program. No gains were expected in the forecast.
  41
  ***Natural
        Gas Price***
  For
        the period
        March 6, 2001 to December 31, 2001, the natural gas price at AECO averaged
        Cdn $4.40 per Mcf compared to Cdn $6.00 per Mcf used in the forecast.
        The
        Trust received an average wellhead price of Cdn $5.33 per Mcf for its gas,
        reflecting both the positive heat content adjustment and the commodity price
        risk management program. This compared to the forecast price of Cdn $7.49
        per
        Mcf, which reflected a Cdn $6.00 AECO average price as well as hedging gains
        of
        $3.3 million or $1.08 per Mcf. The actual prices received include a gain
        of $4.2
        million or $0.89 per Mcf from the commodity price risk management
        program.
  ***Commodity
        Price Risk Management Program***
  Provident’s
        commodity price risk management program has been in place since the inception
        of
        the Trust to help manage the volatility in Provident’s oil and natural gas
        prices and to assist with stabilizing cash flow and distributions per unit.
        A
        combination of forward sales contracts, physical hedges on both wellhead
        prices
        and heavy oil differentials, financial hedging on WTI Crude oil price and
        AECO
        natural gas price and Cdn/US exchange rate hedges were put in place. This
        program positively impacted 2001 fourth quarter cash flow by $5.0 million
        and by
        $8.7 million for the period from inception to December 31, 2001. The positive
        impact of Provident’s commodity price risk management program was clearly
        evident in November 2001 when the all-in wellhead price for heavy oil dropped
        below Cdn $10.00 per barrel while the majority of Provident’s heavy oil
        production was hedged at an all-in wellhead price of Cdn $22.80 per
        barrel.
  For
        open contracts
        in place at December 31, 2001, unrealized hedging gains of Cdn $4.7 million
        on
        crude oil contracts and Cdn $3.0 million on natural gas contracts would have
        been realized based on the commodity prices prevailing at December 31,
        2001.
  For
        2002, the
        commodity price risk management program has resulted in Provident locking-in
        an
        all-in wellhead price of approximately Cdn $19.00 per barrel on 5,000 Bbls/d
        of
        heavy oil, representing approximately 80% of forecast annual heavy oil
        production. In addition, Provident has hedged 250 Bbls/d or approximately
        7% of
        forecast 2002 light crude oil production at a WTI price of US $20.00 to US
        $22.90 per barrel.
  For
        natural gas,
        Provident has hedged 23 Mmcf/d or approximately 67% of forecast 2002 natural
        gas
        production at prices between Cdn $3.95 and Cdn $6.33 per Mcf at AECO. The
        weighted average price of the gas contracts is $4.50 per Mcf.
  For
        more
        information, see “Information on the Trust — Business Overview — Business
        Overview of Provident and the Trust — Risk Management
        Strategy.”
  ***Revenues***
  Gross
        production
        revenues from oil, natural gas and natural gas liquids totalled $78.3 million
        for the period March 6, 2001 to December 31, 2001, 80% higher than the $43.4
        million in the forecast. The increase can be attributed to higher production
        as
        a result of the Maxx acquisition and the effects of the commodity price risk
        management program, partially offset by lower than forecast natural gas
        prices.
  ***Royalties***
  For
        the period
        March 6, 2001 to December 31, 2001, royalties were $13.0 million or 66% higher
        than the $7.9 million in the forecast. The dollar increase ties to increased
        production volumes and revenues. On a per BOE basis, royalties were 25% less
        than forecast at $4.43 per BOE compared to a forecast of $5.82 per BOE. The
        lower BOE amount ties to the lower commodity prices received, prior to the
        commodity price risk management program, when compared to the forecast. As
        a
        percentage of gross production revenue, prior to the impact of commodity
        price
        risk management program activities, the royalty percentage was 18.7% compared
        to
        19.7% in the forecast. The lower percentage rate reflects the change in
        commodity mix to include a greater weighting to heavy oil subsequent to the
        Maxx
        acquisition. Typically, royalties paid on heavy oil production are lower
        than on
        conventional light/medium oil or natural gas. The ARTC rate for all quarters
        in
        2001 was 25% and will remain at 25% for the first quarter of 2002.
  42
  ***Production
        Expenses***
  Production
        expenses
        for the period March 6, 2001 to December 31, 2001 were $6.94 per BOE, $1.37
        per
        BOE higher than the $5.57 per BOE in the forecast. The increase is largely
        attributable to the Maxx-acquired natural gas properties in West Central
        Alberta, which are processed through higher-cost third-party-owned facilities,
        and the increase in the heavy oil component of Provident’s production mix.
        Typically, heavy oil properties incur higher production expenses compared
        to the
        Trust’s natural gas and light oil assets. Heavy oil has a large component of
        discretionary maintenance costs where Provident will incur expenditures to
        maintain production when prices received for heavy oil are attractive and
        cease
        discretionary programs when the prices fall below an economic threshold,
        which
        is typically at a wellhead price of Cdn $13.00 per barrel. The 2001 pricing
        environment provided attractive heavy oil wellhead prices for the first three
        quarters and an extremely low heavy oil price environment in the fourth quarter.
        Provident’s operating costs reflect this environment. Heavy oil operating costs
        were $8.17 per barrel for the first three quarters, then decreased significantly
        to $6.19 per barrel in the fourth quarter when wells that were shut-in were
        not
        reactivated. The heavy oil wellhead price has rebounded early in 2002 resulting
        in Provident undertaking an active program of reactivation and workovers
        of
        shut-in heavy oil wells.
  ***Operating
        Netback***
  The
        Trust’s
        operating netback for the period March 6, 2001 to December 31, 2001 was $15.27
        per BOE as compared to the forecast netback of $20.72. The per BOE increase
        in
        the production expenses reflects the shift in the production mix associated
        with
        the Maxx acquired properties. The lower per BOE gross production revenue
        reflects both the production shift to a greater percentage of heavy oil and
        the
        lower natural gas price achieved compared to the forecast.
  The
        table below
        sets out the Trust’s field netbacks for the period compared to the
        forecast:
  **(per
                  BOE)**
              
              **Actual**
              
              **Forecast**
              
              **Percent
                  Change**Gross
                  production revenue before commodity price risk management
                  program
              $
              23.69
              $
              29.54
              
              (20)Commodity
                  price risk management program
              
              2.95
              
              2.57
              
              15Less:
                  Royalties (net of ARTC)
              
              (4.43)
              
              (5.82)
              
              (24)Production
                  expenses
              
              (6.94)
              
              (5.57)
              
              25Field
                  netbacks
              $
              15.27
              $
              20.72
              
              (26)
 43
 ***General
        and Administrative Expense***
  General
        and
        administrative expense for the period March 6, 2001 to December 31, 2001
        totalled $3.4 million, compared to the forecast of $1.8 million. The higher
        expense was entirely due to increased costs associated with the Maxx
        acquisition. On a BOE basis, general and administrative expense was $1.16,
        which
        was 13% lower than the $1.33 per BOE in the forecast. The lower per BOE amount
        reflects the economies the Trust has achieved with the larger production
        base.
        The Trust does not capitalize general and administrative expenses. For 2002,
        it
        is expected the per BOE expense will decrease to less than $1.00 per BOE,
        recognizing the increased production base resulting from the acquisition
        of
        Richland.
  ***Management
        Fee***
  The
        Trust is
        actively managed by Provident Management Corporation. For the period ended
        December 31, 2001 the Manager was paid a fee of $897,195 in respect of a
        base
        management fee, calculated as 2% of operating income, compared to $560,000
        in
        the forecast. The Manager also received a total return fee of $256,069, which
        was based on distributions and unit price performance during the period,
        compared to an assumption of nil for the forecast. On a BOE basis the total
        management fee was $0.40 compared to $0.41 in the forecast. The base management
        fee was settled monthly in cash and the total return fee was paid through
        the
        issue of 31,798 Trust Units in February 2002 at a price of $8.21 per unit.
        The
        total return fee also included the January 2002 distribution payable on the
        units issued. The Manager does not receive any form of compensation with
        respect
        to salaries or fees on acquisitions or dispositions.
  ***Interest
        Expense***
  Interest
        expense
        for the period March 6, 2001 to December 31, 2001 totalled $2.7 million compared
        to $1.5 million in the forecast. The interest reflects the increase in the
        capitalization of the Trust subsequent to closing the Maxx acquisition. Interest
        expense fell to $0.91 per BOE compared to $1.09 per BOE in the forecast.
        The
        weighted average interest rate of the Trust for the period was 5.5% compared
        to
        7.25% in the forecast.
  ***Current
        and Future Tax***
  The
        current capital
        tax expense for the period March 6, 2001 to December 31, 2001 was $1.2 million
        compared to $0.8 million in the forecast, and was comprised of Large
        Corporations Tax (“LCT”) and the Saskatchewan resource surcharge. The Maxx
        acquisition had an impact on the LCT but due to the vast majority of the
        production of Maxx being in Alberta, there was virtually no increase in the
        Saskatchewan resource surcharge.
  The
        future tax on
        the balance sheet was increased by $57.1 million as part of purchase accounting
        method used to record the acquisition of Maxx. The subsequent booking of
        the
        ceiling test write-downs in 2001 resulted in an associated future tax recovery
        of $43 million. In total, the future tax recovery was $51.8 million compared
        to
        an expense of $5.8 million in the forecast, which did not anticipate any
        purchase price adjustments or write-downs.
  ***Depletion,
        Depreciation and Amortization, the Ceiling Test and Future Tax
        Recovery***
  The
        depletion,
        depreciation and amortization expense for the period March 6, 2001 to
        December 31, 2001 was $11.48 per BOE, compared to the forecast rate
        of
        $8.27 per BOE. The actual per BOE amount is prior to the additional expense
        booked as a result of Provident electing to take ceiling test write-downs
        at
        September 30 and December 31. The increased depletion, depreciation and
        amortization per BOE is a result of the change in the depletable asset base
        resulting from the purchase accounting method used to record the acquisition
        of
        Maxx.
  44
  During
        the period,
        the Trust elected to record two ceiling test write-downs, one at
        September 30, 2001 primarily due to the low natural gas price, and
        the
        other at December 31, 2001 due to the low heavy oil wellhead price. The ceiling
        test calculation is based on prices in effect at the date of the balance
        sheet.
        The combined write-downs were booked to the balance sheet as a reduction
        to
        property, plant and equipment of $101.3 million, coupled with a decrease
        to the
        future tax liability of $43.0 million. The net impact on the statement of
        operations was a reduction in earnings of $58.3 million. The earnings impact
        was
        recorded as $101.3 million of additional depletion, depreciation and
        amortization offset by a future tax recovery in the amount of $43.0 million.
        The
        effect of the write-downs will be to improve future earnings and reduce current
        tax expense.
  The
        September 30,
        2001 ceiling test calculation used prices in effect at September 30, 2001
        of Cdn
        $16.77 per barrel for heavy oil, Cdn $29.72 per barrel for light/medium oil,
        Cdn
        $2.19 per Mcf for natural gas and Cdn $26.71 per barrel for natural gas liquids.
        This pricing resulted in a ceiling test deficiency recorded as a $64.2 million
        decrease to property, plant and equipment offset by an associated future
        tax
        recovery of $27.2 million. The write-down was virtually all attributable
        to a
        substantial decrease in the natural gas price prevailing at September 30,
        2001.
        The use of the average commodity prices received for the month of September
        would have resulted in a ceiling test cushion of approximately $9.5
        million.
  At
        December 31, 2001 Provident completed a ceiling test calculation using the
        prices in effect at December 31, 2001 of Cdn $13.69 per barrel for heavy
        oil,
        Cdn $25.46 per barrel for light/medium oil, Cdn $3.65 per Mcf for natural
        gas
        and Cdn $22.31 per barrel for natural gas liquids. This resulted in a write-down
        of $37.1 million to property, plant and equipment and a future tax recovery
        of
        $15.8 million. The Cdn $13.69 per barrel heavy oil price at December 31,
        2001
        truncated approximately 4.5 million barrels of proved heavy oil reserves
        from
        the proved undeveloped reserve category in the constant dollar reserve report.
        The truncated reserves resulted from no new heavy oil wells being drilled
        under
        the prevailing heavy oil price economics at December 31, 2001. If the ceiling
        test were calculated using prices at February 28, 2002, the result would
        have
        been a recovery of the truncated reserves and a corresponding ceiling test
        cushion of approximately $15.0 million.
  ***Cash
        Flow and (Loss) Income***
 **Actual**
              
              **Forecast****Amount**
                **($000s)**
              
              **Per**
                **BOE**
              
              **Per
                  Weighted Average Unit**
              
              **Amount**
                **($000s)**
              
              **Per
                  BOE**
              
              **Per
                  Weighted Average Unit**Net
                  operating
                  income
              $
              44,859
              $
              15.27
              $
              3.25
              $
              28,016
              $
              20.72
              $
              3.95General
                  and
                  administration
              
              3,418
              
              1.16
              
              0.25
              
              1,794
              
              1.33
              
              0.25Management
                  fee
              
              1,153
              
              0.40
              
              0.08
              
              560
              
              0.41
              
              0.08Interest
                  expense
              
              2,671
              
              0.91
              
              0.19
              
              1,471
              
              1.09
              
              0.21Current
                  tax
                  expense
              
              1,178
              
              0.40
              
              0.09
              
              807
              
              0.60
              
              0.11Other
              
              211
              
              0.07
              
              0.02
              
              -
              
              -
              
              -8,631
              
              2.94
              
              0.63
              
              4,632
              
              3.43
              
              0.65Cash
                  flow
                  from operations (1)
              
              36,228
              
              12.33
              
              
              
              23,384
              
              17.29Depletion,
                  depreciation and amortization
              
              33,753
              
              11.48
              
              2.44
              
              11,186
              
              8.27
              
              1.58Additional
                  DD&A (2)
              
              101,300
              
              34.46
              
              7.34
              
              -
              
              -
              
              -Future
                  income
                  tax (2)
              
              (51,759)
              
              (17.61)
              
              (3.75)
              
              5,787
              
              4.28
              
              0.82Other
              
              (211)
              
              (0.07)
              
              (0.02)
              
              -
              
              -
              
              -83,083
              
              28.26
              
              6.01
              
              16,973
              
              12.55
              
              2.40Net
                  (loss)
                  income
              $
              (46,855)
              $
              (15.93)
              $
              (3.39)
              $
              6,411
              $
              4.74
              $
              0.90
 (1)  Cash
        flow from
        operations per weighted average unit has been omitted from the
        table.
 (2)  Amounts
        reflect
        ceiling test write-downs the Trust elected to book at September 30 and December
        31, 2001.
  45
  Cash
        flow from
        operations for the period March 6, 2001 to December 31, 2001 was $36.2 million,
        55% higher than the forecast of $23.4 million. Higher net operating income
        driven by the acquisition of Maxx was partially offset by increased general
        and
        administration costs, management fees, interest and current tax expense.
        Net
        operating income was $15.27 per BOE and $3.25 per Unit versus the forecast
        of
        $20.72 per BOE and $3.95 per Unit. Net operating income was significantly
        impacted by the change in the production mix due to the acquisition of Maxx
        as
        well as the lower natural gas price received compared to the
        forecast.
  The
        net loss of
        $46.9 million ($3.39 per Unit) compared to the forecast income of $6.4 million
        ($0.90 per Unit) was due to the ceiling test write-downs not anticipated
        in the
        forecast.
  **Year
        Ended
        December 31, 2000 compared to Year Ended December 31,
        1999**
  The
        following
        analysis provides a detailed explanation of the financial and operating results
        for the years ended December 31, 2000 and 1999.
  Founders’
        results
        for the year ended December 31, 2000 benefited from commodity prices
        being
        at their highest levels since the inception of Founders. Daily production
        volumes in 2000 were 15% lower than the comparable 1999 year primarily as
        a
        result of the sale of 1,200 BOE/d of annualized production in 1999.
        Comparative operating results for the fiscal years ended 2000 and 1999 are
        as
        follows.
  ***Operations***
  **Operating
                  Revenue**
                **($000s)**
              **2000**
              **1999**
              **Percent**
                **Change**Gross
                  production revenue
              49,226
              30,805
              60Royalties
                  (net of ARTC)
              (9,922)
              (6,395)
              55Production
                  expenses
              (9,701)
              (8,811)
              10Net
                  operating
                  revenue
              29,603
              15,599
              90**Daily
                  Average Production**Med./light
                  crude oil and NGLs (Bpd)
              1,106
              1,837
              (40)Heavy
                  oil
                  (Bpd)
              1,334
              1,036
              29Natural
                  gas
                  (Mcf/d)
              10,636
              12,286
              (13)Oil
                  equivalent (BOE/d)
              3,503
              4,102
              (15)**Average
                  Selling Price(1)**Crude
                  oil and
                  ngl ($/Bbl)
              32.53
              18.74
              74Natural
                  gas
                  ($/Mcf)
              5.19
              2.49
              108Oil
                  Equivalent ($/BOE)
              38.39
              20.57
              87
 
 
 (1)
              Average
                  selling price includes the impact of hedging gains and losses where
                  applicable.
  ***Production
        Revenue***
 Gross
        production
        revenue, prior to the impact of hedging losses for the year ended
        December 31, 2000 increased by 45% to $49.8 million compared to $34.3
        million for the 1999 year-end. The increase in revenue for 2000 reflected
        a 15%
        decrease in production on a barrel of equivalent basis more than offset by
        an
        87% increase in commodity prices on a BOE basis when compared to the year
        1999.
        The production volume decrease was primarily attributable to the 1,200
        annualized BOE/d’s of production sold in 1999 as part of Founders’
        reorganization initiatives to streamline operations and to lower debt levels.
        Hedging losses for the year ended December 31, 2000 were $0.6 million
        or
        $0.44 per BOE, an 83% decrease from $3.5 million or $2.36 per BOE for 1999.
        Gross production revenue, after the impact of hedging losses for 2000, was
        $49.2
        million, an increase of 60% above the $30.8 million recorded in
        1999.
  46
  ***Crude
        Oil Price***
  The
        average crude
        oil price attained by Founders in 2000 was $32.10 per barrel, an increase
        of 71%
        over the $18.84 per barrel received for the comparable 1999 year. The 2000
        corporate oil price increase included a $0.69 per barrel foreign exchange
        hedging loss compared to $3.13 per barrel of hedging losses on foreign exchange
        and financial crude oil sales contracts in 1999. Founders’ record 2000 oil price
        reflected the WTI oil price average of U.S. $30.20 per barrel in 2000, a
        57%
        increase from the U.S. $19.24 for the 1999 fiscal year. Founders’ pre-hedged
        price per barrel of oil did not have a linear relationship to WTI due to
        the
        nature of Founders’ production mix and changes in crude oil
        differentials.
  Foreign
        exchange
        hedging losses in 2000 of $0.6 million were the result of three Canadian/U.S.
        dollar foreign exchange contracts as compared to 1999 foreign exchange hedge
        losses of $0.5 million. During 2000, Founders did not hedge any crude oil
        production while in 1999 commodity hedging losses of $2.5 million were realized
        on three fixed price crude oil hedges that were entered into during
        June 1999 on a total of 1,500 BOE/d of crude oil production through
        to
        December 31, 1999.
  ***Natural
        Gas Price***
  Natural
        gas prices
        realized by Founders for the year ended December 31, 2000 improved
        significantly to average of $5.19 per Mcf, a 108% increase from $2.49 received
        in 1999. Founders’ average natural gas selling price for the year ended 2000
        were not impacted by hedging while in the year ended December 31,
        1999 a
        net loss of $0.5 million or $0.12 per Mcf was realized on several forward
        sales
        contracts which expired at various dates in 1999.
  ***Royalties***
  Royalties,
        net of
        ARTC, on a BOE basis for the year ended December 31, 2000 increased
        81% to
        $7.74 per BOE, from $4.27 per BOE for the 1999 year-end. The BOE increase
        was
        due to both the 63% increase in corporate prices per BOE, prior to hedging
        activity, and the significant decrease in the ARTC rate for eligible Alberta
        production as a result of increased commodity prices. The ARTC rate averaged
        26%
        for 2000 compared to 69% in 1999. As a percentage of pre-hedged production
        revenue, net royalties averaged 19.9% in 2000 compared to 18.6% in 1999.
        The
        percentage increase was mainly due to the decrease in the ARTC claim in 2000
        which represented less than 1% of gross production revenue prior to hedging
        losses while on the comparable 1999 royalties the ARTC claim was in excess
        of 2%
        of gross production revenue. An additional contributing factor for increase
        in
        the royalty percentage during 2000 was the disposition of a number of ARTC
        eligible properties included in the asset rationalization undertaken by Founders
        in late 1999.
  ***Production
        Expenses***
  Production
        expenses
        for the year ended December 31, 2000 increased 10% to $9.7 million
        from
        $8.8 million incurred in 1999. The increase in absolute production expense
        occurred while production volumes on a BOE basis decreased by 15%. Unit
        production expenses increased by 29% to $7.57 per BOE from $5.88 per BOE
        for the
        comparable 1999 year-end. The increase in per unit operating costs
        reflected the shift in Founders’ operating activities as a result of the asset
        rationalization program completed in late 1999. This shift in operating focus
        resulted in a larger percentage of Founders’ operating cost base being fixed and
        not related to volumes. During 2000, there was also a general increase in
        the
        cost of services and supplies within the industry. During 2000 Founders also
        increased its production optimization budget, particularly in the Lloydminster
        heavy oil area, to take advantage of the exceptional commodity price
        environment.
  47
  ***Netbacks***
  For
        the year ended
        December 31, 2000, Founders’ field netbacks averaged $23.08 per BOE, a 121%
        increase from $10.42 per BOE recorded in the 1999 year-end. The table below
        sets
        out the impact of record commodity prices, offset by higher unit royalties
        and
        increased unit production expenses, on Founders’ field netbacks for the 2000
        year-end as compared to the same period in 1999.
  **(per
                  BOE)**
              **2000**
              **1999**
              **Percent**
                **Change**Gross
                  production revenue
              $38.39
              $20.57
              87Less:Royalties
                  (net of ARTC)
              7.74
              4.27
              81Production
                  expenses
              7.57
              5.88
              29Field
                  netbacks
              $23.08
              $10.42
              121
  ***General
        and Administrative Expense***
  General
        and
        administrative expense for the year ended December 31, 2000, before
        recoveries from joint accounts, increased 13% to $2.6 million compared to
        $2.3
        million for the year ended December 31, 1999. The year 2000 increase
        reflected the new team staffing levels and the impact of new corporate incentive
        programs incorporated as part of the corporate reorganization. Overhead
        recoveries from joint accounts amounted to $0.9 million for the year 2000
        compared to $0.6 million for the comparable 1999 period. The year over year
        increase in overhead recoveries in 2000 was due to both an increase in capital
        overhead recoveries in 2000 associated with increased capital spending and
        an
        increase in operating recoveries associated with new drills and the Neilburg
        property acquisition in the Lloydminster core area. On a net basis, general
        and
        administrative expense remained flat at $1.7 million in both 2000 and 1999.
        On a
        BOE basis, net general and administration expenses for the 2000 year-end
        increased 20% to $1.36 per BOE from $1.13 per BOE recorded in 1999 primarily
        as
        a result of the reduction in production volumes.
 48
  ***Interest
        Expense***
  Interest
        expense
        for the year ended December 31, 2000 decreased 9% to $3.3 million
        compared
        to $3.5 million recorded in 1999. The decrease was a result of a 14% decrease
        in
        average long-term debt levels to $42.7 million in 2000 compared to
        the
        $49.8 million average outstanding in 1999. The reduced debt level
        reflected
        Founders’ focus on managing and reducing its long-term debt as part of its asset
        rationalization program that was finalized in February 2000. The drop
        in
        the average long-term debt levels was however, partially offset by an increase
        in Founders’ weighted average interest rate to 7.6% in 2000 compared to 6.9% for
        the 1999 year **.**
  **($000s)**
              **2000**
              **1999**
              **Percent
                  Change**Interest
                  expense
              $3,265
              $3,454
              (5)Average
                  debt
                  outstanding
              $42,690
              $49,823
              (14)Average
                  interest rate
              7.6%
              6.9%
              10Interest
                  expense per BOE
              $2.55
              $2.30
              11
  ***Depletion,
        Depreciation and Amortization***
  Founders
        recorded
        depreciation, deletion and amortization for the year ended December 31,
        2000 in the amount of $11.8 million, a 4% decrease when compared to the $12.3
        million booked in 1999. The decrease occurred as a result of lower production,
        which was partially offset by an increase in the depreciation, deletion and
        amortization rate per BOE, which was up 12% to $9.17 per BOE on a 10:1 basis
        in
        2000 compared to $8.19 in 1999. The rate incorporated Founders’ depletable asset
        base, reserve additions and revisions for the year and current year production.
        At 6:1 the BOE rate for depletion, depreciation and amortization was $7.62
        in
        2000 compared to $6.82 in 1999.
  ***Capital
        and Future Taxes***
  Founders’
        capital
        tax expense for the year ended December 31, 2000 increased 100% to
        $1.0
        million compared to $0.5 million in 1999. The year over year increase was
        due
        entirely to the increase in the Saskatchewan resource surcharge, which was
        $0.9
        million in 2000 compared to $0.4 million for the 1999 year-end. This tax
        is
        levied at the wellhead against all production revenue generated in the province
        of Saskatchewan. The federal large corporations tax was approximately $0.1
        million for both 2000 and 1999.
  Effective
        January 1, 2000, Founders recorded a charge to retained earnings (deficit)
        and an offsetting increase in its future income taxes account on the balance
        sheet in the amount of $8.8 million. This resulted from a change in Founders’
        accounting policy to retroactively adopt the liability method of accounting
        for
        income taxes as recommended by the Canadian Institute of Chartered Accountants.
        Under this method, Founders’ records future income taxes based on the difference
        between the accounting and income tax value of an asset or liability. The
        significant adjustment of $11.2 million to both retained earnings (deficit)
        and
        future income taxes, recorded in the first quarter of 2000 and subsequently
        adjusted in the fourth quarter to $8.8 million reflecting January 1,
        2000
        updated tax pool balances. For Founders, the historical difference between
        the
        accounting and tax base value arose almost entirely through corporate
        acquisitions and flow-through share renouncements. For the year ended
        December 31, 2000 Founders recorded $5.2 million of future income
        tax on
        both the income statement and the balance sheet and for the comparable period
        in
        1999, recorded $0.2 million on the income statement. The increase was due
        to
        increased earnings driven by record commodity prices.
 49
  ***Tax
        Pools***
  Estimated
        tax pools
        amounted, in aggregate, to $51.0 million at December 31, 2000. The
        tax
        pools increased 18% from the $43.4 million estimate as at December 31,
        1999. The increase reflected an upward 9% adjustment to the year-end 1999
        balances as well as 2000 additions to the pools less the estimated claims
        required to eliminate income subject to tax in 2000. The following table
        summarizes Founders’ tax pool estimates at December 31, 2000.
  **($000s)**Canadian
                  exploration expense
              $10,770Canadian
                  development expense
              14,540Canadian
                  oil
                  and gas property expense
              13,650Undepreciated
                  capital cost
              10,420Other
              1,665Total
              $51,045
  ***Cash
        Flow and Earnings***
  **2000**
              **1999****Amount**
                **($000s)**
              
