**UNITED
        STATES**
 **SECURITIES
        AND EXCHANGE COMMISSION**
 Washington,
        D.C. 20549
  **FORM
        40-F**
  (Check
        one)
  o
              REGISTRATION STATEMENT PURSUANT TO
                SECTION 12 OF THE SECURITIES EXCHANGE ACT OF 1934ORþ
              ANNUAL REPORT PURSUANT TO SECTION
                13(A)
                OR 15(D) OF THE SECURITIES EXCHANGE ACT OF
                1934
  For
          the
          fiscal year ended December 31, 2004
  Commission
            file number 1-15196
 PROVIDENT
                    ENERGY TRUST(Exact
                  name of Registrant as specified in its
                  charter)
   **Alberta,
                  Canada**
              **1311**
              **Not
                  applicable**(Province
                    or other jurisdiction of
                  incorporation
                      or organization)
              (Primary
                    Standard Industrial
                  Classification
                      Code Number
                    (ifapplicable))
              (I.R.S.
                    Employer
                  Identification
                      Number
                    (ifApplicable))
 **Suite
                    800, 112 - 4th Avenue S.W., Calgary, Alberta, Canada T2P
                    0H3****(403)
                    296-2233**(Address
                  and telephone number of Registrant’s principal executive
                  offices)**Dorsey
                      & Whitney LLP**
                  **250
                      Park Avenue, New York, NY 10177-1500**
                    **(212)
                      415-9200**(Name,
                    Address (Including Zip Code) and Telephone Number(Including
                    Area Code) of Agent For Service in the United
                    States)
  Securities
        registered or to be registered pursuant to Section 12(b) of the Act.
  **Title
                  of each class**
                Trust
                    Units
              **Name
                  of each exchange on which registered**
                American
                    Stock Exchange
  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
  For
        annual reports, indicate by check mark the information filed with this Form:
  þ
              Annual
                  information form
              þ
              Audited
                  annual financial statements
  Indicate
            the number of outstanding shares of each of the issuer’s classes of capital or
            common stock as of the close of the period covered by the annual report:
            188,665,788
  Indicate
            by check mark whether the registrant by filing the information contained
            in this
            Form is also thereby furnishing the information to the Commission pursuant
            to
            Rule 12g3-2(b) under the Securities Exchange Act of 1934 (the “Exchange Act”).
            If “Yes” is marked, indicate the file number assigned to the registrant in
            connection with such rule.
 Yes
                o
                No
                þ
 Indicate
            by check mark whether the registrant: (1) has filed all reports required
            to be
            filed by Section 13 or 15(d) of the Exchange Act 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
                þ
                No
                o


**FORM
        40-F**


**Principal
        Documents**
   The
        following documents have been filed as part of this Annual Report on Form
        40-F,
        beginning on the following page:
  (a)
              Annual
                  Information Form for the fiscal year ended December 31,
                  2005;(b)
              Management's
                  Discussion and Analysis of Financial
                  Condition and Results of Operations for the fiscal year ended December
                  31,
                  2005; and(c)
              Consolidated
                  Financial Statements for the fiscal year ended December 31, 2005*(Note
                  20 to the Consolidated Financial Statements relates to United States
                  Accounting Principles and Reporting (U.S.
                  GAAP)).*










**RENEWAL
      ANNUAL INFORMATION FORM**




For
      the
      year ended December 31, 2005









March
      29,
      2006







**TABLE
        OF CONTENTS**
   **Page**
              
              **Page**GLOSSARY
                  OF TERMS
              1
              OIL
                  AND NATURAL GAS OPERATIONS
              29ABBREVIATIONS,
                  TERMS AND
              
              NATURAL
                  GAS MIDSTREAM, NGLCONVERSIONS
              5
              PROCESSING
                  AND MARKETING OPERATIONS
              29PRESENTATION
                  OF OIL AND GAS
              
              General
              29RESERVES
                  AND PRODUCTION
              
              NGL
                  Extraction
              29INFORMATION
              5
              NGL
                  Fractionation
              30NON-GAAP
                  MEASURES
              6
              NGL
                  Transportation
              30NOTE
                  REGARDING FORWARD LOOKING
              
              NGL
                  Storage
              30STATEMENTS
              6
              NGL
                  Marketing
              30INCORPORATION
                  AND STRUCTURE
              8
              Commercial
                  Arrangements
              31The
                  Trust
              8
              Midstream
                  services and marketingProvident
              8
              assets
              32Provident
                  Holdings Trust
              8
              Midstream
                  and marketing services
              33Provident
                  Acquisitions L.P
              8
              MARKET
                  FOR SECURITIES
              34Provident
                  Midstream L.P
              8
              RECORD
                  OF CASH DISTRIBUTIONS
              36Provident
                  Acquisitions Inc
              9
              DIRECTORS
                  AND OFFICERS
              37Provident
                  Midstream Inc
              9
              AUDIT
                  COMMITTEE INFORMATION
              42Pro
                  Holding Company
              9
              INFORMATION
                  CONCERNING THE OILBreitburn
                  Energy Company L.P
              9
              AND
                  GAS INDUSTRY
              44INTERCORPORATE
                  RELATIONSHIPS
              9
              RISK
                  FACTORS
              46Provident
                  Energy Trust
              11
              Oil
                  and Gas Production Risk Factors
              46Provident
                  Energy Ltd
              17
              Natural
                  Gas Midstream, NGLProvident
                  Holdings Trust, Provident
              
              Processing
                  and MarketingAcquisitions
                  L.P., Provident
              
              Business
                  Risk Factors
              48Marketing
                  L.P. and Provident
              
              General
                  Risk Factors
              51Midstream
                  L.P
              19
              INTERESTS
                  OF MANAGEMENT ANDProvident
                  Acquisitions Inc
              19
              OTHERS
                  IN MATERIALProvident
                  Midstream Inc
              19
              TRANSACTIONS
              55Breitburn
                  Energy Company L.P
              19
              TRANSFER
                  AGENT AND REGISTRAR
              55Pro
                  Holding Company
              20
              INTERESTS
                  OF EXPERTS
              55Internalization
                  of Management
              20
              MATERIAL
                  CONTRACTS
              55GENERAL
                  DEVELOPMENT OF THE
              
              DOCUMENTS
                  INCORPORATED BY REFERENCEBUSINESS
                  OF THE TRUST AND
              
              REFERENCE
              55PROVIDENT
              21
              PRINCIPAL
                  HOLDERS OF TRUST UNITS
              56SIGNIFICANT
                  ACQUISITIONS
              24
              ADDITIONAL
                  INFORMATION
              56CORPORATE
                  STRATEGY AND RISKMANAGEMENT
              25General
              25Risk
                  Management
              25SCHEDULE
                  A - AUDIT COMMITTEE
                  INFORMATION








**GLOSSARY
      OF TERMS**




" **8%
      Debentures** "
      means
      the 8% convertible unsecured subordinated debentures of the Trust;




" **8.75%
      Debentures** "
      means
      the 8.75% convertible unsecured subordinated debentures of the
      Trust;




" **10.5%
      Debentures** "
      means
      the 10.5% convertible unsecured subordinated debentures of the
      Trust;




" **ABCA** "
      means
      the *Business
      Corporations Act* (Alberta), S.A. 1981, c. B-15, as amended, including the regulations
      promulgated thereunder;




" **Accrete** "
      means
      Accrete Energy Inc., formerly 1101130 Alberta Ltd.;




" **Acquired
      Properties** "
      means
      the oil and gas properties located in southeast Alberta acquired by the Trust
      effective May 1, 2002 from a U.S. based exploration and production company
      pursuant to an agreement of purchase and sale dated March 25, 2002;




" **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";




" **Board
      of Directors** "
      or
      " **Board** "
      means
      the board of directors of Provident;




" **Breitburn
      L.P.** "
      means
      Breitburn Energy Company L.P., a Delaware limited partnership and an indirect
      subsidiary of the Trust;




" **Breitburn** "
      means
      Breitburn Energy Company LLC, a former California limited liability
      company;




" **Breitburn
      Acquisition** "
      means
      the transaction in which the Trust acquired all of the issued and outstanding
      shares of Breitburn pursuant to an agreement and plan of merger dated
      June 15, 2004 among the Trust, Breitburn, Pro GP Corp., Pro LP Corp. and BB
      Merger LLC;




" **Breitburn
      Properties** "
      means
      the oil and gas properties held by Breitburn L.P. in the State of California
      with minor interests offshore in the Gulf of Mexico and the State of
      Wyoming;




" **CGA** "
      means
      Cawley, Gillespie and Associates, Inc., independent petroleum
      engineers;




" **Chamaelo** "
      means
      Chamaelo Energy Inc., formerly 1100974 Alberta Inc.;




" **Distributable
      Cash** "
      means
      all amounts distributed or to be distributed during any applicable period to
      Unitholders;




" **Distribution
      Record Date** "
      means
      on or about the 20 th day of
      each calendar month or such other date as may be determined from time to time
      by
      the Trustee;




" **Founders** "
      means
      Founders Energy Ltd., a predecessor of Provident;




" **GLJ** "
      means
      Gilbert Laustsen Jung Associates Ltd., independent petroleum
      engineers;




" **Holdings
      Trust** "
      means
      Provident Holdings Trust;




-1-
 TABLE
            OF CONTENTS





" **Initial
      6.5% Debentures** "
      means
      the 6.5% convertible unsecured subordinated debentures of the Trust issued
      on
      March 1, 2005;




" **Kinetic** "
      means
      collectively, Kinetic Resources U.S.A., a partnership formed under the laws
      of
      the State of Michigan and Kinetic Resources (LPG), a partnership formed under
      the laws of the Province of Alberta;




" **McDaniel** "
      means
      McDaniel & Associates Consultants Ltd., independent oil and gas reservoir
      engineers of Calgary, Alberta; ****




" **Manager** " **** means
      Provident Management Corporation, a corporation incorporated under the
      ABCA;




" **Meota** "
      means
      Meota Resources Corp.;




" **Midstream
      NGL Acquisition** "
      means
      the acquisition by Provident of certain assets, shares and partnership interests
      which comprised the natural gas liquids business of EnCana Corporation, 1140102
      Alberta Ltd., EnCana Midstream Inc., WD Energy Services Inc. and EnCana
      Kerrobert Pipelines Limited for an aggregate purchase price of $697 million,
      plus working capital and other adjustments which closed on December 13,
      2005;




" **Midstream
      NGL Business** " **** means
      the
      natural gas midstream, NGL processing and marketing business acquired by
      Provident from EnCana Corporation, 1140102 Alberta Ltd., EnCana Midstream Inc.,
      WD Energy Services Inc. and EnCana Kerrobert Pipelines Limited; ****




" **NSA** "
      means
      Netherland, Sewell and Associates, Inc., independent petroleum
      engineers;




" **Nautilus** "
      means
      Nautilus Resources LLC;




" **Nautilus
      Acquisition** "
      means
      the acquisition of all of the membership interests in Nautilus by Breitburn
      L.P.
      pursuant to a membership interest purchase and sale agreement dated February
      9,
      2005 among Breitburn L.P. and all of the membership interest holders of
      Nautilus;




" **Nautilus
      Properties** "
      means
      the oil and gas producing properties in the State of Wyoming held by Nautilus
      and acquired by Breitburn L.P. pursuant to the Nautilus
      Acquisition;




" **Non-Resident** "
      means a
      non-resident of Canada for the purposes of the Tax Act;




" **NYSE** "
      means
      the New York Stock Exchange;




" **Olympia** "
      means
      Olympia Energy Inc.;




" **Olympia
      Arrangement** "
      means
      the plan of arrangement in which the Trust acquired all of the issued and
      outstanding common shares of Olympia pursuant to an arrangement agreement dated
      April 6, 2004 among the Trust, Provident, Olympia and Accrete;




" **Option
      Plan** "
      means
      the trust unit option plan of the Trust providing for the issuance of options
      to
      acquire Trust Units to employees, officers, directors and consultants of the
      Trust;




" **Orcutt
      Hill Acquisition** "
      means
      the acquisition by Breitburn L.P. of certain oil and natural gas producing
      properties, related interests and 5,000 acres of surface acreage situated in
      the
      Orcutt Hill Oil Field located in Santa Barbara County, California pursuant
      to a
      purchase and sale agreement dated September 13, 2004 between Breitburn L.P.
      and an arm's length third party vendor;




-2-
 TABLE
            OF CONTENTS





" **Orcutt
      Hill Properties** "
      means
      the oil and natural gas producing properties, related interests and 5,000 acres
      of surface acreage situated in the Orcutt Hill Oil Field located in Santa
      Barbara County, California acquired by Breitburn L.P. pursuant to the Orcutt
      Hill Acquisition;




" **PAI** "
      means
      Provident Acquisitions Inc.;




" **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;




" **PMI** "
      means
      Provident Midstream Inc.;




" **PHC** "
      means
      Pro Holding Company;




" **Provident** "
      means
      Provident Energy Ltd.;




" **Redwater
      Acquisition** "
      means
      the acquisition by Provident of the Redwater natural gas liquids processing
      business from Williams Canada for an aggregate purchase price of approximately
      $298.6 million (including costs associated with the acquisition), subject to
      certain adjustments, which closed on September 30, 2003;




" **Redwater
      Midstream NGL Assets** "
      means
      the assets acquired pursuant to the Redwater Acquisition consisting of a natural
      gas gathering system and processing plant, as well as an NGL extraction plant,
      fractionation facilities, transportation systems and storage assets previously
      owned by Williams Canada;




" **Special
      Resolution** "
      means a
      resolution proposed to be passed as a special resolution at a meeting of
      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;




" **Special
      Voting Unit** "
      means a
      special voting unit of the Trust, which shall be entitled to such number of
      votes at meetings of 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;




" **Subsequent
      Investment** "
      means
      those investments which the Trust is permitted to make pursuant to 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;




-3-
 TABLE
            OF CONTENTS





" **Subsidiary** "
      means,
      when used to indicate a relationship with another body corporate:




(a)
            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;




" **Supplemental
      6.5% Debentures** "
      means
      the 6.5% convertible unsecured subordinated debentures of the Trust issued
      on
      November 15, 2005;




" **Tax
      Act** "
      means
      the *Income
      Tax Act* (Canada), R.S.C. 1985, c.1, 5th Supplement, as amended;




" **Trust** "
      means
      Provident Energy Trust, a trust settled pursuant to the laws of
      Alberta;




" **Trust
      Indenture** "
      means
      the trust indenture dated as of January 25, 2001 as amended from time to time,
      between Computershare Trust Company of Canada and Founders;




" **Trust
      Fund** ",
      at any
      time, shall mean such of the following monies, properties and assets that are
      at
      such time held by the Trustee for the purposes of the Trust under the Trust
      Indenture: (a) the initial $100 used to settle the Trust; (b) all funds realized
      from the issuance of Trust Units; (c) any Permitted Investments in which funds
      may from time to time be invested; (d) the initial royalty granted to the Trust;
      (e) any Subsequent Investment; (f) any proceeds of disposition of any of the
      foregoing property; (g) the common shares of Founders and the initial notes
      of
      Provident held by the Trust; and (h) all income, interest, profit, gains and
      accretions and additional assets, rights and benefits of any kind or nature
      whatsoever arising directly or indirectly from or in connection with or accruing
      to such foregoing property or such proceeds of disposition;




" **Trust
      Unit** "
      means a
      unit of the Trust, each unit representing an equal undivided beneficial interest
      therein;




" **Unitholders** "
      means
      the holders from time to time of the Trust Units;




" **Trustee** "
      means
      Computershare Trust Company of Canada or such other trustee, from time to time,
      of the Trust;




" **TSX** "
      means
      the Toronto Stock Exchange;




" **United
      States** "
      and
      " **U.S.** "
      mean
      the United States of America, it territories and possessions, any state of
      the
      United States, and the District of Columbia;




" **Viracocha** "
      means
      Viracocha Energy Inc.;




" **Viracocha
      Arrangement** "
      means
      the plan of arrangement in which the Trust acquired all of the issued and
      outstanding common shares of Viracocha pursuant to an arrangement agreement
      dated April 6, 2004 among the Trust, Provident, Viracocha and Chamaelo;
      and




" **Williams
      Canada** "
      means
      Williams Energy (Canada), Inc .




Words
      importing the singular number only include the plural and vice versa and words
      importing any gender include all genders. All dollar amounts set forth in this
      Annual Information Form are in Canadian dollars, except where otherwise
      indicated.




-4-
 TABLE
            OF CONTENTS





**ABBREVIATIONS,
      TERMSAND CONVERSIONS**




In
      this
      Annual Information Form, the abbreviations and terms set forth below have the
      meanings indicated.




**Oil
                and Natural Gas Liquids**
            **Natural
                Gas**bbls
            barrels
            Mcf
            thousand
                cubic feetMbbl
            thousand
                barrels
            MMcf
            million
                cubic feetbpd
                or bbl/d
            barrels
                of oil per day
            bcf
            billion
                cubic feetmmbbls
            million
                barrels
            mcfd
                or Mcf/d
            thousand
                cubic feet per dayNGLs
            natural
                gas liquids
            mmcfd
            million
                cubic feet per daySTB
            stock
                tank barrel of oil
            m3
            cubic
                metresMstb
            thousand
                stock tank barrels of oil
            mmbtu
            million
                British Thermal Unitsboed
                or boe/d
            barrels
                of oil equivalent per day
            GJ
            gigajoulegjpd
            gigajoule
                per day**Other**boe
            means
                barrel of oil equivalent, using the conversion factor of 6 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.





The
      following table sets forth certain conversions between Standard Imperial Units
      and the International System of Units (or metric units).




**To
                Convert From**
            **To**
            **Multiply
                By**mcf
            cubic
                metres
            0.0282cubic
                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




**PRESENTATION
      OF OIL AND GAS RESERVES AND PRODUCTION
      INFORMATION**




All
      oil
      and natural gas reserve information contained in this Annual Information Form
      has been prepared and presented in accordance with National Instrument 51-101 *Standard
      of Disclosure for Oil and Gas Activities* ("NI
      51-101"). The actual oil and natural gas reserves and future production will
      be
      greater than or less than the estimates provided in this Annual Information
      Form. The estimated future net revenue from the production of the disclosed
      oil
      and natural gas reserves does not represent the fair market value of these
      reserves. The Trust has adopted the standard of 6 mcf:1 boe when converting
      natural gas to barrels of oil equivalent. Boe may be misleading, particularly
      if
      used in isolation. A boe conversion ratio of 6 mcf:1 boe is based on an energy
      equivalency conversion method primarily applicable at the burner tip and does
      not represent a value equivalency at the wellhead.




-5-
 TABLE
            OF CONTENTS




**NON-GAAP
      MEASURES**




In
      this
      Annual Information Form, the Trust uses the terms "cash flow", "adjusted cash
      flow" and "funds flow from operations" to refer to the amount of cash available
      for distribution to Unitholders and as indicators of financial performance.
      "Cash flow", "adjusted cash flow" and "funds flow from operations" are not
      measures recognized by Canadian generally accepted accounting principles
      ("GAAP") and do not have standardized meanings prescribed by GAAP. Therefore,
      "cash flow", "adjusted cash flow" and "funds flow from operations" of the Trust
      may not be comparable to similar measures presented by other issuers, and
      investors are cautioned that "cash flow", "adjusted cash flow" and "funds flow
      from operations" should not be construed as alternatives to net earnings, cash
      flow from operating activities or other measures of financial performance
      calculated in accordance with GAAP. All references to "cash flow", "adjusted
      cash flow" and "funds flow from operations" are based on cash flow before
      changes in non-cash working capital related to operating activities and site
      restoration expenditures, as presented in the consolidated financial statements
      of the Trust. **The
      actual amount of cash that is distributed cannot be assured and future
      distributions may vary.** The
      Trust uses such terms as an indicator of financial performance because such
      terms are commonly utilized by investors to evaluate royalty trusts and income
      funds in the oil and gas sector. The Trust believes that such terms are useful
      supplemental measures as they provide investors with information of what cash
      is
      available for distribution from the Trust to Unitholders in such
      periods.




**NOTE
      REGARDING FORWARD LOOKING STATEMENTS**




This
      Annual Information Form and the documents incorporated by reference herein
      contain forward-looking statements. These statements relate to future events
      or
      the Trust's future performance. All statements other than statements of
      historical fact are forward-looking statements. In some cases, forward-looking
      statements can be identified by terminology such as "may", "will", "should",
      "expect", "plan", "anticipate", "believe", "estimate", "predict", "potential",
      "continue", or the negative of these terms or other comparable terminology.
      Forward looking statements or information in this analysis include, but are
      not
      limited to, business strategy and objectives, reserve quantities and the
      discounted present value of future net cash flows from such reserves, net
      revenue, future production levels, capital expenditures, exploration plans,
      development plans, acquisition and disposition plans and the timing thereof,
      operating and other costs, royalty rates, budgeted levels of cash distributions
      and the performance associated with Provident's natural gas midstream, NGL
      processing and marketing business. These statements are only predictions. Actual
      events or results may differ materially. In addition, this Annual Information
      Form and the documents incorporated by reference herein may contain
      forward-looking statements attributed to third party industry sources. Undue
      reliance should not be placed on these forward-looking statements, as there
      can
      be no assurance that the plans, intentions or expectations upon which they
      are
      based will occur. By its nature, forward-looking information involves numerous
      assumptions, known and unknown risks and uncertainties, both general and
      specific, that contribute to the possibility that the predictions, forecasts,
      projections and other forward-looking statements will not occur. Forward-looking
      statements in this Annual Information Form and the documents incorporated by
      reference herein include, but are not limited to, statements with respect
      to:




·
            the
                Trust's ability to benefit from the combination of growth opportunities
                and the ability to grow through the capital
                markets;


·
            the
                Trust's acquisition strategy, the criteria to be considered in connection
                therewith and the benefits to be derived
                therefrom;


·
            sustainability
                and growth of production and reserves through prudent management
                and
                acquisitions;


·
            the
                emergence of accretive growth
                opportunities;


·
            the
                ability to achieve a consistent level of monthly cash
                distributions;





-6-
 TABLE
            OF CONTENTS





·
            the
                impact of Canadian governmental regulation on the
                Trust;


·
            the
                existence, operation and strategy of the commodity price risk management
                program;


·
            the
                approximate and maximum amount of forward sales and hedging to be
                employed;


·
            changes
                in oil and natural gas prices and the impact of such changes on cash
                flow
                after hedging;


·
            the
                level of capital expenditures devoted to development activity rather
                than
                exploration;


·
            the
                sale, farming out or development using third party resources to exploit
                or
                produce certain exploration
                properties;


·
            the
                use of development activity and acquisitions to replace and add to
                reserves;


·
            the
                quantity of oil and natural gas reserves and oil and natural gas
                production levels;


·
            currency,
                exchange and interest rates;


·
            the
                performance characteristics of Provident's natural gas midstream,
                NGL
                processing and marketing business;


·
            the
                growth opportunities associated with the natural gas midstream, NGL
                processing and marketing business;
                and


·
            the
                nature of contractual arrangements with third parties in respect
                of
                Provident's natural gas midstream, NGL processing and marketing
                business.




Although
      the Trust believes that the expectations reflected in the forward-looking
      statements are reasonable, there can be no assurance that such expectations
      will
      prove to be correct. The Trust can not guarantee future results, levels of
      activity, performance, or achievements. Moreover, neither the Trust nor any
      other person assumes responsibility for the accuracy and completeness of the
      forward-looking statements. Some of the risks and other factors, some of which
      are beyond the Trust's control, which could cause results to differ materially
      from those expressed in the forward-looking statements contained in this Annual
      Information Form and the documents incorporated by reference herein include,
      but
      are not limited to:




·
            general
                economic conditions in Canada, the United States and
                globally;


·
            industry
                conditions, including fluctuations in the price of crude oil, natural
                gas
                and natural gas liquids and conditions associated with the natural
                gas
                midstream, NGL processing and marketing
                business;


·
            uncertainties
                associated with estimating
                reserves;


·
            royalties
                payable in respect of oil and gas
                production;


·
            governmental
                regulation of the oil and gas industry, including income tax and
                environmental regulation;


·
            fluctuation
                in foreign exchange or interest
                rates;


·
            stock
                market volatility and market
                valuations;


·
            the
                impact of environmental events;


·
            the
                need to obtain required approvals from regulatory
                authorities;


·
            unanticipated
                operating events which can reduce production or cause production
                to be
                shut-in or delayed;


·
            failure
                to obtain industry partner and other third party consents and approvals,
                when required;


·
            third
                party performance of obligations under contractual arrangements;
                and


·
            the
                other factors set forth under "Risk Factors" in this Annual Information
                Form.




Statements
      relating to "reserves" or "resources" are deemed to be forward-looking
      statements, as they involve the implied assessment, based on certain estimates
      and assumptions, that the resources and reserves described can be profitably
      produced in the future. Readers are cautioned that the foregoing list of factors
      is not exhaustive. The forward-looking statements contained in this Annual
      Information Form and the documents incorporated by reference herein are
      expressly qualified by this cautionary statement. Subject to the Trust's
      obligations under applicable securities laws, the Trust is not under any duty
      to
      update any of the forward-looking statements after the date of this Annual
      Information Form to conform such statements to actual results or to changes
      in
      the Trust's expectations.




-7-
 TABLE
            OF CONTENTS




**INCORPORATION
      AND STRUCTURE**




**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 the Trust are located at 800, 112 - 4th Avenue S.W.,
      Calgary, Alberta T2P 0H3. The registered office of the Trust is located at
      3700,
      400 - 3rd Avenue S.W., Calgary, Alberta T2P 4H2.




**Provident**




Provident
      Energy Ltd. is a corporation the common shares of which are wholly-owned by
      the
      Trust. Provident was incorporated under the ABCA on January 19, 2001 and was
      amalgamated with Founders pursuant to a plan of arrangement involving the Trust,
      Provident and Founders effective March 6, 2001. Provident subsequently
      amalgamated with Maxx Petroleum Ltd. ("Maxx") effective May 25, 2001 pursuant
      to
      a plan of arrangement involving the Trust, Provident and Maxx. Provident was
      also amalgamated with Richland Petroleum Corporation ("Richland") effective
      January 16, 2002 pursuant to a plan of arrangement involving the Trust,
      Provident and Richland. Provident was amalgamated with Provident Management
      Corporation pursuant to a management internalization transaction involving
      the
      Trust, Provident, the Manager and the shareholders of the Manager effective
      January 17, 2003. Provident was also amalgamated with Olympia and Viracocha
      on
      June 1, 2004 pursuant to plans of arrangement involving the Trust, Provident,
      Viracocha and Olympia. The head and principal offices of Provident are located
      at 800, 112 - 4th Avenue S.W., Calgary, Alberta T2P 0H3. The registered office
      of Provident is located at 3700, 400 - 3rd Avenue S.W., Calgary, Alberta T2P
      4H2.




**Provident
      Holdings Trust**




Provident
      Holdings Trust is an open-end unincorporated commercial trust governed by the
      laws of the Province of Alberta. Holdings Trust was formed pursuant to a trust
      indenture dated April 25, 2002 and is wholly-owned by the Trust. Holdings Trust
      currently holds a 99% limited partnership interest in the limited partnerships,
      Provident Acquisitions L.P., Provident Marketing L.P. and Provident Midstream
      L.P. The head and principal offices of Holdings Trust are located at 800, 112
      -
      4th Avenue S.W., Calgary, Alberta T2P 0H3. The registered office of Holdings
      Trust is located at 3700, 400 - 3rd Avenue S.W., Calgary, Alberta T2P
      4H2.




**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 limited
      partnership agreement dated April 19, 2002. The general partner of Provident
      Acquisitions L.P. is Provident which holds a 1% interest in the partnership.
      Holdings Trust is the limited partner of Provident Acquisitions L.P. with a
      99%
      interest in the partnership. The head and principal offices of Provident
      Acquisitions L.P. are located at 800, 112 - 4th Avenue S.W., Calgary, Alberta
      T2P 0H3. The registered office of Provident Acquisitions L.P. is located at
      3700, 400 - 3rd Avenue S.W., Calgary, Alberta T2P 4H2.




**Provident
      Midstream L.P.**




Provident
      Midstream L.P. is a limited partnership registered in the Province of Alberta.
      Provident Midstream L.P. was formed pursuant to a limited partnership agreement
      dated December 8, 2005. Provident Midstream L.P. directly and indirectly holds
      the Canadian partnership interests acquired pursuant to the Midstream NGL
      Acquisition. The general partner of Provident Midstream L.P. is




-8-
 TABLE
            OF CONTENTS





Provident
      GP Inc. which holds a 1% interest in the partnership. Holdings Trust and PMI
      are
      the limited partners of Provident Midstream L.P. with a 99% total interest
      in
      the partnership. The head and principal offices of Provident Midstream L.P.
      are
      located at 800, 112 - 4th Avenue S.W., Calgary, Alberta T2P 0H3. The registered
      office of Provident Midstream L.P. is located at 3700, 400 - 3rd Avenue S.W.,
      Calgary, Alberta T2P 4H2.