              
              **Per**
                
                **BOE**
              **Amount**
                **($000s)**
              **Per
                  BOE**Netback
              
              $
              29,604
              
              $
              23.08
              $
                  15,599
              $
                  10.42General
                  and
                  administrative expense
              
              
              1,748
              
              
              1.36
              1,686
              1.13Interest
                  expense
              
              
              3,265
              
              
              2.55
              3,454
              2.30Reorganization
                  costs
              
              
              -
              
              
              -
              1,150
              0.77Capital
                  tax
                  expense
              
              
              1,027
              
              
              0.80
              509
              0.346,040
              
              
              4.71
              6,799
              4.54Cash
                  flow
                  from operations
              
              
              23,564
              
              
              18.37
              8,800
              5.88Depletion,
                  depreciation and amortization
              
              
              11,755
              
              
              9.17
              12,257
              8.19Future
                  income
                  tax
              
              
              5,212
              
              
              4.06
              197
              0.1316,967
              
              
              13.23
              12,454
              8.32Net
                  earnings
                  (loss)
              
              $
              6,597
              
              $
              5.14
              $(3,654)
              $
                  (2.44)
 
 Cash
        flow from
        operations for year ended December 31, 2000 increased 169% to $23.6
        million
        from $8.8 million for the 1999 year-end. Net earnings increased dramatically
        to
        $6.6 million compared to a loss of $3.6 million for the 1999 comparable period.
        The 2000 results reflected record commodity prices while 1999 reflected the
        impact of lower commodity prices, $3.5 million in hedging losses and $1.1
        of
        non-recurring reorganization costs.
  50
  **Liquidity
        and Capital Resources**
  ***Capital
        Expenditures*** ***and
        Cash Distributions***
  **The
                  Trust**
              **Founders****Capital
                  Expenditures and Funding Expenditures**
                **($000s)**
              **For
                  the period March 6, 2001 to December 31, 2001**
              **For
                  the year ended December 31, 2000**
              **For
                  the year ended December 31, 1999****Expenditures:**Property,
                  plant and equipment
              $10,979
              $23,503
              $19,049Acquisition
                  of Maxx Petroleum Ltd.
              39,434
              —
              —Acquisition
                  of oil and gas properties
              —
              4,571
              138Cash
                  reserve
                  for future site restoration
              479
              —
              —Future
                  site
                  restoration costs
              —
              147
              39Acquisition
                  of Opal Energy Inc. and minority interests
              —
              —
              3,916Cash
                  distributions to unitholders
              36,880
              —
              —Settlement
                  of
                  financial instruments
              4,620
              —
              —Total
                  expenditures
              $92,392
              $28,221
              $23,142**Funded
                  by:**Cash
                  flow
                  from operations
              $36,228
              $23,564
              $    
                  8,800Disposition
                  of oil and gas properties
              1,421
              1,027
              15,392Issuance
                  of
                  common shares
              —
              95
              803Issuance
                  of
                  trust units
              57,039
              —
              —Increase
                  (decrease) in long-term debt
              7,500
              (9,540)
              (9,360)Increase
                  in
                  deferred charges
              —
              (700)
              —Convertible
                  debenture, net of issue costs
              —
              —
              14,275Change
                  in
                  working capital
              (9,796)
              13,775
              (6,768)Total
                  funds
              $92,392
              $28,221
              $23,142
  Capital
        expenditures are not budgeted a year in advance, but capital expenditures
        on
        wells are determined in conjunction with property or corporate acquisitions.
        No
        firm capital commitments were in place as of December 31, 2001. As of June
        30,
        2002, Provident had estimated capital expenditures for 2002 of $20 million
        related to planned or existing drilling at approximately 30
        locations.
  For
        the period
        March 6, 2001 to December 31, 2001, the Trust incurred total capital
        expenditures of $12.2 million, comprised of $0.4 million in land retention
        costs, $0.3 million in seismic costs, $5.7 million in drilling
        expenditures, $2.7 million in completion and equipping costs, $1.8 million
        in
        facility costs $0.1 million in office equipment, and $2.6 million of property
        acquisitions. During the period, the Trust also disposed of $1.4 million
        of
        non-core assets. This compares to forecast capital spending of
        $5.1 million, which did not include the increased activity associated
        with
        the assets acquired as part of the Maxx acquisition. More specifically, the
        forecast assumed drilling 11 heavy oil wells as compared to 18 wells that
        were
        actually drilled, and did not include amounts for property acquisitions or
        dispositions or the full amount expended to buy-out the sale-leaseback contracts
        on the gas processing facilities.
  Founders’
        all in
        capital expenditure program for the year ended December 31, 2000 totalled
        $28.2 million and was funded by cash flow from operations, property
        disposition proceeds and the change in working capital resulting from the
        receipt of funds upon closing its Pouce Coupe asset disposition on
        February 28, 2000. At December 31, 1999, the proceeds to close
        this
        asset sale were held under current assets, as assets held for sale. All in
        capital expenditures for the 1999 year totalled $23.1 million and were funded
        by
        a combination of cash flow from operations, property disposition proceeds,
        share
        issue proceeds and the issue of the convertible debenture partially offset
        by
        the related change in working capital.
  51
  ***Acquisition
        of Maxx Petroleum Ltd.***
  On
        May 25, 2001, pursuant to the Maxx Arrangement, Provident amalgamated with
        Maxx
        and recorded the assets and liabilities of Maxx using the purchase method
        of
        accounting. This resulted in increases to property, plant and equipment of
        $205.2 million which was comprised of the issuance of 7,475,000 units for
        $87.0
        million, cash consideration of $35.4 million, acquisition costs of $4.0 million,
        future income taxes of $57.1 million, assumed bank debt and working deficiency
        of $12.4 million and other liabilities assumed of $9.3 million. Operationally,
        the assets acquired from Maxx contributed 5,200 BOE/d or 53% of the production
        and $19.2 million or 43% of the net operating income for the period March
        6,
        2001 to December 31, 2001.
  In
        the 2001 forecast, Provident’s production mix was 16% light/medium oil, 42%
        heavy oil and 42% natural gas and natural gas liquids. The acquisition of
        Maxx
        resulted in light/medium oil remaining at 16%, heavy oil increasing to 52%
        and
        natural gas and natural gas liquids decreasing to 32%.
  ***Acquisition
        of Opal Energy Inc.***
  In
        January 1999, Founders acquired the remaining outstanding shares of
        Opal
        pursuant to the compulsory acquisition provisions of the *Canada
        Business
        Corporations Act* and Founders and
        Opal were amalgamated effective February 1, 1999. The total consideration
        paid in 1999 for the remainder of the outstanding shares of Opal amounted
        to
        $3.9 million in cash and 3,792,339 common shares with an ascribed value of
        $2.5 million.
  ***Bank
        Debt***
  At
        December 31, 2001 the Trust had $35.6 million of bank debt drawn against
        an $85
        million revolving demand credit facility with a syndicate of chartered banks.
        This amount drawn reflected the net proceeds of the December 2001 equity
        offering in the amount of $33 million, which was subsequently offset against
        the
        debt associated with the Richland acquisition in January 2002. Under the
        terms
        of the facility, the interest rate is calculated quarterly based on one-quarter
        trailing cash flow annualized and divided into the debt outstanding at
        quarter-end. The interest rates range from a minimum of prime plus 0.5% to
        a
        maximum of prime plus 1.5% at various debt to cash flow multiples. The Trust
        can
        draw on Canadian prime rate loans or, to lower its effective borrowing rate,
        access the banker’s acceptance market. As collateral security, Provident has
        pledged a $125 million fixed and floating charge debenture against all of
        its
        assets. Provident has no off-balance sheet debt.
  At
        December 31, 2000 Founders had $26.1 million of bank debt drawn against
        a
        $35 million revolving credit facility and had not drawn on an available $5.0
        million reducing term facility with a Canadian chartered bank. Founders’ total
        debt at December 31, 2000 was $40.3 million, compared to $49.6 million
        at
        December 31, 1999.
  ***Future
        Site Reclamation***
  Effective
        May 1,
        2001, as per the royalty agreement, Provident established a cash reserve
        for
        future site reclamation expenditures. In accordance with the agreement,
        Provident funds the reserve by paying $0.20 per BOE produced on a 10:1 basis
        into a segregated cash account. Actual expenditures incurred are then funded
        from the cash in this account. For the period ended December 31, 2001 the
        cash
        amount contributed to the reserve was $478,703. The Forecast did not have
        a cash
        fund for reclamation. Actual expenditures incurred for the period, net of
        salvage values, totalled $54,688.
  52
  ***Subordinated
        Convertible Debenture***
  On
        June 2, 1999, Founders closed a $15 million subordinated convertible
        debenture financing with Citicorp. Proceeds from this financing were used
        in
        1999 to repay the bridge loan that was used to fund the acquisition of Opal
        and
        the balance was applied to working capital. As part of the plan of arrangement
        among Founders, Provident and the Trust effective March 6, 2001, Citicorp
        agreed to the partial redemption and early conversion of the
        debenture.
  ***Equity***
  The
        Unitholders’
        equity balance at March 6, 2001 was brought forward from Founders’ share capital
        at the equivalent dollar value and the shares of Founders were exchanged
        on a
        one-for-three basis. On May 25, 2001 the Trust closed the Maxx acquisition
        and
        issued 7,475,000 Trust Units with an ascribed value of $87.0 million. On
        August
        29, 2001 the Trust closed a financing for 2,435,500 Units to raise gross
        proceeds of $26.4 million and on December 13, 2001 the Trust raised an
        additional $35 million through the issue of 4,000,000 Units. Costs associated
        with the financings and the conversion of the Founders shares totalled
        approximately $5.0 million. As of December 31, 2001 the Trust had 21,022,321
        Units outstanding.
  **Number
                  of Units**
              
              **Amount**Balance
                  at
                  beginning of period
              
              7,092,221
              $
              43,649Units
                  issued
                  to acquire Maxx Petroleum Ltd.
              
              7,475,000
              
              87,009Units
                  issued
                  to directors of Provident
              
              19,600
              
              243Units
                  issued
                  from treasury
              
              6,435,500
              
              61,425Share
                  issue
                  costs, net of tax
              
              -
              
              (4,995)Unitholders
                  capital at end of period
              
              21,022,321
              $
              187,331
  On
        January 27, 2000 Founders’ shareholders approved the consolidation of
        Founders’ shares on a one for four basis. For a detailed analysis of common
        share equity, employee stock options and other convertible or dilutive
        instruments, refer to Notes 5 and 6 of the Founders audited financial statements
        that form part of this annual report.
  ***Business
        Prospects***
  Provident
        believes
        that the business environment in 2002 will continue to support a number of
        positive opportunities, including both corporate and property acquisitions
        and
        continued access to capital. Provident’s strategy is to pursue growth
        opportunities that are accretive to both net asset value and cash flow, on
        a per
        unit basis. Provident will continue to adhere to a consistent and disciplined
        commodity price risk management program that is focused on minimizing the
        impact
        of volatile commodity prices on cash flow and to help lock-in the economics
        of
        accretive acquisitions. In addition, Provident will continue to manage its
        capital structure to ensure the prudent use of debt. Over the next twelve
        months, Provident expects to be able to meet its working capital, capital
        expenditure and debt service requirements through cash flow from operations
        and
        borrowings under its revolving credit facility.
  53
  **Item
                  6.**
              **Directors,
                  Senior Management and
                  Employees**
  **A.**
              **Directors
                  and Senior Management**
  The
        following are
        the names and municipality of residence of the directors and officers of
        Provident, their principal position with Provident and their principal
        occupations. The Trust does not have any directors or officers. All of the
        persons listed below have been engaged for more than five years in their
        present
        principal occupation or executive position with the same or associated companies
        except as indicated.
  **Name
                  and municipality**
                
                **of
                  residence**
              **Principal
                  occupation**
              **Date
                  first elected or appointed to office**
              **Number
                  of Trust Units owned beneficially or controlled (4)**
              **Percentage
                  ownership of Trust Units outstanding as of May 31,
                  2002**Grant
                  D.
                  Billing (2) (3)
                
                Chairman
                  of
                  the Board
                
                Calgary,
                  Alberta
              Chairman
                  of
                  the Board since March 6, 2001, and prior to that, Senior
                  Executive
                  Officer from October 1999 to March, 2001 and Executive Chairman,
                  Superior Propane Inc., a propane marketing company, since 1998.
                  From 1994
                  to 1998, President and Chief Executive Officer Norcen Energy Ltd.,
                  an oil
                  and gas exploration and production company.
              June 22,
                  1998
              463,707
              1.3%Thomas
                  W.
                  Buchanan (3)
                
                Calgary,
                  Alberta
              Chief
                  Executive Officer of Provident and the Manager since March 6,
                  2001,
                  and prior to that, Executive Vice President Corporate Development
                  and
                  Chief Financial Officer since October 1999. Prior to that,
                  President
                  and Chief Executive Officer of Provident and Director of Hawk Oil
                  Inc.
                  since 1996.
              November 23,
                  1994
              119,085
              0.3%Randall
                  J.
                  Findlay (3)
                
                DeWinton,
                  Alberta
              President
                  of
                  Provident and of the Manager since March 6, 2001, and prior
                  to that,
                  Executive Vice President and Chief Operating Officer since
                  December 1999 and, since October 2000, director of
                  TransAlta
                  Power L.P. Prior to that, Senior Vice President of TransCanada
                  PipeLines
                  Ltd. and President and Chief Executive Officer of TransCanada Gas
                  Processing L.P. from June 1998 to August 1999. From
                  1997 to 1998
                  President and Chief Executive Officer of Novagas Canada Ltd. and
                  from 1995
                  to 1997 Executive Vice President of Novagas Clearinghouse Ltd.
                  (both
                  Midstream service providers).
              December 14,
                  1999
              91,732
              0.3%Bruce
                  R.
                  Libin (1) (3)
                
                Calgary,
                  Alberta
              President
                  of
                  B.R. Libin Capital Corp., an investment, merchant banking and investment
                  banking advisory services company, since 1995. Chairman and Managing
                  Director of Destiny Resource Services Corp., a resource services
                  company,
                  since 1997 and December 2000, respectively. Director of
                  Maxx
                  Petroleum Ltd. from December 20, 2000 to May 25,
                  2001
              May 25,
                  2001
              85,133
              0.2%M.H.
                  (Mike)
                  Shaikh (1) (3)
                
                Calgary,
                  Alberta
              President
                  of
                  M.H. Shaikh Professional Corporation (Chartered Accountants).
              September 14,
                  1993
              149,676
              0.4%Byron
                  J.
                  Seaman (1) (3)
                
                Calgary,
                  Alberta
              Independent
                  businessman and private investor.
              November 23,
                  1994
              102,068
              0.3%Jeffrey
                  T.
                  Smith (2) (3)
                
                Calgary,
                  Alberta
              Independent
                  businessman and private investor. Prior to that, Chief Operating
                  Officer
                  of Northstar Energy Ltd., an oil and gas exploration and production
                  company, since 1996. Director of Maxx Petroleum Ltd. from
                  December 20, 2000 to May 25, 2001.
              May 25,
                  2001
              58,233
              0.2%John
                  B.
                  Zaozirny, Q.C. (2)(3)
                
                Calgary,
                  Alberta
              Counsel
                  to
                  the law firm of McCarthy Tétrault LLP and Vice-Chairman of Canaccord
                  Capital Corporation. Director and strategic advisor to a number
                  of public
                  and private corporations, as well as a Governor of the Business
                  Council of
                  British Columbia. Minister of Energy and Natural Resources for
                  Alberta
                  from 1982 to 1986, having first been elected as a Member of the
                  Alberta
                  Legislature in 1979.
              September 15,
                  1997
              71,316
              0.2%
 