**Provident
      Acquisitions Inc.**




Provident
      Acquisitions Inc. is a corporation wholly-owned by Provident. PAI was
      incorporated under the ABCA on August 19, 2002. PAI is the beneficial owner
      of
      all of the Class A common shares of 101011500 Saskatchewan Ltd. ("Provident
      Saskco") and holds a 0.00001% interest in the Meota (2000) Partnership.
      Provident Saskco holds the remaining interest in the Meota (2000) Partnership.
      The head and principal offices of PAI are located at 800, 112 - 4th Avenue
      S.W.,
      Calgary, Alberta T2P 0H3. The registered office of PAI is located at 3700,
      400 -
      3rd Avenue S.W., Calgary, Alberta T2P 4H2.




**Provident
      Midstream Inc.**




Provident
      Midstream Inc. is a corporation wholly-owned by Provident and Pro Holding
      Company. PMI was incorporated under the ABCA on June 6, 2005. PMI holds
      Provident's Redwater Midstream NGL Assets. The head and principal offices of
      PMI
      are located at 800, 112 - 4th Avenue S.W., Calgary, Alberta T2P 0H3. The
      registered office of PMI is located at 3700, 400 - 3rd Avenue S.W., Calgary,
      Alberta T2P 4H3.




**Pro
      Holding Company**




Pro
      Holding Company is a corporation incorporated under the laws of Delaware and
      is
      wholly-owned by the Trust and Provident. PHC owns all of the outstanding shares
      of Pro LP Corp. and Pro GP Corp. which in turn own approximately 96% of the
      outstanding partnership interests in Breitburn L.P. PHC also owns all of the
      shares of Pro US LLC and Pro Midstream Company which are the partners of the
      Kinetic Resources U.S.A. partnership. The head and principal offices of PHC
      are
      located at 515 S. Flower Street, Suite 4800, Los Angeles, California. The
      registered office of PHC is located at 2711 Centerville Road, Suite 400,
      Wilmington, Delaware.




**Breitburn
      Energy Company L.P.**




Breitburn
      Energy Company L.P. is a Delaware limited partnership and an indirect subsidiary
      of the Trust. Breitburn L.P. resulted from the merger of Breitburn, a former
      California limited liability company, and BB Merger LLC, a Delaware limited
      liability company and wholly-owned indirect subsidiary of the Trust, upon
      completion of the indirect acquisition of all of the issued and outstanding
      shares of Breitburn by the Trust on June 15, 2004. The Trust, through Pro
      Holding Company, Pro LP Corp. and Pro GP Corp., currently holds approximately
      96% of the outstanding partnership interests in Breitburn L.P. with the
      remaining partnership interests held by Breitburn's co-founders and co-chief
      executive officers. The head and principal offices of Breitburn L.P. are located
      at 515 S. Flower Street, Suite 4800, Los Angeles, California. The registered
      office of Breitburn L.P. is 2711 Centerville Road, Suite 400, Wilmington,
      Delaware.




**INTERCORPORATE
      RELATIONSHIPS**




The
      following diagram describes the flow of cash from the oil and gas properties
      and
      the natural gas midstream, NGL processing and marketing business to the Trust
      and from the Trust to the Unitholders. Reference should be made to the
      appropriate sections of this Annual Information Form for a complete description
      of the structure of the Trust.




-9-
 TABLE
            OF CONTENTS










-10-
 TABLE
            OF CONTENTS





**INFORMATION
      CONCERNING THE TRUST, PROVIDENT AND CERTAIN
      SUBSIDIARIES**




**Provident
      Energy Trust**




***Cash
      Flow***




The
      Trust
      indirectly holds interests in petroleum and natural gas properties and the
      natural gas midstream, NGL processing and marketing business through Provident
      and its various subsidiaries. Cash flow from the petroleum and natural gas
      properties flows from Provident and the Trust's various subsidiaries to the
      Trust by way of royalty payments and interest payments and principal repayments
      on notes issued by the Trust from time to time. Cash flow from the natural
      gas
      midstream, NGL processing and marketing business flows from Provident to the
      Trust and the Trust's various subsidiaries by way of interest payments and
      principal repayments on notes issued by the Trust. Distributable income
      generated by the royalty payments, interest payments and principal repayments
      is
      then distributed monthly to the Unitholders.




Under
      the
      terms of the Trust Indenture the Trust is also entitled to (i) invest in
      securities of Provident from time to time; (ii) acquire royalties; (iii)
      temporarily hold cash and Permitted Investments for the purposes of paying
      the
      expenses and liabilities of the Trust and paying amounts payable by the Trust
      in
      connection with the redemption of any Trust Units and making distributions
      to
      Unitholders; (iv) acquire or invest in Subsequent Investments; and (v) pay
      the
      costs, fees and expenses associated with or incidental to the
      foregoing.




***Cash
      Distributions***




The
      Trustee intends to make cash distributions on or about the 15th day of each
      month to 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 notes issued by the Trust from
      time to time. It is anticipated however, that the Trust will reinvest a portion
      of the repayments of principal on the notes outstanding 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, among other
      things, fluctuations in the quantity of petroleum and natural gas substances
      produced, prices received for that production, hedging contract receipts and
      payments, taxes, direct expenses of the Trust, reclamation fund contributions,
      fluctuations in the demand for NGLs and natural gas, competition from other
      gas
      processing plants, operational matters and hazards related to the natural gas
      midstream, NGL processing and marketing business, capital expenditures, debt
      servicing, operating costs, debt service charges and general and administrative
      expenses as determined necessary by Provident on behalf of the Trust **.**




***Trust
      Units***




An
      unlimited number of Trust Units may be created and issued pursuant to the Trust
      Indenture. Each Trust Unit represents an equal fractional undivided beneficial
      interest in any distribution from the 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, the Trust in the event of the termination or winding-up
      of
      the Trust. All Trust Units rank among themselves equally and rateably without
      discrimination, preference or priority. Each Trust Unit is transferable, is
      not
      subject to any conversion or pre-emptive rights and entitles the holder thereof
      to require the Trust to redeem any or all of the Trust Units held by such holder
      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 the Trust or with respect to any acts performed by the Trustee or
      any
      other person pursuant to the Trust Indenture.




-11-
 TABLE
            OF CONTENTS




***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 and 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 thereof any other rights. As of March 21, 2006,
      there was one Special Voting Unit issued and outstanding.




***8.75%
      Debentures***




In
      September 2003, the Trust issued $75,000,000 aggregate principal amount of
      convertible unsecured subordinated debentures. The 8.75% Debentures mature
      on
      December 31, 2008 and bear interest at a rate of 8.75% per annum, payable
      semi-annually in arrears on June 30 and December 31 in each year. The 8.75%
      Debentures are convertible at the option of the holder into Trust Units at
      any
      time prior to the earlier of December 31, 2008 and the business day immediately
      preceding any date specified by the Trust for redemption at a conversion price
      of $11.05 per Trust Unit, subject to adjustment in certain circumstances. After
      January 1, 2007 and prior to maturity, the Trust may redeem the 8.75% Debentures
      in whole or in part from time to time at a price of $1,050 per 8.75% Debenture
      from January 1, 2007 until January 1, 2008 and at a price of $1,025 per 8.75%
      Debenture thereafter until maturity, in each case plus accrued and unpaid
      interest. On redemption or maturity of the 8.75% Debentures, the Trust may,
      subject to regulatory approval, elect to satisfy the redemption price or
      principal amount by issuing Trust Units to the 8.75% Debenture holder. As of
      March 21, 2006, there was $32,254,000 aggregate principal amount of 8.75%
      Debentures outstanding.




***8%
      Debentures***




In
      July
      2004, the Trust issued $50,000,000 aggregate principal amount of convertible
      unsecured subordinated debentures. The 8% Debentures mature on July 31, 2009
      and
      bear interest at a rate of 8% per annum, payable semi-annually in arrears on
      July 31 and January 31 in each year. The 8% Debentures are convertible at the
      option of the holder into Trust Units at any time prior to the earlier of July
      31, 2009 and the business day immediately preceding any date specified by the
      Trust for redemption at a conversion price of $12.00 per Trust Unit, subject
      to
      adjustment in certain circumstances. After July 31, 2007 and prior to maturity,
      the Trust may redeem the 8% Debentures in whole or in part from time to time
      at
      a price of $1,050 per 8% Debenture from July 31, 2007 until July 31, 2008 and
      at
      a price of $1,025 per 8% Debenture thereafter until maturity, in each case
      plus
      accrued and unpaid interest. On redemption or maturity of the 8% Debentures,
      the
      Trust may, subject to regulatory approval, elect to satisfy the redemption
      price
      or principal amount by issuing Trust Units to the 8% Debenture holder. As of
      March 21, 2006, there was $33,578,000 aggregate principal amount of 8%
      Debentures outstanding.




***Initial
      6.5% Debentures***




In
      March
      2005, the Trust issued $100,000,000 aggregate principal amount of convertible
      unsecured subordinated debentures. The Initial 6.5% Debentures mature on
      August 31, 2012 and bear interest at a rate of 6.5% per annum, payable
      semi-annually in arrears on August 31 and February 28 in each year.
      The Initial 6.5% Debentures are convertible at the option of the holder into
      Trust Units at any time prior to the earlier of August 31, 2012 and the
      business day immediately preceding any date specified by the Trust for
      redemption at a conversion price of $13.75 per Trust Unit, subject to adjustment
      in certain circumstances. After August 31, 2008 and prior to maturity, the
      Trust may redeem the Initial 6.5% Debentures in whole or in part from time
      to
      time at a price of $1,050 per Initial 6.5% Debenture from August 31, 2008
      until August 31, 2009, at a price of $1,025 per Initial 6.5% Debenture
      after August 31,




-12-
 TABLE
            OF CONTENTS





2009
      and
      on or before August 31, 2010 and after August 31, 2010 and prior to
      maturity at a price of $1,000 per Initial 6.5% Debenture, in each case plus
      accrued and unpaid interest. On redemption or maturity of the Initial 6.5%
      Debentures, the Trust may, subject to regulatory approval, elect to satisfy
      the
      redemption price or principal amount by issuing Trust Units to the Initial
      6.5%
      Debenture holder. As of March 21, 2006, there was $99,034,000 aggregate
      principal amount of Initial 6.5% Debentures outstanding.




***Supplemental
      6.5% Debentures***




In
      November 2005, the Trust issued $150,000,000 aggregate principal amount of
      convertible unsecured subordinated debentures. The Supplemental 6.5% Debentures
      mature on April 30, 2011 and bear interest at a rate of 6.5% per annum,
      payable semi-annually in arrears on April 30 and October 31 in each
      year, commencing April 30, 2006. The Supplemental 6.5% Debentures are
      convertible at the option of the holder into Trust Units at any time prior
      to
      the earlier of April 30, 2011 and the business day immediately preceding
      any date specified by the Trust for redemption at a conversion price of $14.75
      per Trust Unit, subject to adjustment in certain circumstances. After
      October 31, 2008 and prior to maturity, the Trust may redeem the
      Supplemental 6.5% Debentures in whole or in part from time to time at a price
      of
      $1,050 per 6.5% Debenture from October 31, 2008 until October 31, 2009, at
      a
      price of $1,025 per Supplemental 6.5% Debenture after October 31, 2009 and
      on or before October 31, 2011, in each case plus accrued and unpaid interest.
      On
      redemption or maturity of the Supplemental 6.5% Debentures, the Trust may,
      subject to regulatory approval, elect to satisfy the redemption price or
      principal amount by issuing Trust Units to the Supplemental 6.5% Debenture
      holder. As of March 21, 2006, there was $150,000,000 aggregate principal
      amount of Supplemental 6.5% Debentures outstanding.




***Meetings
      of Unitholders***




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. The Trust Indenture provides that meetings of Unitholders
      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
      royalties as an entirety or substantially as an entirety, and the commencement
      of winding-up the affairs of the Trust.




Unitholders
      may attend and vote at all meetings of Unitholders 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.




***Termination
      of the Trust***




Unitholders
      may vote to terminate the Trust at any meeting of Unitholders duly called for
      that purpose, subject to the following: (a) a vote may only be held if
      requested in writing by the holders of not less than 20% of the Trust Units;
      (b) a quorum of 50% of the issued and outstanding Trust Units is present in
      person or by proxy; and (c) the termination must be approved by Special
      Resolution.




Unless
      the Trust is terminated or extended by vote of Unitholders 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
      certain royalties 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 Unitholders in respect of the Special Resolution
      authorizing the termination of the Trust. After paying, retiring or discharging
      or making provision for the payment, retirement or discharge of all known
      liabilities and obligations of the




-13-
 TABLE
            OF CONTENTS





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 assets together with any cash remaining in the Trust among
      the
      Unitholders in accordance with their pro rata share.




***Trust
      Unit Option Plan***




The
      Trust
      discontinued its trust unit option plan as of May 2, 2005. No options were
      issued under the Option Plan after March 2005 and the Trust does not intend
      to
      issue any further options under the Option Plan in the future. However, options
      to acquire Trust Units previously granted under the Option Plan will continue
      to
      remain exercisable in accordance with their terms. Additional information
      concerning the Option Plan is included in the Trust's Proxy Statement and
      Information Circular dated March 31, 2006. As of March 21, 2006, there were
      3,081,837 options granted and outstanding under the Option Plan.




***Premium
      Distribution, Distribution Reinvestment and Optional Unit Purchase
      Plan***




The
      Trust
      has implemented a premium distribution, distribution reinvestment and optional
      unit purchase plan (the "DRIP") to provide holders of Trust Units with a means
      to automatically reinvest sums received on account of distributions on Trust
      Units. Provident reserves the right to prorate the participation in the DRIP
      to
      manage the amount of cash reinvested in the Trust and the Trust Units issued
      under the DRIP. Computershare Trust Company of Canada, as plan agent, may at
      the
      election of a participant (a) purchase Trust Units with the cash
      distributions at 95% of the market value of the Trust Units, or (b) elect
      to purchase additional Trust Units with the cash distributions and deliver
      such
      Trust Units to a broker in exchange for a premium cash distribution equal to
      an
      amount up to 102% of the monthly cash distribution, or (c) purchase new Trust
      Units under the optional unit purchase plan at a subscription price of 100%
      of
      the average market price of the Trust Units. If a participant has elected either
      (a) or (b), the plan agent may, on behalf of such participant, purchase
      additional Trust Units with the cash distributions at the market value of such
      Trust Units. Residents of Canada are eligible to elect options (a), (b), or
      (c).
      Due to regulatory restrictions, residents of the United States are eligible
      to
      elect option (a) only at this time.




***Limitation
      on Non-Resident Trust Unitholders***




In
      accordance with the Trust Indenture, in order to ensure the maintenance of
      the
      Trust's "mutual fund trust" status, Provident will: (i) prior to the
      consummation of any transaction involving the acquisition by the Trust of any
      Subsequent Investment; (ii) prior to any material modification to the Trust
      Fund other than as contemplated by subclause (i); (iii) promptly following
      any proposed amendment to paragraph 132(7)(a) of the Tax Act (which
      provision relates to the level of "taxable Canadian property") or the
      publication of any administrative bulletin or other notice of interpretation
      relating to the interpretation or application of such section; or
      (iv) otherwise at any time when requested by the Trustee, obtain an opinion
      of counsel confirming whether the Trust is, at the date thereof and following
      such transaction or event (which in the case of (iii) shall mean the coming
      into
      effect of the amendment or change of interpretation), entitled to rely on
      paragraph 132(7)(a) of the Tax Act (or any successor provision thereto) for
      purposes of qualifying as a "mutual fund trust" under the Tax Act.




If
      at any
      time the board of directors of Provident determines, in its sole discretion,
      or
      becomes aware that the Trust's ability to continue to rely on
      paragraph 132(7)(a) of the Tax Act (or any successor provision thereto) for
      purposes of qualifying as a "mutual fund trust" thereunder is in jeopardy,
      then
      forthwith after such determination Provident will take such steps as are
      necessary or desirable to ensure that the Trust is not maintained primarily
      for
      the benefit of Non-Residents.




Provident
      may, at any time and from time to time, in its sole discretion, request that
      the
      Trustee make reasonable efforts, as practicable in the circumstances, to obtain
      declarations as to beneficial ownership, perform residency searches of
      shareholder and beneficial shareholder mailing address lists and take such
      other
      steps specified by Provident, at the cost of the Trust, to determine or estimate
      as best possible the residence of the beneficial owners of Trust
      Units.




-14-
 TABLE
            OF CONTENTS





If
      at any
      time the board of directors of Provident, in its sole discretion, determines
      that it is in the best interest of the Trust, Provident, notwithstanding the
      ability of the Trust to continue to rely on subsection 132(7)(a) of the Tax
      Act
      for the purpose of qualifying as a "mutual fund trust" under the Tax Act, may
      (i) require the Trustee to refuse to accept a subscription for Trust Units
      from, or issue or register a transfer of Trust Units to, a person unless the
      person provides a declaration to Provident that the Trust Units to be issued
      or
      transferred to such person will not when issued or transferred be beneficially
      owned by a Non-Resident; (ii) to the extent practicable in the
      circumstances, send a notice to registered holders of Trust Units which are
      beneficially owned by Non-Residents, chosen in inverse order to the order of
      acquisition or registration of such Trust Units beneficially owned by
      Non-Residents or in such other manner as Provident may consider equitable and
      practicable, requiring them to sell their Trust Units which are beneficially
      owned by Non-Residents or a specified portion thereof within a specified period
      of not less than 60 days. If the Unitholders receiving such notice have not
      sold the specified number of such Trust Units or provided Provident with
      satisfactory evidence that such Trust Units are not beneficially owned by
      Non-Residents within such period, Provident may, on behalf of such registered
      Unitholder, sell such Trust Units and, in the interim, suspend the voting and
      distribution rights attached to such Trust Units and make any distribution
      in
      respect of such Trust Units by depositing such amount in a 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 so
      disposed of and their rights shall be limited to receiving the net proceeds
      of
      sale, and any distribution in respect thereof deposited as aforesaid, net of
      applicable taxes and costs of sale, upon surrender of the certificates
      representing such Trust Units; (iii) delist the Trust Units from any
      non-Canadian stock exchange; and (iv) take such other actions as the board
      of directors of Provident determines, in its sole discretion, are appropriate
      in
      the circumstances that will reduce or limit the number of Trust Units held
      by
      Non-Residents to ensure that the Trust is not maintained primarily for the
      benefit of Non-Residents.




Generally,
      a trust cannot qualify as a "mutual fund trust" for the purposes of the Tax
      Act
      if it is established or is being maintained primarily for the benefit of
      non-residents. Although not without uncertainty, this is generally accepted
      to
      exist in most situations where Non-Resident holders own significantly in excess
      of 50% of the aggregate number of Trust Units issued and outstanding. However,
      there is currently an exception to the non-resident ownership restriction in
      paragraph 132(7)(a) of the Tax Act where not more than 10% of the trust's
      property has at any time consisted of "taxable Canadian property".




***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 Trust Unit (the "Market
      Redemption Price") equal to the lesser of: (i) 90% of the simple average of
      the
      closing 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 (ii) 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.




The
      aggregate Market Redemption Price payable by the 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. In certain
      circumstances, the aggregate Market Redemption Price payable by the Trust may
      be
      satisfied by distributing notes having an aggregate principal amount equal
      to
      the aggregate Market Redemption Price of the Trust Units tendered for
      redemption.




It
      is
      anticipated that this redemption right will not be the primary mechanism for
      holders of Trust Units to dispose of their Trust Units. Notes which may be
      distributed in specie to holders of Trust Units in




-15-
 TABLE
            OF CONTENTS





connection
      with a redemption will not be listed on any stock exchange and no market is
      expected to develop in such notes. Notes will not be qualified investments
      for
      trusts governed by registered retirement savings plans, registered retirement
      income funds and deferred profit sharing plans.




***Trustee***




Computershare
      Trust Company of Canada is the trustee of the Trust. The Trustee is responsible
      for, among other things: (a) accepting subscriptions for Trust Units and issuing
      Trust Units pursuant thereto; (b) maintaining the books and records of the
      Trust
      and providing timely reports to Unitholders; and (c) paying cash distributions
      to Unitholders. 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 Unitholders 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 was until the first annual meeting
      of
      Unitholders. 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
      Unitholders. The Trustee may resign upon 60 days' notice to the Trust. The
      Trustee may also be removed by Special Resolution. Such resignation or removal
      becomes effective upon the acceptance or appointment of a successor
      trustee.




The
      Trustee, its directors, officers, employees, shareholders and agents shall
      not
      be liable to any Unitholder or any other person, in tort, contract or otherwise,
      in connection with any matter pertaining to the Trust or the Trust Fund, arising
      from the exercise by the Trustee of any powers, authorities or discretion
      conferred under the Trust Indenture, unless such liabilities arise out of the
      gross negligence, wilful default or fraud of the Trustee or any of its
      directors, officers, employees, shareholders or agents. 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, judgements,
      costs, charges or expenses against or with respect to the Trust or the Trust
      Fund. In addition, the Trust Indenture contains other customary provisions
      limiting the liability of the Trustee.




***Amendments
      to the Trust Indenture***




The
      Trust
      Indenture may be amended or altered from time to time by Special Resolution.
      The
      Trustee may, without the approval of the 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 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 and any other agreement
                of
                the Trust or any offering document pursuant to which securities of
                the
                Trust are issued, 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 Unitholders are not prejudiced thereby;
                and




·
            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 Unitholders are
                not
                prejudiced thereby.




-16-
 TABLE
          OF CONTENTS




***Provident
          Energy Ltd.***
  The
          principal business of Provident is to manage and administer the operating
          activities associated with the oil and gas properties and the natural gas
          midstream, NGL processing and marketing business. Provident is also engaged
          in
          the acquisition, exploitation, development and production of crude oil
          and
          natural gas in the Western Canadian Sedimentary Basin. Provident currently
          has
          579 employees, consultants and contract operators at its head office location
          and in several field offices within the core areas of Lloydminster, west
          central
          Alberta, southern Alberta, southwest Saskatchewan, southeast Saskatchewan,
          California and Wyoming and the NGL midstream facilities in Redwater  and
          Empress, Alberta, Sarnia, Ontario, Lynchburg, Virginia and Houston,
          Texas.
  ***Delegation
          of Authority, Administration and Trust Governance***


The
      board
      of directors of Provident has generally been delegated the significant
      management decisions of the Trust. In particular, the Trustee has delegated
      to
      Provident responsibility for any and all matters relating to: (a) the
      redemption of Trust Units; (b) the acquisition of Subsequent Investments by
      the Trust and the negotiation of management agreements respecting Subsequent
      Investments; (c) any offering of securities of the Trust including:
      (i) the listing and maintaining of the listing on the TSX or NYSE of the
      Trust Units; (ii) 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;
      (iii) ensuring compliance with all applicable laws; (iv) 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; (v) all matters concerning the terms of the sale or
      issuance of Trust Units or rights to Trust Units; (d) the determination of
      any
      Distribution Record Date other than the last date of each calendar month; and
      (e) the determination of any borrowing under the Trust Indenture. Holders of
      Trust Units are entitled to elect all of the members of the board of directors
      of Provident pursuant to the terms of the Unanimous Shareholder Agreement.




***Decision
      Making***




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: (i) 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; (ii) the approval of annual operating and capital expenditure
      budgets; and (iii) 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: (i) the issuance of additional Trust Units; and (ii) the
      determination of the amount of Distributable Cash. Any amendment to 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 thereto.




***Common
      Shares***




All
      of
      the issued and outstanding common shares of Provident are held by the Trust.
      Each common share of Provident 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 the common 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. All such common shares are entitled to share equally in any distribution
      of the assets of Provident upon the liquidation, dissolution,
      bankruptcy




-17-
 TABLE
            OF CONTENTS





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 common shares.




No
      dividends have been paid on the common shares of Provident. Any decision to
      pay
      dividends on the common shares of Provident in the future will be made by the
      board of directors of Provident on the basis of Provident's earnings, financial
      requirements and other conditions existing at the time.




***Series
      A Exchangeable Shares***




Provident
      issued a total of 1,682,242 Series A exchangeable shares in 2003. All of the
      Series A exchangeable shares are held by corporations related to two senior
      officers of Provident and were issued in connection with the Trust's management
      internalization transaction completed at the beginning of 2003.




The
      Series A exchangeable shares are generally intended to represent an economic
      equivalent to the Trust Units that the vendors would have received from the
      sale
      of the common shares of the Manager had they elected to receive Trust Units.
      Each Series A exchangeable share is exchangeable for Trust Units on the basis
      of
      an exchange ratio, initially equal to one, subject to certain adjustments to
      reflect the cash distributions on the Trust Units.




The
      Trust
      has issued a Special Voting Unit to Computershare Trust Company of Canada,
      the
      Trustee, for the benefit of the holders of the Series A exchangeable shares.
      The
      Special Voting Unit carries a number of votes, exercisable at any meeting at
      which Unitholders are entitled to vote equal to the number of Trust Units
      (rounded down to the nearest whole number) into which the Series A exchangeable
      shares are then exchangeable.




Provident
      is authorized to issue an unlimited number of exchangeable shares, issuable
      in
      series. As of March 21, 2006, there were 463,545 Series A exchangeable
      shares of Provident outstanding at an exchange ratio of 1.55261.




***Series
      B Exchangeable Shares***




On
      June
      1, 2004, Provident issued 2,650,000 Series B exchangeable shares as partial
      consideration pursuant to the Viracocha Arrangement and Olympia Arrangement.
      The
      exchange ratio for the Series B exchangeable shares was initially equal to
      one
      Trust Unit for one Series B exchangeable share and was increased on each date
      a
      distribution was paid by the Trust following the date of issuance and the date
      the Series B exchangeable share was exchanged, at the option of the holder,
      into
      Trust Units. On January 15, 2006, all remaining Series B exchangeable
      shares were acquired by the Trust in exchange for Trust Units. As a result,
      the
      Trust now holds all of the issued and outstanding Series B exchangeable
      shares of Provident.




***Royalties***




Provident
      has granted certain royalties to the Trust which entitle the Trust to cash
      distributions in respect of the production from oil and gas properties held
      by
      Provident.




Provident
      is entitled to make farmouts or other similar dispositions of specific interests
      in any part of the properties subject to the royalties, and upon the farmee
      or
      other participant earning its interest pursuant to the farmout or other
      disposition, these royalties shall burden only the working interest retained
      by
      or reserved 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 currently funds this reserve at $0.30 per barrel
      of oil equivalent (converting gas to oil at 6:1) (in 2004 and 2003
      -




-18-
 TABLE
            OF CONTENTS





$0.25
      per
      barrel of oil equivalent and in 2002 and prior - $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.




***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 and principal repayments on the various notes held
      by
      the Trust. In addition, cash flow from the natural gas midstream, NGL processing
      and marketing business flows from Provident to the Trust by way of interest
      payments and principal repayments on notes issued to the Trust.




**Provident
      Holdings Trust, Provident Acquisitions L.P., Provident
      Marketing L.P. and Provident Midstream L.P.**




Provident
      Acquisitions L.P. holds certain southeast Alberta properties. Holdings Trust
      holds a 99% interest in Provident Midstream L.P., Provident Marketing L.P.
      and
      Provident Midstream L.P. and is managed by Provident. Holdings Trust is
      wholly-owned by the Trust. The general partner of Provident Acquisitions L.P.
      is
      Provident. Provident Acquisitions L.P. has granted a royalty to the Trust
      entitling the Trust to receive the cash flow from all present and future oil
      and
      gas properties and related tangibles owned by Provident Acquisitions L.P. after
      certain cost expenditures and deductions. The general partner of Provident
      Marketing L.P. is Provident Marketing Inc. and the general partner of Provident
      Midstream L.P. is Provident GP Inc. Provident Midstream L.P. holds, either
      directly or indirectly through partnerships, all of the assets located in
      Canada **** acquired
      as a result of the Midstream NGL Acquisition, other than minor general
      partnership interests held by Provident GP Inc., a wholly-owned subsidiary
      of
      Provident. Cash flow from these assets flows to Holdings Trust by way of
      distributions on limited partnership units and from Holdings Trust to the Trust
      by way of interest and principal payments on notes issued by Holdings Trust
      to
      the Trust.




**Provident
      Acquisitions Inc.**




PAI
      holds
      certain Alberta and Saskatchewan properties that were acquired through the
      purchase of Meota. PAI is managed by Provident and has 67% interest in 10101150
      Saskatchewan Ltd. and a 0.00001% interest in Meota (2000) Partnership. 10101150
      Saskatchewan Ltd. holds the remaining 99.9999% interest in the Meota (2000)
      Partnership. PAI has granted a royalty to the Trust entitling the Trust to
      receive the cash flow from all present and future oil and gas properties and
      related tangibles owned by PAI after certain cost expenditures and
      deductions.




**Provident
      Midstream Inc.**




PMI
      holds
      the Redwater Midstream NGL Assets. Provident receives cash flow generated by
      PMI
      by way of interest and principal payments on debt owing from PMI to
      Provident.