 54
 
 (1)
              Member
                  of the
                  Audit, Environmental, Health and Safety
                  Committee.
  (2)
              Member
                  of the
                  Governance, Human Resources and Compensation
                  Committee.
  (3)
              Member
                  of the
                  Reserves Committee.
  (4)
              Beneficial
                  ownership of Units as of May 31, 2002, including Unit options that
                  are
                  exercisable within 60 days of May 31, 2002 and convertible, unsecured
                  subordinated debentures. See “Information on the Trust - History and
                  Development - General Development of the Business of the Trust
                  and
                  Provident.”
  The
        following is a
        brief description of the directors, senior officers, and key management and
        consulting personnel of Provident. Each of Provident’s directors serves until
        the next annual meeting of shareholders, or until the director’s resignation,
        whichever is earlier. Each of Provident’s executive officers works full-time for
        Provident.
  **Grant
        D.
        Billing**
 **Chairman
        of
        the Board**
  Mr. Billing
        obtained a B.Sc. from the University of Calgary in 1971 and a Chartered
        Accountant designation in 1976. Mr. Billing has more than 25 years
        of
        senior management experience in the oil and gas industry. Since March 6,
        2001, he has been Chairman of the Board of Provident and prior to that, he
        was
        Executive Chairman of Founders from October 1999 to March 6,
        2001 and
        a director since 1998. Mr. Billing is Chairman of the Board of Superior
        Propane Inc. and prior to September 2000, was Chairman and Chief Executive
        Officer of Superior Propane Inc. since 1998. Prior to 1998, Mr. Billing
        was
        President and Chief Executive Officer of Norcen Energy Resources Limited
        from
        1994 to 1998 and from 1992 to 1994 was President and Chief Executive Officer
        of
        Sceptre Resources Limited, an oil and gas company. Mr. Billing served
        as
        the Chairman of the Canadian Association of Petroleum Producers (“CAPP”) from
        1995 to 1996 and was a director of CAPP from 1993 to 1994.
  **Thomas
        W.
        Buchanan**
 **Chief
        Executive Officer and Director**
  Mr. Buchanan
        obtained a B.Comm from the University of Calgary in 1979 and a Chartered
        Accountant designation in 1981. He has over 19 years of senior financial
        and
        management experience primarily in the oil and gas industry. Mr. Buchanan
        has been Chief Executive Officer of Provident since March 6, 2001
        and prior
        to that he was Executive Vice President and Chief Financial Officer of Founders
        from October 1999 to March 6, 2001. Prior to that, Mr. Buchanan
        was President and Chief Executive Officer of Provident since November 1993.
        Mr. Buchanan has been a director of Provident or its predecessor since
        1993.
  55
  **Randall
        J.
        Findlay**
 **President
        and Director**
  Mr. Findlay
        obtained a B.Sc in Chemical Engineering from the University of British Columbia
        in 1973. He has more than 27 years of senior management experience in all
        aspects of the oil and gas industry. Mr. Findlay has been President
        of
        Provident since March 6, 2001 and prior to that he was Executive Vice
        President, Chief Operating Officer and a director of Founders from
        December 1999 to March 6, 2001. He has been a director of TransAlta
        Power L.P. since October 2000. Prior to that he was Senior Vice President
        of TransCanada PipeLines Limited, President of TransCanada Midstream and
        President and Chief Executive Officer of TransCanada Gas Processing L.P.
        from
        1998 to 1999. From 1995 to 1997 he held senior executive positions at Novagas
        Canada Ltd. as President and Executive Vice President of Novagas Canada Ltd.
        and
        Novagas Clearinghouse Ltd. Prior to that, Mr. Findlay held several
        senior
        executive positions at exploration and production companies in the oil and
        gas
        industry.
  **Bruce
        R.
        Libin**
 **Director**
  Mr. Libin
        was
        a director of Maxx from December 20, 2000 to May 25, 2001.
        Mr. Libin has also been the President of B.R. Libin Capital Corp.,
        an
        investment, merchant banking and investment banking advisory services company
        since 1995. He has been the Chairman and Managing Director of Destiny Resource
        Services Corp., a resource services company, since 1997 and December 2000,
        respectively.
  **Byron
        J.
        Seaman**
 **Director**
  Mr. Seaman
        is
        a private investor and co-owner of the Calgary Flames Hockey Club.
        Mr. Seaman holds a Bachelor of Science degree in Mechanical Engineering
        and
        an Honorary Doctorate in Science from the University of Saskatchewan. He
        has
        over 50 years of experience in the oil, gas and resource industries. Until
        1990,
        he was Chairman of Bovar Inc., a public corporation that provides environmental
        waste management services, and continues to serve as director of that company.
        Mr. Seaman has been a director of Provident or its predecessor since
        November 1994. He has been a director of Zargon Oil and Gas since
        1993,
        Endless Energy Corp. since 1997, Rider Resources Inc., an oil and gas company,
        since 1993 and Gauntlet Energy Corp. since 1994.
  **M.H.
        (Mike)
        Shaikh**
 **Director**
  Mr. Shaikh
        is
        President of M.H. Shaikh Professional Corporation, an accounting firm. Prior
        to
        that, he was an associate of Shaikh & Shikaze, Chartered Accountants for 12
        years. In the past five years, Mr. Shaikh has been an officer or director
        of the following public companies: Hawk Oil Inc., Lodestar Energy Inc., Winstar
        Resources Ltd., an oil and gas company, Maramar Ventures Inc., an oil and
        gas
        company, and Spearhead Resources Ltd., an oil and gas company. Mr. Shaikh
        has been a director of Provident or its predecessor since
        September 1993.
  56
  **Jeffrey
        T.
        Smith**
 **Director**
  Mr. Smith
        was
        a director of Maxx from December 20, 2000 to May 25, 2001.
        Prior to
        that, he was Chief Operating Officer of Northstar Energy Ltd., an oil and
        gas
        exploration and production company, since 1996. He has been a director of
        Rosetta Exploration Inc., an oil and gas company, since 2001 and Compton
        Petroleum Corporation since 1999.
  **Mark
        N.
        Walker**
 **Chief
        Financial Officer**
  Mr. Walker
        obtained a Bachelor of Commerce degree from the University of Calgary in
        1984
        and a Certified Management Accountant designation in 1988. He has been Chief
        Financial Officer of Provident since March 2001. Prior to this, he
        held the
        positions of Chief Financial Officer and/or Controller of Founders from
        September 1996 to March 2001. From 1993 to August 1996
        Mr. Walker held various financial and accounting positions at Sceptre
        Resources Limited, an oil and gas company.
  **John
        B.
        Zaozirny, Q.C.**
 **Director**
  Mr. Zaozirny
        is counsel to the law firm of McCarthy Tétrault and Vice-Chairman of Canaccord
        Capital Corporation. He is also a director and a strategic advisor to a number
        of public and private corporations, as well as a Governor of the Business
        Council of British Columbia. He served as Alberta’s Minister of Energy and
        Natural Resources from 1982 to 1986, having first been elected as a Member
        of
        the Alberta Legislature in 1979. Mr. Zaozirny has been a director
        of
        Provident since April 1998. He has been a director of Acetex Corporation,
        an industrial (chemicals and fertilizers) company, since September 1995,
        Canadian Oil Sands since June 1996, Computer Modelling Group Ltd.
        since
        March 1996, Fording Inc., a coal company, since September 2001,
        IPSCO
        Inc., an industrial (steel) company, since April 1987, Matrikon Inc.,
        a
        industrial products (technology) company, since April 1987, Middlefield
        Bancorp, a holding company, since February 2001, Pengrowth Energy
        Inc., an
        oil and gas company, since August 1987, Ravenwood Resources Inc.,
        an oil
        and gas company, since March 2001, Silent Witness Enterprises, an
        industrial products (technology) company, since January 1997.
  **B.**
              **Compensation**
  The
        following table
        sets forth the compensation of the executive officers of Provident in the
        year
        ended December 31, 2001 and of Founders in the years ended December 31, 2000
        and
        1999. In 2001, other than the granted Trust Unit options, the compensation
        to
        Messrs. Buchanan and Findlay set forth below was provided by the Manager
        in
        connection with the services they provided to the Trust and Provident under
        the
        Management Agreement.
  57
  **Summary
        Compensation Table**
  **Annual
                  Compensation**
              **Long
                  Term Compensation****Awards**
              **Payouts****Name
                  and Principal Position**
              **Year(5)**
              **Salary
                  ($)**
              **Bonus
                  ($)**
              **Other
                  Annual Compensation ($)**
              **Securities
                  Under Options Granted (#)(2)**
              **Restricted
                  Shares or Restricted Trust Units (#)**
              **LTIP
                  Payouts ($)**
              **All
                  Other Compensation ($)**Grant
                  D.
                  Billing(3)
                Executive
                Chairman
                of
                  the Board
                  of
                Directors
              2001
                2000
                1999
              $100,000
                $100,000
                $19,744(3)
              Nil
                Nil
                Nil
              (1)
              40,000
                118,750
                118,750
              Nil
                Nil
                Nil
              Nil
                Nil
                Nil
              Nil
                Nil
                NilThomas
                  W.
                  Buchanan
                Executive
                  Vice-President, Business Development and Chief Financial
                  Officer
              2001
                2000
                1999
              Nil
                $180,000
                $180,000
              Nil
                Nil
                Nil
              (1)
              Nil
                165,000
                127,500
              Nil
                Nil
                Nil
              Nil
                Nil
                Nil
              Nil
                Nil
                NilRandall
                  J.
                  Findlay(4)
                Executive
                  Vice-President and
                Chief
                  Operating Officer
              2001
                2000
                1999
              Nil
                $180,000
                $9,135(4)
              Nil
                Nil
                Nil
              (1)
              Nil
                125,000
                125,000
              Nil
                Nil
                Nil
              Nil
                Nil
                Nil
              Nil
                Nil
                Nil
  
 (1)
              Does
                  not
                  exceed the lesser of $50,000 or 10% of the annual salary and bonus
                  for the
                  named executive officer.
  (2)
              The
                  “Securities Under Options Granted” have been adjusted by dividing the
                  number of options outstanding at year-end by four to reflect the
                  reorganization of Founders into the
                  Trust.
  (3)
              Mr. Billing
                  was appointed as the Executive Chairman of Founders effective
                  October 28**,**1999 at an
                  annual salary of $100,000.
  (4)
              Mr. Findlay
                  was appointed as an Executive Vice-President and the Chief Operating
                  Officer effective December 14, 1999 at an annual salary
                  of
                  $180,000.
  (5)
              For
                  2001,
                  “Year” signifies the period March 6, 2001 to December 31,
                  2001.
  **Employee
        Incentive Share Option Plan**
  In
        connection with the Founders Arrangement, effective March 6, 2001
        all
        Founders stock options immediately vested and became exercisable prior to
        such
        arrangement becoming effective. Any stock options not exercised at such time
        were canceled. Founders made a loan available to any employee, officer or
        director exercising options (including Randall J. Findlay and
        Thomas W. Buchanan) for a maximum term of three months from the date
        of the
        arrangement taking effect at an interest rate equal to the average commercial
        bank lending rate available to Founders. Any distributions on the Trust Units
        made to such employee, officer or director during that period would be applied
        to the loan amount due. Principal and accrued interest on the loans would
        be due
        and payable in full on the earlier of the due date of the loans or at the
        time
        of termination of employment. Grant D. Billing was provided with similar
        loan
        arrangements in respect of the exercise of certain common share purchase
        warrants issued by Founders. The term of any such loan provided to
        Mr. Billing in respect of such warrants would be to December 31,
        2001.
        As of June 24, 2002, no directors and officers of Provident had loans
        outstanding payable to the Trust.
  **Trust
        Unit
        Option Plan**
  Provident
        Energy
        Trust has implemented a trust unit option plan (the “Trust Option Plan”). Under
        the Trust Option Plan, options to purchase a maximum of 700,000 Trust Units
        may
        be granted to employees, officers, directors and consultants to the Trust
        and
        its subsidiaries. The Trust Option Plan will be administered by Provident.
        Subject to regulatory approval, the exercise price of an option will be
        determined at the time of grant and is to be not less than the closing price
        of
        the Trust Units on the TSX on the last day preceding the grant on which a
        trade
        of Trust Units occurred on such exchange, subject to certain reductions in
        the
        exercise price of an option in certain circumstances based upon the cash
        distributions made on the Trust Units. The term of an option and vesting
        provisions are to be determined at the time of grant and may vary as between
        individual grants of options. However, the term of an option shall not be
        less
        than one year and not more than ten years from the date of grant. Options
        are
        exercisable only during the term of employment or service of an employee,
        consultant or officer or during the period of service as a director or trustee.
        Provident shall determine whether any or all of the options shall be exercisable
        for a period following the date of termination of employment or service at
        the
        time of granting the option, subject to regulatory approvals.
  58
  The
        number of Trust
        Units subject to options which may be granted from time to time under the
        Trust
        Option Plan shall not exceed 700,000 Trust Units (which number may be decreased
        at any time and may be increased from time to time, subject to regulatory
        approval and the approval of the Trust Unitholders). The number of Trust
        Units
        reserved for issuance pursuant to options granted to insiders of the Trust
        or
        Provident (or their advisors, including ManagementCo) shall not exceed 10%
        of
        the total number of Trust Units then outstanding. Furthermore, the issuance
        to
        insiders of the Trust or Provident (or their advisors, including ManagementCo)
        shall not exceed or result in the issuance to such insider during a one year
        period of more than 10% of the total number of Trust Units outstanding, nor
        may
        the issuance of Trust Units held by such insider of the Trust or Provident
        (or
        their advisors, including ManagementCo), and associates of such insider,
        within
        a one-year period, exceed 5% of the total number of Trust Units then
        outstanding. In addition, the number of Trust Units reserved for issuance
        to any
        one person pursuant to options shall not exceed 5% of the total number of
        Trust
        Units then outstanding. Options are not assignable or transferable. No financial
        assistance will be provided to holders of options who wish to exercise their
        options to acquire Trust Units. As of May 31, 2002, there were 635,101 options
        outstanding under the Trust Option Plan.
  **Employment
        Contracts**
  On
        March 6, 2001, Founders converted from an exploration and production company
        into a cash-distributing energy trust through the Founders Arrangement, which
        was approved by the shareholders of Founders. Prior to the conversion, Founders
        had employment agreements with its employees, as discussed below. Following
        the
        conversion, all of the employment agreements were terminated, as the Trust
        has
        no employees. Under the Management Agreement, the Manager manages the Trust
        and
        compensates its employees in connection with the services they provide to
        the
        Trust and Provident.
  The
        terms of
        compensation for the executive officers of Founders were established under
        employment agreements (the “Employment Agreements”) dated:
        (i) November 1, 1999, between Founders and its Executive Chairman,
        Mr. Grant D. Billing; (ii) effective December 1,
        1997
        between Founders and its Executive Vice-President, Corporate Development
        and
        Chief Financial Officer, Mr. Thomas W. Buchanan; and (iii) effective
        December 14, 1999 between Founders and its Executive Vice-President
        and
        Chief Operating Officer, Mr. Randall J. Findlay. Pursuant to
        the
        Employment Agreements, Mr. Billing received an annual salary of $100,000
        and Messrs. Buchanan and Findlay received an annual salary of $180,000.
        If
        employment had been terminated other than for cause, then each of
        Messrs. Billing, Buchanan and Findlay would have been entitled to
        receive,
        within seven business days after the date of termination, an amount equal
        to two
        times their then current annual salary plus an amount equal to the employee
        benefits that would have been available for a period of 24 months from the
        effective date of the termination. In the event of a “change of control” in
        Provident (as defined in the Employment Agreements), each of such executive
        officers would have been deemed, at their election, to have given formal
        notice
        of termination and would have been entitled to receive the compensation
        described above. Under the Employment Agreements, if any of such officers
        had
        been terminated without cause or had elected to receive notice of termination
        pursuant to a change of control they would have each had the right to exercise
        all stock options, whether or not such options had vested, for a period of
        six
        months from the date of such notice or election.
  59
  Pursuant
        to the
        Founders Arrangement, effective March 6, 2001 Mr. Billing terminated
        his position as Executive Chairman of Founders and became Chairman of the
        Board
        of Provident. Under the terms of his Employment Agreement, Mr. Billing
        received a cash settlement of $319,555, of which $300,000 was to be reimbursed
        by the Manager from management fees paid by Provident.
  **Compensation
        of Directors**
  Effective
        March 6, 2001, the compensation plan for the directors of Provident
        was
        changed to better align the director’s compensation with that of other oil and
        gas trusts and other comparable sized Canadian public companies. As a result,
        the annual retainer paid to the directors was set at $50,000 for the
        non-executive board of directors Chairman and $12,000 for each other independent
        director, excluding the nominees of the Manager. In addition, an annual retainer
        of $3,000 will be paid to the Chairman of any committee of the board of
        directors and $1,500 will be paid to any member of a committee of the board
        of
        directors. The annual retainer for the independent members of the board of
        directors and board of directors committees are to be paid in four equal
        quarterly cash installments on the first day of January, April, July and
        October of each calendar year. In addition, the non-executive board
        of
        directors Chairman will receive $1,250 for each meeting attended and each
        independent director will receive $1,000 for each meeting attended. All
        independent directors are compensated $500 per meeting for attending single
        purpose meetings to set the monthly cash distribution amount for the Trust.
        Each
        director is also compensated for all reasonable out-of-pocket expenses incurred
        in respect of attending any board or committee meeting. The President and
        Chief
        Executive Officer of Provident, who also act as directors of Provident, do
        not
        receive any compensation for acting as directors of Provident.
  All
        directors,
        excluding the nominees of the Manager, are also entitled to participate in
        the
        Trust Option Plan for Provident. In this regard, on March 6, 2001
        the
        directors were granted a total of 105,000 options to purchase Trust Units
        at an
        exercise price of $10.95 per Unit, and on March 29, 2001 the directors
        were
        granted an additional 125,000 options to purchase Trust Units at an exercise
        price of $11.09 per Unit. These options expire on March 5, 2005 and March
        28,
        2005, respectively.
  The
        following table
        summarizes the details concerning the grant of options to the directors of
        Provident during the period March 6, 2001 to December 31, 2001. No options
        to
        acquire Trust Units were exercised by any director of Provident during this
        period.
  **Name**
              **Trust
                  Units Under Option Granted**
              **Date
                  of Grant**
              **Trust
                  Units Under Option Vested**
              **Exercise
                  Price ($/Trust Unit)**
              **Option
                  Expiration Date**Thomas
                  W.
                  Buchanan
              Nil
              -
              -
              -
              -Randall
                  J.
                  Findlay
              Nil
              -
              -
              -
              -Grant
                  D.
                  Billing
              15,000
                25,000
              March
                  6,
                  2001
                March
                  29,
                  2001
              5,000
                8,333
              $10.95
                $11.09
              March
                  5,
                  2005
                March
                  28,
                  2005Bruce
                  R.
                  Libin
              40,000
              May
                  28,
                  2001
              13,333
              $12.39
              May
                  27,
                  2005M.H.
                  (Mike)
                  Shaikh
              25,000
                25,000
              March
                  6,
                  2001
                March
                  29,
                  2001
              15,000
                8,333
              $10.95
                $11.09
              March
                  5,
                  2005
                March
                  28,
                  2005Byron
                  J.
                  Seaman
              25,000
                25,000
              March
                  6,
                  2001
                March
                  29,
                  2001
              15,000
                8,333
              $10.95
                $11.09
              March
                  5,
                  2005
                March
                  28,
                  2005Jeffrey
                  T.
                  Smith
              40,000
              May
                  28,
                  2001
              13,333
              $12.39
              May
                  27,
                  2005John
                  B.
                  Zaozirny
              25,000
                25,000
              March
                  6,
                  2001
                March
                  29,
                  2001
              15,000
                8,333
              $10.95
                $11.09
              March
                  5,
                  2005
                March
                  28,
                  2005Victor
                  Roskey
                  (1)
              15,000
                25,000
              March
                  6,
                  2001
                March
                  29,
                  2001
              5,000
                8,333
              $10.95
                $11.09
              March
                  5,
                  2005
                March
                  28,
                  2005
  60
 
 (1)
              Mr.
                  Roskey
                  resigned his position as a director of Provident on January 28,
                  2002. In
                  accordance with the terms of the Trust Option Plan, all options
                  to
                  purchase Trust Units shall expire and terminate 90 days following
                  the date
                  such option holder ceases to be a director of
                  Provident.
  The
        options issued
        to the directors of Provident vest as to one-third immediately upon the date
        of
        issuance and as to a further one-third in each of the first and second
        anniversaries of the date of issuance.
  The
        following table
        summarizes, for the directors of Provident, the number of Trust Units acquired
        pursuant to the exercise of options, if any, the aggregate value realized
        upon
        exercise, if any, and the number of Trust Units issuable pursuant to unexercised
        options as of December 31, 2001. Value realized upon exercise is the
        difference between the market value of the Trust Units on the exercise date
        and
        the exercise price of the options. The value of the unexercised and in-the-money
        options is the difference between the exercise price of the options and the
        closing stock value of the Trust Units on December 31, 2001, which
        was
        $8.19 per Trust Unit, and includes certain allowable reductions to the exercise
        price of the options in accordance with the Trust Option Plan based upon
        the
        cash distributions to Unitholders.
  **Unexercised
                  options at**
                **December
                  31, 2001**
              **Value
                  of Unexercised in-the-Money Options at December 31, 2001
                  ($)****Name**
              **Securities
                  Acquired on Exercise**
              **Aggregate
                  Value Realized ($)**
              **Vested**
              **Not
                  Vested**
              **Vested**
              **Not
                  Vested**Thomas
                  W.
                  Buchanan
              Nil
              -
              -
              -
              -
              -Randall
                  J.
                  Findlay
              Nil
              -
              -
              -
              -
              -Grant
                  D.
                  Billing
              Nil
              -
              13,333
              26,667
              Nil
              NilBruce
                  R.
                  Libin
              Nil
              -
              13,333
              26,667
              Nil
              NilM.H.
                  (Mike)
                  Shaikh
              Nil
              -
              23,333
              26,667
              Nil
              NilByron
                  J.
                  Seaman
              Nil
              -
              23,333
              26,667
              Nil
              NilJeffrey
                  T.
                  Smith
              Nil
              -
              13,333
              26,667
              Nil
              NilJohn
                  B.
                  Zaozirny
              Nil
              -
              23,333
              26,667
              Nil
              NilVictor
                  Roskey(1)
              Nil
              -
              13,333
              26,667
              Nil
              Nil
 
  (1)
              Mr.
                  Roskey
                  resigned his position as a director of Provident on January 28,
                  2002. In
                  accordance with the terms of the Trust Option Plan, all options
                  to
                  purchase Trust Units expire and terminate 90 days following the
                  date such
                  option holder ceases to be a director of
                  Provident.
  For
        the financial
        year ended December 31, 2000, each of the independent directors of
        Founders
        was entitled to participate under Founders’ independent directors compensation
        arrangement, which provided an annual retainer to the independent directors
        of
        Founders for their services in their capacity as directors. The directors’
        compensation arrangement was comprised of the following:
  ·
              an
                  annual
                  retainer paid to independent directors of Founders or any of its
                  affiliates in the amount of $12,000, with the board of directors
                  or a
                  committee of the board of directors determining who will be paid
                  an annual
                  retainer and the amount of the annual
                  retainer;
  ·
              the
                  annual
                  retainer being paid in two components, with one-half paid in cash
                  each
                  quarter and one-half paid through the issuance of Common Shares
                  on
                  January 1, 2000; and
  ·
              the
                  number of
                  Trust Units issued to each independent director being determined
                  by
                  dividing one-half of the annual retainer by the closing price of
                  Common
                  Shares on the TSX on the first trading day in January 1,
                  2000, which
                  was $1.68 per share.
  The
        issuance of
        common shares under the directors’ compensation arrangement was intended to
        further align the interests of the independent directors with the long term
        interests of the shareholders. The following table outlines the cash and
        number
        and value of the common shares of Founders issued to the independent directors
        for the 2000 fiscal year.
  61
  **Name**
              **Annual**
                **Retainer**
              **Cash
                  Component**
              **Value
                  of Compensation to be paid in Shares**
              **#
                  of
                  Shares**
                **Issued(1)**M.H.
                  (Mike)
                  Shaikh
              $12,000
              $6,000
              $6,000
              3,572John
                  B.
                  Zaozirny, Q.C.
              $12,000
              $6,000
              $6,000
              3,572Byron
                  J.
                  Seaman
              $12,000
              $6,000
              $6,000
              3,572Kelly
                  J.
                  Ogle(2)
              $7,500
              $1,500
              $6,000
              3,572Victor
                  Roskey
              $12,000
              $6,000
              $6,000
              3,572
 
 
 (1)
              Based
                  on the
                  closing price for Founders’ common shares on the TSX at December 31,
                  1999 of $1.68 divided into the equivalent dollar value of compensation
                  to
                  be received for the ensuing calendar
                  year.
  (2)
              Mr. Ogle
                  resigned as a director of Founders effective March 1,
                  2000.
  **Directors’
        and Officers’ Insurance**
  As
        of June 30, 2002, directors’ and officers’ liability insurance in the amount of
        $15,000,000 and subject to a $50,000 deductible is purchased on an annual
        basis
        for the directors and officers of Provident. Coverage is in force for a 12-month
        term commencing October 1, 2001. The cost of such policy for the current
        year is
        $5,900.
  In
        addition, run-off directors’ and officers’ liability coverage in the amount of
        $5,000,000 and subject to a $10,000 corporate reimbursement and $15,000
        securities claim was purchased for the term of August 3, 1999 to
        August 3, 2005 for the directors and officers of Opal Energy Inc.,
        a
        company acquired by Founders on December 22, 1998. The cost of such
        policy
        was $23,050.
  **C.**
              **Board
                  Practices**
  **Committees
        of the Board**
  The
        Board presently
        has three standing committees, being the Audit, Environmental, Health and
        Safety
        Committee, the Governance, Human Resources and Compensation Committee, and
        the
        Reserves Committee. All of the members of the Audit, Environmental, Health
        and
        Safety Committee and the Governance, Human Resources and Compensation Committee
        are independent directors. All directors are members of the Reserves
        Committee.
  ***Audit,
        Environmental, Health and Safety Committee***
  The
        Audit,
        Environmental, Health and Safety Committee consists of Messrs. M.H.
        (Mike)
        Shaikh (Chairman), Bruce Libin and Byron Seaman. The functions of the Audit,
        Environmental, Health and Safety Committee include the review and recommendation
        to the board of directors of the annual financial statements and related
        management’s discussion and analysis, and the review of the interim financial
        statements. The committee reviews and establishes, in conjunction with the
        external auditors and management, audit plans and procedures. The committee
        also
        reviews and makes recommendations to the board of directors on Provident’s
        internal control procedures and management information systems. The committee
        discusses with the external auditors its independence from management and
        Provident, and it considers the compatibility of the external auditor’s
        non-audit services to Provident, vis-à-vis its independence.
  The
        committee is
        responsible for ensuring that management has in place effective programs
        relating to environment, health and safety matters, including the identification
        of risks and the compliance with legal requirements, and ensuring that
        management administers Provident’s policies and procedures on these
        matters.
  62
  ***Governance,
        Human Resources and Compensation Committee***
  The
        Governance,
        Human Resources and Compensation Committee consists of Messrs. John
        Zaozirny (Chairman), Grant Billing and Jeffrey Smith. The committee is
        responsible for recommending to the board of directors suitable candidates
        for
        director positions. The selection assessment factors include diversity, age,
        skills, judgment, integrity, gender, experience, profile, business prospects,
        and such other factors deemed appropriate, all in a context of an assessment
        of
        the perceived needs of the board of directors and Provident at the time.
        In
        addition, the committee assists the board of directors on corporate governance
        issues and in compiling the results of a directors’ questionnaire dealing with
        the effectiveness of the board of directors, its members and its
        committees.
  The
        committee also
        has the mandate of reviewing Provident’s human resources policies and procedures
        and compensation and incentive programs. The committee is responsible for
        assessing senior management’s performance and reviewing and negotiating the
        Management Agreement. The compensation committee reviews the adequacy and
        form
        of directors’ compensation and makes recommendations designed to ensure that
        directors’ compensation realistically reflects the responsibilities of the board
        of directors. The committee also administers the Trust Option Plan and makes
        recommendations to the board of directors respecting grants of options under
        the
        plan.
  ***Reserves
        Committee***
  The
        Reserves
        Committee is comprised of all the members of the board of directors (the
        majority of whom are “unrelated directors”) and is responsible for ensuring that
        the Manager and management have designed and implemented effective reserve
        programs, controls and reporting systems. The committee’s mandate also includes
        reviewing the independent reserves evaluation of Provident, reviewing and
        approving any proposals to change the evaluating engineers and resolving
        any
        disputes that may arise between the evaluating engineers and management.
        The
        committee communicates regularly with the Manager and management to ensure
        that
        all reserve evaluations and reports have been properly handled and
        reported.
  **D.**
              **Employees**
  As
        of May 20, 2002, Provident employed 130 staff, 72 at its head office in Calgary,
        Alberta and 58 staff at various field locations in Alberta and
        Saskatchewan.
  **E.**
              **Share
                  Ownership**
  See
“—Directors
        and
        Senior Management.”
   **Item
                  7.**
              **Major
                  Shareholders and Related Party
                  Transactions**
  **A.**
              **Major
                  Shareholders**
  As
        of June 24, 2002, to the knowledge of the directors and officers of
        Provident, no person beneficially owned or exercised control or direction
        over
        Trust Units carrying more than 5% of the voting rights attached thereto,
        other
        than Citadel Smart Funds, which owned 1,947,800 Trust Units (acquired in
        March
        2002) or approximately 5.3% of the outstanding Trust Units. As of June 24,
        2002, none of the Trust’s Unitholders had any special voting
        rights.
  63
  To
        the best of the Trust’s knowledge, as of May 15, 2002 there were approximately
        2,083 U.S. residents (according to the records of Cede & Co. - a depository
        trust firm holding securities on behalf of brokerage firms and other financial
        institutions in the United States) holding approximately 15% of the Trust’s
        issued and outstanding Trust Units.
  **B.**
              **Related
                  Party Transactions**
  Pursuant
        to the
        Management Agreement, the Manager provides certain management, administrative
        and support services to both Provident and the Trust. As compensation, the
        Manager receives a fee equal to 2% of Operating Cash Flow and 6% of the Total
        Return Amount, the latter of which is payable, at the option of the board
        of
        directors of Provident, in cash or Trust Units. The Manager is owned by Messrs.
        Buchanan and Findlay, the Chief Executive Officer and President, respectively,
        of Provident. See “Memorandum and Articles of Association — Provident Management
        Corporation.”
   **Item
                  8.**
              **Financial
                  Information**
  See
“Item
        17 -
        Financial Statements” and pages F-1 through F-31.
  **Legal
        Proceedings**
 There
        are no
        material legal proceedings currently outstanding, threatened or pending,
        by or
        against the Trust or Provident.
   **Item
                  9.**
              **The
                  Listing**
  The
        outstanding
        Trust Units are traded on the TSX under the trading symbol “PVE.UN” and on the
        AMEX under the trading symbol “PVX.” The Trust Units commenced trading on the
        AMEX on June 22, 2001. Prior to March 12, 2001, the trading
        information in this annual report is in respect of the common shares of
        Founders, which were traded on the TSX under the trading symbol “FDE.” The
        following tables set forth the price range and trading volume of Trust Units
        on
        the TSX and the AMEX for the periods indicated.
  64
  **TSX**
  **Period(1)**
              **High**
              **Low**
              **Volume****Founders**
                
                **1997**Annual
              2.15
              0.60
              27,976,409**1998**Annual
              1.27
              0.51
              9,888,751**1999
                  - Pre-Consolidation(2)**First
                  Quarter
              0.65
              0.35
              4,435,641Second
                  Quarter
              0.70
              0.40
              5,043,331Third
                  Quarter
              0.80
              0.40
              6,589,316Fourth
                  Quarter
              0.78
              0.36
              6,394,587Annual
              0.80
              0.35
              22,462,875**2000
                  - Post-Consolidation(3)**First
                  Quarter
              1.60
              1.10
              2,097,178Second
                  Quarter
              2.55
              1.30
              2,081,173Third
                  Quarter
              2.40
              1.91
              1,287,981Fourth
                  Quarter
              2.65
              1.91
              2,675,000Annual
              2.65
              1.10
              8,141,332**The
                  Trust**
                
                **Period
                  from March 6, 2001 to December 31, 2001**First
                  Quarter
              11.55
              10.50
              681,990Second
                  Quarter
              12.50
              10.25
              5,462,742Third
                  Quarter
              11.50
              8.72
              3,644,781Fourth
                  Quarter
              10.20
              7.77
              5,043,512Period
                  from
                  March 6, 2001 to December 31, 2001
              12.50
              7.77
              14,833,025**2001**December
              8.75
              7.77
              1,697,343**2002**January
              9.00
              8.15
              8,319,317February
              9.52
              8.71
              3,797,732March
              10.75
              9.50
              4,446,084April
              10.65
              9.80
              3,991,014May
              11.44
              10.20
              4,038,140
 