**Breitburn
      Energy Company L.P.**




Breitburn
      L.P. holds the Breitburn Properties acquired pursuant to the Breitburn
      Acquisition and the Orcutt Hill Properties acquired pursuant to the Orcutt
      Hill
      Acquisition. Breitburn L.P. also holds all of the membership interests of
      Nautilus, which holds oil and gas producing properties in the State of Wyoming.
      The Trust currently indirectly holds approximately 96% of the outstanding
      partnership interests of Breitburn L.P. with the remaining approximately 4%
      of
      the partnership interests held by Breitburn's co-founders and co-chief executive
      officers. Cash flow from the oil and gas properties and related tangibles held
      by Breitburn L.P. is distributed to Breitburn L.P.'s partners, Breitburn
      Energy  Corporation, Pro LP Corp. and Pro GP Corp. and from Pro LP Corp.
      and Pro GP Corp. to the Trust in the form of dividends and interest payments
      on
      intercompany debt.




-19-
 TABLE
            OF CONTENTS




Breitburn
      L.P. currently has 122 employees and continues to operate and report as a
      separate business unit of the Trust.




**Pro
      Holding Company**




PHC
      owns
      as of the outstanding shares of Pro LP Corp. and Pro GP Corp. which in turn
      own
      approximately **** 96% **** of
      the
      outstanding partnership interests in Breitburn L.P. PHC also owns all of the
      shares of Pro US LLC and Pro Midstream Company which in turn hold all of the
      partnership interests in the Kinetic Resources U.S.A. partnership. Pro US LLC
      holds all of the assets located in the U.S. **** acquired
      as a result of the Midstream NGL Acquisition, other than those held by the
      Kinetic Resources U.S.A. partnership.




**Internalization
      of Management**




Prior
      to
      2003, the principal business of the Manager was 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 provided
      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
      Manager was 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.




On
      November 22, 2002 the Trust, Provident, the Manager, Scimitar Energy Limited
      and
      Hastings Street Management Limited (the "Vendors") entered into a share purchase
      agreement pursuant to which Provident agreed to purchase all of the issued
      and
      outstanding common shares of the Manager in consideration of $18 million,
      payable by the issuance of an aggregate of 1,682,242 Series A exchangeable
      shares at an agreed upon price of $10.70 per share, subject to certain
      adjustments. Each Series A exchangeable share issued to the Vendors is
      exchangeable for Trust Units on the basis of an exchange ratio which takes
      into
      account the cash distributions on the Trust Units. On the date of issuance
      of
      the Series A exchangeable shares, the exchange ratio was equal to one Trust
      Unit
      for each exchangeable share.




As
      a
      condition of completing the internalization transaction, the Vendors entered
      into escrow agreements. The escrow provisions resulted in all Series A
      exchangeable shares issued pursuant to the share purchase agreement being held
      in escrow. The number of Series A exchangeable shares held in escrow
      representing 25% of the initial underlying Trust Units to be issued to the
      Vendors are releasable per year beginning on June 30, 2003 and are also
      releasable in certain other limited circumstances.




The
      escrow agreements also provide for the monthly release from escrow of a number
      of Series A exchangeable shares to account for the adjustment to the exchange
      ratio as a result of distributions paid on the Trust Units. The release of
      such
      Series A exchangeable shares effectively releases to the Vendors the
      distributions paid on the Trust Units. The number of Series A exchangeable
      shares to be released from escrow to account for such distributions on the
      Trust
      Units shall be determined by multiplying the number




-20-
 TABLE
            OF CONTENTS





of
      Series
      A exchangeable shares held by a Vendor on the last day of the month in question
      which have not been released from escrow or are not releasable from escrow
      by
      the difference between the exchange ratio in effect on the last day of the
      month
      in question and the exchange ratio in effect on the last day of the month
      immediately preceding the month in question and dividing the product thereof
      by
      the exchange ratio in effect on the last day of the month in
      question.




In
      the
      event of a change of control of the Trust or Provident, all Series A
      exchangeable shares held in escrow will be released to the underlying holders.
      In addition, the escrow agreements provide for early release of the securities
      in the event of the death or disability of either Thomas Buchanan or Randall
      Findlay, or if either is terminated from their employment with Provident or
      any
      other subsidiary of the Trust without just cause. Securities held in escrow
      may
      be charged, pledged or encumbered, provided that the securities will remain
      in
      escrow pursuant to the terms of the escrow agreements.




In
      addition, the Series A exchangeable shares held in escrow which have not been
      released or are not releasable from escrow at the applicable time will be
      subject to cancellation and forfeiture by Provident if the relevant individual
      voluntarily resigns from Provident or any other subsidiary of the
      Trust.




The
      escrow provisions and forfeiture provisions are intended to enhance alignment
      between management and Unitholder interests and to retain
      management.




In
      connection with the closing of the internalization transaction, Provident
      entered into executive employment agreements with each of Mr. Buchanan and
      Mr.
      Findlay. Under the terms of the executive employment agreements, each of Mr.
      Buchanan and Mr. Findlay receives an annual salary of $250,000 for the first
      year of services and thereafter as determined by the Board of Directors
      annually, provided that each annual determination shall not be less than the
      previous year's annual salary. Mr. Buchanan and Mr. Findlay will also be
      entitled to a cash bonus of up to 50% of his annual salary in an amount
      determined by the Board of Directors based on certain established
      criteria.




In
      addition, options to purchase 500,000 Trust Units were granted to each of Mr.
      Buchanan and Mr. Findlay effective January 1, 2003. Such options vest as to
      1/3
      immediately and 1/3 on each subsequent anniversary of the grant.




Each
      of
      Mr. Buchanan and Mr. Findlay will also receive and participate in any and all
      fringe benefit plans, coverages and other perquisites made available from time
      to time to Provident's senior officers and executives.




In
      the
      event of a change of control or termination of employment for any reason other
      than cause, each of Mr. Buchanan and Mr. Findlay will receive two times the
      aggregate of his then current salary and the bonus paid to him in respect of
      the
      most recently completed financial year.




It
      has
      been agreed that each of Mr. Buchanan and Mr. Findlay will be nominated by
      the
      Board of Directors for a position as a director of Provident at each meeting
      of
      Unitholders at which directors of Provident are elected.






**GENERAL
      DEVELOPMENT OF THE BUSINESS OF THE TRUST AND
      PROVIDENT**




In
      March
      2001, shareholders of Founders approved the reorganization of Founders into
      the
      Trust. The following information describes the development of the business
      of
      the Trust and its material subsidiaries over the last three completed financial
      years.




On
      September 30, 2003, Provident completed the acquisition of the Redwater natural
      gas liquids processing business from Williams Canada for an aggregate purchase
      price of approximately $298.6 million (including costs associated with the
      acquisition), subject to certain adjustments. The Redwater Midstream NGL Assets
      acquired pursuant to the Redwater Acquisition consisted of a natural
      gas




-21-
 TABLE
            OF CONTENTS





gathering
      system and processing plant, as well as an NGL extraction plant, fractionation
      facilities, transportation systems and storage assets owned by Williams Canada.
      The Redwater Midstream NGL Assets are strategically located in one of the four
      main NGL hubs in North America and have an approximately 25% share of NGL
      processing capacity in western Canada with a significant amount of its capacity
      contracted on a long-term fee for service or fixed margin contract
      basis.




In
      connection with the Redwater Acquisition, the Trust completed a public offering
      of 19,205,000 Trust Units and $75,000,000 aggregate principal amount of 8.75%
      Debentures for gross proceeds of $276,653,000. The net proceeds from the
      offering were used to fund the Redwater Acquisition.




On
      October 21, 2003, the Trust announced the appointment of Norman Gish to the
      Board of Directors of Provident and the appointments of Andrew Gruszecki as
      Vice
      President of the NGL Services division of Provident and Gary Kline as Vice
      President of Commercial Development and Risk Management.




On
      January 12, 2004, the Trust announced the appointment of Dr. Robert
      Mitchell to the Board of Directors of Provident.




On
      February 4, 2004, the Trust completed a public offering of 4,500,000 Trust
      Units
      for gross proceeds of $50,400,000. The net proceeds were used to fund a portion
      of the Trust's 2004 capital expenditure program and to repay debt.




On
      April
      6, 2004, the Trust, Provident, Olympia and Accrete entered into an arrangement
      agreement providing for the acquisition by the Trust of all of the issued and
      outstanding common shares of Olympia pursuant to the Olympia Arrangement. In
      connection with the Olympia Arrangement, certain exploration and development
      properties of Olympia were transferred to Accrete, a newly created company,
      the
      shares of which were distributed to Olympia's shareholders under the Olympia
      Arrangement. On May 27, 2004, shareholders of Olympia approved the Olympia
      Arrangement. On June 1, 2004, the Trust, Provident, Olympia and Accrete
      completed the Olympia Arrangement. Provident and Olympia were then amalgamated
      and continued as Provident Energy Ltd.




On
      April
      6, 2004, the Trust, Provident, Viracocha and Chamaelo entered into an
      arrangement agreement providing for the acquisition by the Trust of all of
      the
      issued and outstanding common shares of Viracocha pursuant to the Viracocha
      Arrangement. In connection with the Viracocha Arrangement, certain exploration
      and development properties of Viracocha in Alberta were transferred to Chamaelo,
      a newly created company, the shares of which were distributed to Viracocha's
      shareholders under the Viracocha Arrangement. On May 27, 2004, shareholders
      of Viracocha approved the Viracocha Arrangement. On June 1, 2004, the
      Trust, Provident, Viracocha and Chamaelo completed the Viracocha Arrangement.
      Provident and Viracocha were then amalgamated and continued as Provident Energy
      Ltd.




On
      June
      15, 2004, the Trust entered into an agreement and plan of merger among
      Breitburn, a California limited liability company, Pro GP Corp., a Delaware
      corporation and wholly-owned indirect subsidiary of the Trust, Pro LP Corp.,
      a
      Delaware corporation and wholly-owned indirect subsidiary of the Trust and
      BB
      Merger LLC ("Acquisition LLC"), a Delaware limited liability company and
      wholly-owned indirect subsidiary of the Trust, pursuant to which the Trust
      acquired all of the issued and outstanding shares of Breitburn, for an aggregate
      purchase price of $155 million in cash and the assumption of approximately
      $35
      million of working capital deficiency and financial obligations of Breitburn,
      subject to certain adjustments. Under the terms of the Breitburn agreement,
      Breitburn and Acquisition LLC were merged and Breitburn was converted into
      Breitburn L.P., a Delaware limited partnership. The Breitburn Acquisition was
      completed on June 15, 2004 and resulted in the Trust indirectly holding 92%
      of the outstanding partnership interests of Breitburn L.P. as of that date,
      with
      the remaining 8% of the outstanding partnership interests of Breitburn L.P.
      retained by Breitburn's co-founders and co-chief executive officers for an
      aggregate purchase price of $13.7 million.




-22-
 TABLE
            OF CONTENTS





In
      connection with the Breitburn Acquisition, the Trust completed a public offering
      on July 6, 2004 of 13,100,000 Trust Units and $50,000,000 aggregate
      principal amount of 8% Debentures for gross proceeds of $186,240,000. The net
      proceeds from the offering were used to fund the Breitburn Acquisition, to
      fund
      the Trust's capital expenditure program and for general corporate
      purposes.




On
      September 13, 2004, Breitburn L.P., entered into a purchase and sale
      agreement with an arm's length third party vendor pursuant to which Breitburn
      L.P. agreed to purchase the Orcutt Hill Properties, consisting of certain oil
      and natural gas producing properties, related interests and 5,000 acres of
      surface acreage situated in the Orcutt Hill Oil Field and located in Santa
      Barbara County, California for a purchase price of US$45,000,000, subject to
      adjustment. The Orcutt Hill Acquisition was completed on October 4,
      2004.




In
      connection with the Orcutt Hill Acquisition, the Trust completed a public
      offering on October 4, 2004 of 11,480,000 Trust Units for gross proceeds of
      $125,706,000. The net proceeds from the offering were used to fund the Orcutt
      Hill Acquisition, to fund the Trust's capital expenditure program and for
      general corporate purposes.




On
      February 9, 2005, Breitburn L.P., entered into a membership interest
      purchase and sale agreement with all of the holders of membership interests
      in
      Nautilus pursuant to which Breitburn L.P. agreed to acquire all membership
      interests in Nautilus for an aggregate purchase price of US$75,000,000, subject
      to adjustment. The Nautilus Acquisition was completed on March 2, 2005. The
      reserves attributable to Nautilus were evaluated in accordance with NI 51-101
      by
      NSA, independent petroleum engineers, in a report of NSA dated February 22,
      2005
      and effective January 1, 2005.




In
      connection with the Nautilus Acquisition, the Trust completed a public offering
      on March 1, 2005 of 8,400,000 Trust Units and $100,000,000 aggregate
      principal amount of Initial 6.5% Debentures for gross proceeds of $200,800,000.
      The net proceeds from the offering were used to fund the Nautilus Acquisition,
      to fund the Trust's capital expenditure program and for general corporate
      purposes.




On
      March
      11, 2005, the Trust announced the appointment of Hugh Fergusson to the Board
      of
      Directors of Provident.




On
      May
      31, 2005, all outstanding 10.5% convertible unsecured subordinated debentures
      of
      the Trust (the "10.5% Debentures"), were redeemed at an amount of $1,050 plus
      all accrued and unpaid interest to May 30, 2005 per each $1,000 principal amount
      of 10.5% Debenture. An aggregate of $3 million was paid on redemption of the
      10.5% Debentures. An aggregate of 3,507,570 Trust Units were issued upon
      conversion of the then outstanding 10.5% Debentures prior to the redemption
      of
      such debentures.




On
      June
      28, 2005, the Trust announced that Mr. Dan O'Byrne was appointed to the newly
      created position of Executive Vice-President, Operations and Chief Operating
      Officer. Mr. O'Byrne is responsible for Provident's oil and gas production
      and
      its midstream operations.




On
      October 3, 2005, the Trust announced that Mr. Grant Billing was stepping down
      as
      Chairman of the board of directors of Provident. Mr. John Zaozirny, Q.C., was
      appointed to replace Mr. Billing as the Chairman of the board of directors
      of
      Provident. Provident's board believes the regular rotation of the Chairman
      of
      the board of directors and Chairs of board committees is good governance
      practice. Mr. Billing continues to be a director of Provident.




On
      October 20, 2005, the Trust signed an agreement with EnCana Oil & Gas
      Partnership, an affiliate of EnCana Corporation, to provide rail offloading
      and
      terminalling services for condensate to be used as a heavy oil diluent. A new
      condensate offloading facility is under construction at Provident's NGL
      fractionation plant at Redwater, Alberta. The existing Redwater plant is being
      expanded to offload and re-deliver an additional 35,000 barrels per day of
      condensate for EnCana Oil & Gas Partnership and other heavy oil producers.
      The expansion will also include a new multi-product truck loading facility.
      These




-23-
 TABLE
            OF CONTENTS





new
      terminals will complement the existing pipeline connections to and from the
      plant and are expected to be in service in the second quarter of 2006, at a
      total cost of approximately $50 million. Full utilization of this facility's
      capacity is expected by management of Provident to increase the current western
      Canadian diluent supply by more than 15%.




On
      October 27, 2005, the Trust and Provident entered into a purchase and sale
      agreement with EnCana Corporation, 1140102 Alberta Ltd., EnCana Midstream Inc.,
      WD Energy Services Inc. and EnCana Kerrobert Pipelines Limited (collectively,
      the "EnCana Vendors") pursuant to which Provident agreed to acquire certain
      assets, shares and partnership interests which comprised the EnCana Vendors'
      natural gas liquids business for a purchase price, net of cash acquired, of
      $772
      million. The assets of the Midstream NGL Business include interests in certain
      NGL extraction plants, pipelines, storage and fractionation facilities,
      distribution facilities, contracts and the EnCana Vendors' interest in the
      NGL
      marketing business operated by Kinetic Resources U.S.A., a partnership formed
      under the laws of the State of Michigan and Kinetic Resources (LPG), a
      partnership formed under the laws of the Province of Alberta. The Midstream
      NGL
      Acquisition was completed on December 13, 2005.




In
      connection with the Midstream NGL Acquisition, the Trust completed a public
      offering on November 15, 2005 of 21,830,000 subscription receipts and
      $150,000,000 aggregate principal amount of Supplemental 6.5% Debentures for
      gross proceeds of approximately $425,000,000. The net proceeds of the Midstream
      NGL Acquisition were used to pay a portion of the purchase price in respect
      of
      the Midstream NGL Acquisition. Each subscription receipt was automatically
      exchanged for one Trust Unit upon closing of the Midstream NGL
      Acquisition.




In
      the
      fourth quarter of 2005, the Trust expanded its term credit facilities from
      $410.0 million at December 31, 2004. The expanded facilities are comprised
      of $750 million of lending capacity related to its Canadian assets and US$100
      million of lending capacity related to its U.S. assets. The facilities are
      separate and each is provided by separate syndicates of banks.




On
      December 16, 2005, the Trust Units were listed on the NYSE under the symbol
      "PVX" and the Trust discontinued the listing of the Trust Units on the AMEX.




On
      January 17, 2006, the Trust announced the appointment of David I. Holm to the
      newly-created position of Executive Vice President, Finance and Strategy,
      effective February 1, 2006. Mr. Holm will be responsible for overseeing
      corporate functions at Provident, including finance, strategy, planning,
      business development, risk management, and communications. On March 28, 2006,
      Mr. Holm was appointed Corporate Secretary.







**SIGNIFICANT
      ACQUISITIONS**




On
      October 27, 2005, the Trust and Provident entered into a purchase and sale
      agreement with the EnCana Vendors pursuant to which Provident agreed to acquire
      certain assets, shares and partnership interests which comprised the EnCana
      Vendors' natural gas liquids business. The assets of the Midstream NGL Business
      include interests in certain natural gas liquids extraction plants, pipelines,
      storage and fractionation facilities, distribution facilities, contracts and
      the
      EnCana Vendors' interest in the NGL marketing business operated by Kinetic.
      The
      Midstream NGL Acquisition closed on December 13, 2005.




The
      assets of the Midstream NGL Business extend from Taylor, British Columbia to
      Sarnia, Ontario and Lynchburg, Virginia, U.S.A. The assets of the Midstream
      NGL
      Business include interests in certain NGL extraction plants, pipelines, storage
      and fractionation facilities, distribution facilities, contracts, and the
      Vendors' interest in Kinetic, which markets NGLs, owns a distribution terminal
      and leases approximately 700 rail cars. Kinetic focuses on higher value markets
      across Canada and the United States. Kinetic has access to long term NGL supply
      and transportation arrangements, which enhance its optimization, arbitrage
      and
      marketing capabilities.




-24-
 TABLE
            OF CONTENTS





Additional
      information concerning the Midstream NGL Acquisition, including the annual,
      interim and pro forma financial statements of the Midstream NGL Business, are
      set forth in the business acquisition report of the Trust dated
      February 24, 2006 incorporated by reference herein and filed on SEDAR at
      www.sedar.com.




**CORPORATE
      STRATEGY AND RISK MANAGEMENT**




**General**




Provident's
      strategy is focused on achieving a consistent level of monthly cash
      distributions to the Unitholders. To this end, Provident pursues a balanced
      portfolio strategy that incorporates the integration of the oil and gas
      production business and the natural gas midstream, NGL processing and marketing
      business. This balanced portfolio extends the economic life of the Trust,
      assists with the stability of cash flows and provides Provident access to a
      broader range of opportunities across the energy value chain.




With
      respect to the oil and gas production business, Provident is focused on the
      acquisition, development, exploitation, production and marketing of crude oil
      and natural gas. Provident's operations are currently located in five core
      regions in the Western Canadian Sedimentary basin and in the States of
      California and Wyoming. In management's opinion, these areas generally offer
      low
      to medium risk development potential and a well developed operational
      infrastructure, all of which is ideally suited to a trust. Provident focuses
      its
      development activities on low risk drilling opportunities that can be used
      to
      partially offset production declines.




Provident's
      natural gas midstream, NGL processing and marketing business adds an additional
      dimension to the Trust - one with minimal on-going capital requirements and
      reduced exposure to commodity price risk. This provides the Trust with more
      stable, longer life cash flows and provides the Trust access to a broader range
      of growth opportunities along the energy value chain.




A
      consistent, disciplined integrated 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 crude, natural gas and NGL prices.




Provident's
      main vehicle for growth will continue to be acquisitions both in its oil and
      gas
      business and energy infrastructure business. Acquisition opportunities will
      continue to be evaluated against the criteria of being accretive to cash flow
      and net asset value.




**Risk
      Management**




Provident's
      integrated risk management program is designed to protect the Unitholders,
      as
      well as Provident's employees, stakeholders, environment and reputation. This
      key management tool helps ensure more predictable and stable cash distributions.
      Provident's Risk Management Committee (the "RMC"), in conjunction with the
      board
      of directors, establishes the operational, strategic and governance risk
      mitigation practices and guidelines for the Trust. Members of the RMC include
      Provident's chief executive officer, president, chief operating officer,
      executive vice president strategy, finance & business development, chief
      financial officer, and senior executive vice president of commercial development
      and risk management. Provident's definition of risk is broad and so too are
      the
      policies and procedures Provident uses to identify, monitor, measure and
      mitigate business and market risks.




Provident
      is exposed to all the normal business and market risks inherent within the
      oil,
      natural gas and natural gas liquids business, including commodity price risk,
      foreign-currency rate risk, interest rate risk, and counterparty credit risk.
      Since its inception, Provident has used financial hedging instruments to manage
      the commodity and foreign exchange exposures associated with its revenue
      stream.




-25-
 TABLE
            OF CONTENTS





In
      2003,
      Provident broadened the scope of its risk management activities hiring
      additional internal expertise and implementing an integrated risk management
      program that cuts across business lines and commodities, and incorporates
      systematic programs to identify, monitor, measure and mitigate business and
      market risks.




***Commodity
      Price Risk***




Provident's
      Commodity Price Risk Management Program ("CPRMP") involves a disciplined hedging
      strategy and use of derivative instruments to minimize price risk associated
      with the volatility of commodity prices. These instruments may include fixed
      for
      floating swaps, costless collars, puts, calls, and fixed and indexed referenced
      pricing.




The
      CPRMP
      involves a disciplined hedging strategy that utilizes derivative instruments
      to
      provide for insurance against lower commodity prices, protect against price
      volatility, secure bank financing, improve debt coverage and assist with more
      predictable and stable cash distributions. The hedging strategy protects a
      percentage of production against a decline in commodity prices while with some
      products, allowing the Trust to participate in a rising commodity price
      environment. It provides price stabilization and protection of inventory values
      and fractionation spread margin associated with the midstream services and
      marketing business units. As well, the CPRMP reduces foreign exchange risk
      due
      to the exposure arising from the conversion of U.S. dollars into Canadian
      dollars.




Provident
      will continue to execute the CPRMP in 2006. The derivative instruments the
      Trust
      uses include puts, calls, costless collars, participating swaps, fixed and
      indexed referenced pricing.




***Oil
      and Natural Gas Hedging***




Provident's
      oil and natural gas businesses are exposed to lower commodity prices, market
      and
      quality differentials, higher power prices and the risk of operational failure.




In
      the
      oil and gas business units, the hedging cost associated with crude oil on 2005
      totaled $59.0 million ($8.36 per barrel) and $5.6 million related to natural
      gas
      ($0.19 per gj), with a combined total of $64.6 million or $5.24 per
      boe.




In
      the
      oil and natural gas production business, Provident consistently layers in
      hedging positions such that it will have 50 to 70 percent of production hedged
      12 months forward and 25 to 50 percent hedged 12 to 24 months out. The decisions
      to enter into hedge positions and risk management strategy selection are made
      by
      senior officers of Provident who are also members of the RMC. The RMC receives
      input and commodity expertise from each business unit in the decision making
      process. Strategies are selected based on their ability to help Provident
      provide stable cash flow and distributions per unit rather than to simply lock
      in a specific price per barrel of oil or cubic foot of natural gas.




***Midstream
      Services***




The
      business risks faced by the NGL midstream services business include a narrowing
      frac spread, NGL price decline between the purchase and sale of inventory,
      the
      relationship of NGL product prices to crude oil, basis risk between pricing
      points, higher power and operating costs, lack of available feedstock,
      composition of gas and operational failure.




The
      commodity price risk profile of the NGL midstream services business differs
      from
      that of the oil and gas production business. While oil and gas hedging involves
      protecting absolute prices, midstream hedging protects the margins created
      through buying, processing and selling commodities. Provident has a number
      of
      long-term, fee-based and fixed margin contracts in place that reduce the effects
      of fluctuating natural gas feedstock and NGL prices. In addition to these
      long-term NGL contracts, Provident utilizes derivative instruments to further
      protect margins and inventory values associated with the midstream
      business.




-26-
 TABLE
            OF CONTENTS





To
      support the cash flow stream from the Midstream NGL Business that Provident
      acquired late in 2005, Provident implemented a hedging program to effectively
      fix a portion of midstream services cash flow derived from frac spread margins.
      The program uses a combination of hedging products to protect a floor level
      of
      cash flow on a portion of Provident's NGL production when the oil to gas ratio
      is above target levels.




In
      2005,
      the midstream segment recorded a hedging cost of $2.3 million primarily on
      propane and ethane price stabilization and frac-spread margin hedging
      activities.




***Foreign
      Currency***




Provident
      receives both Canadian and U.S. dollars for oil and gas and NGL sales, exposing
      Provident to positive or negative effects of fluctuations in the U.S./Canadian
      dollar exchange rate. Provident manages this exposure by matching a significant
      portion of expected cash costs and revenues in the same currency. Provident
      uses
      derivative instruments that include forward and swap contracts to effectively
      manage the U.S. cash requirements of its U.S. and Canadian business
      lines.




Provident's
      foreign exchange hedging strategy reduced the effect of the 7 percent
      appreciation of the Canadian dollar relative to the U.S. dollar in 2005.
      Provident's strategy manages the exposure it has to fluctuations in the
      U.S./Canadian dollar exchange rate when the underlying commodity price is based
      upon a U.S. index price. Provident may also use derivative products that provide
      for insurance against a stronger Canadian dollar, while allowing it to
      participate if the currency weakens relative to the U.S. dollar.




The
      derivative hedging contracts in place at December 31, 2005 are summarized in
      the
      following tables:

















-27-
 TABLE
            OF CONTENTS










***Interest
      Rate Risk***




Provident
      is also exposed to fluctuations in the Canadian prime interest rate as a result
      of the use of its term revolving debt facility. Provident actively monitors
      interest rates and the tools available to effectively fix interest payable
      at
      current or lower rates.




***Credit
      Risk***




Credit
      risk is the risk of non-payment by a customer or counterparty. Provident's
      credit policy has determined portfolio limits to ensure a diversified customer
      base and mitigate counterparty exposure. Provident evaluates the business and
      financial risk factors for each counterparty through internal credit procedures
      and in certain situations may request credit support in the form of letters
      of
      credit, guarantee or cash prepayment. A maximum credit limit is determined
      for
      each counterparty based on the credit ratings and internal models for each
      counterparty, which are based on company specific information and industry
      analysis. Credit exposures and limits are monitored routinely and reported
      to
      the RMC.




***Insurance***




Provident
      continually reviews its insurance requirements and policies to ensure adequate
      coverage of its assets. Insurance is in place for property damage, general
      liability, environmental impact, business interruption, directors and officers.
      The RMC receives reports and monitors the adequacy and appropriateness of
      Provident's insurance coverage.




-28-
 TABLE
            OF CONTENTS




**OIL
      AND NATURAL GAS OPERATIONS**




Provident's
      Canadian reserves were evaluated by McDaniel effective December 31, 2005, in
      accordance with NI 51-101. Provident's United States reserves were evaluated
      by
      NSA and by CGA effective December 31, 2005 in accordance with NI 51-101.
      McDaniel, NSA and CGA are independent qualified reserves evaluators appointed
      pursuant to NI 51-101. The McDaniel evaluation report is dated February 24,
      2006 with a preparation date of December 31, 2005. The NSA evaluation report
      is
      dated March 27, 2006 with a preparation date of December 31, 2005 and the CGA
      evaluation report is dated February 1, 2006 with a preparation date of
      December 31, 2005.




The
      Trust's Statement of Reserves Data and Other Oil and Gas Information on
      Form 51-101F1, the Report on Reserves Data by Independent Qualified
      Reserves Evaluator or Auditor on Form 51-101F2 and the Report of Management
      and Directors on Oil and Gas Disclosure on Form 51-101F3 all dated
      effective March 13, 2006 have been filed on SEDAR at www.sedar.com and are
      incorporated by reference in this Annual Information Form.




**NATURAL
      GAS MIDSTREAM, NGL PROCESSING AND MARKETING
      OPERATIONS**




**General**




The
      Canadian NGL industry involves the production, transportation and marketing
      of
      products that are extracted from natural gas prior to its sale to end use
      customers. On a production basis, the Canadian industry is about one third
      the
      size of the US industry, and Provident's natural gas midstream, NGL processing
      and marketing business represents one of the five largest NGL production asset
      groupings in North America. The profitability of the industry is based on the
      products extracted being of greater economic value as separate commodities
      than
      as components of natural gas.