 
 (1)
              All
                  information is as reported by the
                  TSX.
  (2)
              Effective
                  January 27, 2000, the shareholders of Founders approved
                  the
                  consolidation of Founders’ common shares on a four-for-one basis.
                  Accordingly, all per common share information and trading volumes
                  for the
                  2000 calendar year reflect the impact of the
                  consolidation.
  (3)
              As
                  part of
                  the arrangement involving Founders, Provident and the Trust effective
                  as
                  of March 6, 2001, each three common shares of Founders were
                  ultimately exchanged for one Trust
                  Unit.
  65
  **AMEX**
 **Period(1)**
                **High**
                **Low**
                **Volume****2001**June
                8.05
                6.8
                115,400July
                7.6
                6.51
                178,900August
                7.49
                6.7
                538,900September
                7
                5.6
                433,300October
                6.71
                5.65
                564,300November
                6.19
                5.45
                604,300December
                5.69
                5.06
                577,200**2002**January
                5.58
                5.12
                688,100February
                5.97
                5.41
                556,800March
                6.85
                5.95
                979,100April
                6.9
                6.16
                1,126,800May
                7.52
                6.5
                1,866,600
 **_________________________**
  (1)  All
        information is
        as reported by the AMEX. The Trust Units began trading on the AMEX in June
        2001.
   **Item
                  10.**
              **Additional
                  Information**
  **A.**
              **Share
                  Capital**
  Not
        applicable.
  **B.**
              **Memorandum
                  and Articles of
                  Association**
  **I.**  **Provident
        Energy Trust**
  **Trust
        Units**
  An
        unlimited number of Trust Units may be created and issued pursuant to the
        Trust
        Indenture. Each Unit represents an equal fractional undivided beneficial
        interest in any distribution from Provident Energy Trust (whether of net
        income,
        net realized capital gains or other amounts) and in any net assets of the
        Trust
        in the event of termination or winding-up of the Trust. All Trust Units
        outstanding from time to time shall be entitled to an equal share of any
        distributions from, and in any net assets of, Provident Energy Trust in the
        event of the termination or winding-up of Provident Energy Trust. All Trust
        Units of Provident Energy Trust shall rank among themselves equally and ratably
        without discrimination, preference or priority. Each Unit is transferable,
        is
        not subject to any conversion or pre-emptive rights and entitles the holder
        thereof to require Provident Energy Trust to redeem any or all of the Trust
        Units held by such holder (see “—Redemption Right”) and to one vote at all
        meetings of holders of Trust Units for each Trust Unit held. Holders of Trust
        Units shall not be subject to any liability in contract or tort or of any
        other
        kind in connection with the assets, obligations or affairs of Provident Energy
        Trust or with respect to any acts performed by the Trustee or any other person
        pursuant to the Trust Indenture.
  66
  **Special
        Voting Units**
  An
        unlimited number of Special Voting Units may be created and issued pursuant
        to
        the Trust Indenture. Holders of Special Voting Units, shall not be entitled
        to
        any distributions of any nature whatsoever from Provident, shall be entitled
        to
        such number of votes at meetings of holders of Trust Units as may be prescribed
        by the board of directors of Provident in the resolution authorizing the
        issuance of any Special Voting Units. Except for the right to vote at meetings
        of the holders of Trust Units, the Special Voting Units shall not confer
        upon
        the holders of Special Voting Units any other rights. As of June 24,
        2002,
        no Special Voting Units have been issued or are outstanding.
  **Cash
        Distributions**
  The
        Trustee intends
        to make cash distributions on or about the 15th day of each month to Trust
        Unitholders of record on the immediately preceding distribution record date
        in
        amounts equal to all of the interest, royalty and dividend income of the
        Trust,
        net of the Trust’s administrative expenses. In addition, Unitholders may, at the
        discretion of the Trustee, receive distributions in respect of repayments
        of
        principal made by Provident to the Trust on the Initial Notes or Acquisition
        Notes, as the case may be. It is anticipated however, that the Trust will
        reinvest a substantial portion of the repayments of principal on the Initial
        Notes and Acquisition Notes to enable Provident to make capital expenditures
        to
        develop or acquire additional oil and natural gas properties to enhance cash
        flow from operations.
  The
        Trust seeks to
        provide a stable stream of cash distributions, subject to fluctuations in
        the
        quantity of petroleum and natural gas substances produced, prices received
        for
        that production, hedging contract receipts and payments, taxes, management
        fees,
        direct expenses of the Trust, reclamation fund contributions, capital
        expenditures, debt servicing, operating costs, debt service charges and general
        and administrative expenses as determined necessary by ManagementCo on behalf
        of
        the Trust.
  **Redemption
        Right**
  Trust
        Units are
        redeemable 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
        redemption. Upon receipt of the redemption request by the Trust, the holder
        thereof shall only be entitled to receive a price per Unit (the “Market
        Redemption Price”) equal to the lesser of:
  ·
              90%
                  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
                  are
                  surrendered for redemption; and
  ·
              the
“closing
                  market price” on the principal market on which the Trust Units are quoted
                  for trading on the date that the Trust Units are surrendered for
                  redemption.
  For
        the purposes of
        this calculation, “market price” will be an amount equal to the simple average
        of the closing price of the Trust Units for each of the trading days on which
        there was a closing price; provided that, if the applicable exchange or market
        does not provide a closing price but only provides the highest and lowest
        prices
        of the Trust Units traded on a particular day, the market price shall be
        an
        amount equal to the simple average of the average of the highest and lowest
        prices for each of the trading days on which there was a trade; and provided
        further that if there was trading on the applicable exchange or market for
        fewer
        than five of the 10 trading days, the market price shall be the simple average
        of the following prices established for each of the 10 trading days; the
        average
        of the last bid and last ask prices for each day on which there was no trading;
        the closing price of the Trust Units for each day that there was trading
        if the
        exchange or market provides a closing price; and the average of the highest
        and
        lowest prices of the Trust Units for each day that there was trading, if
        the
        market provides only the highest and lowest prices of Trust Units traded
        on a
        particular day. The “closing market price” shall be: an amount equal to the
        closing price of the Trust Units if there was a trade on the date; an amount
        equal to the average of the highest and lowest prices of the Trust Units
        if
        there was trading and the exchange or other market provides only the highest
        and
        lowest prices of Trust Units traded on a particular day, and the average
        of the
        last bid and last ask prices if there was no trading on the date.
  The
        aggregate
        Market Redemption Price payable by Provident Energy Trust in respect of any
        Trust Units surrendered for redemption during any calendar month shall be
        satisfied by way of a cash payment on the last day of the following month.
        The
        entitlement of holders of Trust Units to receive cash upon the redemption
        of
        their Trust Units is subject to the limitation that the total amount payable
        by
        Provident Energy Trust in respect of such Trust Units and all other Trust
        Units
        tendered for redemption in the same calendar month and in any preceding calendar
        month during the same year shall not exceed $250,000; provided that Provident
        may, in its sole discretion, waive such limitation in respect of any calendar
        month. If this limitation is not so waived, the Market Redemption Price payable
        by Provident Energy Trust in respect of Trust Units tendered for redemption
        in
        such calendar month shall be paid on the last day of the following month
        by:
  67
  ·
              the
                  Trust
                  distributing Initial Notes having an aggregate principal amount
                  equal to
                  the aggregate Market Redemption Price of the Trust Units tendered
                  for
                  redemption; or
  ·
              if
                  Provident
                  does not hold Initial Notes having a sufficient principal amount
                  outstanding to effect such payment, by the Trust issuing its own
                  promissory notes having an aggregate principal amount equal to
                  the
                  aggregate Market Redemption Price of the Trust Units tendered for
                  redemption, which promissory notes (“Redemption Notes”) shall have terms
                  and conditions substantially identical to those of the Initial
                  Notes.
  If
        at the time Trust Units are tendered for redemption by a holder of Trust
        Units,
        the outstanding Trust Units are not listed for trading on the TSX and are
        not
        traded or quoted on any other stock exchange or market which Provident
        considers, in its sole discretion, provides representative fair market value
        price for the Trust Units or trading of the outstanding Trust Units is suspended
        or halted on any stock exchange on which the Trust Units are listed for trading
        or, if not so listed, on any market on which the Trust Units are quoted for
        trading, on the date such Trust Units are tendered for redemption or for
        more
        than five trading days during the 10 trading day period, commencing immediately
        after the date such Trust Units were tendered for redemption, then such holder
        of Trust Units shall, instead of the Market Redemption Price, be entitled
        to
        receive a price per Provident Unit (the “Appraised Redemption Price”) equal to
        90% of the fair market value thereof as determined by Provident as of the
        date
        upon which such Trust Units were tendered for redemption. The aggregate
        Appraised Redemption Price payable by the Trust in respect of Trust Units
        tendered for redemption in any calendar month shall be paid on the last day
        of
        the third following month by, at the option of the Trust, a cash payment
        or a
        distribution of Initial Notes or Redemption Notes, as described
        above.
  It
        is anticipated that this redemption right will not be the primary mechanism
        for
        holders of Trust Units to dispose of their Trust Units. Initial Notes or
        Redemption Notes which may be distributed in specie to holders of Trust Units
        in
        connection with a redemption will not be listed on any stock exchange and
        no
        market is expected to develop in such Initial Notes or Redemption Notes.
        Initial
        Notes or Redemption Notes will not be qualified investments for trusts governed
        by registered retirement savings plans, registered retirement income funds
        or
        deferred profit sharing plans.
  68
  **Meetings
        of
        Holders of Trust Units**
  The
        Trust Indenture
        provides that meetings of holders of Trust Units must be called and held
        for,
        among other matters, the election or removal of the Trustee, the appointment
        or
        removal of the auditors of the Trust, the approval of certain amendments
        to the
        Trust Indenture, to assign, transfer or dispose of the Initial Royalty as
        an
        entirety or substantially as an entirety, and the commencement of winding-up
        the
        affairs of the Trust. Meetings of holders of Trust Units will be called and
        held
        annually for, among other things, the election of the directors of Provident
        and
        the appointment of the auditors of the Trust.
  Holders
        of Trust
        Units may attend and vote at all meetings of holders of Trust Units either
        in
        person or by proxy and a proxy holder need not be a holder of Trust Units.
        Two
        persons present in person or represented by proxy and representing in the
        aggregate at least 5% of the votes attaching to all outstanding Trust Units
        shall constitute a quorum for the transaction of business at all such meetings.
        For the purposes of determining such quorum, the holders of any issued Special
        Voting Units who are present at the meeting shall be regarded as representing
        outstanding Trust Units equivalent in number to the votes attaching to such
        Special Voting Units.
  **Trust
        Unitholder Rights Plan**
  Pursuant
        to a
        Unitholder Rights Plan Agreement entered into between Provident Energy Trust
        and
        Computershare Trust Company of Canada on March 6, 2001, Provident
        Energy
        Trust has put in place a unitholder rights plan.
  The
        Unitholder
        Rights Plan is intended to address deficiencies that the Trust believes exist
        in
        current Canadian takeover bid legislation. The purpose of the Unitholder
        Rights
        Plan is to afford both the holders of Trust Units and Provident sufficient
        time
        to evaluate and respond to an unsolicited offer made for the Trust Units.
        Further, the Unitholder Rights Plan is intended to assist in ensuring that
        all
        holders of Provident Units have an equal opportunity to participate in any
        takeover bid.
  The
        following is a
        summary of the principal terms of the Unitholder Rights Plan, which is qualified
        in its entirety by the actual text of the Unitholder Rights Plan
        Agreement.
  ***Issue
        of Rights***
  On
        the effective date of the Unitholder Rights Plan, one right (a “Right”) shall be
        issued and attached to each of the outstanding Trust Units and will attach
        to
        each Provident Unit that is subsequently issued. Initially, certificates
        representing Units also represent the Rights.
  ***Rights
        Exercise Privilege***
  The
        Rights will
        separate from the Trust Units and will be exercisable, subject to action
        by
        Provident, 10 trading days (the “Separation Time”) after a person has
        acquired, or commences a takeover bid to acquire, 20% or more of the Trust
        Units, other than by an acquisition pursuant to a takeover bid permitted
        by the
        Unitholder Rights Plan (a “Permitted Bid”). The acquisition by any person (an
“Acquiring Person”) of 20% or more of the Trust Units, other than by way of a
        Permitted Bid, is referred to as a “Flip-in Event”. Any Rights held by an
        Acquiring Person will become void upon the occurrence of a Flip-in Event.
        In the
        absence of action by Provident and 10 days after the occurrence of a Flip-in
        Event, each Right (other than those held by the Acquiring Person), will permit
        the purchase of that number of Trust Units having an aggregate market price
        (as
        defined in the Unitholder Rights Plan) equal to twice the exercise price
        for an
        amount in cash equal to the exercise price (which the Unitholder Rights Plan
        currently sets at $30).
  69
  The
        issue of the
        Rights is not initially dilutive. However, holders of Rights not exercising
        their Rights upon the occurrence of a Flip-in Event may suffer substantial
        dilution.
  ***Certificates
        and Transferability***
  After
        the
        Separation Time, the Rights will be evidenced by Rights certificates, which
        will
        be transferable and traded separately from the Provident Units.
  ***Permitted
        Bid Requirements***
  The
        requirements
        for a Permitted Bid include the following:
  ·
              the
                  take-over
                  bid must be made to all holders of Trust Units, other than the
                  Acquiring
                  Person;
  ·
              the
                  take-over
                  bid must contain, and the take-up and payment for securities tendered
                  or
                  deposited is subject to, an irrevocable and unqualified provision
                  that no
                  Trust Units will be taken up or paid for pursuant to any take-over
                  bid
                  prior to the close of business on the date which is not less than
                  45 days following the date of the take-over bid and only
                  if at such
                  date more than 50% of the Trust Units held by independent holders
                  of Trust
                  Units shall have been deposited or tendered pursuant to the take-over
                  bid
                  and not withdrawn;
  ·
              the
                  take-over
                  bid contains an irrevocable and unqualified provision that unless
                  the
                  take-over bid is withdrawn, Trust Units may be deposited pursuant
                  to such
                  take-over bid at any time during the period of time between the
                  date of
                  the take-over bid and the date on which Trust Units may be taken
                  up and
                  paid for and that any Trust Units deposited pursuant to the take-over
                  bid
                  may be withdrawn until taken up and paid for;
                  and
  ·
              the
                  take-over
                  bid must contain an irrevocable and unqualified provision that
                  if, on the
                  date on which Trust Units may be taken up and paid for, more than
                  50% of
                  the Trust Units held by independent holders of Trust Units shall
                  have been
                  deposited pursuant to the take-over bid and not withdrawn, the
                  Acquiring
                  Person will make a public announcement of that fact and the take-over
                  bid
                  will remain open for deposits and tenders of Trust Units for not
                  less than
                  10 Business Days from the date of such public
                  announcement.
  The
        Unitholder
        Rights Plan allows for a competing Permitted Bid (a “Competing Permitted Bid”)
        to be made while a Permitted Bid is in existence. A Competing Permitted Bid
        must
        satisfy all the requirements of a Permitted Bid (subject to certain
        exceptions).
  ***Waiver
        and Redemption***
  Provident
        may,
        prior to a Flip-in Event, waive the dilutive effects of the Unitholder Rights
        Plan in respect of a particular Flip-in Event resulting from a takeover bid
        made
        by way of a takeover bid circular to all holders of the Trust Units, in which
        event such waiver would be deemed also to be a waiver in respect of any other
        Flip-in Event occurring under a takeover bid made by way of a takeover bid
        circular to all holders of the Trust Units prior to the expiry of the takeover
        bid in respect of which the waiver is granted. Provident may also waive the
        Unitholder Rights Plan in respect of a particular Flip-in Event that has
        occurred through inadvertence, provided that the Acquiring Person that
        inadvertently triggered such Flip-in Event reduces its beneficial holdings
        to
        less than 20% of the outstanding Provident Units within 10 days or such other
        period as may be specified by Provident.
  70
  At
        any time prior to the occurrence of a Flip-in Event, Provident may at its
        option
        redeem all, but not less than all, of the outstanding Rights at a price of
        $0.00001 per Right.
  **Termination
        of the Trust**
  The
        holders of
        Trust Units may vote to terminate the Trust at any meeting of the holders
        of
        Trust Units duly called for that purpose, subject to the following:
  ·
              a
                  vote may
                  only be held if requested in writing by the holders of not less
                  than 20%
                  of the Trust Units;
  ·
              a
                  quorum of
                  50% of the issued and outstanding Trust Units is present in person
                  or by
                  proxy; and
  ·
              the
                  termination must be approved by Provident Special
                  Resolution.
  Unless
        the Trust is
        terminated or extended by vote of the holders of Trust Units earlier, the
        Trustee shall commence to wind-up the affairs of the Trust on December 31,
        2099. In the event that the Trust is wound-up, the Trustee will sell and
        convert
        into money the Initial Royalty (see “—Material Contracts — The Provident Royalty
        Agreements”) and other assets in one transaction or in a series of transactions
        at public or private sale and do all other acts as may be appropriate to
        liquidate assets and shall in all respects act in accordance with the
        directions, if any, of the holders of Trust Units in respect of termination
        authorized pursuant to the Provident Special Resolution authorizing the
        termination of the Trust. In no event shall the Trust be wound up until the
        Initial Royalty shall have been disposed of, and under no circumstances shall
        any holder of Trust Units come into possession of any interest in the Initial
        Royalty. After paying, retiring or discharging or making provision for the
        payment, retirement or discharge of all known liabilities and obligations
        of the
        Trust and providing for indemnity against any other outstanding liabilities
        and
        obligations, the Trustee shall distribute the remaining part of the proceeds
        of
        the sale of the Initial Royalty and other assets together with any cash
        remaining in the Trust among the holders of Trust Units in accordance with
        their
        Pro Rata Share.
  **Limitation
        on Non-Resident Trust Unitholders**
  Certain
        provisions
        of the Tax Act require that the Trust not be established nor maintained
        primarily for the benefit of Non-Residents. Accordingly, in order to comply
        with
        such provisions, the Trust Indenture contains restrictions on the ownership
        of
        Trust Units by Trust Unitholders who are Non-Residents. Trust Unitholders
        may be
        required to provide to the Trustee a declaration (a “Residence Declaration”)
        specifying whether or not they are Non-Residents and if the Trustee becomes
        aware, as a result of requiring Residence Declarations or otherwise, that
        the
        beneficial owners of 25% of the Trust Units then outstanding are or may be
        Non-Residents or that such a situation is imminent, the Trustee shall thereafter
        request Residence Declarations at least annually in conjunction with the
        annual
        meetings of Trust Unitholders. If at any time the Trustee becomes aware,
        as a
        result of requiring Residence Declarations as to beneficial ownership or
        otherwise, that the beneficial owners of 49% of the Trust Units then outstanding
        are or may be Non-Residents or that such a situation is imminent, the Trustee
        may make a public announcement thereof and shall 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 Residence Declaration that the person is not
        a
        Non-Resident. If notwithstanding the foregoing, the Trustee determines that
        a
        majority of the Trust Units are held by Non-Residents, the Trustee 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 the Trustee
        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 Trust Unitholders receiving such notice have not sold the specified number
        of Trust Units or provided the Trustee with satisfactory evidence that they
        are
        not Non-Residents within such period, the Trustee may on behalf of such Trust
        Unitholder sell such Trust Units and, in the interim, shall suspend the voting
        and distribution rights attached to such Trust Units and shall make any
        distribution in respect of such Trust Units by deposition such amount in
        separate bank account in a Canadian chartered bank (net of any applicable
        taxes). Any sale shall be made on any stock exchange on which the Trust Units
        are then 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 Trust certificates representing such Trust
        Units.
  71
  **Provident
        Trustee**
  Computershare
        Trust
        Company of Canada is the initial trustee of Provident Energy Trust. The Trustee
        is responsible for, among other things:
  ·
              accepting
                  subscriptions for Trust Units and issuing Trust Units pursuant
                  thereto;
  ·
              maintaining
                  the books and records of the Trust and providing timely reports
                  to holders
                  of Trust Units; and
  ·
              paying
                  cash
                  distributions to holders of Trust
                  Units.
  The
        Trust Indenture
        provides that the Trustee shall 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 holders of Trust Units and, in connection therewith, shall
        exercise that degree of care, diligence and skill that a reasonably prudent
        trustee would exercise in comparable circumstances.
  The
        initial term of
        the Trustee’s appointment is until the first annual meeting of holders of Trust
        Units. Thereafter, the Trustee shall be reappointed or changed every year
        as may
        be determined by a majority of the votes cast at a meeting of the holders
        of
        Trust Units. The Trustee may resign upon 60 days’ notice to Provident Energy
        Trust. The Trustee may also be removed by Provident Special Resolution of
        the
        holders of Trust Units. Such resignation or removal becomes effective upon
        the
        acceptance or appointment of a successor trustee.
  ***Liability
        of the Trustee***
  The
        Trustee, its
        directors, officers, employees, shareholders and agents shall not be liable
        to
        any Trust Unitholder or any other person, in tort, contract or otherwise,
        in
        connection with any matter pertaining to Provident Energy Trust or the Trust
        Fund, arising from the exercise by the Trustee of any powers, authorities
        or
        discretion conferred under the Trust Indenture, including, without limitation,
        any action taken or not taken in good faith in reliance on any documents
        that
        are, prima facie, properly executed, any depreciation of, or loss to, the
        Trust
        Fund incurred by reason of the sale of any asset, any inaccuracy in any
        evaluation provided by ManagementCo or any other appropriately qualified
        person,
        any reliance on any such evaluation, any action or failure to act of
        ManagementCo, Provident, or any other person to whom the Trustee has, with
        the
        consent of Provident, delegated any of its duties hereunder, or any other
        action
        or failure to act (including failure to compel in any way any former trustee
        to
        redress any breach of trust or any failure by ManagementCo or Provident to
        perform its duties under or delegated to it under the Trust Indenture or
        certain
        material contracts), unless such liabilities arise out of the gross negligence,
        willful default or fraud of the Trustee or any of its directors, officers,
        employees, shareholders or agents. If the Trustee has retained an appropriate
        expert, adviser or legal counsel with respect to any matter connected with
        its
        duties under this Indenture or certain material contracts, the Trustee may
        act
        or refuse to act based on the advice of such expert, adviser or legal counsel,
        and the Trustee shall not be liable for and shall be fully protected from
        any
        loss or liability occasioned by any action or refusal to act based on the
        advice
        of any such expert, adviser or legal counsel. In the exercise of the powers,
        authorities or discretion conferred upon the Trustee under the Trust Indenture,
        the Trustee is and shall be conclusively deemed to be acting as Trustee of
        the
        assets of the Trust and shall not be subject to any personal liability for
        any
        debts, liabilities, obligations, claims, demands, judgments, costs, charges
        or
        expenses against or with respect to Provident Energy Trust or the Trust Fund.
        In
        addition, the Trust Indenture contains other customary provisions limiting
        the
        liability of the Trustee.
  72
  **Amendments
        to the Trust Indenture**
  The
        Trust Indenture
        may be amended or altered from time to time by Provident Special
        Resolution.
  The
        Trustee may,
        without the approval of the Trust Unitholders, make certain amendments to
        the
        Trust Indenture, including amendments for the purpose of:
  ·
              ensuring
                  the
                  Trust’s continuing compliance with applicable laws or requirements of
                  any
                  governmental agency or authority of Canada or of any
                  province;
  ·
              ensuring
                  that
                  the Trust will satisfy the provisions of each of subsections 108(2)
                  and
                  132(6) of the Tax Act as from time to time amended or
                  replaced;
  ·
              ensuring
                  that
                  such additional protection is provided for interests of Trust Unitholders
                  as the Trustee may consider
                  expedient;
  ·
              removing
                  or
                  curing any conflicts or inconsistencies between the provisions
                  of the
                  Trust Indenture or any supplemental indenture, the Management Agreement
                  or
                  the Provident Royalties and any other agreement of Provident Energy
                  Trust
                  or any offering document pursuant to which securities of Provident
                  Energy
                  Trust are issued with respect to Provident Energy Trust, or any
                  applicable
                  law or regulations of any jurisdiction, provided that in the opinion
                  of
                  the Trustee the rights of the Trustee and of the Trust Unitholders
                  are not
                  prejudiced thereby;
  ·
              curing,
                  correcting or rectifying any ambiguities, defective or inconsistent
                  provisions, errors, mistakes or omissions, provided that in the
                  opinion of
                  the Trustee the rights of the Trustee and of the Trust Unitholders
                  are not
                  prejudiced thereby.
  **II.**  **Provident
        Energy Ltd.**
  The
        principal
        business of Provident is to manage and administer the operating activities
        associated with the oil and gas properties. Provident is engaged in the
        acquisition, exploitation, development and production of crude oil and natural
        gas in the Western Canadian Sedimentary Basin.
  **Delegation
        of Authority, Administration and Trust Governance**
  The
        board of
        directors of Provident has generally been delegated the significant management
        decisions of Provident Energy Trust, and Provident Management Corporation
        has
        been retained to administer Provident Energy Trust on behalf of the Trustee.
        In
        particular, the Trustee has delegated to Provident responsibility for any
        and
        all matters relating to:
  ·
              the
                  redemption of Trust Units;
  73
 ·
              the
                  acquisition of Subsequent Investments by the Trust and the negotiation
                  of
                  management agreements respecting Subsequent
                  Investments;
  ·
              any
                  offering
                  of securities of the Trust including the listing and maintaining
                  of
                  the listing on the TSX of the Trust Units; the filing of
                  documents or
                  obtaining of permission from any governmental or regulatory authority
                  or
                  the taking of any other step under federal or provincial law to
                  enable
                  securities which a holder of Trust Units is entitled to receive
                  to be
                  properly and legally delivered and thereafter traded; ensuring
                  compliance
                  with all applicable laws; all matters relating to the content of
                  any
                  prospectus, information memorandum, private placement memorandum
                  and
                  similar public or private offering documents, and the certification
                  thereof; and all matters concerning the terms of the sale or issuance
                  of
                  Trust Units or rights to Trust Units, including without limitation
                  all
                  matters concerning the adoption of any Unitholder Rights
                  Plan;
  ·
              the
                  determination of any Distribution Record Date other than the last
                  date of
                  each calendar month; and
  ·
              the
                  determination of any borrowing under the Provident Trust
                  Indenture.
  Holders
        of Trust
        Units are entitled to elect a majority of the board of directors of Provident
        pursuant to the terms of the Unanimous Shareholder Agreement. Subject to
        the
        ultimate authority of the board of directors of Provident, Provident and
        the
        Trust will be managed by ManagementCo.
  **Decision
        Making**
  Although
        ManagementCo provides certain advisory and management services to Provident
        pursuant to the Management Agreement, the board of directors of Provident
        supervises the management of the business and affairs of the Trust, including
        the business and affairs of the Trust delegated to Provident. In particular,
        significant operational decisions and all decisions relating to:
  ·
              the
                  acquisition and disposition of properties for a purchase price
                  or proceeds
                  in excess of an amount equal to 5% of the market capitalization
                  of the
                  Trust;
  ·
              the
                  approval
                  of annual operating and capital expenditure budgets;
                  and
  ·
              the
                  establishment of credit facilities
  are
        made by the
        board of directors of Provident. In addition, the Trustee has delegated certain
        matters to the board of directors of Provident including all decisions relating
        to the issuance of additional Trust Units and the determination of
        the
        amount of Distributable Cash. Any amendment to the Management Agreement or
        the
        Provident Royalties will require the approval of the board of directors of
        Provident on behalf of the Trust. The board of directors of Provident generally
        holds regularly scheduled meetings to review the business and affairs of
        Provident and make any necessary decisions relating to that business and
        those
        affairs.
  **Board
        Practices: Powers and Restrictions**
  Under
        both the
        by-laws of Provident and the ABCA, the board of directors may from time to
        time
        without the authorization of the shareholders:
  ·
              borrow
                  money
                  upon the credit of Provident;
  74
  ·
              issue,
                  reissue, sell or pledge bonds, debentures, notes or other evidence
                  of
                  indebtedness or guarantee of Provident, whether secured or
                  unsecured;
  ·
              charge,
                  mortgage, hypothecate, pledge or otherwise create, issue, execute
                  and
                  deliver a security interest in all or any currently owned or subsequently
                  acquired real or personal, movable or immovable property of Provident,
                  including book debts, rights, powers, franchises and undertaking
                  to secure
                  any such bonds, debentures, notes or other evidences of indebtedness
                  or
                  guarantee or any other present or future indebtedness or liability
                  of
                  Provide; and
  ·
              give
                  a
                  guarantee on behalf of Provident to secure the obligation of any
                  person.
  In
        accordance with the by-laws of Provident, a director or officer who is a
        party
        to, or who is a director or officer of or has a material interest in any
        person
        who is a party to, a material contract or proposed material contract with
        Provident shall disclose the nature and extent of his interest to the board
        of
        directors at the time and in the manner provided by the ABCA. Any such contract
        or proposed contract shall be referred to the board of directors for approval
        even if such contract is one that in the ordinary course of Provident’s business
        would not require approval by the board of directors, and a director interested
        in a contract so referred to the board of directors shall not vote on any
        resolution to approve the same except as provided by the ABCA. In addition,
        the
        Management Agreement contains provisions which require the Manager
        to:
  ·
              make
                  disclosure to the board of directors of Provident of the fact and
                  substance of any particular conflict of
                  interest;
  ·
              use
                  all
                  reasonable efforts to resolve such conflict of interest in a manner
                  which
                  will treat the Trust or Provident, as the case may be, and the
                  other
                  interested party fairly taking into account all of the circumstances
                  of
                  the Trust or Provident, as the case may be and such interested
                  party;
  ·
              make
                  decisions in resolving such conflicts on a basis consistent with
                  the
                  objectives and financial resources of each group of interested
                  parties,
                  the time limitations or investment of such financial resources,
                  and on the
                  basis of operating efficiencies having regard to the then current
                  holdings
                  of properties of each group of interested parties all consistent
                  with the
                  duties of Provident to each such group of persons;
                  and
  ·
              act
                  honestly
                  and in good faith in making any such
                  resolutions.
  The
        ABCA provides
        that subject to the articles or by-laws of a corporation, or any unanimous
        shareholder agreement, the directors of a corporation may fix the remuneration
        of the directors, officers and employees of the corporation, with the disclosure
        of the aggregate remuneration paid to be made as prescribed. Provident’s by-laws
        provide that the directors shall be paid such reasonable remuneration as
        may
        from time to time be determined by the board of directors. Such remuneration
        shall be in addition to any salary or professional fees payable to a director
        who serves Provident in any other capacity. In addition, directors shall
        be paid
        such sums in respect of their out-of-pocket expenses incurred in attending
        board
        of directors’ committee or shareholders’ meetings or otherwise in respect of the
        performance by them of their duties as the board of directors may from time
        to
        time determine.
  In
        addition, the board of directors has created a Governance, Human Resources
        and
        Compensation Committee, all of the members of which are unrelated directors.
        The
        committee’s mandate includes, among other things, reviewing Provident’s human
        resources policies and procedures and compensation and incentive programs.
        The
        committee is responsible for assessing senior management’s performance and
        reviewing and negotiating the Management Agreement. The committee reviews
        the
        adequacy and form of directors’ compensation and makes recommendations designed
        to ensure that directors’ compensation adequately reflects the responsibilities
        of the board of directors. The committee also administers the Trust Option
        Plan
        and makes recommendations to the board of directors respecting grants of
        options
        thereunder. See “Directors, Senior Management and Employees — Board
        Practices.”
  75
  There
        are no age
        limit restrictions in respect of the retirement or non-retirement of the
        members
        of the board of directors of Provident and no minimum number of Trust Units
        are
        required to be held by any current or proposed director of
        Provident.
  **Common
        Shares**
  All
        of the issued
        and outstanding common shares of Provident are held by the Trust. Each Provident
        Share entitles its holder to receive notice of and to attend all meetings
        of the
        shareholders of Provident and to one vote at such meetings. The holders of
        Provident Shares are, at the discretion of the board of directors of Provident
        and subject to applicable legal restrictions, entitled to receive any dividends
        declared by the board of directors on the common shares. The holders of
        Provident Shares are entitled to share equally in any distribution of the
        assets
        of Provident upon the liquidation, dissolution, bankruptcy or winding-up
        of
        Provident or other distribution of its assets among its shareholders for
        the
        purpose of winding-up its affairs. Such participation is subject to the rights,
        privileges, restrictions and conditions attaching to any instruments having
        priority over the Provident Shares.
  **Notes**
  From
        time to time,
        Provident has issued notes to the Trust in connection with certain acquisitions
        and other transactions undertaken by the Trust. Cash flow from Provident’s
        producing properties distributed from Provident to the Trust includes interest
        payments (if applicable) and principal repayments on the various notes held
        by
        the Trust. The following summary of the material attributes and characteristics
        of the various notes outstanding
  **Initial
        Notes**
  The
        following is a
        summary of the material attributes and characteristics of the Initial Notes
        issued pursuant to the provisions of the Founders Note Indenture dated
        March 6, 2001, as amended, and made between Provident and the Note
        Trustee.
  ***Terms
        and Issue of Initial Notes***
  The
        Initial Notes
        are held by the Trust, are unsecured and bear interest from the date of issue
        at
        12% per annum. Interest is payable for each month during the term on the
        15th
        day of the month following such month. The first interest payment was payable
        on
        April 15, 2001 for the period commencing on March 6, 2001 and
        ending
        on March 31, 2001.
  Commencing
        on
        April 15, 2001, and on the 15th day of each subsequent month during
        the
        term, Provident will be required, subject to the terms of any secured financing,
        to make principal payments on the Initial Notes in an amount equal to
        one-twelfth of Provident’s Available Cash Flow (as defined below) (calculated
        pursuant to the Founders Note Indenture) for the prior calendar
        year.
  Available
        Cash Flow
        for a calendar year shall, in general terms, consist of Provident’s gross
        production revenue less all royalties, taxes, general and administrative
        expenses, operating expenses, capital expenditures, principal and interest
        payments on all secured debt and on the Initial Notes, and fees payable to
        the
        Manager.
  76
  Because
        of the
        variable factors determining Available Cash Flow, Provident may not be required
        in any calendar year to pay any principal to holders of Initial
        Notes.
  All
        principal will
        be due on maturity, December 31, 2021. Provident shall at any time
        be
        allowed to prepay all or any part of the outstanding principal without notice
        or
        bonus.
  In
        contemplation of the possibility that Initial Notes may be distributed to
        holders of Trust Units upon the redemption of their Trust Units, the Founders
        Note Indenture provides that if persons other than the Trust (the “Non-Fund
        Holders”) own Initial Notes having an aggregate principal amount in excess of
        $1,000,000, either the Trust or the Non-Fund Holders shall be entitled, among
        other things, to require the Note Trustee to exercise the powers and remedies
        available under the Founders Note Indenture upon an event of default and,
        with
        the Trust, the Non-Fund Holders may provide consents, waivers or directions
        relating generally to the variance of the Founders Note Indenture and the
        rights
        of noteholders. The Founders Note Indenture will allow the Trust flexibility
        to
        delay payments of interest or principal otherwise due to it while payment
        is
        made to other noteholders, and to allow other noteholders to be paid out
        before
        the Trust. Any delayed payments will be due 5 days after
        demand.
  Principal
        and
        interest on the Initial Notes is payable in lawful money of Canada directly
        to
        the holders of Initial Notes at their address set forth in the register of
        holders of Initial Notes. The Trust is the holder of all of the issued and
        outstanding Initial Notes.
  ***Ranking***
  The
        Initial Notes
        are unsecured debt obligations of Provident and rank pari passu with all
        other
        unsecured indebtedness of Provident, but subordinate to all secured
        debt.
  ***Events
        of Default***
  The
        Founders Note
        Indenture provides that any of the following shall constitute an event of
        default: (i) default in payment of the principal of the Initial Notes
        when
        required; (ii) the failure to pay all of the interest obligations
        on the
        Initial Notes for a period of 90 days; (iii) if Provident has defaulted
        and
        a demand for payment has been made under any material instrument, indenture
        or
        document evidencing indebtedness of more than $5 million and Provident has
        failed to remedy such default within applicable curative periods;
        (iv) certain events of winding-up, liquidation, bankruptcy, insolvency,
        receivership or seizure; (v) default in the observance or performance
        of
        any other covenant or condition of the Founders Note Indenture and continuance
        of such default for a period of 30 days after notice in writing has been
        given
        by the Note Trustee to Provident specifying such default and requiring Provident
        to rectify the same; (vi)  Provident ceasing to carry on its business;
        and
        (vii) material default by Provident under material agreements if property
        having a fair market value in excess of $5,000,000 is liable to forfeiture
        or
        termination.
  **Acquisition
        Notes**
  The
        following is a
        summary of the material attributes and characteristics of the Acquisition
        Notes
        issued pursuant to the provisions of the Maxx Note Indenture dated as of
        May 25, 2001 and made between Provident and the Note Trustee.
  77
  ***Terms
        and Issue of Acquisition Notes***
  Pursuant
        to the
        Maxx Arrangement, holders of Maxx Shares received Acquisition Notes of Provident
        on the basis of the Per Share Principal Amount of Acquisition Notes for every
        one Maxx Share held by such holders. All of the Acquisition Notes outstanding
        were transferred by the former holders of Maxx Shares to the Trust in return
        for
        Trust Units and/or cash. The Maxx Note Indenture provided that initially
        one
        global Note was issued to the Note Trustee in trust for the former holders
        of
        Maxx Shares receiving Trust Units. The Note Trustee then, on behalf of the
        former holders of Maxx Shares, transferred that Acquisition Note to the Trust,
        subject to receiving Trust Units for delivery to the former holders of Maxx
        Shares, all as contemplated by the Maxx Arrangement. Upon receipt of the
        Trust
        Units, the Note Trustee allocated those Trust Units to the former holders
        of
        Maxx Shares. Subject to a former holder of Maxx Shares returning the required
        letter of transmittal and share certificate, the Note Trustee then forwarded
        to
        the former holder of Maxx Shares the Trust Units and/or cash allocated to
        such
        former holder.
  The
        Acquisition
        Notes are unsecured, bear no interest and are payable in whole or in part
        upon
        demand.
  ***Ranking***
  The
        Acquisition
        Notes are unsecured debt obligations of Provident and rank pari passu with
        all
        other unsecured indebtedness of Provident, but subordinate to all secured
        debt.
  **Richland
        Notes**
  The
        following is a
        summary of the material attributes and characteristics of the Richland Notes
        issued pursuant to the provisions of the Richland Note Indenture dated as
        of
        January 15, 2002 and made between Provident and Computershare Trust Company
        of
        Canada, as trustee.
  The
        Richland Notes
        are unsecured, bear no interest and are payable in whole or in part upon
        demand.
        The Richland Notes represent unsecured debt obligations of Provident and
        rank
        pari passu with all other unsecured indebtedness of Provident, but subordinate
        to all secured debt. Provident may prepay all or any part of the outstanding
        principal of the Richland Notes without notice or bonus.
  The
        Richland Notes
        were issued in connection with the Richland Arrangement pursuant to the Richland
        Note Indenture.
  **III.**  **Provident
        Management Corporation**
  **The
        Manager**
  The
        principal
        business of the Manager is to provide administrative and management services
        to
        the Trust including the acquisition, exploitation, development and production
        of
        crude oil and natural gas from the properties. Pursuant to the provisions
        of the
        Management Agreement, the Manager provides certain management, administrative
        and support services to the Trust and its affiliates, including those necessary:
        (a) to ensure compliance by the Trust with continuous disclosure
        obligations under applicable securities legislation; (b) to provide
        investor relations services; (c) to provide or cause to be provided
        to
        holders of Trust Units all information to which holders of Trust Units are
        entitled under the Trust Indenture; (d) to call, hold and distribute
        materials including notices of meetings and information circulars in respect
        of
        all necessary meetings of holders of Trust Units; (e) to determine
        the
        amounts payable from time to time to holders of Trust Units including
        Distributable Cash; and (f) to determine the timing and terms of future
        offerings of Trust Units, if any. The board of directors of Provident is
        required to approve all matters referred to in items (d), (e) and (f) above
        and,
        in addition, will be required to approve any amendment to the Management
        Agreement or the Provident Royalties on behalf of the Trust. ManagementCo
        provides the executive officers to Provident, being Thomas W. Buchanan
        as
        Chief Executive Officer and Randall J. Findlay as President.
  78
  ManagementCo
        is
        owned by Thomas W. Buchanan and Randall J. Findlay and was
        incorporated solely for the purpose of providing management, advisory and
        administration services to Provident and the Trust.
  **Management
        Agreement**
  The
        Management
        Agreement has an initial term expiring on December 31, 2004. Subject to the
        Management Agreement, and any directions or restrictions imposed from time
        to
        time by the board of directors of Provident, ManagementCo provides all
        management services and arranges for administrative and support services
        pertaining to Provident’s oil and natural gas properties, Provident, the Trust
        and all related services incidental to them.
  ManagementCo
        will
        be paid fees for providing such services. ManagementCo and the Trust are
        responsible for ensuring compliance with the continuous disclosure obligations
        under all applicable securities legislation. ManagementCo will be indemnified
        by
        Provident in respect of damages suffered relating to the services provided
        by
        ManagementCo under the Management Agreement provided that ManagementCo is
        in
        compliance with the standard of care described below and it and any of its
        directors, officers or employees will be indemnified by Provident provided
        that
        these persons shall not be found to be liable for or guilty of fraud, willful
        default or negligence (other than in the case of services which constitute
        the
        conduct of operations on behalf of Provident as described in the 1990 Canadian
        Association of Petroleum Landman Operating Procedure where the standard shall
        be
        gross negligence rather than negligence).
  In
        exercising its powers and discharging its duties under the Management Agreement,
        ManagementCo is required to exercise that degree of care, diligence and skill
        that a reasonably prudent operator and manager having responsibility for
        the
        management, advisory and administrative services would exercise in comparable
        circumstances.
  **Acquisition
        and Disposition Strategy**
  ManagementCo
        employs a strategy which focuses on maximizing the level of sustainable
        production of oil and natural gas from Provident’s existing properties and to
        supplementing production by reserve acquisitions. Capital expenditures are
        and
        will be focused on development activity as opposed to exploration. Some
        exploration properties will be sold, farmed out or developed using third
        party
        resources. Reserve replacement and additions will be achieved through
        development activity and acquisitions.
  In
        addition, as part of the services to be provided by ManagementCo to Provident
        and the Trust, ManagementCo may recommend that Provident enter into agreements
        to dispose of its oil and natural gas properties and make farmouts and other
        dispositions of such properties. Approval by the board of directors of Provident
        of any acquisitions or dispositions is required where the properties being
        acquired or disposed of have a purchase price or proceeds in excess of an
        amount
        equal to 5% of the total market capitalization of the Trust at such
        time.
  79
  **Compensation**
  In
        its role under the Management Agreement as manager and administrator of
        Provident and the Trust, ManagementCo will receive the following
        fees:
  (a)
              a
                  fee in an
                  amount equal to 2% of Operating Cash Flow, such amount to be calculated
                  as
                  at the end of each calendar month or portion of the month if applicable
                  and paid on the 15th day following the calendar month or if the
                  day is not
                  a business day, on the next business day;
                  and
  (b)
              a
                  fee equal
                  to 6% of the Total Return Amount, such amount to be calculated
                  as at the
                  end of each Return Period and paid on the 15th day following the
                  end of
                  each such Return Period or if such day is not a business day on
                  the next
                  business day.
  ManagementCo
        will
        not be entitled to a fee in respect of acquisitions and dispositions. In
        addition, ManagementCo has the option (subject to any necessary regulatory
        approval) of receiving all or part of the fee provided in (b) above in Trust
        Units at the Unit Market Price calculated as at the end of the relevant
        period.
  In
        addition, ManagementCo is entitled to reimbursement of general and
        administrative costs and expenses related to its performance under the
        Management Agreement by the Trust and Provident, other than costs related
        solely
        to ManagementCo. The salaries of Thomas W. Buchanan and Randall J.
        Findlay are not reimbursable but the costs of certain of the benefits and
        perquisites will be reimbursable, subject to certain limits. The Management
        Agreement also provides that in most instances of termination, ManagementCo
        is
        entitled to receive the management fees described in this annual report and
        the
        general and administrative costs owing at the time of termination and (in
        certain instances) an amount equal to all such management fees payable in
        respect of the two Return Periods immediately preceding the termination (or
        if
        there have been less than two Return Periods an amount equal to such management
        fees as would have been payable in respect of two complete Return
        Periods).
  **Conflicts
        of Interest**
  Some
        of the
        directors, officers and employees of Provident Management Corporation, and
        some
        of the consultants retained by Provident Management Corporation from time
        to
        time, will also be directors and officers of other companies. The Management
        Agreement contains provisions which require Provident Management Corporation
        to:
  (a)
              make
                  disclosure to the board of directors of Provident of the fact and
                  substance of any particular conflict of
                  interest;
  (b)
              use
                  all
                  reasonable efforts to resolve such conflict of interest in a manner
                  which
                  will treat the Trust or Provident, as the case may be, and the
                  other
                  interested party fairly taking into account all of the circumstances
                  of
                  the Trust or Provident, as the case may be and such interested
                  party;
  (c)
              make
                  decisions in resolving such conflicts on a basis consistent with
                  the
                  objectives and financial resources of each group of interested
                  parties,
                  the time limitations on investment of such financial resources,
                  and on the
                  basis of operating efficiencies having regard to the then current
                  holdings
                  of properties of each group of interested parties all consistent
                  with the
                  duties of ManagementCo to each such group of persons;
                  and
 80
 (d)
                act
                    honestly
                    and in good faith in making any such
                    resolutions.
 ManagementCo
        shall
        devote its personnel and resources exclusively to or for the benefit of the
        Trust and Provident and shall not become engaged in any other business
        activities other than those contemplated in the Management Agreement. The
        principals of ManagementCo shall be entitled to hold board positions or similar
        positions in respect of entities other than the Trust and Provident provided
        the
        entity on which board such principal sits is not in competition with the
        Trust
        and the time commitments are not significant.
  **Unanimous
        Shareholders Agreement**
  Pursuant
        to the
        Unanimous Shareholders Agreement among Provident and the Trustee as trustee
        for
        and on behalf of Provident Energy Trust, the holders of Trust Units are entitled
        to notice of and to attend all meetings of shareholders of Provident and
        except
        as set forth below, to direct the manner in which Provident Energy Trust
        will
        vote its shares in Provident at all such meetings. Prior to Provident Energy
        Trust voting its shares in Provident, each holder of Trust Units shall be
        entitled to vote in respect of the matter on the basis of one vote per Trust
        Unit held and Provident Energy Trust shall be required to vote its shares
        in
        Provident in accordance with the result of the vote of holders of Trust Units.
        Holders of Trust Units shall be entitled to direct Provident Energy Trust
        as to
        how to vote in respect of all matters placed before the shareholder of Provident
        including, the election of the directors of Provident, approving its financial
        statements and appointing auditors of Provident, who shall be the same as
        the
        auditors of Provident Energy Trust. In addition, holders of Trust Units will
        be
        entitled to direct Provident Energy Trust as to how to vote its shares in
        Provident on any proposed amendment to the Unanimous Shareholders Agreement,
        where such amendment is required to be approved by special resolution. Provident
        Energy Trust will not be entitled, without the direction of holders of Trust
        Units, to exercise its rights as the sole shareholder of Provident except
        as set
        forth above.
  It
        is a term of the Unanimous Shareholders Agreement that the board of directors
        of
        Provident shall consist of a minimum of 5 and a maximum of 15 directors.
        The
        Unanimous Shareholders Agreement provides that holders of Trust Units are
        entitled to elect a majority of the board of directors of Provident. Under
        the
        terms of the Unanimous Shareholders Agreement, Provident Management Corporation
        shall have the right to nominate 2 directors to the board of directors of
        Provident.
  **C.**
              **Material
                  Contracts**
  The
        following is a
        summary of the material contracts entered into by Provident or Founders,
        as the
        case may be, during the two years prior to the date of this annual report,
        which
        are **** presently
        material
        to Provident, other than those entered into in the ordinary course of
        business.
  **The
        Trust
        Indenture**
  The
        Trust was
        created pursuant to the Trust Indenture dated as of January 25, 2001
        between Founders Energy Ltd. and Montreal Trust Company of Canada (now
        Computershare Trust Company of Canada), as amended from time to time. See
        “—Memorandum and Articles of Association — Provident Energy Trust” for a
        discussion of the material terms of the Trust Indenture.
  **The
        Maxx
        Arrangement Agreement**
  The
        Maxx
        Arrangement Agreement provided for the implementation of the Maxx Arrangement.
        Under the terms of the Maxx Arrangement Agreement, each issued and outstanding
        Maxx Share was exchanged with Provident for Acquisition Notes on the basis
        of
        $7.00 principal amount of Acquisition Notes for every one Maxx Share. The
        Acquisition Notes were then exchanged with the Trust for Trust Units and/or
        cash, resulting in the acquisition by the Trust of all of the Acquisition
        Notes
        and the acquisition by holders of Acquisition Notes of Trust Units or cash
        or a
        combination thereof on the basis of $7.00 cash for each Maxx Share for those
        Maxx shareholders that elected to receive all cash, or $1.9745 cash and 0.4523
        of a Trust Unit for those Maxx shareholders that elected to receive all Trust
        Units.
  81
  **The
        Qualification Rights Agreement**
  The
        Qualification
        Rights Agreement provided the framework for the secondary offering of Trust
        Units acquired by Citicorp under the Founders Arrangement. The Qualification
        Rights Agreement provided that if, at any time, the Trust proposed to qualify
        for distribution any securities of the Trust by way of a prospectus, the
        Trust
        would use its reasonable commercial efforts to include in any qualification
        all
        of the Trust Units acquired by Citicorp pursuant to the Founders Arrangement,
        if
        requested to do so by Citicorp. In the case of an underwritten offering,
        the
        underwriters could limit the number of Trust Units held by Citicorp included
        in
        the underwriting pursuant to any qualification, if, in their opinion, the
        number
        of Trust Units held by Citicorp proposed to be sold in the underwriting exceeded
        the number that can be sold without materially adversely interfering with
        the
        orderly sale and distribution of the securities being offered under the
        qualification.
  In
        accordance with the terms of the Qualification Rights Agreement, the Trust
        agreed to bear all fees and expenses incidental to the performance of or
        compliance with the Qualification Rights Agreement by the Trust, provided
        however, that Citicorp would be responsible for 50% of any commissions, fees
        or
        discounts of the underwriters related to the Trust Units of Citicorp being
        distributed pursuant to an offering. Pursuant to the Qualification Rights
        Agreement, Citicorp sold 750,000 Trust Units as part of the Trust’s public
        offering in August 2001. As of the date of this annual report, Citicorp
        does not own, directly or indirectly, any Trust Units.
  **The
        Management Agreement**
  See
“—Memorandum
        and Articles of Association — Provident Management Corporation” for a discussion
        of the material terms of the Management Agreement.
  **The
        Provident Royalty Agreements**
  The
        Provident
        Royalty Agreements provide for the Initial Royalty and the Subsequent Royalty.
        As owner of the Initial Royalty, the Trust is entitled, commencing
        January 1, 2002, to cash distributions in respect of royalty production
        income, being 13.5% of Provident’s gross revenue from its working interest in
        oil and gas properties owned as at March 6, 2001 less 13.5% of operating
        costs and facility usage costs. Such cash distributions are to be paid on
        or
        about the 15th day of the second month following the month to which the
        distribution relates.
  Provident
        is
        entitled to make farmouts or other similar dispositions of specific interests
        in
        any part of the properties subject to the Initial Royalty, and upon the farmee
        or other participant earning its interest pursuant to the farmout or other
        disposition, the Initial Royalty shall burden only the working interest retained
        by or reserved to Provident. Any net proceeds from the sale of properties
        subject to the Initial Royalty (to the extent allocable to Canadian Resource
        Property, as defined in the Tax Act) are allocable as to 86.5% to Provident
        and
        as to 13.5% to the Trust.
  The
        Initial Royalty
        does not constitute an interest in land, and the Trust is not entitled to
        take
        its share of production in kind or to separately sell or market its share
        of
        petroleum substances.
  82
  As
        owner of the Subsequent Royalty, the Trust is entitled, commencing May 1,
        2001, to cash distributions of approximately 99% of the cash flow from all
        present and future oil and gas properties and related tangibles owned by
        Provident (including the properties subject to the Initial Royalty) after
        certain costs, expenditures and deductions, which include 99% of:
  ·
              all
                  amounts
                  of interest and principal payable by Provident on account of or
                  in respect
                  of its credit facilities and any indebtedness of Provident owing
                  to the
                  Trust;
  ·
              Provident’s
                  share of operating costs and capital expenditures including amounts
                  payable in respect of the Initial Royalty and Crown
                  royalties;
  ·
              income
                  taxes,
                  capital taxes and other direct taxes of
                  Provident;
  ·
              amounts
                  required to be paid to certain
                  reserves;
  ·
              general
                  and
                  administrative expenses of
                  Provident;
  ·
              acquisition
                  costs of future oil and gas properties and related tangibles;
                  and
  ·
              amounts
                  required to be paid to the Trustee pursuant to the Trust
                  Indenture.
  These
        cash
        distributions are to be paid on or about the 15th day of the second month
        following the month to which the distribution relates.
  From
        time to time
        upon notice from Provident, the Trust has an obligation (the “Deferred Purchase
        Price Obligation”) to pay Provident, as partial consideration for the Subsequent
        Royalty, such portion of the acquisition cost of future oil and gas properties
        and capital expenditures including amounts borrowed to fund such costs and
        expenditures as may be designated by Provident.
  Provident
        is