Natural
      gas is a mixture of various hydrocarbon components, the most abundant of which
      is methane. The higher value hydrocarbons, which include ethane (C2), propane
      (C3), butane (C4) and pentanes-plus (C5+), are generally in gaseous form at
      the
      pressures and temperatures under which natural gas is gathered and transported.
      The basis of the NGL industry is the recovery of these higher value hydrocarbons
      from natural gas for sale in a liquid form. In Canada, approximately 90% of
      NGLs
      are a by-product of natural gas processing, with 10% resulting from the refining
      of crude oil. Approximately 75% of NGL production in Canada results from natural
      gas production in Alberta.




The
      NGL
      value chain begins with the gathering of gas that is produced. The gas then
      gets
      processed through processing plants, extraction facilities and fractionation
      facilities in order to remove high value NGLs, as well as water, sulphur and
      other impurities. The value chain culminates with the transportation and
      eventual sale of NGLs to the final customer.







-29-
 TABLE
            OF CONTENTS





**NGL
      Extraction**




The
      heart
      of the NGL value chain lies in the extraction of NGLs from natural gas, which
      takes place in a number of steps at extraction facilities. NGLs are recovered
      primarily at three types of extraction facilities: natural gas field plants,
      natural gas straddle plants and oil refineries. Field plants process raw natural
      gas, which is produced from wells in the immediate vicinity, to remove
      impurities such as water, sulphur and carbon dioxide prior to the delivery
      of
      natural gas to the major natural gas pipeline systems. Field plants also remove
      almost all pentanes-plus and as much as 65% of propane and 80% of butane in
      order to meet pipeline specifications. Most field plants do not remove ethane,
      but there is currently about 70,000 b/d of ethane produced from Alberta field
      plants out of a total 240,000 b/d of ethane production from western Canada.
      The
      NGLs extracted are generally removed in mixes (either ethane-plus or
      propane-plus), which must be further processed in subsequent steps to separate
      out the individual products. Approximately 40% of the 700 field plants in
      western Canada extract NGLs.




**NGL
      Fractionation**




NGL
      mix
      extracted at field plants is transported to fractionation facilities, which
      enhances its value by separating the mix into its components: ethane, propane,
      butane and pentanes-plus. Fractionation generally does not occur at field
      plants, but rather at a central location (although there is some fractionation
      capacity at certain field plants in Alberta). The NGL mixes are moved by truck
      or pipeline to fractionation centres, with the greater Edmonton region serving
      as the major fractionation centre in Alberta and one of the four main
      fractionation hubs in North America, along with Sarnia, Ontario, Conway, Kansas
      and Mont Belvieu, Texas. Once fractionated, the products are then transported
      to
      markets in Alberta or outside the province, by pipeline, truck or
      rail.




**NGL
      Transportation**




The
      efficient movement of NGL products in western Canada requires significant
      infrastructure, including transportation assets (pipelines, trucks, rail cars),
      storage facilities and terminals (rail and truck). The most efficient and the
      lowest cost means for moving NGL products to markets is by pipeline. The western
      Canadian NGL sector has an extensive pipeline network for the transportation
      of
      natural gas to field plants and extraction facilities, and NGLs to fractionation
      facilities, petrochemical complexes, underground storage facilities and the
      final customer. Truck and rail account for a smaller amount of the NGLs movement
      transported in Alberta, with pipelines serving as the main mode of
      transport.




**NGL
          Storage**
  Storage
          assets offer a number of key strategic advantages, which include:
          (i) providing the necessary buffer between production of NGLs (which varies
          daily depending on gas flows and composition) and
  Large
        NGL
        storage facilities in Alberta are located in the Fort Saskatchewan / Redwater
        area. Such facilities use salt caverns deep underground which are created
        by
        washing the salt away with water until an open space is made.


-30-
 TABLE
            OF CONTENTS




**NGL
      Marketing**




The
      end
      uses for NGLs are abundant and expanding. While NGLs are generally used directly
      as an energy product and also as a feedstock for the petrochemical and crude
      oil
      refining industries, the specific uses for NGLs vary substantially by
      product.




Ethane
      is
      used primarily as feedstock for the petrochemical industry and as a miscible
      flood agent for enhanced oil recovery operations. A significant amount of the
      ethane produced in the western Canadian sedimentary basin is sold through
      long-term contracts for feedstock to Alberta's expanding petrochemical industry.
      The production of ethane provides a secure and stable source of revenue and
      contributes to the long-term economic viability and growth of the NGL
      infrastructure.




Propane,
      which makes up over 65% of propane-plus extracted from major extraction
      facilities, is the most versatile of the NGL products from a marketing
      perspective. Uses for propane include home and commercial heating, crop drying,
      food processing, cooking and motor fuel. Approximately 75% of Canadian propane
      is exported to the US.




Butane,
      which makes up approximately 25% of propane-plus produced in major extraction
      facilities, is used primarily in gasoline blending or in the production of
      Canadian iso-octane. Approximately 25% of Canadian butane is exported to the
      US.




Pentanes-plus,
      which represents less than 10% of propane-plus produced at major extraction
      facilities, is used as a diluent to increase the viscosity of heavy crude oil
      for shipping through pipelines and as a refinery feedstock to make gasolines.
      Virtually all pentanes-plus in Alberta and Saskatchewan are used for this
      purpose.




**Commercial
      Arrangements**




***Extraction***




An
      extraction facility's fees may be based either on a cost-of-service arrangement
      (reimbursement for operating expenses plus a deemed return on capital employed)
      or tied to production. In order to produce NGLs, the owner of the facility
      must
      purchase natural gas (referred to as shrinkage gas) to replace the energy
      removed from the natural gas stream in the form of NGLs as part of the
      extraction process. The cost of the shrinkage make-up gas, which is typically
      tied to a benchmark natural gas price, accounts for approximately 80% of a
      facility's total costs. For the right to extract NGLs from the gas stream,
      extraction facility owners generally pay shippers a premium to the shrinkage
      gas
      price, which effectively amounts to sharing with shippers a portion of the
      value
      that is added through the recovery and sale of NGLs. Other expenses include
      electrical power, labour, maintenance, property taxes, insurance and other
      overhead.




-31-
 TABLE
            OF CONTENTS


For
        ethane, market prices usually consist of a shrinkage gas cost which flows
        through to ethane buyers, and an additional fixed fee to cover plant extraction
        costs. As a result, the ethane operations of an extraction facility generally
        generate a relatively predictable cash flow stream.


However,
      an extraction facility's other revenues are often tied to the market prices
      of
      propane, butane and pentanes-plus. The majority of the facility's costs to
      produce propane-plus are shrinkage gas and therefore the plant's profitability
      is influenced by the relative spread between natural gas prices and NGL product
      prices, often referred to as the "frac spread". The impact on margins can be
      significant when changes in the prices of NGLs and natural gas occur at
      different rates or move in different directions.




Generally,
      the commercial structure of the propane-plus business at extraction plants
      offers greater leverage to a favourable shift in commodity prices than the
      ethane business. Since the prices of propane, butane and pentanes-plus are
      set
      in the open market and are linked to the price of oil, and the costs of these
      products are primarily tied to the cost of natural gas, the profitability of
      a
      propane-plus producer is driven by the relative spread between these two
      commodities. Favourable movements in the spread between these prices offer
      substantial upside to a propane-plus producer. Most extraction facilities have
      profit sharing arrangements for propane-plus with exposure to both price and
      volume. Certain facilities have the frac spread exposure shifted onto buyers
      of
      propane-plus through the use of cost-of-service agreements.




***Fractionation***




While
      fluctuations in the frac spread are of particular importance in determining
      the
      profitability of most extraction plants, the financial performance of
      fractionation facilities is not frac spread dependent. A fractionation facility
      provides a package of services, which may include transportation of the NGL
      mix
      to the facility; fractionation of an incoming ethane-plus or propane-plus
      mixture into specification ethane, propane, butane and pentanes-plus; storage
      of
      NGLs at the facility; distribution and terminalling of the specification
      products; and marketing of the products. The facility receives a fee for these
      services which varies depending upon the complexity of the services provided.
      The expense side of the equation includes operating costs associated with
      gathering, transporting, fractionating, storing and distributing the NGL mix.
      Hence, profit is earned not on the spread differential between natural gas
      and
      NGLs, but on the difference between the fees charged and the costs incurred
      for
      the service provided. Alternatively, the owner of a fractionator may purchase
      NGL streams in the field for its own account, transport and process the stream,
      then sell the resulting products in the Edmonton or downstream market. In this
      case, its profit will be the difference between the sales prices it receives
      and
      the sum of its purchase price for the NGL stream and its costs of production
      (transportation, fractionation, storage).




**Midstream
      services and marketing assets**




***Midstream
      NGL Acquisition***




On
      December 13, 2005 Provident completed the Midstream NGL Acquisition and acquired
      the Midstream NGL Business.




***The
      Assets***




The
      Midstream NGL Business unit extracts, processes, stores, transports and markets
      NGLs. This is accomplished within two integrated systems and complementary
      assets. The Redwater system is comprised of three core assets:




·
            100%
                ownership of the Redwater NGL fractionation facility, a 65,000 barrels
                per
                day (bbl/d) fractionation, storage and transportation facility that
                includes 12 pipeline receipt and delivery points, railcar loading
                facilities with direct access to rail facilities, two propane truck
                loading facilities, and six million gross barrels of salt cavern
                storage.
                The facility can process high-sulphur NGL streams and is one of only
                two
                facilities in western Canada capable of extracting ethane from the
                natural
                gas liquids stream.




-32-
 TABLE
          OF CONTENTS


·
            43.3%
                ownership of the 38,500 bbl/d Younger NGL extraction plant located
                at
                Taylor in north eastern British Columbia that supplies 16,700 bbl/d
                of net
                NGLs for processing at Redwater.




·
            100%
                ownership of the 565 kilometer proprietary Liquids Gathering System
                ("LGS") that runs along the Alberta-British Columbia border providing
                access to a highly active basin for liquids-rich natural gas exploration
                and exploitation. Provident also has long-term shipping rights on
                the
                Pembina Peace Pipeline that extends the product delivery transportation
                network through to the Redwater fractionation
                facility.




The
      recently acquired Empress/Sarnia system is comprised of 5 core
      assets:




·
            Approximately
                2.0 bcf/d of extraction capacity at Empress Alberta. This is the
                combination of 60% ownership of the 1.2 bcf/d capacity Provident
                Empress
                NGL Extraction plant, 12.4% ownership in the 1.1 bcf/d capacity ATCO
                Plant, 8.3% ownership in the 2.4 bcf/d capacity Duke Plant and 33.0%
                ownership in the 2.7 bcf/d capacity BP Empress 1
                Plant.




·
            100%
                ownership of a 50,000 bbl/d debutanizer at Empress,
                Alberta.




·
            50%
                ownership in the 130,000 bbl/d Kerrobert Pipeline and 2.5 mmbbl
                underground storage facility near Kerrobert, Saskatchewan which
                facilitates injection into the Enbridge Pipeline System. Along the
                Enbridge Pipeline System, Provident holds 18.3 % ownership of 300,000
                bbls
                of Superior Storage staging facility and 18.3 % ownership of the
                6,600
                bbl/d Superior Depropanizer.




·
            In
                Sarnia, Ontario, 10.3% ownership of an approximately 150,000 bbl/d
                fractionator, 1.7 mmbbl of raw product storage capacity and 18% of
                5.0
                mmbbl of finished product storage and rail, truck and pipeline
                terminalling.




·
            49%
                interest in a partnership which owns the 6.9 mmbbl Marysville Underground
                Storage Terminal.




In
      addition, the Midstream NGL Acquisition included the acquisition by Provident
      of
      100% ownership in the NGL marketing group Kinetic, which operates a fleet of
      approximately 700 rail cars and a propane distribution terminal at Lynchburg,
      Virginia.




**Midstream
      and marketing services**




Provident's
      midstream services offer customers several types of services and contractual
      arrangements, which include:




***Fee
      for service processing*** :
      In
      these arrangements, NGL owners (typically natural gas producers) deliver their
      NGLs to Provident and pay fees for the transportation, fractionation, short
      term
      storage and distribution of their NGL barrels. The NGL owner is responsible
      for
      marketing their product.




***Marketing
      Services*** :
      This
      service involves NGL owners delivering their product to Provident, with
      Provident taking title to the product. Provident pays the NGL owner an amount
      that is a delivery price of raw NGLs which is discounted to postings. The
      discounted purchase price that Provident pays for the product covers the costs
      of transportation, fractionation, storage, and marketing of the
      NGLs.




***Storage*** :
      NGL
      owners pay fees to Provident to store their NGLs.




-33-
 TABLE
          OF CONTENTS




***Transport
      and Distribution*** :
      NGL
      owners or purchasers pay fees to transport NGLs through the LGS pipeline and
      use
      rail and truck loading facilities at Redwater, Sarnia, Marysville and
      Lynchburg.




***The
      Contracts***




At
      the
      Redwater facility, approximately 75% of the available capacity is contracted
      through fee-for-service or fixed margin arrangements with major oil and natural
      gas producers and petrochemical businesses. As a result of these contracts,
      approximately 68% of Redwater's system capacity is contracted for 10 years
      or
      longer.




As
      with
      most Alberta straddle plants, all ethane produced from Provident's collective
      Empress interests is sold under long term contracts.




***Plant
      Capacities and Throughput***




The
      Redwater facility (100% ownership) was constructed between 1996 and 1998. It
      is
      the most modern facility of its type in Canada and is currently designed for
      throughput capacity of 65,000 bpd of NGLs with an expectation to average
      approximately 63,000 bpd.




The
      Provident Empress plant (60% ownership) was commissioned in September 1996
      and
      subsequently expanded in 1999 and 2003. It is one of the newest and most cost
      efficient facilities at Empress. The plant has a design capacity of 1.2 bcf/d
      to
      extract ethane and propane-plus.




The
      BP
      Empress 1 plant (33% ownership) base plant was commissioned in 1971 with
      expansions commissioned in 1994 and 2005. The base plant has a capacity of
      1.7
      bcf/d to extract ethane and propane-plus. The 1994 train addition has 1 bcf/d
      capacity to extract propane-plus.




The
      Duke
      plant (8.3% ownership) was commissioned in 1964. It has a capacity of 2.4 bcf/d
      and has the following unique aspects (1) an airstrip; (2) treatment for ethane
      to remove CO 2 ;
      (3) a
      Ferus CO 2 plant
      hosted on a shared operating cost basis; (4) the only plant at the Empress
      Complex with full ethane-plus fractionation facilities; and (5) the ability
      to
      dispatch products by truck, rail, the IPF Jenner Pipeline, the Kerrobert
      Pipeline, and the PTC Pipeline.




The
      ATCO
      Plant (12.4% ownership) was commissioned in 1982, and expanded in 1999, and
      has
      an extraction capacity of 1.1 bcf/d.




The
      Provident Debutanizer (100% ownership) was commissioned at the end of 2005.
      It
      has a design capacity of 50,000 bbl/d of propane-plus and will remove condensate
      currently delivered to the Kerrobert Pipeline.




The
      Kerrobert Pipeline (50% ownership) is an NEB regulated pipeline constructed
      in
      1971 to deliver propane-plus product from the Empress Comples to Kerrobert
      Storage near Kerrobert, Saskatchewan. It has a capacity of 130,000 bbl/d.
      Kerrobert Storage was also developed in 1971 and has a design capacity of 2.5
      mmbbls.




Superior
      Storage (18.3% ownership) has a design capacity of 300,000 bbls and was built
      to
      accommodate the change in shipping rates within the Enbridge Pipeline
      system.




The
      Superior Depropanizer was built in 1991 and is designed to process approximately
      10,000 bbl/d of propane-plus and extract 6,600 bbl/d of propane.




Sarnia
      Fractionation (10.3% ownership) began operations in 1970. It has an average
      capacity of approximately 150,000 bbl/d.




Provident
      had a 49% partnership interest in the Marysville Partnership which owns the
      Marysville Underground Storage Terminal. This interest was sold in February
      2006
      for US $12.5 million.




**MARKET
        FOR SECURITIES**
  The
        outstanding Trust Units of the Trust are listed and posted for trading on
        the
        TSX under the symbol PVE.UN and the NYSE under the symbol PVX.


-34-
 TABLE
            OF CONTENTS





The
      Trust
      Units were previously listed on the AMEX prior to December 16, 2005, at which
      time the Trust Units began trading on the NYSE. The 8.75% Debentures, 8%
      Debentures, Initial 6.5% Debentures and Supplemental 6.5% Debentures of the
      Trust are listed and posted for trading on the TSX under the symbol PVE.DB.A,
      PVE.DB.B, PVE.DB.C and PVE.DB.D, respectively.




The
      following table summarizes the Trust Unit and debenture trading activity for
      the
      periods indicated on both the Toronto Stock Exchange and the American Stock
      Exchange, as applicable.




**Toronto
      Stock Exchange**




***Trust
      Units***




**Period**
            **High**
            **Low**
            **Volume
                (000's)****2005**January
            11.82
            11.17
            5,795February
            12.60
            11.90
            10,143March
            12.49
            11.60
            10,185April
            12.44
            11.82
            5,428May
            12.65
            12.19
            6,746June
            13.05
            12.40
            3,777July
            13.87
            12.91
            4,877August
            14.40
            13.05
            6,997September
            14.19
            13.68
            4,342October
            14.42
            12.79
            7,538November
            12.98
            12.29
            9,155December
            13.45
            12.55
            14,092


***8.75%
      Debentures***




**Period**
            **High**
            **Low**
            **Volume****2005**January
            110.00
            107.75
            12,830February
            114.00
            109.56
            33,090March
            113.00
            106.01
            22,310April
            113.27
            107.29
            16,920May
            113.50
            110.27
            48,030June
            117.50
            110.28
            23.890July
            125.19
            112.52
            104,805August
            129.25
            118.00
            22,920September
            128.54
            116.00
            18,340October
            130.41
            115.12
            19,810November
            118.14
            110.29
            5,890December
            122.00
            114.43
            3,750


***8%
      Debentures***




**Period**
            **High**
            **Low**
            **Volume****2005**January
            110.25
            105.25
            10,460February
            110.00
            105.52
            117,600March
            109.59
            104.50
            23,380April
            110.75
            105.03
            14,130May
            110.00
            103.50
            10,010June
            108.02
            105.50
            6,590July
            115.00
            108.50
            14,030August
            119.50
            107.90
            16,680September
            120.99
            111.00
            17,830October
            121.00
            102.02
            23,090November
            110.83
            105.50
            1,670December
            114.86
            105.03
            4,660


***Initial
      6.5% Debentures***




-35-
 TABLE
          OF CONTENTS


**Period**
            **High**
            **Low**
            **Volume****2005**March
            100.99
            99.00
            727,875April
            100.69
            99.50
            82,010May
            100.50
            99.00
            64,065June
            100.50
            99.00
            123,720July
            104.00
            100.00
            95,645August
            110.00
            102.56
            39,540September
            106.75
            102.96
            116,340October
            106.75
            100.00
            44,110November
            102.99
            100.50
            39,500December
            105.49
            102.01
            19,190


**Note:**


(1)  The
      Initial 6.5% Debentures began trading on the TSX on March 1,
      2005.




***Supplemental
      6.5% Debentures*** ****




**Period**
            **High**
            **Low**
            **Volume****2005**November(1)
            100.00
            99.00
            267,260December
            101.97
            99.50
            171,900


**Note:**


(1)  The
      Supplemental 6.5% Debentures began trading on the TSX on November 15,
      2005.




**American
      Stock Exchange/New York Stock Exchange**




***Trust
      Units***




**Period**
            **High**
            **Low**
            **Volume
                (000's)****2005**January
            9.63
            9.15
            15,550February
            10.24
            9.64
            20,644March
            10.40
            9.52
            28,079April
            10.09
            9.48
            17,143May
            10.18
            9.74
            14,017June
            10.55
            9.98
            15,388July
            11.35
            10.65
            13,549August
            11.99
            10.70
            24,946September
            12.19
            11.53
            15,512October
            12.38
            10.84
            24,585November
            11.10
            10.37
            19,111December(1)
            11.69
            10.70
            10,866


**Note:**


(1)  The
      Trust
      Units ceased trading on the AMEX and began trading on the NYSE on
      December 16, 2005.




**RECORD
      OF CASH DISTRIBUTIONS**




The
      following table sets forth the per Trust Unit amount of monthly cash
      distributions paid by the Trust since its inception.




-36-
 TABLE
          OF CONTENTS


**Distribution
                Amount**
              **(Cdn$)**
            
            **Distribution
                Amount**
              **(US$)****(1)****2001**
              March
                - December
            
            $
            2.54
            
            $
            1.64**2002**
              January
                - December
            
            $
            2.03
            
            $
            1.29**2003**
              January
                - December
            
            $
            2.06
            
            $
            1.47**2004**January
                - December
            
            $
            1.44
            
            $
            1.10**2005**January
                - December
            
            $
            1.44
            
            $
            1.20**2006**January
            
            $
            0.12
            
            $
            0.10February
            
            $
            0.12
            
            $
            0.10March
            
            $
            0.12
            
            $
            0.10**Total
                to date for 2006**
            
            $
            0.36
            
            $
            0.30





Since
      its
      inception, the Trust has paid an aggregate of $9.87 (US$7.00) in cash
      distributions to Unitholders.




**Note:**


(1)  The
      exchange rate is based on the Bank of Canada noon rate on the payment
      date.




**DIRECTORS
      AND OFFICERS**




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 above 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 below:




**Name
                and Background**
            **Number
                of Trust Units**
              **Beneficially
                Owned**
              **or
                Controlled****G.D.
                Billing**(2)of
                Calgary, Alberta is the Executive Chairman and a director of Superior
                Plus
                Inc., since 1998. He has been a director of Provident since 2001.
                Prior
                thereto he was President and Chief Executive Officer of Norcen Energy
                Ltd.
                an oil and gas exploration and production company, from 1994 to 1998.
                He
                is also a director of Capitol Energy Resources Ltd.
            65,740(5)**Thomas
                W. Buchanan**of
                Calgary, Alberta has been the Chief Executive Officer and a director
                of
                Provident since March 2001. Prior thereto he was Executive Vice President
                Corporate Development and Chief Financial Officer of Founders Energy
                Ltd.
                from October 1999 to March 2001. Prior thereto he was President and
                Chief
                Executive Officer of Founders Energy Ltd. from 1996 to October 1999.
                He is
                also a director of Churchill Energy Inc. and Hawk Energy
                Corp.
            966,793(4)(5)




-37-
 TABLE
          OF CONTENTS




**Randall
                J. Findlay**of
                DeWinton, Alberta has been the President and a director of Provident
                since
                March 2001. Prior thereto he was Executive Vice President and Chief
                Operating Officer of Founders Energy Ltd. from December 1999 to March
                2001. Prior thereto Senior Vice President of TransCanada Pipelines
                Ltd., a
                pipeline company, and President and Chief Executive Officer of TransCanada
                Gas Processing L.P., a gas processing partnership, from June 1998
                to
                August 1999. He is also a director of Canadian Helicopters Income
                Fund and
                TransAlta Power LP.
            932,188(4)**Mr.
                Hugh A. Fergusson**(1),
                (3)of
                Calgary, Alberta is the former Vice President and Director with Dow
                Chemical Canada Inc. He has been a director of Provident since 2005
                and is
                also a director of Canexus Income Fund and Taylor NGL Limited
                Partnership.
            5,000(5)**Norman
                R. Gish**(2)of
                Calgary, Alberta is the President, Gish Consulting Inc., energy
                consultants. Prior thereto he was Chairman, President and Chief Executive
                Officer of Alliance Pipeline Ltd. and Aux Sable Liquid Products Inc.
                He
                has been a director of Provident since 2003 and is also a director
                of
                Falconbridge Limited, Railpower Technologies Corp. and Superior Plus
                Inc.
            7,000**Bruce
                R. Libin**(1),
                (3)of
                Calgary, Alberta is the Chairman and Executive Chairman and Chief
                Executive Officer of Destiny Resource Services Corp., a resource
                services
                company, since 1997 and December 2000, respectively. He has also
                been
                President of B.R. Libin Capital Corp., an investment, merchant banking
                and
                investment banking advisory services company since 1995. He has been
                a
                director of Provident since 2001 and is also a director of Winstar
                Resources Ltd.
            97,403**Dr.
                Robert Mitchell**(3)of
                Calgary, Alberta has been an independent businessman since September
                2003.
                From 1984 to September 2003, he was Executive Vice President of Talisman
                Energy Inc. He has been a director of Provident since 2004 and is
                also a
                director of Winstar Resources Ltd.
            6,000**Byron
                J. Seaman**(3)of
                Calgary, Alberta is an independent businessman and private investor.
                He
                has been a director of Provident since 2001 and is also a director
                of
                Rider Resources Ltd.
            35,068**M.H.
                (Mike) Shaikh**(1)of
                Calgary, Alberta is the President of M.H. Shaikh Professional Corporation
                (Chartered Accountants). He has been a director of Provident since
                2001
                and is also a director of Churchill Energy Inc. and Mystique Energy
                Inc.
                and is an officer of Hawk Energy Corp.
            57,634**Jeffrey
                T. Smith**(2),
                (3)of
                Calgary, Alberta is an independent businessman and private investor.
                He
                has been a director of Provident since 2001 and is also a director
                of
                Compton Petroleum Ltd. and Cordero Energy Inc.
            4,900**John
                B. Zaozirny**(2)of
                Calgary, Alberta is counsel to the law firm of McCarthy
                Tétraultllpand Vice-Chairman of Canaccord Capital Corporation. He has been a
                director
                of Provident since 2001 and is also a director of Bankers Petroleum
                Ltd.,
                Canadian Oil Sands Trust, Candax Inc., Computer Modelling Group Ltd.,
                Fording Canadian Coal Trust, High Arctic Energy Services Trust, IPSCO
                Inc., Pengrowth Energy Trust, Petroworld Corp. and TerraVest Income
                Fund.
            53,339


**Notes:**


(1)  Member
      of
      the Audit Committee.


(2)  Member
      of
      the Governance, Human Resources and Compensation Committee.


(3)  Member
      of
      the Reserves, Operations and Environment, Health and Safety
      Committee.


(4)  Includes
      Trust Units issuable upon exchange of exchangeable shares of Provident held
      by
      such director at an exchange ratio of 1.55261.


(5)  Mr.
      Billing also holds $500,000 principal amount of the Initial 6.50% Debentures.
      Mr. Buchanan also holds $100,000 of the Supplemental 6.50% Debentures. Mr.
      Fergusson also holds $100,000 of the Supplemental 6.50% Debentures.
      Mr. Shaikh also holds $250,000 principal amount of the
      Supplemental **** 6.50%
      Debentures. Mr. Gish also holds $20,000 principal amount of the 8.75% Debentures
      and also holds $50,000 principal amount of the Supplemental 6.50%
      Debentures.




-38-
 TABLE
            OF CONTENTS





**Murray
      Buchanan**




Co-President,
      NGL Services




Mr.
      Buchanan received his masters of business administration from Queen's
      University, as well as an honours bachelor of administration degree from Queen's
      University. Mr. Buchanan is responsible for commercial activities associated
      with Provident's midstream services business unit including natural gas liquids
      fractionation, storage, processing, marketing and transportation services.
      Murray joined Provident in 2005 following Provident's acquisition of the Empress
      midstream assets. He has over 25 years of NGL marketing and petroleum industry
      experience and had been president of Kinetic Resources for eight
      years.




***Andrew
      Gruszecki***




Co-President,
      NGL Services




Mr. Gruszecki
      received his honours bachelor of science in science from the University of
      Western Ontario and did his co-op master's of business administration at
      McMaster University and joined Provident in 2003. He brings over 25 years of
      experience and expertise in oil and NGL marketing, business development, and
      planning. From 2000 to 2003, he was senior manager of commercial operations
      at
      Williams Energy (Canada). Prior to joining Williams, Mr. Gruszecki was vice
      president of NGL Marketing for Coast Energy Canada. From 1997 to 1998, he was
      director of commercial operations at TransCanada Midstream and the former
      Novagas Canada. While at Novagas, Mr. Gruszecki oversaw commercial issues
      related to the planning, construction and implementation of the NGL business
      which included the construction of the Redwater fractionation facilities.
      Mr. Gruszecki began his career in the energy business in 1981 and held
      positions of increasing responsibility before joining Novagas in
      1997.




***David
      Holm***




Executive
      Vice President, Strategy, Finance and Business Development and Corporate
      Secretary




Mr.
      Holm
      received his Bachelor of Commerce Degree from the University of Alberta and
      his
      Bachelor of Laws Degree from the University of Western Ontario. He was called
      to
      the Alberta Bar in 1986. Mr. Holm has spent the last six years in investment
      banking and most recently was Managing Director, North American Energy with
      TD
      Securities Inc. Prior to his move into investment banking, Mr. Holm practiced
      securities law for 15 years, most recently as a partner with Macleod Dixon
      LLP .