        entitled to make farmouts or other similar dispositions of specific interests
        in
        any part of the properties subject to the Subsequent Royalty, and upon the
        farmee or other participant earning its interest pursuant to the farmout
        or
        other disposition, the Subsequent Royalty shall burden only the working interest
        retained by or reserved to Provident. Any net proceeds from the sale of
        properties subject to the Subsequent Royalty (to the extent allocable to
        petroleum and natural gas rights) less any amount payable in respect of the
        Initial Royalty shall be allocated to the Trust as to 99%. The remaining
        1% and
        all amounts allocated to tangibles and miscellaneous interests shall be
        allocated to Provident.
  Provident
        is
        required to establish a reserve to fund future well bore and facility
        abandonment and environmental and reclamation obligations and liabilities
        (the
“Reclamation Fund”). Provident is obligated to pay $0.20 per barrel of oil
        equivalent (converting gas to oil at 10:1) produced, less current year well
        bore
        and facility abandonment and environmental and reclamation obligations and
        liabilities out of production revenues and other revenues for a calendar
        year
        into the Reclamation Fund.
  The
        Subsequent
        Royalty does not constitute an interest in land. Except upon the insolvency
        of
        Provident, the Trust is not entitled to take its share of production in kind
        or
        to separately sell or market its share of petroleum substances.
  **The
        Unanimous Shareholders Agreement**
  The
        Unanimous
        Shareholders Agreement dated as of March 6, 2001 between Provident
        and
        Computershare Trust Company of Canada, as trustee for the Trust, outlines
        the
        rights and obligations of the Trust and Trust Unitholders in respect of the
        Provident Shares and the Trust Units, as well as certain management and control
        issues in respect of Provident. See “—Memorandum and Articles of Association —
        Provident Management Corporation — Unanimous Shareholders Agreement” for a
        discussion of the material terms of the Unanimous Shareholders
        Agreement.
  83
  **The
        Richland Arrangement Agreement**
  The
        Richland
        Arrangement Agreement provided for the implementation of the Richland
        Arrangement in which the Trust, Provident and Richland agreed to combine
        their
        assets and operations in accordance with a plan of arrangement. Under the
        terms
        of the Richland Arrangement Agreement, Richland shareholders received 0.4
        of a
        Trust Unit and one share of Terraquest for each issued and outstanding common
        share of Richland. Pursuant to the plan of arrangement, each issued and
        outstanding common share of Richland was exchanged by Richland shareholders
        for
        one newly created Class A Share and one Class B Share of Richland. As part
        of
        the Richland Arrangement, upon completion of the sale of the Terraquest Assets
        to Terraquest for Terraquest Shares, Richland redeemed all of the issued
        and
        outstanding Class B Shares held by Richland shareholders in consideration
        for the transfer of the Terraquest Shares held by Richland for the Class B
        Shares held by Richland shareholders. Each issued and outstanding Class A
        Share
        held by Richland shareholders was then exchanged for 0.4 of a Trust
        Unit.
  The
        Terraquest
        Assets sold by Richland to Terraquest as part of the Richland Arrangement
        were
        comprised of certain producing properties of Richland located in southern
        and
        northwest Alberta which represented production as at September 30,
        2001 of
        approximately 200 BOE/d, 426 MBOE of Proved Reserves and 88,000 net acres
        of
        undeveloped lands and associated seismic data. Pursuant to the Richland
        Arrangement Agreement, Provident received gross overriding royalties on industry
        standard terms on certain of the Terraquest properties.
  The
        Richland
        Arrangement was completed on January 16, 2002 following the approval
        of the
        Richland shareholders at a special meeting held on January 15,
        2002.
  **The
        Acquired Properties Purchase Agreement**
  The
        Acquired
        Properties Purchase Agreement provided for the acquisition by Provident from
        Devon and Devon ARL of certain oil and gas properties for a purchase price
        of
        $72 million (subject to adjustment), payable in cash.
  The
        Trust also
        issued 100,000 Trust Units to an arm’s length third party as compensation for
        services provided in connection with the acquisition of the Acquired
        Properties.
  The
        Acquired
        Properties consist primarily of mature light oil and natural gas assets located
        in southeast Alberta producing 3,600 BOE/d. The assets are comprised primarily
        of high working interest, operated properties with year round operating
        access.
  The
        acquisition of
        the Acquired Properties closed on May 1, 2002.
  **D.**
              **Exchange
                  Controls**
  *The
        Investment
        Canada Act* (the “ICA”), which
        became effective on June 30, 1985, regulates the acquisition by
        non-Canadians of control of a Canadian business enterprise. In effect the
        ICA
        required review by Investment Canada, the agency which administers the ICA,
        and
        approval by the Canadian government in the use of an acquisition of control
        of a
        Canadian business by a non-Canadian (other than a “NAFTA investor” as defined in
        the ICA) where: (i) in the case of a direct acquisition (for example, through
        a
        share purchase or asset purchase), the asset of the business are $5 million
        or
        more in value; or (ii) in the cast of an indirect acquisition (for example,
        the
        acquisition of the foreign parent of the Canadian business) where, the Canadian
        business has assets of $50 million or more in value or if the Canadian business
        represents more than 50% of the assets of the original group and the Canadian
        business has assets of $3 million or more in value. Review and approval are
        also
        required for acquisition or establishment of a new business in areas concerning
        “Canada’s cultural heritage or national identity” such as book publishing, film
        production and distribution, television and radio, production and distribution
        of music, and the oil and natural gas industry, regardless of the size of
        the
        investment.
  84
  In
        the context of the Trust, in essence, three methods of acquiring control
        of a
        Canadian business are regulated by the ICA: (i) the acquisition of all or
        substantially all of the assets used in carrying on the Canadian business;
        (ii)
        the acquisition, directly or indirectly, of voting shares of a Canadian
        corporation carrying on the Canadian business; (iii) the acquisition of voting
        shares of an entity which controls, directly or indirectly, another entity
        carrying on a Canadian business. An acquisition of a majority of the voting
        interests of an entity including a corporation, is deemed to be an acquisition
        of control under the ICA. An acquisition of less than one-third of the voting
        shares of a corporation is deemed not to be an acquisition of control. An
        acquisition of less than a majority, but one-third or more, of the voting
        shares
        of a corporation is presumed to be an acquisition of control unless it can
        be
        established that on the acquisition the corporation is not, in fact, controlled
        by the acquirer through the ownership of voting shares. For partnerships,
        trusts, joint ventures or other unincorporated entities, an acquisition of
        less
        than a majority of the voting interests is deemed not to be an acquisition
        of
        control.
  In
        1998, the ICA was amended pursuant to the Free Trade Agreement dated
        January 2, 1988 between Canada and the United States to relax the
        restriction of the ICA. As a result of these amendments, except where the
        Canadian business is in the cultural, oil and gas, uranium, financial services
        or transportation sectors, the threshold for direct acquisition of control
        by
        U.S. investors and other foreign investors acquiring control of a Canadian
        business from U.S. investors has been raised from $5 million to $150 million
        of
        gross assets, and indirect acquisitions are not reviewable.
  In
        addition to the foregoing, the ICA requires that all other acquisitions of
        control of Canadian businesses by non-Canadians are subject to formal
        notification to the Canadian government. These provisions require a foreign
        investor to give notice in the required form, which notices are for information,
        as opposed to review, purposes.
  **E.**
              **Taxation**
  The
        following is a
        general description of the material United States federal income tax
        consequences of the ownership and disposition of Trust Units to a holder
        of
        Trust Units who is a United States person and who holds the Trust Units as
        capital assets (a “U.S. Unitholder”). As used in this annual report, the term
“United States person” means an individual who is a citizen or resident of the
        United States, a partnership, corporation or other entity organized in or
        under
        the laws of the United States or any state thereof, an estate that is subject
        to
        United States federal income taxation without regard to the source of its
        income
        or a trust if (A) a United States court has primary supervision over its
        administration and one or more United States persons have the authority to
        control all substantial decisions of the trust or (B) the trust has made
        a valid
        election to be treated as a United States person.
  This
        description is
        for general information purposes only and is based on the United States Internal
        Revenue Code of 1986, as amended (the “Code”), Treasury regulations promulgated
        thereunder, and judicial and administrative interpretations thereof, all
        as in
        effect on the date hereof and all of which are subject to change (possibly
        with
        retroactive effect) so as to result in federal income tax consequences different
        than those discussed below. This summary does not discuss all the tax
        consequences that may be relevant to a United States holder of Trust Units
        in
        light of such holder’s particular circumstances or to United States holders
        subject to special rules, such as dealers in securities or currencies, financial
        institutions, insurance companies, tax-exempt organizations, partnerships
        or
        other pass-through entities, persons holding notes as a part of a straddle,
        hedge or conversion transaction or a synthetic security or other integrated
        transaction, United States persons whose “functional currency” is not the United
        States dollar, and holders who are not U.S. Unitholders.
  85
  **This
        discussion of U.S. federal income tax consequences is for general information
        purposes only and is not tax advice. Each U.S. Holder of Trust Units is urged
        to
        consult and depend on his own tax advisor in analyzing the U.S. federal,
        state
        and local tax consequences and foreign tax consequences to him of the receipt
        and ownership of Trust Units.**
  **I.**  **Trust
        Treated as a Corporation - Tax Consequences for U.S.
        Unitholders**
  ***Possible
        Passive Foreign Investment Company Status***
  The
        Trust was
        treated as a corporation for U.S. federal income tax purposes (until, following
        year-end 2001, the partnership election discussed below became effective).
        For
        U.S. tax purposes, a foreign corporation, or trust treated as a foreign
        corporation, is classified as a PFIC for each taxable year in which either
        (i)
        at least 75% of its gross income in a taxable year, including the gross income
        of any corporation, U.S. or foreign, in which it is considered to own 25%
        or
        more of the shares by value, is “passive” income (the “Income Test”) or (ii) at
        least 50% of the average value of its assets is attributable to assets that
        produce passive income or are held for the production of passive income (the
        “Asset Test”). The consequences that would result if the Trust were a PFIC are
        discussed below under “ — Tax
        Consequences if
        the Trust is a Passive Foreign Investment Company.”
  Since
        the Trust
        owns 100% of the voting stock of Provident, the Trust will be treated as
        related
        to Provident for purposes of the Income and Asset Tests under the PFIC rules.
        Because it is anticipated that more than 25% of the gross income of the Trust
        will consist of royalties received from Provident, a related oil and gas
        operating company, such income will not be treated as passive income for
        purposes of the Income Test and, therefore, the Trust will not satisfy the
        Income Test. Furthermore, because it is anticipated that more than 50% of
        the
        Trust’s assets are attributable to assets that do not produce passive income,
        the Trust will not meet the requirements of the Asset Test. Accordingly,
        since
        the Trust will not satisfy either the Income Test or the Asset Test, the
        Trust
        should not be treated as a PFIC for U.S. federal income tax purposes. However,
        because PFIC status is fundamentally factual in nature, generally cannot
        be
        determined until the close of the taxable year in question, and is determined
        annually, there can be no certainty or assurance that the Trust will not
        be a
        PFIC for either the current taxable year or for any subsequent taxable year.
        U.S. Unitholders are urged to consult their own tax advisers regarding the
        possible classification of the Trust as a PFIC and the consequences to such
        U.S.
        Unitholders if such classification were to occur. The balance of this
        discussion, other than the section “ — Tax
        Consequences if
        the Trust is a Passive Foreign Investment Company,” assumes that the Trust is
        not a PFIC.
  ***Dividends***
  During
        the period
        when the Trust was treated as a corporation for U.S. tax purposes, a U.S.
        Unitholder was required to include in gross income as ordinary income the
        gross
        amount of any distribution from the Trust, including any taxes withheld,
        to the
        extent that the distribution did not exceed the current or accumulated earnings
        and profits of the Trust as calculated for U.S. tax purposes (a “dividend”).
        These dividends were not eligible for the dividends received deduction, which
        is
        generally allowed to U.S. corporate shareholders on dividends received from
        a
        domestic corporation. Distributions in excess of the current and accumulated
        earnings and profits of the Trust were first treated as a tax-free return
        of
        capital to the extent of the U.S. Unitholder’s tax basis in the Trust Units and
        were applied against and reduced such basis on a dollar-for-dollar basis
        (thereby increasing the amount of gain and decreasing the amount of loss
        recognized on a subsequent disposition of Trust Units). To the extent that
        the
        distribution exceeds the U.S. Unitholder’s tax basis, the excess constitutes
        gain from a sale or exchange of the Trust Units.
  86
  ***Foreign
        Tax Credits***
  Any
        Canadian tax
        withheld with respect to the dividends on the Trust Units may, subject to
        certain complex limitations, have been claimed as a foreign tax credit against
        a
        U.S. Unitholder’s U.S. federal income tax liability or have been claimed as a
        deduction for U.S. federal income tax purposes. The limitation on foreign
        taxes
        eligible for credit is calculated separately with respect to specific classes
        of
        income. For this purpose, dividends distributed by the Trust with respect
        to
        Trust Units were “passive income” or, in the case of certain U.S. Unitholders,
“financial services income.” Because of the complexity of those limitations,
        each U.S. Unitholder is urged to consult his own tax advisor with respect
        to the
        amount of foreign taxes that may have been claimed as a credit.
  ***Foreign
        Currency Gains***
  Taxable
        dividends
        with respect to Trust Units that are paid in Canadian dollars were included
        in
        the gross income of a U.S. Unitholder as translated into U.S. dollars calculated
        by reference to the exchange rate in effect on the day the dividend was received
        by the U.S. Unitholder regardless of whether the Canadian dollars were converted
        into U.S. dollars at that time. A U.S. Unitholder who received payment in
        Canadian dollars and converted Canadian dollars into United States dollars
        at a
        conversion rate other than the rate in effect on such day may have a foreign
        currency exchange gain or loss that would be treated as ordinary income or
        loss.
        U.S. Unitholders are urged to consult their own tax advisors concerning the
        U.S.
        tax consequences of acquiring, holding and disposing of Canadian
        dollars.
  **Sale
        or
        Exchange of Trust Units Prior to January 5, 2002**
  During
        the period
        when the Trust was treated as a corporation for U.S. tax purposes, a U.S.
        Unitholder generally recognized gain or loss upon the sale or exchange of
        Trust
        Units equal to the difference (if any) between (i) the amount realized by
        such
        holder on the sale or exchange and (ii) the U.S. Unitholder’s adjusted tax basis
        in the Trust Units. Any gain or loss was capital gain or loss and was long-term
        capital gain or loss if the U.S. Unitholder’s holding period for the Trust Units
        is more than one year at the time of such sale or exchange. Gain or loss,
        if
        any, realized by a U.S. Unitholder upon a sale or exchange of Trust Units
        generally was treated as having a U.S. source for U.S. foreign tax credit
        limitation purposes. Deduction of capital losses is limited by the
        Code.
  ***Foreign
        Currency Gains on Disposition of Trust Units***
 In
        the case of a cash basis U.S. Unitholder who received foreign currency (e.g.,
        Canadian dollars) in connection with a sale, exchange or other disposition
        of
        Trust Units, the amount realized was based on the U.S. dollar value of the
        foreign currency received with respect to the Trust Units as determined on
        the
        settlement date of such sale or exchange. A U.S. Unitholder who received
        payment
        in Canadian dollars and converted Canadian dollars into United States dollars
        at
        a conversion rate other than the rate in effect on the settlement date may
        have
        a foreign currency exchange gain or loss that would be treated as ordinary
        income or loss.
  An
        accrual basis U.S. Unitholder may elect the same treatment required of cash
        basis taxpayers with respect to a sale or exchange of Trust Units, provided
        that
        the election is applied consistently from year to year. Such election may
        not be
        changed without the consent of the IRS. In the event that an accrual basis
        U.S.
        Unitholder does not elect to be treated as a cash basis taxpayer (pursuant
        to
        the Treasury regulations applicable to foreign currency transactions), such
        holder may have a foreign currency gain or loss for U.S. federal income tax
        purposes because of differences between the U.S. dollar value of the currency
        received prevailing on the date of the sale or exchange of Trust Units and
        the
        date of payment. Any such currency gain or loss would be treated as ordinary
        income or loss and would be in addition to gain or loss, if any, recognized
        by
        such holder on the sale, exchange or other disposition of such Trust
        Units.
  87
  **Tax
        Consequences if the Trust is a Passive Foreign Investment
        Company**
  The
        Trust will be a
        PFIC if it meets the requirements of the Income Test or the Asset Test (see
        above). If the Trust were a PFIC, and a U.S. Unitholder did not make either
        an
        election to treat it as a qualified electing fund or a mark-to-market election
        (as described below), excess distributions by the Trust to a U.S. Unitholder
        would be taxed according to a special, adverse regime. Excess distributions
        are
        amounts received by a U.S. Unitholder on the Trust Units in any taxable year
        that exceed 125% of the average distributions received by the U.S. Unitholder
        from the Trust in the shorter of: the three previous taxable years or the
        U.S.
        Unitholder’s holding period for Trust Units before the taxable year of
        distribution. The entire amount of gain that is realized by a U.S. Unitholder
        upon the sale or other disposition of Trust Units will also be treated as
        an
        excess distribution.
  Excess
        distributions must be allocated ratably to each day that a U.S. Unitholder
        has
        held Trust Units. A U.S. Unitholder would then be required to include amounts
        allocated to the current taxable year and any year prior to the first year
        in
        which the Trust was a PFIC in its gross income as ordinary income for that
        year.
        Further, a U.S. Unitholder would be required to pay tax on amounts allocated
        to
        each prior taxable year during which the Trust was a PFIC at the highest
        rate in
        effect for that year on ordinary income and the tax would be subject to an
        interest charge at the rate applicable to deficiencies for income
        tax.
  A
        U.S. Unitholder’s tax basis in Trust Units that were inherited from a deceased
        person who was a U.S. Unitholder would not receive a step-up to fair market
        value as of the date of the deceased’s death but would instead be equal to the
        deceased’s basis, if lower.
  The
        special PFIC
        rules described above will not apply to a U.S. Unitholder if the U.S. Unitholder
        makes an election to treat the Trust as a qualified electing fund (“QEF”) in the
        first taxable year in which the U.S. Unitholder owns Trust Units (and the
        Trust
        is classified as a PFIC) and if the Trust complies with specified reporting
        requirements. Instead, a U.S. Unitholder of a qualified electing fund is
        required for each taxable year to include in income a pro rata share of the
        ordinary earnings of the qualified electing fund as ordinary income and a
        pro
        rata share of the net capital gain of the qualified electing fund as long-term
        capital gain, subject to a separate election to defer payment of taxes. If
        deferred, the taxes will be subject to an interest charge. A QEF election
        cannot, however, be validly made unless the Trust agrees to provide certain
        U.S.
        tax basis information and meet certain other requirements. The Trust has
        not yet
        determined whether it will provide such information or meet such requirements.
        Therefore, no assurance can be given that U.S. Unitholders will be in a position
        to make a timely QEF election. U.S. Unitholders are urged to consult with
        their
        own tax advisors regarding the possible availability of a QEF
        election.
  The
        QEF election is
        made on a shareholder-by-shareholder basis and can be revoked only with the
        consent of the IRS. A shareholder makes a QEF election by attaching a completed
        IRS Form 8621, including the PFIC annual information statement, to a timely
        filed United States federal income tax return. Even if a QEF election is
        not
        made, a shareholder in a PFIC who is a U.S. person must file a completed
        IRS
        Form 8621 every year.
  88
  Alternatively,
        if
        the Trust Units are “publicly traded,” a U.S. Unitholder could elect to mark the
        Trust Units to market annually, recognizing as ordinary income or loss each
        year
        an amount equal to the difference as of the close of the taxable year between
        the fair market value of the Trust Units and the U.S. Unitholder’s adjusted tax
        basis in the Trust Units. Losses would be allowed only to the extent of net
        mark-to-market gain previously included by the U.S. Unitholder under the
        election for prior taxable years. If the mark-to-market election were made,
        then
        the rules presented above would not apply for periods covered by the election.
        If a mark-to-market election with respect to Trust Units is in effect on
        the
        date of a U.S. Unitholder’s death, the tax basis of such Trust Units in the
        hands of a U.S. Unitholder who acquired them from a decedent will be the
        lesser
        of (i) the decedent’s tax basis; or (ii) the fair market value of the Trust
        Units upon the decedent’s death.
  **United
        States Information Reporting and Backup Withholding**
  Dividends
        on Trust
        Units paid within the United States or through certain United States-related
        financial intermediaries are subject to information reporting and may be
        subject
        to backup withholding at the specified rate (31% before August 7, 2001, 30.5%
        after August 6, 2001, and 30% for 2002-2003) unless the holder is a corporation
        or other exempt recipient or provides a taxpayer identification number and
        certifies that no loss of exemption from backup withholding has occurred.
        Information reporting requirements and backup withholding may also apply
        to the
        cash proceeds of a sale of Trust Units.
  Backup
        withholding
        is not an additional tax. Amounts withheld under the backup withholding rules
        may be credited against a U.S. Unitholder’s U.S. tax liability, and a holder may
        obtain a refund of any excess amounts withheld under the backup withholding
        rules by filing the appropriate claim for refund with the IRS.
  Any
        U.S. Unitholder
        who holds 10% or more in vote or value of the Trust Units will be subject
        to
        certain additional United States information reporting
        requirements.
  **II.**  **Trust
        Treated as a Partnership after Year-end 2001 - Tax Consequences
        for**  **U.S.
        Unitholders**
  ***Partnership
        Election***
  The
        Trust elected
        under applicable Treasury Regulations to be treated as a partnership for
        United
        States federal income tax purposes, which election became effective as of
        January 5, 2002. The application of these Regulations is unclear in certain
        respects and no rulings have been requested from the Internal Revenue Service
        (“IRS”) with respect to the United States federal income tax treatment of the
        Trust or other matters regarding the Trust.
  Assuming
        that the
        election had its intended consequences, (1) each U.S. Unitholder would recognize
        gain or loss on the deemed exchange of Trust Units treated as stock of a
        corporation for Trust Units treated as interest in a partnership (see “—Taxable
        Liquidation Triggered by Partnership Election”) and (2) thereafter, the
        consequences of holding Trust Units will be materially different, as discussed
        below.
  ***Classification
        of the Trust Following the Election***
  A
        partnership is generally not a taxable entity and incurs no federal income
        tax
        liability. Instead, as discussed below, each partner in a partnership is
        required to take into account his allocable share of items of income, gain,
        loss
        and deduction of the partnership in computing his federal income tax liability,
        regardless of whether cash or other distributions are made. Distributions
        by a
        partnership to a partner are generally not taxable unless the amount of any
        cash
        distributed is in excess of the partner’s adjusted basis in his partnership
        interest.
  89
  Section
        7704 of the
        Code provides that entities treated as publicly traded partnerships such
        as the
        Trust will, as a general rule, be taxed as corporations. However, an exception
        (the “Qualifying Income Exception”) exists with respect to publicly traded
        partnerships of which 90% or more of the gross income for the relevant taxable
        year and each preceding taxable year beginning after December 31, 1987, during
        which such partnership (or any predecessor) was in existence, consists of
        “qualifying income.” Qualifying income includes interest (from other than a
        financial business), dividends, rents from real property, oil and gas royalty
        income, gains from the sale of oil and gas, and income and gains derived
        from
        the exploration, development, mining, production, processing, refining,
        transportation, or marketing of oil and gas. The Trust believes that the
        natural
        gas facilities should be treated as real property and that rentals paid with
        respect to such gas facilities after the date hereof should be treated as
        rents
        from real property. On that basis and on the basis of estimates with regard
        to
        production and oil and gas prices, which are beyond the control of the Trust,
        the Trust believes it will meet the Qualifying Income Exception in 2002.
        No
        assurance can be given that the Qualifying Income Exception will be met in
        2002
        or subsequent years.
  ***Possible
        Classification of the Trust as a Corporation***
  If
        the Trust fails to meet the Qualifying Income Exception (other than as a
        result
        of a failure which is determined by the IRS to be inadvertent and which is
        cured
        within a reasonable time after discovery), the Trust will be treated as if
        it
        had transferred all of its assets (subject to liabilities) to a newly formed
        corporation (on the first day of the year in which it fails to meet the
        Qualifying Income Exception) in return for stock in that corporation, and
        then
        distributed that stock to U.S. Unitholders in liquidation of their interests
        in
        the Trust. That deemed transfer and liquidation would likely be taxable to
        the
        U.S. Unitholders. Thereafter, the Trust would be treated as a corporation
        for
        federal income tax purposes.
  If
        the Trust were treated as a corporation in any taxable year, either as a
        result
        of a failure to meet the Qualifying Income Exception or otherwise, its items
        of
        income, gain, loss and deduction would not be passed through to U.S.
        Unitholders. Instead, U.S. Unitholders would be subject to tax under the
        rules
        described in Part I above (“Trust Treated as a Corporation - Tax Consequences
        for U.S. Unitholders”), including the potential application of the PFIC regime
        discussed above.
  The
        discussion
        below is based on the premise that the Trust will be treated as a partnership
        for United States federal income tax purposes.
  ***Taxable
        Liquidation Triggered by Partnership Election***
  If,
        immediately
        following its election to be treated as a partnership for United States federal
        income tax purposes, (as a result of a failure to meet the Qualifying Income
        Exception or otherwise) the Trust is not classified as a corporation, the
        U.S.
        Unitholders that hold Trust Units at the time that the Trust’s partnership
        election became effective will be deemed to have disposed of their Trust
        Units
        in a taxable transaction. Specifically, when an entity classified as a
        corporation for United States federal income tax purposes elects to be
        classified as a partnership, the election is treated as a constructive
        liquidation. In the constructive liquidation, the Trust was treated as
        distributing all of its assets and liabilities to holders of Trust Units
        in
        liquidation and such holders were treated, immediately thereafter, as
        contributing all of the distributed assets and liabilities to a newly formed
        partnership. A U.S. Unitholder recognized gain or loss to the extent of the
        difference between the fair market value of his pro rata share of the Trust’s
        assets and his adjusted basis for his Trust Units. See “—Tax Consequences of
        Sale or Exchange of Trust Units” in Part I above.
  90
  ***Tax
        Consequences of Trust Units Ownership***
  ***Flow-through
        of Taxable Income***
  Each
        U.S.
        Unitholder will be required to report on his income tax return his share
        (based
        generally on the percentage of Trust Units owned by that U.S. Unitholder)
        of the
        income, gains, losses and deductions of the Trust without regard to whether
        corresponding cash distributions are received by him. Consequently, a U.S.
        Unitholder may be allocated income from the Trust even if he has not received
        a
        cash distribution from the Trust. Each U.S. Unitholder will be required to
        include in income his share for the taxable year of the Trust ending with
        or
        within the taxable year of the U.S. Unitholder.
  The
        Trust intends
        to make available to each U.S. Unitholder, within 90 days after the close
        of
        each calendar year, certain tax information, sufficient to enable each U.S.
        Unitholder to determine his share of the Trust’s income, gain, loss and
        deduction for the preceding taxable year of the Trust.
  ***Treatment
        of Distributions***
  Distributions
        by
        the Trust to a U.S. Unitholder generally will not be taxable to him for federal
        income tax purposes to the extent of his tax basis in his Trust Units
        immediately before the distribution. Cash distributions in excess of his
        tax
        basis generally will be considered to be gain from the sale or exchange of
        the
        Trust Units, taxable in accordance with the rules described under “—Tax
        Consequences of Sale or Exchange of Trust Units” below.
  ***Basis
        of Trust Units***
  A
        U.S. Unitholder’s initial tax basis for his Trust Units will be the amount (in
        United States dollars) he paid for the Trust Units. That basis will be increased
        by his share (in United States dollars) of the Trust income and decreased
        (but
        not below zero) by distributions to him from the Trust, by his share of Trust
        losses and deductions, and by his share of expenditures of the Trust that
        are
        not deductible in computing its taxable income and are not required to be
        capitalized. See “—Tax Consequences of Sale or Exchange of Trust
        Units—Recognition of Gain or Loss.”
  ***Limitations
        on Deductibility of Losses***
  The
        deduction by a
        U.S. Unitholder of his share of losses of the Trust will be limited to the
        lesser of: (i) the tax basis in his Trust Units and (ii) in the case of either
        (x) an individual U.S. Unitholder or (y) a corporate U.S. Unitholder if more
        than 50% of the value of such corporation’s stock is owned directly or
        indirectly by five or fewer individuals or some tax-exempt organizations,
        to the
        amount for which the U.S. Unitholder is considered to be “at risk” with respect
        to the Trust activities. A U.S. Unitholder must recapture losses deducted
        in
        previous years to the extent that distributions cause his at risk amount
        to be
        less than zero at the end of any taxable year. Losses disallowed to a U.S.
        Unitholder or recaptured as a result of these limitations will carry forward
        and
        will be allowable to the extent that his tax basis or at risk amount, whichever
        is the limiting factor, is subsequently increased. Upon the taxable disposition
        of a Trust Unit, any gain recognized by a U.S. Unitholder can be offset by
        losses that were previously suspended by the at risk limitation but may not
        be
        offset by losses suspended by the basis limitation. Any excess loss above
        that
        gain previously suspended by the at risk or basis limitations is no longer
        utilizable.
  91
  In
        general, a U.S. Unitholder will be at risk to the extent of the tax basis
        in his
        Trust Units, reduced by any amount of money he borrows to acquire or hold
        his
        Trust Units, if the lender of those borrowed funds owns an interest in the
        Trust, is related to a person that owns an interest in the Trust (other than
        the
        U.S. Unitholder whose at risk amount is being considered), or can look only
        to
        the Trust Units for repayment. A U.S. Unitholder’s at risk amount will increase
        or decrease as the tax basis of his Trust Units increases or
        decreases.
  The
        passive loss
        limitations generally provide that individuals, estates, trusts and some
        closely-held corporations and personal service corporations can deduct losses
        from passive activities, which are generally activities in which the taxpayer
        does not materially participate, only to the extent of the taxpayer’s income
        from those passive activities. The passive loss limitations are applied
        separately to each entity such as the Trust which is treated as a
        publicly-traded partnership. Consequently, any passive losses generated by
        the
        Trust will only be available to offset passive income generated in the future
        by
        the Trust and will not be available to offset income from other passive
        activities or investments, including the Trust investments or investments
        in
        other publicly-traded partnerships, or salary or active business income.
        Passive
        losses that are not deductible because they exceed a U.S. Unitholder’s share of
        income may be deducted in full when he disposes of his entire investment
        in the
        Trust in a fully taxable transaction with an unrelated party. The passive
        activity loss rules are applied after other applicable limitations on
        deductions, including the at risk rules and the basis limitation.
  A
        U.S. Unitholder’s share of net income from the Trust may be offset by any
        suspended passive losses from the Trust, but it may not be offset by any
        other
        current or carryover losses from other passive activities, including those
        attributable to other entities treated as publicly-traded partnerships. U.S.
        Unitholders are urged to consult their own tax advisors as to the applicability
        to them of all these limitations.
  ***Limitations
        on Interest Deductions***
  The
        deductibility
        of a non-corporate taxpayer’s “investment interest expense” is generally limited
        to the amount of such taxpayer’s “net investment income.” Investment interest
        expense includes (i) interest on indebtedness properly allocable to property
        held for investment and (ii) the portion of interest expense incurred to
        purchase or carry an interest in a passive activity to the extent attributable
        to portfolio income. The computation of a U.S. Unitholder’s investment interest
        expense will take into account interest on any margin account borrowing or
        other
        loan incurred to purchase or own Trust Units. Net investment income includes
        gross income from property held for investment and amounts treated as portfolio
        income pursuant to the passive loss rules less deductible expenses (other
        than
        interest) directly connected with the production of investment income, but
        generally does not include gains attributable to the disposition of property
        held for investment.
  ***Foreign
        Tax Credits***
  Subject
        to the
        limitations set forth in the Code, United States persons may elect to claim
        a
        credit against their United States federal income tax liability for Canadian
        income tax withheld from distributions received in respect of the Trust Units.
        U.S. Unitholders will also be entitled to claim a foreign tax credit for
        their
        share of any Canadian income taxes paid by the Trust. Income from the Trust
        will
        likely constitute foreign source “passive income” for purposes of the United
        States foreign tax credit limitation. The rules relating to the determination
        of
        the foreign tax credit are complex and U.S. Unitholders are urged to consult
        their own tax advisors to determine whether or to what extent they would
        be
        entitled to such credit. United States persons that do not elect to claim
        foreign tax credits may instead claim a deduction for their share of Canadian
        income taxes paid by the Trust or withheld from distributions from the
        Trust.
  92
  ***Tax
        Treatment of Trust Operations***
  ***Accounting
        Method and Taxable Year***
  The
        Trust uses the
        year ending December 31 as its taxable year and has adopted the accrual method
        of accounting for United States federal income tax purposes. Each U.S.
        Unitholder will be required to include in income his share of the Trust income,
        gain, loss and deduction for the taxable year of the Trust ending within
        or with
        the taxable year of the U.S. Unitholder. In addition, a U.S. Unitholder who
        has
        a taxable year ending on a date other than December 31 and who disposes of
        all
        of his Trust Units following the close of the Trust’s taxable year but before
        the close of his taxable year must include his share of the Trust income,
        gain,
        loss and deduction in income for his taxable year with the result that he
        will
        be required to report in income for his taxable year his share of more than
        one
        year of Trust income, gain, loss and deduction. See “—Tax Consequences of Sale
        or Exchange of Trust Units—Allocations Between Transferors and
        Transferees.”
  ***Depletion***
  Under
        the Code, a
        U.S. Unitholder may deduct in his United States federal income tax return
        a cost
        depletion allowance with respect to the Provident Royalties. U.S. Unitholders
        must compute their own depletion allowance and maintain records of the adjusted
        basis of the Provident Royalties for depletion and other purposes. The Trust,
        however, intends to furnish each U.S. Unitholder with information relating
        to
        this computation.
  Cost
        depletion is
        calculated by dividing the adjusted basis of a property by the total number
        of
        units of oil or gas expected to be recoverable therefrom and then multiplying
        the quotient by the number of units of oil and gas sold during the year.
        Cost
        depletion, in the aggregate, cannot exceed the initial adjusted basis of
        the
        property.
  The
        depletion
        allowance must be computed separately by each U.S. Unitholder for each oil
        and
        gas property, within the meaning of Section 614 of the Code. The IRS is
        currently taking the position that a net profits interest carved from multiple
        properties is a single property for depletion purposes. The Provident Royalties
        burden multiple properties. Accordingly, the Trust intends to take the position
        that the Provident Royalties are a single property for depletion purposes
        and
        the income from the net profits interests will be royalty income qualifying
        for
        an allowance for depletion. The Trust anticipates that it would change this
        position if a different method is required by law.
  ***Depreciation***
  The
        tax basis of
        the various depreciable assets of the Trust will be used for purposes of
        computing depreciation and cost recovery deductions and, ultimately, gain
        or
        loss on the disposition, of such assets.
  ***Valuation
        of the Trust’s Properties***
  The
        United States
        federal income tax consequences of the ownership and disposition of Trust
        Units
        will depend in part on the Trust’s estimates of the relative fair market value
        of its assets. Although the Trust may consult from time to time with
        professional appraisers regarding valuation matters, the Trust will itself
        make
        many of the relative fair market value estimates. These estimates are subject
        to
        challenge and will not be binding on the IRS or the courts. If the estimates
        of
        fair market value are later found to be incorrect, the character and amount
        of
        items of income, gain, loss or deductions previously reported by U.S.
        Unitholders might change, and U.S. Unitholders might be required to adjust
        their
        tax liability for prior years and incur interest and penalties with respect
        to
        those adjustments.
  93
  ***Section
        754 Election***
  The
        Trust will make
        the election permitted by Section 754 of the Code. That election is irrevocable
        without the consent of the IRS. The election will generally require the Trust
        to
        adjust a subsequent Trust Units purchaser’s tax basis in the assets of the Trust
        pursuant to Section 743(b) of the Code to reflect his purchase price. This
        election does not apply to a person who purchases Trust Units directly from
        the
        Trust in this offering.
  A
        Section 754 election is advantageous if the subsequent purchaser’s tax basis in
        his Trust Units is higher than his share of the aggregate tax basis to the
        Trust
        of the assets of the Trust immediately prior to the purchase. In such a case,
        as
        a result of the election, the purchaser would have a higher tax basis in
        his
        share of the assets of the Trust for purposes of calculating depletion and
        depreciation. Conversely, a Section 754 election is disadvantageous if the
        subsequent purchaser’s tax basis in such Trust Units is lower than his share of
        the aggregate tax basis of the assets of the Trust immediately prior to the
        purchase. Thus, the fair market value of the Trust Units may be affected
        either
        favorably or adversely by the election.
  Depreciation
        with
        respect to any basis adjustment resulting from the section 754 election will
        be
        computed in accordance with applicable Treasury Regulations. However, as
        the
        application of those Regulations is not entirely clear, it may be necessary
        for
        the Trust to adopt a different position. Any such different position could
        result in lower depreciation deductions to some U.S. Unitholders and could
        result in a lack of uniformity between Trust Units, either of which could
        reduce
        the value of Trust Units.
  ***Tax
        Consequences of Sale or Exchange of Trust Units***
  ***Recognition
        of Gain or Loss***
  A
        portion of any amount realized on a sale or exchange (which portion could
        be
        substantial) will be separately computed and taxed as ordinary income under
        Section 751 of the Code to the extent attributable to depletion deductions
        or
        depreciation recapture. The difference between the balance of the amount
        realized and the U.S. Unitholder’s tax basis for the Trust Units sold will
        represent gain (or loss) on the disposition of the Trust Units. Ordinary
        income
        attributable to depletion deductions and depreciation recapture could exceed
        net
        taxable gain realized upon the sale of the Trust Units and may be recognized
        even if there is a net taxable loss realized on the sale of the Trust Units.
        Thus, a U.S. Unitholder may recognize both ordinary income and a capital
        loss
        upon a taxable disposition of Trust Units. Net capital loss may offset no
        more
        than $3,000 of ordinary income in the case of individuals and may only be
        used
        to offset capital gain in the case of corporations.
  The
        IRS has ruled
        that a person who acquires interests in an entity such as the Trust, which
        is
        treated as a partnership for United States federal income tax purposes, in
        separate transactions must combine those interests and maintain a single
        adjusted tax basis. Upon a sale or other disposition of less than all of
        those
        interests, a portion of that tax basis must be ratably allocated to the
        interests sold and retained. Although the ruling is unclear as to how the
        holding period of these interests is determined once they are combined, recently
        finalized Regulations allow a seller of such an interest who can identify
        the
        interest sold with an ascertainable holding period to elect to use that holding
        period. Thus, according to the ruling, a U.S. Unitholder will be unable to
        select high or low basis Trust Units to sell as would be the case with corporate
        stock but, according to the finalized Regulations, may designate Trust Units
        sold for purposes of determining the holding period of the Trust Units sold.
        A
        U.S. Unitholder electing to use this approach must consistently use that
        approach for all subsequent sales and exchanges of Trust Units. It is not
        clear
        whether the ruling applies to the Trust because, similar to corporate stock,
        interests in the Trust are readily ascertainable and are evidenced by separate
        certificates. A U.S. Unitholder considering the purchase of additional Trust
        Units or the sale of Trust Units purchased in separate transactions is urged
        to
        consult his own tax advisor regarding the application of this ruling and
        the
        recently finalized Regulations.
  94
  ***Allocations
        Between Transferors and Transferees***
  In
        general, the Trust’s taxable income and losses will be determined annually, will
        be prorated on a monthly basis and will be subsequently apportioned among
        the
        U.S. Unitholders in proportion to the number of Trust Units owned by each
        of
        them on the first business day of the month.
  ***Notification
        Requirements***
  A
        U.S. Unitholder who sells or exchanges Trust Units is required to notify
        the
        Trust in writing of that sale or exchange within 30 days after the sale or
        exchange and in any event by no later than January 15 of the year following
        the
        calendar year in which the sale or exchange occurred. The Trust is required
        to
        notify the IRS of that transaction and to furnish certain information to
        the
        transferor and transferee. However, these reporting requirements do not apply
        with respect to a sale by an individual who is a citizen of the United States
        and who effects the sale or exchange through a broker. Additionally, a
        transferor and a transferee of Trust Units will be required to furnish
        statements to the IRS, filed with their income tax returns for the taxable
        year
        in which the sale or exchange occurred, that allocate the consideration paid
        for
        the Trust Units. This information will be provided by the Trust. Failure
        to
        satisfy these reporting obligations may lead to the imposition of substantial
        penalties.
  ***Constructive
        Termination***
  The
        Trust will be
        considered to have been terminated for United States federal income tax purposes
        if there is a sale or exchange of 50% or more of the total Trust Units within
        a
        12-month period. A termination of the Trust will result in a decrease in
        tax
        depreciation available to the U.S. Unitholders thereafter and in the closing
        of
        its taxable year for all U.S. Unitholders. In the case of a U.S. Unitholder
        reporting on a taxable year other than a fiscal year ending December 31,
        the
        closing of the Trust’s taxable year may result in more than 12 months’ taxable
        income or loss of the Trust being includable in his taxable income for the
        year
        of termination. New tax elections required to be made by the Trust, including
        a
        new election under Section 754 of the Code, must be made subsequent to a
        termination. A termination could also result in penalties if the Trust were
        unable to determine that the termination had occurred. Finally, a termination
        of
        the Trust could result in taxation of the Trust as a corporation if the
        Qualifying Income Exception was not met in the short taxable year caused
        by
        termination. See “—Classification of the Trust Following the
        Election.”
  ***Treatment
        of Unit Lending and Short Sales***
  A
        U.S. Unitholder whose Trust Units are loaned to a “short seller” to cover a
        short sale of Units may be considered as having disposed of ownership of
        those
        Units. If so, he would no longer be a partner with respect to those Trust
        Units
        during the period of the loan and may recognize gain or loss from the
        constructive disposition. As a result, during this period, any Trust income,
        gain, deduction or loss with respect to those Trust Units would not be
        reportable by the U.S. Unitholder, any cash distributions received by the
        U.S.
        Unitholder with respect to those Trust Units would be fully taxable and all
        of
        such distributions would appear to be treated as ordinary income. U.S.
        Unitholders desiring to assure their status as owners of Trust Units and
        avoid
        the risk of gain recognition resulting from the application of these rules
        should modify any applicable brokerage account agreements to prohibit their
        brokers from borrowing or loaning their Trust Units.
  95
  The
        Code also
        contains provisions affecting the taxation of some financial products and
        securities, including interests in entities such as the Trust, by treating
        a
        taxpayer as having sold an “appreciated” interest, one in which gain would be
        recognized if it were sold, assigned or otherwise terminated at its fair
        market
        value, if the taxpayer or related persons enter into a short sale, an offsetting
        notional principal contract, or a futures or forward contract with respect
        to
        the interest on substantially identical property. Moreover, if a taxpayer
        has
        previously entered into a short sale, an offsetting notional principal contract
        or a futures or forward contract with respect to the interest, the taxpayer
        will
        be treated as having sold that portion if the taxpayer or a related person
        then
        acquires the interest or substantially identical property.
  ***Uniformity
        of Trust Units***
  Because
        the Trust
        cannot match transferors and transferees of Trust Units, it must maintain
        uniformity of the economic and tax characteristics of the Trust Units to
        a
        purchaser of these units. In the absence of uniformity, the Trust may be
        unable
        to completely comply with a number of federal income tax requirements, both
        statutory and regulatory.
  A
        lack of uniformity can result from a literal application of some Treasury
        Regulations. Any non-uniformity could have a negative impact on the value
        of the
        units.
  ***Tax-Exempt
        Organizations and Regulated Investment Companies***
  Employee
        benefit
        plans and most other organizations exempt from federal income tax (including
        individual retirement accounts (“IRAs”) and other retirement plans) (“TEOs”) are
        subject to federal income tax on unrelated business taxable income (“UBTI”).
        Because substantially all income of the Trust is expected to be royalty income,
        rents from real property or interest, none of which is UBTI, a TEO should
        not be
        taxable on any income generated by ownership of the Trust Units except as
        described in the next paragraph. However, the Provident Royalties are in
        several
        respects unusual arrangements, for which there is no clear United States
        income
        tax guidance. It is possible that the IRS could contend that some or all
        of the
        income of the Trust under the Provident Royalties does not qualify as royalty
        income and therefore does constitute UBTI. In addition, the classification
        of
        certain facilities owned by the Trust as real property or personal property
        is a
        determination subject to uncertainty. If such facilities were determined
        to be
        personal property for United States federal income tax purposes, the rent
        derived therefrom would be UBTI to a TEO. Prospective purchasers of Trust
        Units
        that are TEOs are encouraged to consult their tax advisors regarding the
        foregoing.
  If
        the Trust Units constitute “debt-financed property” within the meaning of Code
        Section 514(b), then a portion of any interest, rents from real property
        and
        royalty income received by the TEO attributable to the Trust Units will be
        included as UBTI and thus will be taxable to a TEO. Under Code Section 514(b),
        “debt-financed property” is defined as any property which is held to produce
        income and with respect to which there is an acquisition
        indebtedness.
  A
        regulated investment company or “mutual fund” is required to derive 90% or more
        of its gross income from interest, dividends, gains from the sale of stocks
        or
        securities or foreign currency or certain related sources (“RIC Qualifying
        Income”). It is anticipated that substantially all of the Trust’s gross income
        will be non-RIC Qualifying Income. Furthermore, it is unclear whether gain
        from
        the sale of the Trust Units is treated as RIC Qualifying Income. Prospective
        purchasers of Trust Units that are regulated investment companies are encouraged
        to consult their tax advisors regarding these rules.
  96
  ***Administrative
        Matters***
  ***The
        Trust Information Returns***
  The
        Trust is
        currently not required to file a United States federal income tax return,
        since
        it has no gross income derived from sources within the United States or gross
        income which is effectively connected with the conduct of a trade or business
        within the United States. However, the IRS may require a U.S. Unitholder
        to
        provide statements or other information necessary for the IRS to verify the
        accuracy of the reporting by the U.S. Unitholder on its income tax return
        of any
        items of the Trust’s income, gain, loss, deduction, or credit. If the Trust were
        to file a United States tax return in future tax years, the filing would
        change
        the manner in which it provides tax information to the U.S. Unitholders and
        special procedures would also apply to an audit of such tax return by the
        IRS.
  ***Registration
        as a Tax Shelter***
  The
        Code requires
        that “tax shelters” be registered with the Secretary of the Treasury. The
        temporary Treasury Regulations interpreting the tax shelter registration
        provisions of the Code are extremely broad. It is arguable that the Trust
        is not
        subject to the registration requirement on the basis that it will not constitute
        a tax shelter. However, the Trust will register as a tax shelter with the
        Secretary of the Treasury in the absence of assurance that it will not be
        subject to tax shelter registration and in light of the substantial penalties
        which might be imposed if registration is required and not
        undertaken.
  As
        a holder of Trust Units, you will own an interest in the Trust, whose taxpayer
        identification number is 98-0367837. The IRS will issue the Trust a tax shelter
        registration number, which the Trust will make known to U.S.
        Unitholders.
  **YOU
        MUST
        REPORT THE TRUST’S TAX SHELTER REGISTRATION NUMBER TO THE IRS, IF YOU CLAIM ANY
        DEDUCTION, LOSS, CREDIT, OR OTHER TAX BENEFIT OR REPORT ANY INCOME BY REASON
        OF
        YOUR INVESTMENT IN PROVIDENT ENERGY TRUST.**
  You
        must report the
        registration number (as well as the name, and taxpayer identification number
        of
        the Trust) on Form 8271, Investor Reporting of Tax Shelter Registration
        Number.
  Form
        8271 must be
        attached to the return on which you claim the deduction, loss, credit, or
        other
        tax benefit or report any income.
  **ISSUANCE
        OF
        A REGISTRATION NUMBER DOES NOT INDICATE THAT AN INVESTMENT IN PROVIDENT ENERGY
        TRUST OR THE CLAIMED TAX BENEFITS HAVE BEEN REVIEWED, EXAMINED, OR APPROVED
        BY
        THE IRS.**
  A
        U.S. Unitholder who sells or otherwise transfers Trust Units must furnish
        the
        tax shelter registration number to the transferee. The penalty for failure
        of
        the transferor of a Trust Unit to furnish the registration number to the
        transferee is $100 for each such failure. A U.S. Unitholder who fails to
        disclose the tax shelter registration number on his return, without reasonable
        cause for that failure, will be subject to a $250 penalty for each failure.
        Any
        penalties discussed herein are not deductible for federal income tax
        purposes.
  97
  ***Accuracy-Related
        Penalties***
  In
        addition, a penalty equal to 20% of the amount of any portion of an underpayment
        of tax which is attributable to one or more specified causes, including
        negligence or disregard of rules or regulations, substantial understatements
        of
        income tax and substantial valuation misstatements, is imposed by the Code.
        No
        penalty will be imposed, however, with respect to any portion of an underpayment
        if it is shown that there was a reasonable cause for that portion and that
        the
        taxpayer acted in good faith with respect to that portion. Special rules
        exist
        for “tax shelters,” a term that in this context does not appear to include the
        Trust. In addition, the Trust will make a reasonable effort to furnish
        sufficient information for U.S. Unitholders to make adequate disclosure on
        their
        returns to avoid any such penalty attributable to ownership of the Trust
        Units.
  **Canadian
        Income Tax Consequences for Unitholders Not Resident in
        Canada**
  The
        following
        applies to a Non-Resident Unitholder who does not use or hold, and is not
        deemed
        to use or hold, Trust Units in, or in the course of, carrying on a business
        in
        Canada, and is not an insurer who carries on an insurance business or is
        deemed
        to carry on an insurance business in Canada and elsewhere.
  Where
        the Trust
        pays or credits, or is deemed to pay or credit, an amount to a Non-Resident
        Unitholder out of the income of the Trust, such amount will be subject to
        Canadian withholding tax at the rate of 25%, unless such rate is reduced
        under
        the provisions of an applicable tax treaty. The rate of withholding is reduced
        to 15% where such distributions are paid or credited, or deemed to be paid
        or
        credited, to Non-Resident Unitholders who are residents of the United States
        for
        purposes of the Canada-United States Income Tax Convention (1980).
  A
        capital gain realized by a Non-Resident Unitholder from a disposition or
        deemed
        disposition of a Trust Unit will not be subject to tax under the Tax Act
        provided that the Trust Unit does not constitute “taxable Canadian property.”
        Trust Units of a Non-Resident Unitholder will generally not constitute “taxable
        Canadian property” under the Tax Act unless either:
  ·
              at
                  any time
                  during the period of sixty months immediately preceding the disposition
                  of
                  Trust Units by such Non-Resident Unitholder, not less than 25%
                  of the
                  issued Trust Units (taking into account any rights to acquire Trust
                  Units)
                  were owned by the Non-Resident Unitholder, by persons with whom
                  the
                  Non-Resident Unitholder did not deal at arm’s length or by any combination
                  thereof; or
  ·
              the
                  Non-Resident Unitholder’s Trust Units are otherwise deemed to be taxable
                  Canadian property.
  A
        Non-Resident Unitholder will generally compute the adjusted cost base of
        the
        Trust Units under the same rules as apply to residents of Canada.
  Interest
        payable to
        a Non-Resident Unitholder on an Initial Note or Redemption Note will generally
        be subject to Canadian withholding tax at the rate of 25%, unless such rate
        is
        reduced under the provisions of an applicable tax treaty. The rate of
        withholding generally is reduced to 10% of the interest payable where such
        interest is paid or credited, or deemed to be paid or credited, to Non-Resident
        Unitholders who are residents of the United States for purposes of the
        Canada-United States Income Tax Convention (1980).
  98
  If
        the Trust ceases to qualify as a mutual fund trust, there may be adverse
        income
        tax consequences for Non-Resident Unitholders who acquire an interest in
        the
        Trust.
  **F.**
              **Dividends
                  and Paying Agreement**
  Not
        applicable.
  **G.**
              **Statement
                  by Experts**
  Not
        applicable.
  **H.**
              **Documents
                  on Display**
  We
        are subject to the reporting requirements of the Exchange Act that are
        applicable to a foreign private issuer. Under the Exchange Act, we are required
        to file reports, including annual reports on Form 20-F, and other information
        with the SEC. These reports and other information that we file with the SEC
        may
        be obtained, upon written request, from the Corporate Secretary of Provident
        at
        900, 606-4 th Street S.W.,
        Calgary, Alberta T2P 1T1 Canada.
  These
        reports and
        other information can also be inspected without charge and copied at established
        rates at the public reference facilities maintained by the SEC in Room 1024,
        450
        Fifth Street N.W., Washington, D.C. 20549. Copies of these materials are
        also
        available by mail from the Public Reference Section of the SEC, at
        450
        Fifth Street N.W., Washington, D.C. 20549, at established rates.
  As
        a foreign private issuer, we are exempt from the rules under the Exchange
        Act
        prescribing the furnishing and content of proxy statements to shareholders.
        In
        addition, our officers, directors and principal shareholders are exempt from
        the
“short-swing profits” reporting and liability provisions contained in
        Section 16 of the Exchange Act and the rules under the Exchange
        Act.
  **I.**
              **Subsidiary
                  Information.**
  Not
        applicable.
   **Item
                  11.**
              **Quantitative
                  and Qualitative Disclosures about Market
                  Risk**
  Provident’s
        commodity price risk management program was initiated in January 2001
        to
        help minimize the volatility in Provident’s oil and natural gas prices and
        stabilize cash flow. Provident put in place a combination of forward sales
        contracts, physical hedges on both wellhead prices and heavy oil differentials,
        financial hedging on WTI and Cdn/US exchange rate hedges. This program
        positively impacted cash flow by $0.8 million by adding $1.68 per Mcf to
        the
        average gas price and $3.96 per barrel to Provident’s average oil
        price.
  **Commodity
        Price Risk Summary**
  Please
        see “—Operating
        and
        Financial Review and Prospects — Period from March 6, 2001 to December 31, 2001
        compared to Forecast — Commodity Price Risk Management Program” and “Information
        on the Trust - Business Overview - Business Overview of Provident and the
        Trust
        - Risk Management Strategy.”
   99
  **Item
                  12.**
              **Description
                  of Securities other than Equity
                  Securities.**
  Not
        applicable.
   100
  **SIGNATURES**
  The
        registrant
        hereby certifies that it meets all of the requirements for filing on Form
        20-F
        and that it has duly caused and authorized the undersigned to sign this
        amendment to its annual report on its behalf.
  **PROVIDENT
                  ENERGY TRUST**
                **By: Provident
                  Energy
                  Ltd.**Date:
                October
                28, 2005
              By:
              /s/ Mark
                N. WalkerName:Mark N.
                WalkerTitle:Vice
                President, Finance and Chief Financial
                Officer
   101
  **CERTIFICATIONS**
  I,
        Thomas W. Buchanan, certify that:
  1.
        I have reviewed this annual report on Form 20-F of Provident Energy
        Trust;
  2.
        Based on my knowledge, this annual report does not contain any untrue statement
        of a material fact or omit to state a material fact necessary to make the
        statements made, in light of the circumstances under which such statements
        were
        made, not misleading with respect to the period covered by this annual
        report;
  3.
        Based on my knowledge, the financial statements, and other financial information
        included in this annual report, fairly present in all material respects the
        financial condition, results of operations and cash flows of the registrant
        as
        of, and for, the periods presented in this annual report;
  Date:
        October 28,
        2005
 /s/
        Thomas W.
        Buchanan
 Thomas
        W.
        Buchanan
 Chief
        Executive
        Officer of Provident Energy Ltd. (Principal Executive Officer)
  I,
        Mark N. Walker, certify that:
  1.
        I have reviewed this annual report on Form 20-F of Provident Energy
        Trust;
  2.
        Based on my knowledge, this annual report does not contain any untrue statement
        of a material fact or omit to state a material fact necessary to make the
        statements made, in light of the circumstances under which such statements
        were
        made, not misleading with respect to the period covered by this annual
        report;
  3.
        Based on my knowledge, the financial statements, and other financial information
        included in this annual report, fairly present in all material respects the
        financial condition, results of operations and cash flows of the registrant
        as
        of, and for, the periods presented in this annual report;
  Date:
        October 28,
        2005
 /s/
        Mark N.
        Walker___
 Mark
        N.
        Walker
 Vice
        President,
        Finance and Chief Financial Officer of Provident Energy Ltd. (Principal
        Financial Officer




102