***Gary
      Kline***




Senior
      Vice President, Commercial Development and Risk Management




Mr. Kline
      received his bachelor of arts in economics from the University of Calgary.
      He
      later received his Canadian Securities Certificate from the Canadian Securities
      Institute. Mr. Kline has over 20 years of experience in the energy industry
      and before joining Provident in 2003, he was president of GRK Energy Consulting
      from 1998 to 2003. Mr. Kline has held a number of senior management
      positions including managing director of marketing and business development
      for
      Reliant Energy Canada from 1998 to 2002, vice president for natural gas and
      electricity at U.S. Generating Canada from 1996 to 1998, and manager of gas
      marketing at CanStates Gas Marketing from 1986 to 1996 Gary began his energy
      industry career as a regulatory analyst at TransCanada Pipelines in
      1982.




***Daniel
      J. O'Byrne***




Executive
      Vice President, Operations and Chief Operating Officer




Mr.
      O'Byrne received his Bachelor of Science Degree in Petroleum Engineering from
      the University of Alberta and a Masters of Business Administration Degree from
      the University of Western Ontario. Mr.







-39-
 TABLE
            OF CONTENTS





O'Byrne
      has over 25 years of diverse experience in the international and North American
      oil industry and has participated in major projects in Canada, the United
      Kingdom (North Sea), the Middle East, West Africa and other countries. His
      positions have included Division Vice President, Technical Services for Nexen
      Inc. (2001-2005); Vice President, Technical Services for Canadian
      Occidental/Westcana Energy Inc. (1998-2001); and Vice President,
      Operations-Yemen for Canadian Occidental Petroleum Ltd. (1997-1998); as well
      as
      numerous other management position with Canadian Occidental Petroleum Ltd.
      He is
      also a director of the Petroleum Technology Research Centre, a director of
      White
      Max Energy Ltd., and a past chair of the Canadian Oil Sands Network for Research
      and Development. He has contributed to the reserves and safety committees of
      the
      Canadian Associate of Petroleum Producers, is a member of the Association of
      Professional Engineers, Geologists and Geophysicists of Alberta and is one
      of
      the Society of Petroleum Engineers published authors.




***Cameron
      Vouri***




President,
      Canadian Oil and Gas Production Business Unit




Mr. Vouri
      obtained a Bachelor of Science (Petroleum Engineering) degree from New Mexico
      Institute of Mining and Technology in 1988. Prior to Mr. Vouri's appointment
      to
      his current position with Provident, he was Vice President and Chief Operating
      Officer of Provident since January 2003. Prior thereto he held the position
      of
      Vice President with Provident. Mr. Vouri held various senior management
      positions with Koch Exploration Canada, Ltd. from 1989 to 2000.




***Mark
      N. Walker***




Senior
      Vice President, Finance and Chief Financial Officer




Mark
      Walker is Senior Vice President of Finance and Chief Financial Officer of
      Provident. A member of Provident's senior leadership team, Mr. Walker is
      responsible for all finance, financial reporting, treasury, and compliance
      activities. Prior to the appointment to his current position, Mr. Walker
      served as controller and CFO from 1997 to 2002. Mr. Walker joined
      Provident's predecessor Founders in 1996 as controller.




Mr. Walker
      has over 19 years of experience in petroleum finance and accounting. Prior
      to
      joining Founders, Mr. Walker was team leader of financial reporting for
      Sceptre Resources, first joining that company in 1990. From 1988 to 1990,
      Mr. Walker was a revenue accountant with Dome Petroleum. Before Dome,
      Mr. Walker was an accountant with Hudson & Company from 1985 to
      1988.




Mr. Walker
      received his bachelor of commerce in Accounting from the University of Calgary
      and later received his Certified Management Accountant designation.




**Committees
      of the Board**




During
      the year ended December 31, 2005, the Board of Directors had three committees
      -
      the Audit Committee, the Reserves, Operations and Environmental, Health and
      Safety Committee, and the Governance, Human Resources and Compensation
      Committee. In addition, the Trust has established one additional committee
      in
      2006 - the Disclosure Committee, which is comprised entirely of members of
      management. Membership in each committee is set forth below.




***Audit
      Committee***




The
      Audit
      Committee consists of Mr. M.H. (Mike) Shaikh (Chairman), Mr. Bruce R. Libin
      and
      Mr. Hugh A. Fergusson. All members of the Audit Committee are independent and
      financially literate, as determined by applicable securities legislation, and
      at
      least one member of the Committee is an "audit committee financial expert"
      as
      required by U.S. securities laws. The Audit Committee reviews the Trust's
      interim unaudited consolidated financial statements and annual audited
      consolidated financial statements




-40-
 TABLE
            OF CONTENTS





and
      certain corporate disclosure documents including management's discussion and
      analysis and annual and interim earnings press releases before they are approved
      by the board of directors. The Committee also reviews and makes a recommendation
      to the board of directors in respect of the appointment and compensation of
      the
      external auditor and it monitors accounting, financial reporting, control and
      audit functions. The Audit Committee meets to discuss and review the audit
      plans
      of external auditors and is directly responsible for overseeing the work of
      the
      external auditor with respect to preparing or issuing the auditor's report
      or
      the performance of other audit, review or attest services, including the
      resolution of disagreements between management and the external auditor
      regarding financial reporting. The Committee questions the external auditor
      independently of management and reviews a written statement of its independence
      based on the criteria found in the recommendations of the Canadian Institute
      of
      Chartered Accountants. The Committee must be satisfied that adequate procedures
      are in place for the review of the Trust's public disclosure of financial
      information extracted or derived from its financial statements and it
      periodically assesses the adequacy of those procedures. The Audit Committee
      also
      must approve or pre-approve, as applicable, any non-audit services to be
      provided to the Trust by the external auditor. In addition, it reviews and
      reports to the board of directors on the Trust's risk management policies and
      procedures and reviews the internal control procedures to determine their
      effectiveness and to ensure compliance with the Trust's policies and avoidance
      of conflicts of interest. In conjunction with the Trust's whistleblower policy,
      the Committee has established procedures for dealing with complaints or
      confidential submissions which come to its attention with respect to accounting,
      internal accounting controls or auditing matters. See "Audit Committee
      Information" and Schedule A of this Annual Information Form for additional
      information relating to the Audit Committee.




***Governance,
      Human Resources and Compensation Committee***




The
      Governance, Human Resources and Compensation Committee consists of Mr. Jeffrey
      T. Smith (Chairman), Mr. Grant D. Billing, Mr. Norman R. Gish and Mr. John
      B.
      Zaozirny, all of whom are considered independent directors within the meaning
      of
      applicable securities legislation. The Committee is responsible for recommending
      to the board of directors suitable candidates for director positions. The
      selection assessment includes a wide array of factors deemed appropriate, all
      in
      the 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 matters and in assessing the functioning
      and
      effectiveness of the Board.




The
      Governance, Human Resources and Compensation Committee's mandate also includes
      reviewing Provident's human resources policies and procedures and compensation
      and incentive programs. The Committee is responsible for assessing senior
      management's performance and recommending senior management compensation to
      the
      board of directors. 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 incentive plans of the Trust and makes
      recommendations to the board of directors respecting grants of awards
      thereunder.




***Reserves,
      Operations, Environment, Health and Safety Committee***




The
      Reserves, Operations and Environmental, Health and Safety Committee consists
      of
      Mr. Jeffrey T. Smith (Chairman), Dr. Robert Mitchell, Mr. Bruce R. Libin, Mr.
      Byron J. Seaman and Mr. Hugh A. Fergusson, all of whom are considered
      independent directors within the meaning of applicable securities legislation.
      The Committee assists the board in its oversight of the oil and natural gas
      reserves evaluation process and the public disclosure of reserves data and
      related information as required by National Instrument 51-101; the operations
      of
      Provident, including operating activities, operating expenses and capital
      expenditure budget; and the environmental, health and safety issues, including
      the evaluation of Provident's programs, controls and reporting systems, and
      compliance with applicable laws, rules and regulations.




-41-
 TABLE
            OF CONTENTS





***Disclosure
      Committee***




The
      Disclosure Committee is comprised of the Chief Executive Officer, President,
      the
      Executive Vice President, Operations and Chief Operating Officer, the Executive
      Vice President, Finance and Strategy and Corporate Secretary, the Senior Vice
      President, Finance and Chief Financial Officer, the Co- Presidents, Midstream
      Business Unit, the Senior Vice President, Commercial Development and Risk
      Management, the President, Canadian Oil and Gas Production Business Unit, the
      Corporate Controller, the Senior Manager, Investor Relations and Communications
      and the Assistant Corporate Secretary of Provident. The Disclosure Committee's
      primary responsibilities are to oversee the Trust's disclosure practices and
      to
      ensure the Trust meets all Canadian and U.S. regulatory disclosure requirements.
      In particular, the Disclosure Committee will review and, as necessary, help
      revise the Trust's controls and other procedures to ensure that information
      required to be disclosed to securities regulators and the Toronto Stock Exchange
      and New York Stock Exchange, and other information the Trust will disclose
      to
      the public is recorded, processed, summarized and reported accurately and on
      a
      timely basis. In addition, the Committee will determine when events,
      developments, changes or other facts constitute material information or a
      material change in the affairs of Provident and will review and supervise the
      preparation of the Trust's (i) Annual Information Form, Information
      Circular, annual and interim financial statements and any other information
      filed with the Canadian and U.S. securities regulators; (ii) press releases
      containing financial information, earnings guidance, forward looking statements,
      information about operations, or any other information material to the Trust's
      security holders; (iii) correspondence broadly disseminated to
      shareholders; and (iv) other relevant written and oral communications or
      presentations.




The
      Committee will also review risk factors, underlying assumptions and forward
      looking statement language for written and oral communications which contain
      forward looking information and review that there is a reasonable basis for
      any
      conclusions, forecasts or projections contained in such
      information.




**Conflicts
      of Interest**




The
      directors and officers of Provident are engaged in and will continue to engage
      in other activities in the oil and natural gas industry and, as a result of
      these and other activities, the directors and officers of Provident may become
      subject to conflicts of interest. 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, such conflicts will be resolved in accordance with the
      provisions of the ABCA.




As
      at the
      date hereof, Provident is not aware of any existing or potential material
      conflicts of interest between Provident and a director or officer of
      Provident.




**AUDIT
      COMMITTEE INFORMATION**




**Composition
      of the Audit Committee**




The
      Audit
      Committee consists of three members, all of whom are independent and financially
      literate, as defined by Multilateral Instrument 52-110 *Audit
      Committees* .




**Audit
      Committee Charter**




The
      full
      text of the Trust's Audit Committee Charter is set forth in Schedule A of
      this Annual Information Form.


**Relevant
        Education and Experience of Each Audit Committee Member**
  The
        following table sets out the relevant education and experience of each of
        the
        members of the Audit Committee:




-42-
 TABLE
            OF CONTENTS




**Name**
            **Independent**
            **Financially**
              **Literate**
            **Relevant
                Education and Experience**M.H.
                (Mike) Shaikh
            Yes
            Yes
            Mr.
                Shaikh holds the degree of Bachelor of Commerce and is a Chartered
                Accountant. As a Chartered Accountant, Mr. Shaikh attained experience
                in
                preparing, auditing, analyzing and evaluating financial statements.
                Mr.
                Shaikh has an understanding of the accounting principles used by
                Provident
                as well as the implications of those accounting principles on Provident's
                financial results. Mr. Shaikh has also obtained significant financial
                experience and exposure to accounting and financial issues as the
                President of M.H. Shaikh Professional Corporation and in his role
                as a
                director and audit committee member of various public companies.
                He was
                also a board member of the Alberta Securities Commission from 2003
                to
                2006.Bruce
                R. Libin, Q.C.
            Yes
            Yes
            Mr.
                Libin holds the degree of Bachelor of Commerce (Honours), Master
                of
                Business Administration and Juris Doctoris. Mr. Libin has obtained
                significant financial experience and exposure to accounting, disclosure,
                internal controls and financial issues during his legal practice,
                his
                business experience (including as Chief Executive Officer of Beau
                Canada
                Exploration Ltd. and as Executive Chairman and Chief Executive Officer
                of
                Destiny Resource Services Corp.) and his service on the audit committee
                of
                several boards of directors, including Amoco Canada Petroleum Company
                Limited, Maxx Petroleum Ltd., Mark's Work Warehouse Ltd., Calgary
                Health
                Region, Southern Alberta Institute to Technology, NQL Drilling Tools
                Ltd.,
                and Winstar Resources Ltd.Hugh
                A. Fergusson
            Yes
            Yes
            Mr.
                Fergusson holds the degrees of Bachelor of Arts and Bachelor of Laws.
                He
                has also completed Advanced Management Programs at the University
                of
                Western Ontario and Northwestern University. He is an independent
                businessman and Corporate Director. Mr. Fergusson practiced law for
                five
                years following which he was employed by the Dow Chemical Company
                (and
                related companies) for 27 years until he retired in 2004. During
                his
                career with Dow, Mr. Fergusson obtained significant financial experience
                and exposure to accounting and financial issues through a series
                of roles
                including commercial and business leadership largely related to
                hydrocarbons and energy. In addition to being a director of a number
                of
                Dow subsidiaries, Mr. Fergusson was Chairman of Petromont Inc. from
                2002
                until 2004 and a member of its Audit Committee from 2002 until
                2004.





**External
        Auditor Service Fees**
  The
        following table sets forth information about the fees billed to the Trust
        for
        professional services provided by PricewaterhouseCoopers LLP during fiscal
        2005
        and 2004:





-43-
 TABLE
            OF CONTENTS




*(CDN$)*
            
            **2005**
            
            **2004**Audit
                Fees
            
            $
            929,000
            
            $
            868,000Audit-Related
                Fees
            
            
            30,000
            
            
            90,750Tax
                Fees
            
            
            776,300
            
            
            375,000All
                Other Fees
            
            
            -
            
            
            -Total
            
            $
            1,735,300
            
            $
            1,333,750





**INFORMATION
      CONCERNING THE OIL AND GAS
      INDUSTRY**




**Canadian
      Government Regulation**




The
      oil
      and natural gas industry is subject to extensive controls and regulations,
      imposed by various levels of government. Outlined below are some of the more
      significant aspects of the relevant legislation and regulations. It is not
      expected that any of such controls and regulations will affect the operations
      of
      Provident in a manner materially different than they will affect other oil
      and
      gas companies of similar size.




**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. Such 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 licence and Governor in Council
      approval.




**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 licence
      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.




**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




-44-
 TABLE
            OF CONTENTS





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.




**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.




**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 percent for prices
      at
      or below the royalty tax credit reference price of $100 per m 3 decreasing to 25 percent 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.




**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




-45-
 TABLE
            OF CONTENTS





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.




**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.




**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
      natural gas midstream, NGL processing and marketing business and the oil and
      natural gas properties. Accordingly, the Trust is dependent upon the ability
      of
      Provident to meet its interest and principal repayment obligations under the
      notes which the Trust may issue from time to time and to pay royalties.
      Provident's income will be received from the cash flow generated from the
      natural gas midstream, NGL processing and marketing business and from the
      production of oil and natural gas from Provident's existing resource properties
      and will be susceptible to the risks and uncertainties associated with the
      oil
      and natural gas industry and the NGL processing business generally. If the
      oil
      and natural gas reserves associated with Provident's 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 herein and, in particular, the following risk
      factors:




**Oil
      and Gas Production Risk Factors**




***Exploitation
      and Development***




Exploitation
      and development risks are due to the uncertain results of searching for and
      producing oil and natural gas using imperfect scientific methods. These risks
      are mitigated by using experienced staff, focusing exploitation efforts in
      areas
      in which Provident has existing knowledge and expertise or access to such
      expertise, using up-to-date technology to enhance methods and controlling costs
      to maximize returns. Advanced oil and natural gas related technologies such
      as
      three dimensional seismography, reservoir simulation studies and horizontal
      drilling have been used by Provident and will be used by Provident to improve
      its ability to find, develop and produce oil and natural gas.




***Operations***




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
      will have both safety and environmental policies in place to protect its
      operators and employees, as well as to meet the regulatory requirements in
      those
      areas where it operates. In addition, Provident will have liability insurance
      policies in place, in such amounts as it considers adequate, however, it will
      not be fully insured against all of these risks, nor are all such risks
      insurable.




-46-
 TABLE
            OF CONTENTS




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 these 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. Although satisfactory title reviews
      are generally conducted in accordance with industry standards, 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.




***Oil
      and Natural Gas Prices***




The
      price
      of oil and natural gas will fluctuate throughout the life of Provident and
      price
      and demand are factors largely beyond its control. Such fluctuations will have
      a
      positive or negative effect on the revenue to be received by it. Such
      fluctuations will also have an effect on the acquisition costs of any future
      oil
      and natural gas properties that Provident may acquire. As well, cash
      distributions from the Trust will be highly sensitive to the prevailing price
      of
      crude oil and natural gas.




***Marketing***




The
      marketability and price of oil and natural gas, which may be acquired or
      discovered by Provident, will be affected by numerous factors beyond its
      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.




***Capital
      Investment***




The
      timing and amount of capital expenditures will directly affect the amount of
      income for distribution to Trust Unitholders. Distributions may be reduced,
      or
      even eliminated, at times when significant capital or other expenditures are
      made.




***Debt
      Service***




Provident
      currently has a term credit facilities of $750 million and US$100 million.
      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. Although it is believed that the bank
      line
      of credit is sufficient, there can be no assurance that the amount will be
      adequate for the financial obligations of Provident or that additional funds
      can
      be obtained.




The
      lender 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 such as bankruptcy, the lender may
      foreclose on or sell Provident's oil and gas properties free from or together
      with the Provident Royalties.




***Reserves***




Although
      McDaniel, NSA, CGA and Provident have carefully prepared the reserve figures
      included herein such figures are estimates and no assurance can be given that
      the indicated levels of reserves will be produced. Probable reserves estimated
      for properties may require revision based on the actual development strategies
      employed to prove such reserves. 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. The value
      of
      the Trust Units attributable to the oil and gas reserves will have
      no
      value once all of the oil and natural gas reserves of Provident have been
      produced. As a result, holders of Trust Units will have to obtain the return
      of
      capital invested out of cash flow derived from their investment in such Trust
      Units.




-47-
 TABLE
            OF CONTENTS




***Environmental
      Concerns***




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




***Delay
      in Cash Distributions***




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 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.




***Reliance
      on Provident***




Unitholders
      will be dependent on the management of Provident in respect of the
      administration and management of all matters relating to Provident's oil and
      gas
      properties, the royalties, the Trust and Trust Units. Investors who are not
      willing to rely on the management of Provident should not invest in the
      Trust Units.




***Depletion
      of Reserves***




The
      Trust
      has certain unique attributes, which 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 (through public offerings, the DRIP or otherwise) 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.




There
      can
      be no assurance that Provident will be successful in developing or acquiring
      additional reserves on terms that meet the Trust's investment objectives.




**Natural
        Gas Midstream, NGL Processing and Marketing Business Risk
        Factors**
  ***Facilities
        Throughput***


The
      volumes of natural gas processed through Provident's
      natural gas midstream, NGL processing and marketing business and of NGLs and
      other products transported in the pipelines depend on production of


-48-
 TABLE
            OF CONTENTS




natural
      gas in the areas serviced by the business and pipelines. Without reserve
      additions, production will decline over time as reserves are depleted and
      production costs may rise. Producers may shut in production at lower product
      prices or higher production costs. Producers in the areas serviced by the
      business may not be successful in exploring for and developing additional
      reserves, and the gas plants and the pipelines may not be able to maintain
      existing volumes of throughput. Commodity prices may not remain at a level
      which
      encourages producers to explore for and develop additional reserves or produce
      existing marginal reserves.




The
      rate
      and timing of production from proven natural gas reserves tied into the gas
      plants is at the discretion of the producers and is subject to regulatory
      constraints. The producers have no obligation to produce natural gas from these
      lands.




Provident's
      natural gas midstream, NGL processing and marketing business is connected to
      various third party trunkline systems. Operational disruptions or apportionment
      on those third party systems may prevent the full utilization of the
      business.




Over
      the
      long term, business will depend, in part, on the level of demand for NGLs and
      natural gas in the geographic areas in which deliveries are made by pipelines
      and the ability and willingness of shippers having access or rights to utilize
      the pipelines to supply such demand. Provident cannot predict the impact of
      future economic conditions, fuel conservation measures, alternative fuel
      requirements, governmental regulation or technological advances in fuel economy
      and energy generation devices, all of which could reduce the demand for natural
      gas and NGLs.




***Bank
      Financing***




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. Although it is believed that this credit facility
      is
      sufficient, there can be no assurance that the amount will be adequate for
      the
      financial obligations of Provident or that additional funds can be
      obtained.




The
      lenders have 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 such as bankruptcy, the lenders may
      foreclose on or sell Provident's oil and gas properties and other
      assets.




***Operational
      Matters and Hazards***




Provident's
      operations will be subject to common hazards of the natural gas processing
      and
      pipeline transportation business. The operation of Provident's natural gas
      midstream, NGL processing and marketing business could be disrupted by natural
      disasters or other events beyond the control of Provident. A casualty occurrence
      could result in the loss of equipment or life, as well as injury and property
      damage. Provident carries insurance coverage with respect to some, but not
      all,
      casualty occurrences in amounts customary for similar business operations,
      which
      coverage may not be sufficient to compensate for all casualty
      occurrences.




The
      operation of Provident's natural gas midstream, NGL processing and marketing
      business will involve many risks, including the breakdown or failure of
      equipment, information systems or processes, the performance of equipment at
      levels below those originally intended (whether due to misuse, unexpected
      degradation or design, construction or manufacturing defects), failure to
      maintain an adequate inventory of supplies or spare parts, operator error,
      labour disputes, disputes with owners of interconnected facilities and carriers
      and catastrophic events such as natural disasters, fires, explosions, fractures,
      acts of eco-terrorists and saboteurs, and other similar events, many of which
      are beyond the control of the Trust or Provident. The occurrence or continuance
      of any of these events could increase the cost of operating facilities and/or
      reduce its processing or throughput capacity, thereby reducing cash
      flow.




-49-
 TABLE
            OF CONTENTS




***Operating
      and Capital Costs***




Operating
      and capital costs of Provident's natural gas midstream, NGL processing and
      marketing business may vary considerably from current and forecast values and
      rates and represent significant components of the cost of providing service.
      In
      general, as equipment ages, maintenance capital expenditures and maintenance
      expenses with respect to such equipment may increase over time. Distributions
      may be reduced if significant increases in operating or capital costs are
      incurred.




Although
      operating costs are to be recaptured through the tariffs charged on natural
      gas
      volumes processed and oil and NGLs transported, respectively, to the extent
      such
      charges escalate, producers may seek lower cost alternatives or stop production
      of their natural gas.




***Competition***




Provident's
      natural gas midstream, NGL processing and marketing business is subject to
      competition from other gas processing plants which are either in the general
      vicinity of the gas plants or have gathering systems that are or could
      potentially extend into areas served by the gas plants. The pipelines and
      storage, terminal and processing facilities are also subject to competition
      from
      other pipelines and storage, terminal and processing facilities in the areas
      they serve, and the gas products marketing business is subject to competition
      from other marketing firms.




Producers
      in Alberta compete with producers in other regions to supply natural gas and
      gas
      products to customers in North America and the natural gas and gas products
      industry also competes with other industries to
      supply
      the fuel, feedstock and other needs of consumers. Such competition may have
      an
      adverse effect on the production of natural gas and gas products in Alberta
      and,
      as a result, on the demand for Provident's services.




***Regulatory
      Intervention***




Pipelines
      and facilities can be subject to common carrier and common processor
      applications and to rate setting by regulatory authorities in the event
      agreement on fees or tariffs cannot be reached with producers. To the extent
      that producers believe processing fees or tariffs respecting pipelines and
      facilities are too high, they may seek rate relief through regulatory
      means.




***Environmental
      Considerations***




Major
      equipment failure, release of toxic substances or pipeline rupture could result
      in damage to the environment and Provident's natural gas midstream, NGL
      processing and marketing business, death or injury and substantial costs and
      liabilities to third parties. Provident may not be able to insure against these
      events or may elect not to insure because of high premium costs or for other
      reasons. If, at any time, appropriate regulatory authorities deem any one of
      the
      gas plants unsafe, they may order it to be shut down.




The
      gas
      processing and gathering industry is regulated by federal and provincial
      environmental legislation. Activities that do not meet regulatory standards
      or
      that breach such legislation may result in the imposition of fines, penalties
      and suspension of operations. It is possible that increasingly strict
      environmental and safety laws will be implemented, which could result in
      substantial costs of compliance.




**Abandonment**
  Provident
        will be responsible for compliance with all laws and regulations regarding
        abandonment of Provident's natural gas midstream, NGL processing and marketing
        business at the end of their economic life, which abandonment costs may be
        substantial. It is not possible to estimate the abandonment costs at this
        time
        as they will be a function of regulatory requirements at the time of
        abandonment.





-50-
 TABLE
            OF CONTENTS




***Frac
      Spread***




The
      Midstream NGL Business' exposure to commodity price risk applies mainly to
      frac
      spread. The Midstream **** NGL
      Business is exposed to the relative price differential between the NGL produced
      and the shrinkage gas used to replace the heat content removed during extraction
      of the NGL from the natural gas stream. The amount of profit or loss made on
      this portion of the Midstream **** NGL
      Business will increase or decrease as the difference between the price of the
      applicable NGL and the price of natural gas varies. The Midstream NGL Business
      will increase Provident's exposure to frac spread which could result in a
      material variability of cash flow generated by the Midstream NGL Business.
      Any
      such variability could negatively affect the Trust and the cash distributions
      of
      the Trust. Frac spread is of less risk for Provident's natural gas midstream
      and
      NGL processing business.




***Reliance
      on Principal Customers and Operators***




Provident
      will rely on several significant customers to purchase product from the
      Midstream NGL Business. Ethane is predominately purchased by Nova Chemicals
      Corporation and Dow Chemicals Canada Inc. A significant amount of propane is
      purchased by Ferrellgas, a division of Ferrellgas Partners L.P. and AmeriGas
      Partners L.P. EnCana Corporation and its affiliates ("EnCana") will purchase
      the
      majority of the condensate from the EnCana Empress Debutanizer and will also
      be
      the principal supplier of natural gas and NGL for the Midstream NGL Business.
      BP
      Canada operates the BP E1 Plant at Empress, Alberta and the west to east system
      described herein. EnCana currently operates the EnCana Empress Plant. If for
      any
      reason these parties were unable to perform their obligations under the various
      agreements with Provident, the revenue and distributions of the Trust, and
      the
      operations of the Midstream **** NGL
      Business could be negatively impacted.




**General
      Risk Factors**




***Risks
      Associated With the Level of Foreign
      Ownership***




Generally,
      a trust cannot qualify as a "mutual fund trust" for the purposes of the Tax
      Act
      if it is established or is being maintained primarily for the benefit of
      non-residents. Although not without uncertainty, this is generally accepted
      to
      exist in most situations where Non-Resident holders own significantly in excess
      of 50% of the aggregate number of Trust Units issued and outstanding. However,
      there is currently an exception to the non-resident ownership restriction where
      not more than 10% of the trust's property has at any time consisted of "taxable
      Canadian property". The Department of Finance has indicated that it will be
      consulting with the private sector regarding non-resident ownership of mutual
      fund units. No formal consultations have been announced in this regard. There
      can be no assurance that the treatment of mutual fund trusts will not be changed
      in a manner which adversely affects Trust Unitholders.




The
      retention of "mutual fund trust" status under the Tax Act is important for
      both
      resident and non-resident holders of Trust Units and not just for holders of
      Trust units held within Canadian tax exempt plans. The loss of such status
      could
      be expected to have a significant adverse effect on the market price of the
      Trust Units. The importance of mutual fund status and the consequences of losing
      such status are set forth below:




(a)
            By
                virtue of its status as a mutual fund trust, the Trust has been accepted
                for registration effective March 6, 2001 as a "registered investment"
                for registered retirement savings plans ("RRSPs"),registered retirement
                income funds ("RRIFs"), and deferred profit sharing plans ("DPSPs")
                (collectively, "Exempt Plans"). As such, Trust Units are qualified
                investments for Exempt Plans as well as registered education savings
                plans
                ("RESPs") and if the Trust's status as a "registered investment"
                is
                revoked in any year by virtue of ceasing to be a "mutual fund trust"
                the
                Trust Units would remain as qualified investments for Exempt Plans
                and
                RESPs until the end of the year following such
                year;




-51-
 TABLE
            OF CONTENTS





(b)
            Where
                at the end of any month an Exempt Plan or a RESP holds Trust Units
                that
                are not qualified investments, the Exempt Plan or RESP must, in respect
                of
                that month, pay a tax under Part XI.1 of the Tax Act equal to 1 percent
                of
                the fair market value of the Trust Units at the time such Trust Units
                were
                acquired by the Exempt Plan or RESP. An RRSP or RRIF holding Trust
                Units
                that are not qualified investments would become taxable on income
                attributable to the Trust Units while they are not qualified investments
                (including the entire amount of any capital gain arising on a disposition
                of the non-qualified investment). RESPs which hold Trust Units that
                are
                not qualified investments may have their registration revoked by
                the
                Canada Revenue Agency;




(c)
            The
                loss of mutual fund trust status would render the Trust liable for
                the
                payment of a tax under Part XII.2 of the Tax Act in respect of
                certain designated income. The payment of Part XII.2 tax by the Trust
                could have adverse consequences to Unitholders who are not residents
                of
                Canada and to certain Unitholders which are tax exempt entities since
                the
                amount of cash available for cash distributions would be reduced
                by the
                amount of such tax;




(d)
            The
                loss of mutual fund trust status would result in the Trust ceasing
                to be
                eligible for the capital gains refund mechanism available under the
                Tax
                Act; and




(e)
            Upon
                the loss of mutual fund trust status, the Trust Units held by Unitholders
                that are not residents of Canada would become taxable Canadian property.
                Such Unitholders would be subject to Canadian income tax on any gains
                realized on a disposition of Trust Units, and to reporting requirements
                in
                respect thereof.




For
      the
      purpose of maintaining the Trust's status as a "mutual fund trust" under the
      Tax
      Act, Provident may, in accordance with the Trust Indenture:




(a)
            require
                the Trustee to refuse to accept a subscription for Trust Units from,
                or
                issue or register a transfer of Trust Units to, a person unless the
                person
                provides a declaration that the Trust Units to be issued or transferred
                to
                such person will (when issued or transferred) not be beneficially
                owned by
                a non-resident;




(b)
            to
                the extent practicable in the circumstances, send a notice to registered
                holders of Trust Units which are beneficially owned by non-residents,
                chosen in inverse order to the order of acquisition or registration
                of
                such Trust Units beneficially owned by non-residents or in such other
                manner as Provident may consider equitable and practicable, requiring
                them
                to sell their Trust Units which are beneficially owned by non-residents
                or
                a specified portion thereof within a specified period of not less
                than 60
                days. If the Unitholders receiving such notice have not sold the
                specified
                number of such Trust Units or provided Provident with satisfactory
                evidence that such Trust Units are not beneficially owned by non-residents
                within such period, Provident may, on behalf of such registered
                Unitholder, sell such Trust Units and, in the interim, suspend the
                voting
                and distribution rights attached to such Trust Units and make any
                distribution in respect of such Trust Units by depositing such amount
                in a
                separate bank account in a Canadian chartered bank (net of any applicable
                taxes). Upon such sale, the affected holders shall cease to be holders
                of
                Trust Units so disposed of and their rights shall be limited to receiving
                the net proceeds of sale, and any distribution in respect thereof
                deposited as aforesaid, net of applicable taxes and costs of sale,
                upon
                surrender of the certificates representing such Trust
                Units;




(c)
            delist
                the Trust Units from any non-Canadian stock exchange;
                and




(d)
            take
                such other actions as the board of directors of Provident determines,
                in
                its sole discretion, are appropriate in the circumstances that will
                reduce
                or limit the number of Trust Units held by non-resident Unitholders
                to
                ensure that the Trust is not maintained primarily for the benefit
                of
                non-residents.




-52-
 TABLE
          OF CONTENTS




***Changes
      in Legislation***




There
      can
      be no assurance that the treatment of mutual fund trusts will not be changed
      in
      a manner which adversely affects Trust Unitholders. If 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, registered education savings plans and registered
      retirement income funds.




***Investment
      Eligibility***




The
      Trust
      will endeavour to ensure that the Trust Units continue to be qualified
      investments for Exempt Plans and RESPs. The Tax Act imposes penalties for the
      acquisition or holding of non-qualified or ineligible investments and there
      is
      no assurance that the conditions prescribed for such qualified or eligible
      investments will be adhered to at any particular time.




***Nature
      of Trust Units***




The
      Trust
      Units do not represent a traditional investment in the oil and natural gas
      sector and should not be viewed by investors as shares in 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
      price
      per Trust Unit is a function of the anticipated Distributable Cash, the oil
      and
      gas properties of Provident and Provident's ability to affect 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.




**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.**




***Redemption
      Right***




It
      is
      anticipated that the redemption right will not be the primary mechanism for
      Trust Unitholders to liquidate their investments. 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 notes. Cash redemptions are subject to limitations.




***Unitholder
      Limited Liability***




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 Unitholder's share of the Trust's assets.




-53-
 TABLE
            OF CONTENTS





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 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 possibility of any personal liability of this nature arising
      is
      considered unlikely.




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.




On
      July
      1, 2004 the *Income
      Trusts Liability Act* (Alberta) came into force. This Act creates a statutory limitation on the
      liability of unitholders of Alberta income trusts such as the Trust. The
      legislation provides that a unitholder will not be, as a beneficiary, liable
      for
      any act, default, obligation or liability of the trustee that arises after
      the
      legislation come into effect.




***Regulatory
      Matters***




Provident's
      operations are subject to a variety of federal, provincial laws and regulations,
      including laws and regulations relating to the protection of the
      environment.




***Conflicts
      of Interest***




The
      directors and officers of Provident are engaged in and will continue to engage
      in other activities in the oil and natural gas industry and, as a result of
      these and other activities, the directors and officers of Provident may become
      subject to conflicts of interest. 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, such conflicts will be resolved in accordance with the
      provisions of the ABCA. The business of Provident is subject to other risks
      and
      matters, which are outside of their control.




***Competition***




The
      industry is highly competitive in the acquisition of exploration prospects
      and
      the development of new sources of production and the sale of oil and natural
      gas.




***Dependence
      on Key Personnel***




The
      success of the operations of Provident will be largely dependent on the skills
      and expertise of key personnel to manage the overall business and, in the
      natural gas midstream, NGL processing and marketing business, to achieve
      positive margins. The continued success of Provident will be dependent on its
      ability to retain or recruit such personnel.




***Variations
      in Interest Rates and Foreign Exchange Rates***




Variations
      in interest rates could result in a significant change in the amount Provident
      pays to service debt, potentially impacting distributions to
      Unitholders.




In
      addition, the exchange rate for the Canadian dollar versus the U.S. dollar
      has
      increased significantly over the last 12 months, resulting in the receipt by
      the
      Trust of fewer Canadian dollars for its production which may affect future
      distributions. Provident has initiated certain hedges to mitigate these risks.
      The increase in the exchange rate for the Canadian dollar and future
      Canadian/United States exchange rates may impact future distributions and the
      future value of the Trust's reserves as determined by independent
      evaluators.




-54-
 TABLE
            OF CONTENTS





Statutory
      Remedies




The
      Trust
      is not a legally recognized entity within the relevant definitions of the *Bankruptcy
      and Insolvency Act* (Canada), the *Companies'
      Creditors Arrangement Act* (Canada)
      and in some cases, the *Winding
      Up and Restructuring Act* (Canada). As a result, in the event a restructuring of the Trust were necessary,
      the Trust would not be able to access the remedies available thereunder. In
      the
      event of a restructuring, a holder of Debentures may be in a different position
      than a holder of unsecured indebtedness of a corporation.




***Availability
      of Credit***




As
      of
      March 15, 2006, the Trust had drawn $480 million against the Canadian
      credit facility and had $41 million of the Canadian credit facility drawn
      on letters of credit, representing 69% of the Canadian credit capacity. In
      addition, as of March 15, 2006, the Trust had drawn US$48.5 million against
      the U.S. credit facility and had US$4.4 million of the U.S. credit facility
      drawn on letters of credit, representing 53% of the U.S. credit capacity.
      Variations in interest rates and scheduled principal repayments or the need
      to
      refinance the credit facility upon expiration could result in significant
      changes in the amount required to be applied to debt service before payment
      of
      any amounts to the Trust. Although it is believed that the credit facilities
      are
      sufficient, there can be no assurance that the amounts will be adequate for
      the
      financial obligations of the Trust, that additional funds can be obtained or
      that, upon expiration, the credit facility can be refinanced on terms acceptable
      to the Trust or the lenders. In such circumstances, cash distributions may
      be
      reduced.




**INTERESTS
      OF MANAGEMENT AND OTHERS IN MATERIAL
      TRANSACTIONS**




No
      director or executive officer of Provident, no person or company that is the
      direct or indirect beneficial owner of, or who exercises control or direction
      over more than 10% of the outstanding Trust Units and no associate or affiliate
      of any of the foregoing persons or companies, has or has had any material
      interest, direct or indirect, in any transaction within the three most recently
      completed financial years or during the current financial year that has
      materially affected or will materially affect the Trust, other than as described
      in this Annual Information Form.




**TRANSFER
      AGENT AND REGISTRAR**




The
      transfer agent and registrar for the Trust Units and the debentures is
      Computershare Trust Company of Canada at its principal offices in Toronto,
      Ontario and Calgary, Alberta.




**INTERESTS
      OF EXPERTS**




As
      of the
      date hereof, the principals of McDaniel, independent oil and gas reservoir
      engineers, as a group, beneficially own, directly or indirectly, less than
      1
      percent of the Trust Units. As of the date hereof, the principals of NSA,
      independent oil and gas reservoir engineers, as a group, do not beneficially
      own, directly or indirectly, any Trust Units. As of the date hereof, the
      principals of CGA, independent oil and gas reservoir engineers, as a group,
      beneficially own, directly or indirectly, less than 1 percent of the Trust
      Units. As of the date hereof, the principals of GLJ, independent oil and gas
      reservoir engineers, as a group, beneficially own, directly or indirectly,
      less
      than 1 percent of the Trust Units.




**MATERIAL
      CONTRACTS**




Other
      than the Trust Indenture, there are no material contracts entered into by the
      Trust or its subsidiaries during the most recently completed financial year
      or
      since January 1, 2002 and which are still in effect, other than contracts
      entered into in the ordinary course of business.




**DOCUMENTS
        INCORPORATED BY REFERENCE**
  **Any
        statement contained in a document incorporated or deemed to be incorporated
        by
        reference herein shall be deemed to be modified or superseded for the purposes
        of this Annual Information Form to the extent that a statement contained
        herein,
        or any other subsequently filed document which also is or is deemed to be
        incorporated by reference herein, modifies or supersedes that statement.
        The
        modifying or superseding statement need not state that it has modified or
        superseded a prior statement or include any other information set forth in
        the
        document that is modified or superseded.**


-55-
 TABLE
            OF CONTENTS




The
      making of a modifying or superseding
      statement shall not be deemed an admission for any purposes that the modified
      or
      superseded statement, when made, constituted a misrepresentation, an untrue
      statement of a material fact or an omission to state a material fact that is
      required to be stated or that is necessary to make a statement not misleading
      in
      light of the circumstances in which it was made. Any statement so modified
      or
      superseded shall not be deemed, except as so modified or superseded, to
      constitute a part of this Annual Information Form.






The
      Trust
      will provide without charge to each security holder to whom this Annual
      Information Form is delivered, upon the written or oral request of such person
      (and to each person who is not a security holder of the Trust upon payment
      of a
      reasonable charge), a copy of any or all of the documents incorporated herein
      by
      reference, other than exhibits to such documents (unless such exhibits are
      specifically incorporated by reference into such documents). Requests for such
      documents should be directed to the office of Investor Relations, Provident
      Energy Ltd., 800, 112 - 4 th Street
      S.W., Calgary, Alberta T2P 0H3, telephone: (403) 296-2233. Documents
      incorporated by reference in this Annual Information Form are also available
      on
      SEDAR at www.sedar.com.




**PRINCIPAL
      HOLDERS OF TRUST UNITS**




As
      at the
      date hereof, to the knowledge of Provident, no person or company owned of record
      or beneficially, directly or indirectly, more than 10% of the issued and
      outstanding Trust Units. As at March 21, 2006, **** the
      directors and senior officers of Provident, as a group, beneficially owned,
      directly or indirectly, 2.3 million Trust Units or approximately
      1.2% **** of
      the
      issued and outstanding Trust Units and 463,545 Series A exchangeable shares
      of
      Provident representing 100% of the issued and outstanding Series A exchangeable
      shares of Provident. As of March 21, 2006, each such Series A exchangeable
      share of Provident held by such director or senior officer is exchangeable
      into
      Trust Units at an exchange ratio of 1.55621.




**ADDITIONAL
      INFORMATION**




Additional
      information related to the remuneration of the directors and officers of
      Provident for the year ended December 31, 2005, the indebtedness of the
      directors and officers of Provident, the principal holders of Trust Units and
      securities authorized for issuance under equity compensation plans, where
      applicable, is contained in the Management Proxy Statement and Information
      Circular of the Trust dated March 29, 2006, which relates to the Annual
      Meeting of the Unitholders to be held on May 11, 2006. Additional financial
      information is provided in the Trust's audited consolidated financial statements
      and management's discussion and analysis for the year ended December 31,
      2005.




Additional
      copies of this Annual Information Form are available on SEDAR at www.sedar.com
      or may be obtained from Provident. Please contact:




-56-
 TABLE
            OF CONTENTS





Laurie
      Stretch


Investor
      Relations


Provident
      Energy Ltd.


800,
      112
      - 4 th Street
      S.W.


Calgary,
      Alberta T2P 0H3




Telephone:  (403)
      296-2233


Fax:   (403)
      261-6696





Additional
      information relating to the Trust may be found on SEDAR at
      www.sedar.com.





-57-
 TABLE
            OF CONTENTS




**SCHEDULE
      A**













**Audit
      Committee Terms of Reference**




Provident
      Energy Trust (the "Trust") has delegated a number of duties and responsibilities
      regarding the management and administration of the operations and affairs of
      the
      Trust to its subsidiary, Provident Energy Ltd. (the "Corporation") pursuant
      to
      the trust indenture, as amended. As such, the board of directors (the "Board")
      of the Corporation has oversight responsibilities, authorities and duties in
      connection with the business of the Trust and the Corporation. The Board has
      delegated the specific oversight responsibilities, authorities and duties as
      described below to the Audit Committee (the "Committee").




For
      the
      purpose of these terms of reference, the term "Provident" shall include the
      Trust, the Corporation and their subsidiaries.




**Composition**




The
        Committee will consist of three or more directors as determined by the Board.
        The members of the Committee shall be appointed by the Board. The Governance,
        Human Resources and Compensation Committee of the Board shall recommend to
        the
        Board eligible directors to fill vacancies on the Committee. Each member
        shall
        serve until his or
        her successor is appointed, unless he shall resign or be removed by the Board
        or he
        shall otherwise cease to be a director of the Corporation. The Board shall
        fill
        any vacancy if the membership of the Committee is less than three directors. The
        Chair
        of the Committee may be designated by the Board or, if it does not do so,
        the
        members of the Committee may elect a Chair by vote of a majority of the full
        Committee membership.
  All
        members of the Committee must satisfy the independence, financial literacy
        and
        experience requirements of applicable Canadian and United States securities
        laws, rules and guidelines, any applicable stock exchange requirements or
        guidelines and any other applicable regulatory rules. In particular: (i) each member shall be "independent" and
        "financially literate" within the meaning of Multilateral Instrument 52-110 *Audit
        Committees* ("MI 52-110"), (ii) each member shall be "independent" and
        "financially literate" within the meaning of the rules of the New York Stock
        Exchange, and (iii) at least one member must be an "audit committee
        financial expert" within the meaning of that term under the United States *Securities
        Exchange Act of 1934* ,
        as
        amended ,
        and the
        rules adopted by the United States Securities and Exchange Commission thereunder
        (collectively, the "U.S. Rules").
  Members
        of the Committee may not, other than in their respective capacities as members
        of the Committee, the Board or any other committee of the Board, accept directly
        or indirectly any consulting, advisory or other compensatory fee from Provident,
        or be an "affiliated person" (as such term is defined in the U.S. Rules)
        of
        Provident. For greater certainty, director's fees ,
        options
        and similar compensation arrangements and
        fixed amounts of compensation under a retirement plan (including deferred
        compensation) for prior service with Provident that are not contingent on
        continued service should be the only compensation a Committee member receives
        from Provident.


-2-
 TABLE
            OF CONTENTS




**Communication,
      Authority to Engage Advisors and Expenses**




The
      Committee shall have access to such officers and employees of the Provident,
      the
      external auditor, the independent reserves evaluator(s) and to such other
      information respecting Provident, as it considers to be necessary or advisable
      in order to perform its duties and responsibilities.




The
      Committee provides an avenue for communication, particularly for outside
      directors, with the external auditor and financial and senior management and
      the
      Board. The external auditor shall have a direct line of communication to the
      Committee through its Chair and shall report directly to the Committee. The
      Committee, through its Chair, may directly contact any employee of Provident
      as
      it deems necessary, and any employee may bring before the Committee, on a
      confidential basis, any matter involving Provident's financial practices or
      transactions.




The
      Committee has the authority to engage independent counsel and other advisors
      as
      it determines necessary to carry out its duties and to set the compensation
      for
      any such counsel and advisors. Any engagement of independent counsel or other
      advisors is to be at Provident's expense.




Provident
      shall be responsible for all expenses of the Committee that are deemed necessary
      or appropriate by the Committee in carrying out its duties including the
      compensation of the external auditor for issuing an audit report or performing
      other audit, review or attest services.




**Meetings
      and Record Keeping**




Meetings
      of the Committee shall be conducted as follows:




1.
            the
                Committee shall meet at least quarterly at such times and at such
                locations as the Chair of the Committee shall determine, provided
                that
                meetings shall be scheduled so as to permit timely review of the
                Trust's
                quarterly and annual financial statements and related management's
                discussion and analysis and earnings press releases. The external
                auditor
                or any two members of the Committee may also request a meeting of
                the
                Committee. The Committee shall also meet separately with the external
                auditor and/or internal auditor periodically as the Committee may
                deem
                appropriate. The Chair of the Committee shall hold in camera sessions
                of
                the Committee, without management present, at every
                meeting;




2.
            the
                Chair of the Committee shall preside as chair at each Committee meeting
                and lead Committee discussion on meeting agenda
                items;




3.
            the
                quorum for meetings shall be a majority of the members of the Committee,
                present in person or by telephone or by other telecommunication device
                that permits all persons participating in the meeting to hear each
                other;




4.
            if
                the Chair of the Committee is not present at any meeting of the Committee,
                one of the other members of the Committee who is present at the meeting
                shall be chosen by the Committee to preside at the
                meeting;




5.
            the
                Chair shall, in consultation with management and the external auditor,
                establish the agenda for the meetings and instruct management to
                ensure
                that properly prepared agenda materials are circulated to the Committee
                with sufficient time for study prior to the
                meeting;




-3-
 TABLE
          OF CONTENTS


6.
            every
                question at a Committee meeting shall be decided by a majority of
                the
                votes cast;




7.
            the
                Chief Executive Officer (the "CEO"), the President and the Chief
                Financial
                Officer ("CFO") shall be available to advise the Committee, shall
                receive
                notice of meetings and may attend meetings of the Committee at the
                invitation of the Chair of the Committee. Other management
                representatives, other Board members, officers or employees of Provident,
                the external auditor, outside counsel and other experts or consultants
                may
                be invited to attend as necessary;
                and




8.
            a
                Committee member, or any other person selected by the Committee,
                shall be
                appointed at each meeting to act as secretary for the purpose of
                recording
                the minutes of each meeting.




The
      Committee shall provide the Board with a summary of all meetings together with
      a
      copy of the minutes from such meetings. Where minutes have not yet been
      prepared, the Chair shall provide the Board with oral reports on the activities
      of the Committee. Information reviewed and discussed by the Committee at any
      meeting shall be referred to in the minutes and made available for examination
      by the Board upon request to the Chair of the Committee.




**Responsibilities**


The
        Committee is part of the Board. Its primary functions are to assist the Board
        in
        fulfilling its oversight responsibilities with respect to: (i) the integrity
        of
        the Trust's Financial Statements, including the review and recommendation
        for
        approval of the financial statements and the financial reporting of the Trust;
        (ii) the assessment of the system of internal ,
        accounting and financial reporting controls
        and procedures that management has established ,
        including for the
        purpose of monitoring its compliance with regulatory requirements; and (iii) the
        appointment, compensation and evaluation of the external auditor and the
        oversight of the external audit process, including the external auditor's
        performance, qualifications and independence. In addition, the Committee shall
        assist the Board as requested in fulfilling its oversight responsibilities
        with
        respect to :
        (i)
        financial policies and strategies; (ii) financial risk management practices;
        and
        (iii) transactions or circumstances which could materially affect the financial
        profile of the Trust.


Management
      is responsible for establishing and maintaining controls, procedures and
      processes and the Committee is appointed by the Board to oversee, review and
      monitor those controls, procedures and processes.




The
      Committee, in its capacity as a committee of the Board and subject to the rights
      of unitholders and applicable law, shall be directly responsible for overseeing
      the relationship of the external auditor with the Trust, including the
      appointment, compensation, retention and oversight of the work of any external
      auditor engaged (including resolution of disagreements between management of
      Provident and the external auditor regarding financial reporting) for the
      purpose of preparing or issuing an audit report or performing other audit,
      review or attest services for the Trust. The external auditor shall report
      directly to the Committee. The Committee should have a clear understanding
      with
      the external auditor that such external auditor must maintain an open and
      transparent relationship with the Committee, and that the ultimate
      accountability of the external auditor is to the unitholders of the
      Trust.




**Specific
      Duties**




In
      carrying out its role, the Committee has the following specific authorities
      and
      responsibilities:




-4-
 TABLE
            OF CONTENTS


1.
              Financial
                  Information and Reporting


(a)
            to
                review with management and the external auditor, and recommend to
                the
                Board for approval, the annual and interim financial statements of
                the
                Trust and related financial reporting, including management's discussion
                and analysis and earnings press
                releases;




(b)
            to
                review and discuss with management the type and presentation of
                information to be included in press releases which contain financial
                information taken from Provident's financial statements prior to
                the
                release of such press release to the public, paying particular attention
                to any use of information which is not prepared in accordance with
                Canadian generally accepted accounting principles ("GAAP"), such
                as "pro
                forma" or "adjusted" non-GAAP information, as well as financial
                information and earnings guidance provided by Provident to analysts
                and
                rating agencies;




(c)
            to
                review with management and recommend to the Board for approval, any
                financial statements of the Trust which have not previously been
                approved
                by the Board and which are to be included in a prospectus or other
                public
                disclosure document of the Trust;




(d)
            to
                consider and be satisfied that adequate policies and procedures are
                in
                place for the review of the Trust's disclosure of financial information
                extracted or derived from the Trust's financial statements (other
                than
                disclosure referred to in clause (1)(a) above), and periodically
                assess
                the adequacy of such procedures;




(e)
            to
                review major issues regarding accounting principles and financial
                statement presentations, including any significant changes in Provident's
                selection or application of accounting
                principles;




(f)
            to
                review analyses prepared by management and/or the external auditor
                setting
                forth any significant financial reporting issues and judgments made
                in
                connection with the preparation of Provident's financial statements,
                including analyses of the effects of alternative GAAP methods on
                the
                financial statements;




(g)
            to
                review the effect of regulatory and accounting initiatives, as well
                as
                off-balance sheet structures, on Provident's financial
                statements;




2.
            Internal
                Controls




(a)
            to
                review the internal controlstaff functions including:




(i)
            the
                purpose, authority and organizational reporting lines,and




(ii)
            the
                annual audit plan, budget and staffing
                thereof;




(b)
            to
                review, with the CFO, controller or others, as appropriate, Provident's
                internal system of audit controls and the results of internal
                audits;




(c)
            to
                review major issues regarding the adequacy of Provident's internal
                controls and any special audit steps adopted in light of material
                control
                deficiencies;




(d)
            to
                establish procedures for:




-5-
 TABLE
          OF CONTENTS
 (i)
                the
                      receipt, retention and treatment of any complaint regarding
                      accounting,
                      internal accounting controls or auditing matters,and


(ii)
            the
                confidential, anonymous submissions by employees of concerns regarding
                questionable accounting or auditing
                matters;




3.
            External
                Audit




(a)
            to
                recommend to the Board the external auditor to be nominated for the
                purpose of preparing or issuing an auditor's report or performing
                other
                audit, review or attest services and the compensation of such
                auditor;




(b)
            to
                evaluate and oversee the services provided by the external auditor
                and
                recommend to the Board, if necessary, the replacement of the external
                auditor;




(c)


(i)
            to
                pre-approve or approve (if pre-approvalis
                not required by law) the fees related to, any audit service or
                non-prohibited non-audit service and, if desired, establish detailed
                policies and procedures for the pre-approval of audit services and
                non-prohibited non-audit services by an external auditor. The Committee
                may delegate this ability to one or more members of the Committee
                to the
                extent permitted by applicable law, provided that any pre-approvals
                granted pursuant to such delegation must be detailed as to the particular
                service to be provided, may not delegate Committee responsibilities
                to
                management of Provident and must be reported to the full Committee
                at its
                next scheduled meeting, or





(ii)
            adopt
                specific policies and procedures for the engagement of the external
                auditor for the purposes of the provision of non-audit
                services;




(d)
            to
                obtain and review at least annually a written report by the external
                auditor setting out the auditor's internal quality control procedures,
                any
                material issues raised by the auditor's internal quality control
                reviews,
                or by inquiry or investigation by governmental or professional authorities
                within the preceding five years, respecting one or more independent
                audits
                carried out by the firm and the steps taken to resolve those issues;




(e)
            to
                review and discuss with the external auditor all relationships that
                the
                external auditor and its affiliates have with Provident in order
                to
                determine the external auditor's independence, including, without
                limitation:




(i)
            requesting,
                receiving and reviewing, on a periodic basis but at least annually,
                a
                formal written statement from the external auditor delineating all
                relationships that may reasonably be thought to bear on the independence
                of the external auditor with respect to
                Provident,




(ii)
            discussing
                with the external auditor any disclosed relationships or services
                that the
                external auditor believes may affect the objectivity and independence
                of
                the external auditor, and




(iii)
            recommending
                that the Board take appropriate action in response to the external
                auditor's report to satisfy itself of the external auditor's independence
                at least annually, obtain and review a report by the external auditor
                describing: the firm's internal
                quality control procedures; any material issues raised by the most
                recent
                internal quality control review, or peer review, of the firm, or
                by any
                inquiry or investigation by governmental or professional authorities,
                within the preceding five years, respecting one or more independent
                audits
                carried out by a firm, and any steps taken to deal with any such
                issues;




-6-
 TABLE
          OF CONTENTS


(f)
            to
                review the audit plan of the external auditor prior to the commencement
                of
                the audit;




(g)
            to
                set clear hiring policies for Provident regarding partners and employees
                and former partners and employees of the present and former external
                auditor of the Trust;




(h)
            to
                obtain assurance from the external auditor that disclosure to the
                Committee is not required pursuant to the provisions of the United
                States
                Securities Exchange Act of 1934, as amended, regarding the discovery
                of
                any illegal acts by the external
                auditor;




(i)
            to
                review with the external auditor any audit problems or difficulties,
                including any restrictions on the scope of the external auditor's
                activities or on access to requested information, any significant
                disagreements with management, and management's response (such review
                should also include discussion of the responsibilities, budget and
                staffing of Provident's internal audit function, if
                any);




(j)
            to
                review and discuss a report from the external auditor at least quarterly
                regarding:




(i)
            all
                critical accounting policies and practices to be
                used,




(ii)
            all
                alternative treatments within generally accepted accounting principles
                for
                policies and practices related to material items that have been discussed
                with management, including the ramifications of the use of such
                alternative disclosures and treatments, and the treatment preferred
                by the
                external auditor,




(iii)
            other
                material written communications between the external auditor and
                management, such as any management letter or schedule of unadjusted
                differences, and




(iv)
            to
                present its conclusions with respect to the external auditor to the
                full
                Board;




(k)
            the
                Committee will ensure the rotation of partners on the audit engagement
                team of the external auditor in accordance with applicable law. The
                Committee will also periodically consider whether, in order to assure
                continuing external auditor independence, it is appropriate to adopt
                a
                policy of rotating the external auditing firm on a regular
                basis;




(l)
            the
                Committee will review and evaluate the lead partner of the external
                auditor;




4.
            Risk
                Management




(a)
            to
                review and monitor Provident's major financial risks and risk management
                policies and the steps taken by management to monitor and control
                those
                risks;




(b)
            at
                the request of the Board, review transactions or matters which could
                materially affect the financial profile of the
                Trust;




-7-
 TABLE
          OF CONTENTS


(c)
            the
                Committee shall, at least annually, provide a review of the Corporation's
                directors and officers liability insurance to the
                board.




5.
            Compliance
                and Review of CEO and CFO Certification
                Process




(a)
            to
                review Provident's financial reporting procedures and policies to
                ensure
                compliance with all legal and regulatory requirements and to investigate
                any non-adherence to those procedures and policies;
                and




(b)
            in
                connection with its review of the annual audited financial statements
                and
                interim financial statements, the Committee will also review the
                process
                for the CEO and CFO certifications with respect to the financial
                statements and Provident's disclosure and internal controls, including
                any
                material deficiencies or changes in those controls. The Committee
                will
                review with the CEO, the CFO and the external auditor: (i) all significant
                deficiencies and material weaknesses in the design or operation of
                Provident's internal control over financial reporting which could
                adversely affect Provident's ability to record, process, summarize
                and
                report financial information required to be disclosed by the Trust
                in the
                reports that it files or submits under the United States Securities
                Exchange Act of 1934, as amended, within the required time periods,
                and
                (ii) any fraud, whether or not material, that involves management
                of
                Provident or other employees who have a significant role in Provident's
                internal controlover financial reporting.




**Other
      Matters**




1.
            The
                Committee shall review and reassess the adequacy of this mandate
                at least
                annually and otherwise as it deems appropriate and recommend changes
                to
                the Board.




2.
            The
                performance of the Committee shall be evaluated annually by the Board
                against criteria defined in the Committee and Board
                mandates.




3.
            The
                Committee may, at the request of the Board or on its own initiative,
                investigate such other matters as it considers necessary or appropriate
                in
                the circumstances, including, without limitation, matters relating
                to
                corporate governance, compensation and director
                nominations.




4.
            The
                Committee may delegate its responsibilities to sub-committees of
                the
                Committee.












TABLE
            OF CONTENTS


**APPENDIX
        A**
  **AUDIT
        COMMITTEE ANNUAL CALENDAR**
 **(** **December
        31 year end)**
  **Quarterly
        Audit Committee Meetings: May, August and November**
  ·  Approval
        of quarterly financial statements such as:
 MD&A;
 press
        release;
 estimates
        and management judgments; and
 Review
        of report from external auditor .
  ·  Management
        certification process with report from CEO/CFO and processes
        followed.
  ·  Other
        standard items including management reporting on:
 Material
        communication with rating agencies;
 Material
        legal matters/litigation; and
 Analyst
        reports.
  ·
              Report
                  from Audit Committee Chair on pre-approvals for audit, non-audit,
                  review
                  or attestation assignments.
  ·  *In
        camera* review with external auditor .
  **February
        or March Meeting to Review Audited Financial Statements**
  ·  Review
        annual financial statements, MD&A and related disclosure.
  ·  Discuss
        significant accounting policies.
  ·  Discuss
        critical estimates, and judgments and impact on statements.
  ·  Review
        business risks disclosure in MD&A.
  ·
              Receive
                  external auditor's report on statutory audit and various matters
                  where
                  external auditor is required to report, such
                  as:
 auditor
        independence;
 methods
        used to account for significant unusual transactions;
 material
        proposed audit adjustments and immaterial adjustments not recorded by
        management;
 auditor
        judgments about the quality of the Company's accounting principles;
 management-related
        issues encountered in performing the audit; and
 disagreements
        with management over the application of accounting principles, management's
        accounting estimates and related matters.
  ·
              Review
                  management's "internal control report" to be included in annual
                  report and
                  external auditor's assessment of
                  same.
  ·
              Internal
                  control issues, if any.
  ·
              Separate*in
                  camera*meetings with the external auditorand external counsel.
  ·
              Annual
                  information form and comparable 40-F and
                  20-F.
  ·
                Public
                      disclosure relevant to Audit Committee, such as re-appointment
                      of auditor,
                      disclosure of pre-approval procedures as required by SEC Auditor
                      Independence Rules and disclosure relating to financial
                      experts.


A-1
 TABLE
          OF CONTENTS


**October/November
      Meeting**




·
            Discuss
                annual audit plan including scope of engagement and related matters
                such
                as:


audit
      team and potential rotation;


review
      and consideration of budgeted audit fees; and


special
      areas for concentration by external audit.




·
            Review
                preparations for production of "internal control report" for annual
                report.




·
            Review
                Audit Committee charter and report to
                Board.




·
            Review
                and affirmation of principles for pre-approval of audit, non-audit,
                review
                and attestation services.




**Special
      issues to be dealt with at one or more regular meetings or through a special
      meeting of the Audit Committee**




·  Educational
      component to Audit Committee functions such as:




critical
      accounting policies/estimates/general discussion;




treasury
      activities;




internal
      control risks;




support
      to CEO/CFO certification;




financing
      vehicles, loan documents and applicable covenant patterns;




taxation
      issues and tax planning;




new
      developments such as:


-
      non-GAAP earnings measures; and


-
      identification of financial experts;




competitors
      and accounting issues involving competitors;




preparing
      of Audit Committee effectiveness report for Board of Directors;




business
      risks and related oversight responsibilities of Audit Committee including
      applicable procedures; and




earnings
      guides such as:


-
      pro forma reporting; and


-
      selective disclosure policy.




·
            Review
                and consideration of succession planning and related issues with
                respect
                to Audit Committee Chair and Audit Committee members in light of
                independence requirements and financial expertise
                requirements.




·
            Communication
                with the Corporate Governance Committee as may be
                required.




·
            Review
                of complaints received and outcome of
                investigation.




These
      educational elements may be dealt with at a special annual meeting of the
      Committee.




-
          2-
 TABLE
          OF CONTENTS


**2005
        Year-end and Fourth Quarter Results**
 
 **Management’s
        discussion and analysis**
 
 The
        following analysis provides a detailed explanation of Provident’s operating
        results for the quarter and year ended December 31, 2005 compared to the
        quarter
        and year ended December 31, 2004 and should be read in conjunction with the
        consolidated financial statements of Provident. This analysis has been prepared
        using information available up to March 10, 2006.
  Provident
        Energy Trust has diversified investments in certain segments of the energy
        value
        chain. Provident currently operates in three key business segments: Canadian
        crude oil and natural gas production and exploitation (“COGP”), United States
        crude oil and natural gas production and exploitation, (“USOGP”) and midstream
        services and marketing (“Midstream”). Provident’s “COGP” business produces crude
        oil and natural gas from five core areas in the western Canadian sedimentary
        basin. USOGP produces crude oil and natural gas in the Los Angeles and Santa
        Maria basins in California and in Wyoming. The Midstream business unit operates
        in Canada and the U.S.A. and extracts, processes, markets, transports and
        offers
        storage of natural gas liquids within the integrated facilities at Younger
        in
        British Columbia, Redwater, Empress, and Kerrobert in Saskatchewan, Sarnia
        in
        Ontario, Superior in Wisconsin and Lynchburg in Virginia.
  This
        analysis commences with a summary of the consolidated financial and operating
        results followed by segmented reporting on the COGP business unit, the USOGP
        business unit and the Midstream business unit. The reporting focuses on the
        financial and operating measurements management uses in making business
        decisions and evaluating performance.
   **Forward-looking
        statements**
  Certain
        statements included in this analysis constitute forward-looking statements
        under
        applicable  securities
        legislation. These statements relate to future events or Provident’s future
        performance. All statements other than statements of historical fact are
        forward-looking statements. In some cases, forward-looking statements can
        be
        identified by terminology such as "may", "will", "should", "expect", "plan",
        "anticipate", "believe", "estimate", "predict", "potential", "continue",
        or the
        negative of these terms or other comparable terminology. Forward-looking
        statements or information in this analysis include, but are not limited to,
        business strategy and objectives, reserve quantities and the discounted present
        value of future net cash flows from such reserves, net revenue, future
        production levels, capital expenditures, exploration plans, development plans,
        acquisition and disposition plans and the timing thereof, operating and other
        costs, royalty rates, budgeted levels of cash distributions and the performance
        associated with Provident's natural gas midstream, NGL processing and marketing
        business. These
        statements are only predictions. Actual events or results may differ materially.
        In addition, this analysis may contain forward-looking statements attributed
        to
        third party industry sources. Undue reliance should not be placed on these
        forward-looking statements, as there can be no assurance that the plans,
        intentions or expectations upon which they are based will occur. By its nature,
        forward-looking information involves numerous assumptions, known and unknown
        risks and uncertainties, both general and specific, that contribute to the
        possibility that the predictions, forecasts, projections and other
        forward-looking statements will not occur. In addition to other assumptions
        identified in this analysis, assumptions in respect of forward-looking
        statements have been made regarding, among other things:
  o
              Provident’s
                  ability to benefit from the combination of growth opportunities
                  and the
                  ability to grow through the capital
                  markets;
 o
              Provident’s
                  acquisition strategy, the criteria to be considered in connection
                  therewith and the benefits to be derived
                  therefrom;
 o
              the
                  sustainability and growth of production and reserves through prudent
                  management and acquisitions;
 o
              the
                  emergence of accretive growth
                  opportunities;
 o
              the
                  ability to achieve a consistent level of monthly cash
                  distributions;
 o
              the
                  impact of Canadian governmental regulation on
                  Provident;
 o
              the
                  existence, operation and strategy of the commodity price risk management
                  program;
 o
              the
                  approximate and maximum amount of forward sales and hedging to
                  be
                  employed;
 o
              the
                  changes in oil and natural gas prices and the impact on such changes
                  on
                  cash flow after hedging;
 o
              the
                  level of capital expenditures devoted to development activity rather
                  than
                  exploration;
 o
              the
                  sale, farming out or development using third party resources to
                  exploit or
                  produce certain exploration
                  properties;
 o
              the
                  use of development activity and acquisitions to replace and add
                  to
                  reserves;
 o
              the
                  quantity of oil and natural gas reserves and oil and natural gas
                  production levels;
 o
              currency,
                  exchange and interest rates;
 o
              the
                  performance characteristics of Provident's natural gas midstream,
                  NGL
                  processing and marketing business;
 o
              the
                  growth opportunities associated with the natural gas midstream,
                  NGL
                  processing and marketing business;
                  and
 o
              the
                  nature of contractual arrangements with third parties in respect
                  of
                  Provident's natural gas midstream, NGL processing and marketing
                  business.
  1
 TABLE
            OF CONTENTS
 Although
        Provident believes that the expectations reflected in the forward-looking
        statements are reasonable, there can be no assurance that such expectations
        will
        prove to be correct. Provident can not guarantee future results, levels of
        activity, performance, or achievements. Moreover, neither the Trust, Provident
        nor any other person assumes responsibility for the accuracy and completeness
        of
        the forward-looking statements. Some of the risks and other factors, some
        of
        which are beyond Provident's control, which could cause results to differ
        materially from those expressed in the forward-looking statements contained
        in
        this analysis include, but are not limited to:
  o
              general
                  economic conditions in Canada, the United States and
                  globally;
 o
              industry
                  conditions, including fluctuations in the price of crude oil, natural
                  gas
                  and natural gas liquids and conditions associated with the natural
                  gas
                  midstream, NGL processing and marketing
                  business;
 o
              uncertainties
                  associated with estimating
                  reserves;
 o
              royalties
                  payable in respect of oil and gas
                  production;
 o
              governmental
                  regulation of the oil and gas industry, including income tax and
                  environmental regulation;
 o
              fluctuation
                  in foreign exchange or interest
                  rates;
 o
              stock
                  market volatility and market
                  valuations;
 o
              the
                  impact of environmental events;
 o
              the
                  need to obtain required approvals from regulatory
                  authorities;
 o
              unanticipated
                  operating events which can reduce production or cause production
                  to be
                  shut-in or delayed;
 o
              failure
                  to obtain industry partner and other third party consents and approvals,
                  when required; and
 o
              third
                  party performance of obligations under contractual
                  arrangements.
 
 Statements
        relating to "reserves" or "resources" are deemed to be forward-looking
        statements, as they involve the implied assessment, based on certain estimates
        and assumptions, that the resources and reserves described can be profitably
        produced in the future. Readers are cautioned that the foregoing list of
        factors
        is not exhaustive. The forward-looking statements contained in this analysis
        are
        expressly qualified by this cautionary statement. Subject to Provident’s
        obligations under applicable securities laws, Provident is not under any
        duty to
        update any of the forward-looking statements after the date of this analysis
        to
        conform such statements to actual results or to changes in Provident’s
        expectations.
  2
 TABLE
            OF CONTENTS
 
 **Consolidated
        financial highlights**
 **Quarter
                    ended December 31,**
                **Year
                    ended December 31,**($
                    000s except per unit data)**2005**
                
                2004(1)
                %
                    Change
                
                **2005**
                
                2004(1)
                %
                    ChangeRevenue
                    (net of royalties and financial
                  derivative
                    instruments)
                **$**
                **442,687**
                $
                369,435
                20
                **$**
                **1,360,274**
                $
                1,109,857
                23Cash
                    flow from COGP operations
                **$**
                **51,992**
                $
                30,273
                72
                **$**
                **185,129**
                $
                121,144
                53Cash
                    flow from USOGP operations
                
                **16,014**
                
                11,525
                39
                
                **59,821**
                
                21,458
                179Cash
                    flow from midstream services
                  and
                    marketing
                
                **28,292**
                
                16,573
                71
                
                **66,238**
                
                42,644
                55**Total
                    cash flow from operations**
                **$**
                **96,298**
                $
                58,371
                65
                **$**
                **311,188**
                $
                185,246
                68Per
                    weighted average unit - basic(2)
                **$**
                **0.57**
                **$**
                0.41
                39
                **$**
                **1.95**
                **$**
                1.63
                20Per
                    weighted average unit - diluted(3)
                **$**
                **0.51**
                **$**
                0.40
                28
                **$**
                **1.95**
                **$**
                1.63
                20Declared
                    distributions to unitholders
                **$**
                **62,646**
                $
                52,064
                20
                **$**
                **230,714**
                $
                164,628
                40Per
                    unit(2)
                **$**
                **0.36**
                $
                0.36
                -
                **$**
                **1.44**
                $
                1.44
                -Percent
                    of cash flow from operations paid
                  out
                    as declared distributions
                
                **65%**
                
                89%
                (27)
                
                **74%**
                
                89%
                (17)Net
                    income
                **$**
                **54,501**
                $
                38,314
                42
                **$**
                **96,926**
                $
                21,225
                357Per
                    weighted average unit - basic(2)
                **$**
                **0.32**
                $
                0.27
                19
                **$**
                **0.61**
                $
                0.19
                221Per
                    weighted average unit - diluted(3)
                **$**
                **0.32**
                **$**
                0.27
                19
                **$**
                **0.61**
                **$**
                0.19
                221Capital
                    expenditures
                **$**
                **51,011**
                $
                26,471
                93
                **$**
                **156,499**
                $
                76,321
                105Midstream
                    NGL acquisition
                **$**
                **772,303**
                
                -
                -
                **$**
                **772,303**
                
                -
                -Nautilus
                    acquisition
                **$**
                **-**
                $
                -
                -
                **$**
                **91,420**
                $
                -
                -Property
                    acquisitions
                **$**
                **(94)**
                $
                64,036
                (100)
                **$**
                **586**
                $
                72,745
                (99)Property
                    dispositions
                **$**
                **461**
                $
                6,603
                (93)
                **$**
                **45,100**
                $
                13,717
                229Weighted
                    average trust units outstanding (000s)-
                    Basic(2)
                
                **169,609**
                
                141,273
                20
                
                **159,316**
                
                113,310
                41-
                    Diluted(3)
                
                **188,036**
                
                144,922
                30
                
                **159,686**
                
                113,489
                41
 **As
                    at December 31,**($
                    000s)
                
                **2005**
                
                
                2004
                
                %
                    ChangeLong-term
                    debt
                **$**
                **884,604**
                
                $
                432,206
                
                105Unitholders’
                    equity
                **$**
                **1,404,826**
                
                $
                1,009,048
                
                39(1)Restated for the impact of the retroactive implementation of
                    the change in
                    accounting policies for exchangeable securities - non-controlling
                    interest
                    - see note 3(2)Excludes exchangeable shares(3)Includes
                    dilutive impact of unit options, exchangeable shares and convertible
                    debentures.
 3
 TABLE
            OF CONTENTS
  **Operational
        highlights**
  **Quarter
                    ended December 31,**
                
                **Year
                    Ended December 31,**(000s
                    except per unit amounts)COGP
                    and USOGP combined
                
                **2005**
                
                2004
                %
                    Change
                
                
                **2005**
                
                2004
                %
                    Change**Oil
                    and Gas Production**Daily
                    productionLight/medium
                    crude oil (bpd)
                
                **14,051**
                
                14,012
                -
                
                
                **14,979**
                
                10,146
                48Heavy
                    oil (bpd)
                
                **3,195**
                
                6,536
                (51)
                
                
                **4,358**
                
                6,608
                (34)Natural
                    gas liquids (bpd)
                
                **1,653**
                
                1,770
                (7)
                
                
                **1,596**
                
                1,494
                7Natural
                    gas (mcfpd)
                
                **73,363**
                
                87,339
                (16)
                
                
                **77,095**
                
                77,022
                -Oil
                    equivalent (boed)(1)
                
                **31,126**
                
                36,874
                (16)
                
                
                **33,782**
                
                31,085
                9**Average
                    selling price (before hedges)**Light/medium
                    crude oil ($/bbl)
                $
                **55.31**
                $
                45.83
                21
                
                $
                **54.69**
                $
                45.01
                22Heavy
                    oil ($/bbl)
                $
                **28.62**
                $
                25.33
                13
                
                $
                **31.33**
                $
                28.72
                9Corporate
                    oil blend ($/bbl)
                $
                **50.36**
                $
                39.31
                28
                
                $
                **49.43**
                $
                38.59
                28Natural
                    gas liquids ($/bbl)
                $
                **49.44**
                $
                42.80
                16
                
                $
                **49.09**
                $
                40.68
                21Natural
                    gas ($/mcf)
                $
                **11.44**
                $
                6.56
                74
                
                $
                **8.43**
                $
                6.60
                28Oil
                    equivalent ($/boe)(1)
                $
                **57.50**
                $
                39.50
                46
                
                $
                **49.86**
                $
                39.12
                27Field
                    netback (before hedges) ($/boe)
                $
                **34.63**
                $
                22.33
                55
                
                $
                **29.97**
                $
                22.18
                35Field
                    netback (including hedges) ($/boe)
                $
                **28.33**
                $
                16.58
                71
                
                $
                **24.73**
                $
                16.31
                52**Midstream
                    services and marketing**Managed
                    volumes (bpd)
                
                **77,100**
                
                52,870
                46
                
                
                **64,740**
                
                57,484
                13EBITDA
                    (000s)(2)
                $
                **29,566**
                $
                17,957
                65
                
                $
                **70,689**
                $
                50,085
                41(1)Provident reports oil equivalent production converting natural
                    gas to oil
                    on a 6:1 basis.(2)EBITDA
                    is earnings before interest , taxes, depletion, depreciation,
                    accretion
                    and other non-cash items.
  4
 TABLE
            OF CONTENTS
  **Fourth
        quarter highlights**
  The
        fourth quarter highlights section provides commentary on the fourth quarter
        2005
        results compared to the fourth quarter of 2004. Definitions of terms used
        in
        this section, as appropriate, are defined in the year over year section of
        the
        Management’s Discussion and Analysis following later in this press
        release.
 
 
 **Consolidated
        cash flow from operations and cash distributions**
 **Three
                    months ended December 31,**($
                    000s, except per unit data)
                
                **2005**
                
                
                2004
                
                %
                    Change**Revenue,
                    Cash Flow and Distributions**Revenue
                    (net of royalties and financial derivative instruments)
                **$**
                **442,687**
                
                $
                369,435
                
                20Cash
                    flow from operations before changes in working capital and site
                    restoration
                **$**
                **96,298**
                
                $
                58,371
                
                65Per
                    weighted average unit - basic(1)
                **$**
                **0.57**
                
                $
                0.41
                
                39Per
                    weighted average unit - diluted(2)
                **$**
                **0.51**
                
                $
                0.40
                
                28Declared
                    distributions
                **$**
                **62,646**
                
                $
                52,064
                
                20Per
                    Unit(1)
                
                **0.36**
                
                
                0.36
                
                -Percent
                    of cash flow distributed
                
                **65%**
                
                
                89%
                
                (27)(1)Excludes
                    exchangeable shares(2)Includes
                    the dilutive impact of unit options, exchangeable shares and
                    convertible
                    debentures.
  Fourth
        quarter 2005 cash flow was $96.3 million, 65 percent above the $58.4 million
        of
        cash flow recorded in the fourth quarter of 2004. COGP 2005 fourth quarter
        cash
        flow was $52.0 million, 72 percent above the $30.3 million recorded in the
        comparable 2004 quarter. The main drivers for the COGP increase were the
        27
        percent increase in realized crude oil and natural gas liquids prices and
        the 75
        percent increase in realized natural gas prices partially offset by the 26
        percent reduction in production that reflects the 2,100 boed September 2005
        property disposition and production declines partially offset by incremental
        production added through capital expenditures. The Midstream business unit
        added
        $28.3 million to fourth quarter 2005 cash flow, 71 percent above the $16.6
        million recorded in the comparable 2004 quarter. About half of this increase
        is
        attributable to the Midstream NGL Acquisition, with the remainder the result
        of
        increased product premiums in 2005 over 2004. Cash flow from operations in
        USOGP
        increased 39 percent to $16.0 million driven by a 51 percent increase in
        production volumes compared to cash flow of $11.5 million in the comparable
        2004
        quarter.
 
 Declared
        distributions in the fourth quarter of 2005 totaled $62.6 million, 65 percent
        of
        cash flow from operations. This compares to $52.1 million of declared
        distributions in 2004, 89 percent of cash flow from operations.
 
 **Net
        Income**
 **Three
                    months ended December 31,**($
                    000s, except per unit data)
                
                **2005**
                
                
                2004(3)
                
                %
                    Change(Restated)Net
                    income (loss)
                **$**
                **54,501**
                
                $
                38,314
                
                42Per
                    weighted average unit
                  -
                    basic(1)
                
                **0.32**
                
                
                0.27
                
                19Per
                    weighted average unit
                  -
                    diluted(2)
                
                **0.32**
                
                
                0.27
                
                19(1)Based on weighted average number of trust units outstanding(2)Based
                    on weighted average number of trust units outstanding including
                    the
                    dilutive impact of the unit option plan, exchangeable shares
                    and
                    convertible debentures.(3)Restated
                    - note 3
  5
 TABLE
            OF CONTENTS
  Net
        income for the fourth quarter of 2005 increased 42 percent to $54.5 million
        compared to a $38.3 million of net income in the comparable 2004 quarter.
        The
        fourth quarter earnings reflect the impact of higher commodity prices in
        COGP,
        higher production in USOGP as well as significant income generated from the
        Midstream business unit.
 
 The
        COGP
        business segment contributed $34.9 million of net income, $8.8 million above
        2004 fourth quarter income of $26.1 million. The increase in the fourth quarter
        of 2005 reflects increased EBITDA due to higher crude oil and natural gas
        prices, partially offset by natural production declines and an increased
        future
        income tax charge of $5.0 million compared to a $12.6 million recovery in
        the
        fourth quarter of 2004.
 
 The
        Midstream unit contributed $24.1 million of net income in the fourth quarter
        of
        2005, as compared to the $10.8 million of net income in the fourth quarter
        of
        2004. The increase reflects higher product premiums in 2005 and the impact
        of
        the Midstream NGL Acquisition.
 
 USOGP
        incurred a net loss of $4.5 million in the fourth quarter of 2005 with a
        comparative net income of $1.4 million for 2004. The decrease in the fourth
        quarter of 2005 reflects an increased future income tax charge of $18.3 million,
        which more than offsets higher pre-tax income due to an increase in production
        resulting from the acquisition of the Nautilus properties combined with
        unrealized gains on financial derivatives in the fourth quarter of
        2005.
 
 Comparative
        figures for fourth quarter 2004 net income have been restated to reflect
        the
        retroactive application of changes in accounting policy for exchangeable
        shares
        - non-controlling interest that resulted in a reduction to net income of
        $0.9
        million.
 
 
 **Taxes**
 **Three
                    months ended December 31,**($
                    000s)
                
                **2005**
                
                
                2004
                
                %
                    ChangeCapital
                    taxes
                $
                **1,103**
                
                $
                2,547
                
                (57)Current
                    and withholding taxes (recovery)
                
                **(1,296)**
                
                
                664
                
                (295)Future
                    income tax expense (recovery)
                
                **23,327**
                
                
                (10,000)
                
                333$
                **23,134**
                
                $
                (6,789)
                
                441
  Capital
        taxes in the fourth quarter totaled $1.1 million, a decrease of $1.4  million
        from the $2.5 million recorded in the fourth quarter of 2004. The decrease
        reflects an adjustment for the legislated phase-out of the large corporations
        tax, netted against the increase in the Saskatchewan resource surcharge that
        is
        sensitive to crude oil prices.
 
 The
        current and withholding tax recovery is $1.3  million
        in the fourth quarter of 2005 with a comparative expense of $0.7 million
        in the
        fourth quarter of 2004. These taxes arise from Provident’s U.S. based
        operations. The recovery in the quarter was due to the immediate deductibility
        of capital expenditures for income tax purposes of drilling expenditures
        incurred in the quarter.
  The
        2005
        fourth quarter future tax expense of $23.3 million compares to a $10.0 million
        future tax recovery in the fourth quarter of 2004. The future tax expense
        in the
        fourth quarter of 2005 resulted from changes to estimated tax pools in both
        Canada and the U.S.A., partially offset by increases in estimated royalty
        and
        interest charges by the Trust to subsidiaries which reduced estimated tax
        pool
        claims.
 
 
 **Reconciliation
        of non-GAAP measure**
 The
        Trust
        calculates earnings before interest, taxes, depletion, depreciation and
        accretion and other non-cash items (EBITDA) within its segment disclosure.
        EBITDA is a non-GAAP measure. A reconciliation between EBITDA and income
        before
        taxes and non-controlling interests follows:
  6
 TABLE
            OF CONTENTS
 **Three
                    months ended December 31,**EBITDA
                    Reconciliation($
                    000s)
                
                **2005**
                
                2004**EBITDA**
                $
                **103,542**
                $
                68,455Adjusted
                    for:Interest
                    and non-cash expenses excluding unrealized
                  gain
                    on financial instruments
                
                **(56,828)**
                
                (60,921)Unrealized
                    gain on financial instruments
                
                **31,943**
                
                25,083Income
                    before taxes and non-controlling interests
                $
                **78,657**
                $
                32,617
 
 
 **Interest
        Expense**
 **Three
                    months ended December 31,**($
                    000s)
                
                **2005**
                
                
                2004
                
                %
                    ChangeInterest
                    on bank debt
                **$**
                **4,100**
                
                $
                3,365
                
                22Interest
                    on debentures
                
                **3,651**
                
                
                3,981
                
                (8)Total
                    cash interest
                
                **7,751**
                
                
                7,346
                
                6Non
                    -cash accretion expense - convertible debentures
                
                **(752)**
                
                
                (1,165)
                
                (35)Total
                    interest including accretion on convertible debentures
                **$**
                **6,999**
                
                $
                6,181
                
                13
  Cash
        interest expense increased for the quarter as compared to the same quarter
        in
        2004 due to the increase in the overall size of Provident, with commensurate
        increases in debt levels.
 
 
 **Commodity
        Price Risk Management Program (CPRMP)**
 
 The
        Trust
        continues to execute a commodity price risk management program that is designed
        to limit the Trust’s exposure to downturns in commodity prices and to protect
        monthly cash distributions. Our hedging strategy uses structures that provide
        a
        floor price while allowing upside participation in a rising price
        market.
 
 In
        accordance with the Trust’s credit policy, the Trust mitigates associated credit
        risk by limiting financial derivative transactions to counterparties with
        investment grade credit ratings and obtaining financial guarantees from certain
        counterparties.
  7
 TABLE
            OF CONTENTS
  **Activity
        in the Fourth Quarter:**
 
 The
        following is a summary of the net cash flow to settle Commodity contracts
        during
        the fourth quarter of 2005. For comparative purposes, the 2004 amounts are
        also
        summarized.
 
 **a)
        Crude oil**
 
 For
        the
        quarter ending December 31, 2005, Provident paid $16.5 million to settle
        various
        oil market based contracts on an aggregate volume of 0.6 million barrels.
        For
        comparison, during the quarter ending December 31, 2004, Provident paid $16.5
        million to settle various oil market based contracts on an aggregate volume
        of
        1.4 million barrels. As at December 31, 2005 the estimated value of contracts
        in
        place if settled at December 31 market prices would have resulted in an
        opportunity cost of $7.1 million (2004 - $25.2 million).
 
 **b)
        Natural Gas**
 
 For
        the
        quarter ending December 31, 2005, Provident paid $4.1 million to settle various
        natural gas market based contracts on an aggregate volume of 1.5 million
        gj’s.
        For comparison, during the quarter ending December 31, 2004, Provident paid
        $2.0
        million to settle various natural gas market based contracts on an aggregate
        volume of 8.4 million gj’s. As at December 31, 2005 the estimated value of
        contracts in place if settled at December 31 market prices would have resulted
        in an opportunity cost of $6.5 million (2004 - opportunity gain of $0.3
        million).
 
 **c)
        Midstream**
 
 For
        the
        quarter ending December 31, 2005 Provident paid $1.7 million (2004 - $0.3
        million gain) on midstream margin stabilization hedging activities. As at
        December 31, 2005 the estimated value of contracts in place settled at December
        31 market prices would have resulted in an opportunity cost of $0.4 million
        (2004 - opportunity gain of $0.2 million).
 
 **d)
        Foreign exchange contracts**
 
 As
        at
        December 31, 2005 the estimated value of contracts in place settled at December
        31 foreign exchange rates would have resulted in an opportunity cost of $
        0.1
        million (2004 - opportunity gain of $0.2 million). The foreign exchange gains
        have been included as a component of foreign exchange gain and other and
        allocated to their respective business segments.
 
 
 Provident’s
        Commodity Price Risk Management Program is also discussed in the year over
        year
        section of Management’s Discussion and Analysis and in Note 17 to the
        consolidated financial statements.
  8
 TABLE
            OF CONTENTS
  **COGP
        segment review**
 
 **Crude
        Oil Price**
 
 The
        following prices are net of transportation expense.
  COGP
                **Three
                    months ended December 31,**($
                    per bbl)
                
                **2005**
                
                
                2004
                %ChangeWTI
                    (US$)
                **$**
                **60.02**
                
                **$**
                48.27
                24Exchange
                    rate (from US$ to Cdn$)
                **$**
                **1.17**
                
                **$**
                1.21
                (3)WTI
                    expressed in Cdn$
                **$**
                **70.22**
                
                **$**
                58.41
                20Corporate
                    realized crude oil and natural gas liquids price before hedging
                    (Cdn$)
                **$**
                **45.44**
                
                **$**
                35.86
                27Corporate
                    realized light/medium oil price before hedging (Cdn$)
                **$**
                **52.28**
                
                **$**
                42.00
                24Corporate
                    realized heavy oil price before hedging (Cdn$)
                **$**
                **28.62**
                
                **$**
                25.33
                13Corporate
                    realized natural gas liquids price before hedging (Cdn)
                **$**
                **49.62**
                
                $
                42.66
                16
  In
        the
        fourth quarter of 2005 COGP’s realized oil and natural gas liquids price, prior
        to the impact of hedging, increased by 27 percent to $45.44 per barrel compared
        to $35.86 in the fourth quarter of 2004. The 2005 increase related to a higher
        US$ WTI crude oil price and lower conventional heavy oil volumes as a percentage
        of total mix, partially offset by a stronger Canadian dollar and wider
        differentials on heavy oil pricing relative to WTI.
 
 **Natural
        gas price**
 
 The
        following prices are net of transportation expense.
 COGP**Three
                    months ended December 31,**($
                    per mcf)
                
                **2005**
                
                
                2004
                %
                    ChangeAECO
                    (Cdn$) per mcf
                $
                **11.67**
                
                $
                7.07
                65Gas
                    revenue per mcf before hedging(Cdn$)
                $
                **11.40**
                
                $
                6.53
                75
 COGP’s
        fourth quarter 2005 realized natural gas price, prior to the impact of hedging,
        increased 75 percent as compared to the fourth quarter of 2004, higher than
        the
        increase in the benchmark AECO index price of 65 percent. Provident markets
        to
        aggregators and sells to the spot market on monthly or daily indices and
        receives prices which take into account heat content. Provident’s realized
        prices and changes in prices are therefore different than benchmark
        indices.
 
 **Production**
 **Three
                    months ended December 31,**COGP**2005**
                2004
                %Change**Daily
                    production**Crude
                    oil - Light/Medium (bpd)
                **6,866**
                9,281
                (26)-
                    Heavy (bpd)
                **3,195**
                6,536
                (51)Natural
                    gas liquids (bpd)
                **1,617**
                1,746
                (7)Natural
                    gas (mcfd)
                **71,168**
                85,803
                (17)Oil
                    equivalent (boed)(1)
                **23,539**
                31,864
                (26)(1)Provident reports equivalent production converting natural gas
                    to oil on a
                    6:1 basis.
 
 Production
        decreased 26 percent to 23,539 boed during the fourth quarter of 2005 as
        compared to 31,864 boed in 2004. The decrease reflects the September 29,
        2005
        disposition of various non-core properties that averaged approximately 2,100
        boed and the natural production declines including higher than expected declines
        in heavy oil
  9
 TABLE
            OF CONTENTS
  partially
        offset by drilling and optimization activities. Production declines in COGP’s
        heavy oil areas in excess of what was expected were mainly attributable to
        one
        field with declines in the other fields consistent with similar type of
        properties. Provident’s production risk is mitigated by not having any single
        property providing greater than 10 percent of its total production.
 
 Production
        for the fourth quarter of 2005 was weighted 50 percent natural gas, 36 percent
        medium/light crude oil and natural gas liquids and 14 percent heavy oil.
        This
        compared to fourth quarter 2004 production weighted 45 percent natural gas,
        35
        percent medium/light oil and natural gas liquids and 21 percent heavy oil.
        Quarter-over-quarter, the change in mix reflects increased capital spending
        on
        natural gas opportunities, natural production declines and the 2,100 boed
        September 2005 property disposition that included approximately 1,010 boed
        of
        heavy oil, which typically has a lower netback than the other
        commodities.
 
 COGP’s
        production summarized by core areas is as follows:
  COGP**Three
                    months ended**
                  **December
                    31, 2005**
                West
                    Central
                  Alberta
                Southern
                  Alberta
                Southern
                  Saskatchewan
                Lloydminister
                Other
                **Total****Daily
                    production**Crude
                    oil - Light/Medium (bpd)
                1,057
                2,541
                2,063
                1,204
                1
                **6,866**-
                    Heavy (bpd)
                -
                -
                -
                3,195
                -
                **3,195**Natural
                    gas liquids (bpd)
                1,418
                179
                1
                19
                -
                **1,617**Natural
                    gas (mcfd)
                38,343
                22,722
                9,112
                978
                13
                **71,168**Oil
                    equivalent (boed)(1)
                8,865
                6,507
                3,583
                4,581
                3
                **23,539**
 COGP**Three
                    months ended**
                  **December
                    31, 2004**
                West
                    Central
                  Alberta
                Southern
                  Alberta
                Southern
                  Saskatchewan
                Lloydminister
                Other
                Total**Daily
                    production**Crude
                    oil - Light/Medium (bpd)
                1,395
                3,069
                3,012
                1,787
                18
                9,281-
                    Heavy (bpd)
                -
                -
                -
                6,536
                -
                6,536Natural
                    gas liquids (bpd)
                1,576
                142
                -
                22
                6
                1,746Natural
                    gas (mcfd)
                47,705
                27,967
                4,314
                5,030
                787
                85,803Oil
                    equivalent (boed)(1)
                10,922
                7,872
                3,731
                9,184
                155
                31,864(1)Provident reports equivalent production converting natural gas
                    to oil on a
                    6:1 basis.
  Internal
        development activities included 40.7 net wells drilled during the quarter
        ended
        December 31, 2005. Provident’s most active area, southern Saskatchewan realized
        24.1 net wells drilled focused on a shallow gas-drilling program that will
        realize production and reserve adds for several years. Poor weather conditions
        in south Saskatchewan delayed tie-in operations at the beginning of the third
        quarter of 2005 so these wells continued to be brought on production in the
        fourth quarter of 2005. Provident’s other core areas remain active with
        additional activity in southern Alberta where Provident is actively drilling
        in
        shallow gas wells and in Lloydminster where Provident is drilling low risk
        heavy
        oil wells. In West Central Alberta, Provident continues with its strategy
        of
        farming out high risk exploration land to generate cash flow with minimal
        or no
        capital outlay.
  10
 TABLE
            OF CONTENTS
 
 **Revenue
        and royalties**
 
 Revenue
        figures are presented net of transportation expense.
 COGP**Three
                    months ended December 31,**($
                    000s except per boe and mcf data)
                
                **2005**
                
                2004
                %Change**Oil**Revenue
                **$**
                **41,440**
                $
                50,282
                (18)Realized
                    loss on non-hedging derivative instruments
                
                **(11,651)**
                
                (16,511)
                (29)Royalties
                    (net of ARTC)
                
                **(8,969)**
                
                (10,230)
                (12)Net
                    revenue
                **$**
                **20,820**
                $
                23,541
                (12)Net
                    revenue (per barrel)
                **$**
                **22.49**
                $
                16.18
                39Royalties
                    as a percentage of revenue
                
                **21.6%**
                
                20.3%**Natural
                    gas**Revenue
                **$**
                **74,623**
                $
                51,637
                45Realized
                    loss on non-hedging derivative instruments
                
                **(1,521)**
                
                (2,001)
                (24)Royalties
                    (net of ARTC)
                
                **(15,503)**
                
                (11,107)
                40Net
                    revenue
                **$**
                **57,599**
                $
                38,529
                49Net
                    revenue (per mcf)
                **$**
                **8.80**
                $
                4.95
                78Royalties
                    as a percentage of revenue
                
                **20.8%**
                
                21.5%**Natural
                    gas liquids**Revenue
                **$**
                **7,382**
                $
                6,852
                8Royalties
                
                **(2,013)**
                
                (1,464)
                38Net
                    revenue
                **$**
                **5,369**
                $
                5,388
                -Net
                    revenue (per barrel)
                **$**
                **36.09**
                $
                33.54
                8Royalties
                    as a percentage of revenue
                
                **27.3%**
                
                21.4%**Total**Revenue
                **$**
                **123,445**
                $
                108,771
                13Realized
                    loss on non-hedging derivative instruments
                
                **(13,172)**
                
                (18,512)
                (29)Royalties
                    (net of ARTC)
                
                **(26,485)**
                
                (22,801)
                16Net
                    revenue
                **$**
                **83,788**
                $
                67,458
                24Net
                    revenue per boe
                **$**
                **38.69**
                $
                23.01
                68Royalties
                    as a percentage of revenue
                
                **21.5%**
                
                21.0%
   Quarter-over-quarter,
        2005 COGP production revenue was $123.4 million, an increase of 13 percent
        from
        $108.8 million in 2004. The increase in revenue is a result of a 27 percent
        increase in Provident’s realized crude oil and natural gas liquids price and a
        75 percent increase Provident’s realized natural gas prices offset by lower
        production. Total royalties as a percentage of revenue remained relatively
        constant at 21-22 percent. The preceding factors, as well as the decrease
        in
        opportunity cost of hedging activities, account for net revenue of $83.8
        million
        in the fourth quarter of 2005, 24 percent above the $67.5 million recorded
        in
        the fourth quarter of 2004. Net revenue per boe in the fourth quarter of
        2005
        was $38.69 per boe, an increase of 68 percent from $23.01 per boe in the
        fourth
        quarter of 2004. The increase is a result of an increase in natural gas
        production to 50 percent of total mix combined with the increase in realized
        prices.
  11
 TABLE
            OF CONTENTS
  **Production
        expenses**
 COGP
                **Three
                    months ended December 31,**($
                    000s, except per boe data)
                
                **2005**
                
                
                2004
                %
                    ChangeProduction
                    expenses
                **$**
                **23,437**
                
                $
                26,431
                (11)Production
                    expenses (per boe)
                **$**
                **10.82**
                
                $
                9.02
                20
 
 Fourth
        quarter 2005 production expenses decreased 11 percent to $23.4 million from
        $26.4 million in the comparable 2004 quarter due to lower production volumes.
        On
        a boe basis quarter over quarter production expenses have risen to $10.82
        per
        boe, a 20 percent increase from $9.02 per boe in the comparable 2004 quarter.
        Cost increases in power and fuel, chemicals, well servicing, maintenance
        and
        fluid hauling reflect higher commodities prices and labour costs and combined
        with the lower production volumes result in higher operating costs per
        boe.
 
 
 **Operating
        netback**
 COGP
                **Three
                    months ended December 31,**($
                    per boe)
                
                **2005**
                
                
                2004
                %
                    Change**COGP
                    oil equivalent netback per boe**Gross
                    production revenue
                $
                **57.00**
                
                $
                37.10
                54Royalties
                    (net of ARTC)
                
                **(12.23)**
                
                
                (7.78)
                57Operating
                    costs
                
                **(10.82)**
                
                
                (9.02)
                20Field
                    operating netback
                $
                **33.95**
                
                **$**
                20.30
                67Realized
                    loss on non-hedging derivative instruments
                
                **(6.08)**
                
                
                (6.31)
                (4)Operating
                    netback after non-hedging derivative instruments
                $
                **27.87**
                
                $
                13.99
                99
  COGP
        operating netbacks have transportation expense netted against gross production
        revenue.
  The
        fourth quarter 2005 field operating netback of $33.95 per boe was 67 percent
        above the $20.30 per boe in the comparable quarter in 2004. This reflects
        COGP’s
        higher realized prices for both natural gas and crude oil and natural gas
        liquids. These prices combined with a shift in COGP’s production mix to include
        more high netback natural gas and less low netback heavy oil results in a
        significant improvement in the field operating netback. Reflected in the
        shift
        in the production mix is the September 2005 disposition of 2,100 boed of
        low
        netback non-core properties. Royalties, which are price sensitive, increased
        by
        57 percent on a boe basis reflecting the higher prices, prior to the impact
        of
        hedging. The fourth quarter 2005 operating netback after hedging increased
        by 99
        percent to $27.87 from $13.99 reflecting the explanation above as well as
        lower
        2005 fourth quarter hedging opportunity costs of $6.08  per
        boe
        compared to $6.31 in the comparable quarter in 2004.
 
 
 **General
        and administrative**
 
 The
        following table does not incorporate the COGP portion of non-cash unit based
        compensation expenses associated with Provident’s unit option plan and
        restricted and performance unit plan. Fourth quarter non-cash unit based
        compensation expenses for COGP totaled $1.9 million compared to $0.2 million
        recovery in the comparable period .
 COGP
                
                **Three
                    months ended December 31,**($
                    000s, except per boe data)
                
                **2005**
                
                
                2004
                %
                    ChangeCash
                    general and administrative
                $
                **3,727**
                
                $
                3,918
                (5)Cash
                    general and administrative per boe
                $
                **1.72**
                
                $
                1.34
                28
  12
 TABLE
            OF CONTENTS
  Cash
        general and administrative expenses for COGP in the fourth quarter decreased
        5
        percent to $3.7  million
        from $3.9 million recorded in the 2004 comparable quarter. On a boe basis
        the
        cash general and administrative expenses recorded in fourth quarter 2005
        increased 28 percent to $1.72 from $1.34 in the fourth quarter of 2004. The
        increase in general and administrative expenses reflects additional costs
        associated with a more competitive landscape affecting the cost of hiring
        and
        compensating employees and consultants, as well as increases in rent, insurance
        and compliance and reporting costs.
 
 COGP
        operations are capable of absorbing additional production, particularly in
        existing core areas, with little impact on general and administrative expenses.
        2006 costs per boe are forecasted to increase as a result of further increases
        in costs associated with compliance (including costs associated with the
        implementation of procedures and documentation to be in compliance with the
        U.S.
        Sarbanes-Oxley Act) and a more competitive landscape impacting the cost of
        hiring and compensating employees.
 
 
 **Capital
        expenditures**
 COGP**Three
                    months ended December 31,**($
                    000s)
                
                **2005**
                
                
                2004West
                    central and southern Alberta
                $
                **7,259**
                
                $
                8,413Southeast
                    and southwest Saskatchewan
                
                **11,931**
                
                
                8,201Lloydminster
                
                **2,497**
                
                
                4,799Office
                    and other
                
                **(13)**
                
                
                185Total
                    additions
                $
                **21,674**
                
                $
                21,598Property
                    acquisitions
                
                **(94)**
                
                
                413Property
                    dispositions
                $
                **461**
                
                $
                6,603
  In
        the
        fourth quarter of 2005, Provident’s COGP business unit spent $21.7 million on
        capital expenditures. In the southeast and southwest Saskatchewan core areas
        $11.9 million was spent on shallow gas drilling and carrying out several
        recompletions ($6.6 million). Facility work ($5.3 million) in the area focused
        on infrastructure to tie-in future shallow gas production in southwest
        Saskatchewan. In southern Alberta $5.0 million was spent on drilling activities
        and recompletions ($3.3 million) and facility upgrades ($1.6 million). In
        the
        Lloydminster core area $2.5 million was spent primarily on drilling ($1.5
        million) and facility work ($0.9 million) and in West central Alberta $2.3
        million was spent largely on non-operated drilling ($0.6 million) and facility
        work ($1.6 million).
 
 Provident’s
        COGP business unit spent $21.6 million in the fourth quarter of 2004 on various
        drilling, re-completing, optimization and facility projects.
 
 
 **Depletion,
        depreciation and accretion (DD&A)**
 COGP
                
                
                **Three
                    months ended December 31,**($
                    000s, except per boe data)
                
                
                
                
                
                **2005**
                
                
                2004DD&A
                
                
                
                
                **$**
                **33,809**
                
                $
                45,315DD&A
                    per boe
                
                
                
                
                **$**
                **15.61**
                
                $
                15.46
  COGP
        DD&A rate of $15.61 per boe remained relatively flat for the fourth quarter
        of 2005 compared to $ 15.46 per boe for the fourth quarter of 2004. Accretion
        expense associated with asset retirement obligations was $0.5 million in
        the
        fourth quarter of 2005 compared to $0.6 million in the fourth quarter of
        2004.
        The decrease is mainly a result of the non-core property disposition in the
        third quarter of 2005.
  13
 TABLE
            OF CONTENTS
  **USOGP
        Segment Review**
 
 The
        USOGP
        business unit incorporates activities from Provident’s subsidiary, Breitburn
        Energy LP (Breitburn), an oil and gas exploitation and production business
        based
        in Los Angeles, California.
 
 On
        March
        2, 2005 Breitburn acquired Nautilus Resources, LLC, a U.S. private company
        with
        operations focused in the Big Horn and Wind River basins of Wyoming for cash
        consideration of $90.2 million and acquisition costs of $1.2
        million.
 
 **USOGP
        Pricing**
 USOGP
                **Three month ended December 31,****2005**
                
                
                2004
                
                %
                    ChangeUSOGP
                    realized crude oil and natural gas liquids price before hedging
                    (Cdn$ per
                    bbl)
                $
                **58.11**
                
                $
                53.34
                
                9Natural
                    Gas (Cdn$ per mcf)
                
                **12.97**
                
                
                8.02
                
                62
 The
        majority of USOGP oil production is light, sweet crude that attracts smaller
        differentials to benchmark prices relative to heavier blends. Realized prices
        before hedging increased by nine percent while WTI increased by 24 percent
        in
        the fourth quarter of 2005 compared with the fourth quarter of 2004. This
        was
        due to production and revenue from the acquired Wyoming properties being
        included in 2005 average prices. Oil production from the Wyoming properties
        is a
        heavier blend of crude oil that attracts wider differentials from WTI pricing,
        and generate approximately 20 percent less revenue per boe than Southern
        California operations. Production in Wyoming represents approximately 30
        percent
        of fourth quarter 2005 production.
 
 
 **Production**
 **Three
                    month ended December 31,**USOGP
                
                **2005**
                
                2004
                
                %
                    Change**Daily
                    production - by product**Crude
                    oil - Light/Medium (bpd)
                
                **7,185**
                
                4,730
                
                52Natural
                    gas liquids (bpd)
                
                **36**
                
                24
                
                50Natural
                    gas (mcfd)
                
                **2,195**
                
                1,536
                
                43Oil
                    equivalent (boed)(1)
                
                **7,587**
                
                5,010
                
                51(1)Provident reports equivalent production converting natural gas
                    to oil on a
                    6:1 basis.
 
 **Three
                    month ended December 31,**USOGP
                
                **2005**
                
                2004
                
                %
                    Change**Daily
                    Production - by area (boed)****(1)**Los
                    Angeles
                
                **3,974**
                
                3,558
                
                12Santa
                    Maria
                
                **1,356**
                
                1,364
                
                (1)Wyoming
                
                **2,257**
                
                88
                
                2,465**7,587**
                
                5,010
                
                51(1)Provident reports equivalent production converting natural gas
                    to oil on a
                    6:1 basis.
 
 USOGP
        production increased 2,577 boe per day or 51 percent in the fourth quarter
        of
        2005 when compared to the fourth quarter of 2004. The increase in Los Angeles
        production is a result of successful drilling and optimization activities.
        The
        Wyoming increase is primarily attributable to the addition of the Nautilus
        properties on March 2, 2005.
  14
 TABLE
            OF CONTENTS
  **Revenue
        and royalties**
 
 The
        following table outlines USOGP revenue and royalties by product line. The
        table
        excludes revenues earned from operating certain properties ($0.3  million
        in 2005 and $0.3 million in 2004) on behalf of third parties.
 USOGP
                **Three
                    month ended December
                    31,**($
                    000s, except per boe and mcf amounts)
                **2005**
                
                2004
                %
                    Change**Oil**Revenue
                **$**
                **38,583**
                $
                23,212
                66Realized
                    loss on non-hedging derivative instrument
                
                **(4,875)**
                
                (81)
                5,919Royalties
                
                **(3,703)**
                
                (2,041)
                81Net
                    revenue
                **$**
                **30,005**
                $
                21,090
                42Net
                    revenue (per bbl)
                **$**
                **45.39**
                $
                48.46
                (6)Royalties
                    as a percentage of revenue
                
                **9.6%**
                
                8.8%**Natural
                    gas**Revenue
                **$**
                **2,620**
                $
                1,134
                131Royalties
                
                **(370)**
                
                -
                -Net
                    revenue
                **$**
                **2,250**
                $
                1,134
                98Net
                    revenue (per mcf)
                **$**
                **11.14**
                $
                6.56
                70Royalties
                    as a percentage of revenue
                
                **14.1%**
                
                0.0%**Natural
                    gas liquids**Revenue
                **$**
                **135**
                $
                118
                14Royalties
                
                **(3)**
                
                -
                -Net
                    revenue
                **$**
                **132**
                $
                118
                12Net
                    revenue (per bbl)
                **$**
                **40.06**
                $
                52.23
                (23)Royalties
                    as a percentage of revenue
                
                **2.1%**
                
                0.0%**Total**Revenue
                **$**
                **41,338**
                $
                24,464
                69Realized
                    loss on non-hedging derivative instrument
                
                **(4,875)**
                
                (81)
                5,919Royalties
                
                **(4,076)**
                
                (2,041)
                100Net
                    revenue
                **$**
                **32,387**
                $
                22,342
                45Net
                    revenue (per boe)
                **$**
                **46.40**
                $
                48.47
                (4)Royalties
                    as a percentage of revenue
                
                **9.9%**
                
                8.3%
  Total
        production revenue for the fourth quarter of 2005 was $41.3 million or 69
        percent higher than the $24.5 million of revenue in the fourth quarter of
        2004.
        The increase was primarily driven by higher commodity prices combined with
        revenues from the Wyoming properties acquired in the first quarter of 2005.
        Total net revenue increased $10.1 million or 45 percent in the fourth quarter
        of
        2005 compared to the fourth quarter of 2004. The increase was driven by higher
        commodity prices combined with the revenues from the acquired Wyoming properties
        offset by increases in realized losses on non-hedging derivative instruments.
        The increase in royalties as a percentage of revenue is primarily driven
        by the
        addition of the acquired Wyoming properties as these properties have, on
        average, higher royalty rates than Southern California production.
  15
 TABLE
            OF CONTENTS
  **Production
        expenses**
 
 USOGP
              **Three
                  months ended December 31,**($
                  000s, except per boe amounts)
              
              **2005**
              
              
              2004
              %
                  ChangeProduction
                  expenses
              **$**
              **11,510**
              
              $
              6,989
              65Production
                  expenses (per boe)
              **$**
              **16.49**
              
              $
              15.16
              9
   Production
        expenses increased 65 percent to $11.5 million in the fourth quarter of 2005
        compared to $7.0 million for the comparable quarter in 2004. This increase
        is
        due to the 51 percent increase in production volumes and higher costs on
        a boe
        basis. Operating costs per boe have increased nine percent to $16.49 in the
        fourth quarter of 2005 from $15.16 in the comparable quarter in 2004. This
        change reflects both the increase in utilities and other costs and
        services  driven
        by
        the high commodity price environment as well as higher operating cost crude
        oil
        wells that were returned to production to take advantage of high crude oil
        prices. Increases in production expense per boe were tempered by expenses
        from
        acquired properties in Wyoming. Wyoming production expenses are, on average,
        20
        percent lower than production expenses incurred in the Southern California
        operations.
 
 
 **General
        and administrative**
 USOGP
                **Three
                    months ended December 31,**($
                    000s, except per boe amounts)
                
                **2005**
                
                
                2004
                %
                    ChangeCash
                    general and administrative
                **$**
                **4,525**
                
                $
                2,264
                100Cash
                    general and administrative (per boe)
                **$**
                **6.48**
                
                $
                4.91
                32
  Cash
        general and administrative expenses in the fourth quarter at $4.5  million
        or $6.48  per
        boe
        is a 32 percent increase from the fourth quarter of 2004. The increase is
        primarily associated with an increase in personnel combined with an increased
        in
        short-term incentive plans to attract and retain personnel in a highly
        competitive environment.
 
 
 **Operating
        netback**
 USOGP
                **Three
                    months ended December 31,**($
                    per boe)
                
                **2005**
                
                2004
                %
                    Change**Netback**Gross
                    production revenue
                **$**
                **59.22**
                
                $
                53.08
                12Royalties
                
                **(5.84)**
                
                
                (4.43)
                32Operating
                    costs
                
                **(16.49)**
                
                
                (15.16)
                9Field
                    Operating Netback
                **$**
                **36.89**
                
                $
                33.49
                10Non-hedging
                    derivative instruments
                
                **(6.98)**
                
                
                (0.18)
                3,778Operating
                    netback after non-hedging derivative instruments
                **$**
                **29.91**
                
                $
                33.31
                (10)
  The
        operating netback for the fourth quarter of 2005 remains strong driven by
        high
        commodity prices partially offset by increased operating costs. The fourth
        quarter 2005 operating netback of $29.91 per boe is 10 percent lower than
        the
        $33.31 per boe due to the increased hedge losses incurred by USOGP operations.
        The majority of the hedges entered into in 2005, however, lapsed on December
        31,
        2005.
  16
 TABLE
            OF CONTENTS
  **Income
        taxes and cash taxes**
 USOGP
                **Three
                    months ended December 31,**($
                    000s)
                
                **2005**
                
                
                2004
                %
                    ChangeCapital,
                    current and withholding taxes
                $
                **(1,296)**
                
                $
                853
                (252)Future
                    income tax expense
                
                **18,320**
                
                
                -
                -$
                **17,024**
                
                $
                853
                1896
 
 Current
        and withholding taxes include current U.S. federal and state income taxes
        as
        well as accrued or paid U.S. withholding taxes on payments that have been
        or
        will be made from Breitburn Energy LP to Provident. The recovery in the quarter
        was due to the immediate deductibility of capital expenditures for income
        tax
        purposes of drilling expenditures incurred in the quarter. The 2005 future
        income tax expense resulted from deduction of drilling costs for tax purposes
        in
        2005 which are capitalized for accounting purposes and from changes to estimated
        tax pools.
 
 **Capital
        expenditures**
 
 USOGP
        capital expenditures for the fourth quarter of 2005 totaled $11.5 million.
        Of
        this total, $7.0 million was directed at drilling, optimization and facility
        upgrades at West Pico, Santa Fe Springs and Orcutt. $2.5 million was directed
        at
        drilling and optimization work in Wyoming, while $2.0 million was directed
        at
        optimization projects at smaller fields as well as head office related capital
        expenditures.
 
 USOGP
        capital expenditures for the fourth quarter of 2004 totaled $63.1 million.
        This
        included $58.5 million for the Orcutt property acquisition, $3.1 million
        to
        increase Breitburn’s working interest in certain wells at West Pico and
        Sawtelle, and $1.5 million on drilling, optimization and facility upgrades
        at
        West Pico and Santa Fe Springs. Optimization capital was partially focused
        at
        returning previously uneconomic wells to production to take advantage of
        the
        high commodity price environment.
  17
 TABLE
            OF CONTENTS
  **Midstream
        services and marketing segment review**
 
 The
        Midstream services and marketing business segment extracts, processes, stores,
        transports and markets natural gas liquids (NGL’s) across integrated assets in
        British Columbia, Alberta, Ontario and the United States.
 
 **NGL
        Acquisition**
 
 On
        December 13, 2005 Provident acquired NGL assets and the Kinetic marketing
        entity
        from EnCana Corporation (Midstream NGL Acquisition) for $772.3 million, net
        of
        cash acquired, including $38.9 million of working capital that includes $85.5
        million of inventory. The assets acquired are described in the year over
        year
        MD&A section. The fourth quarter results incorporate the results of
        operations associated with these Midstream assets since
        acquisition.
 
 **Operations
        - managed NGL volumes**
 
 Midstream
        managed approximately 77,100 bpd of NGL’s over the fourth quarter and closed the
        year with managed NGL volumes of approximately 140,640 bpd. This reflects
        enhanced operations of the Redwater facilities as well as the addition of
        the
        newly acquired Empress/Sarnia assets and NGL marketing. NGL product managed
        in
        the fourth quarter of 2004 was 52,870 bpd.
 
 **Product
        sales and service revenues**
 
 For
        the
        fourth quarter of 2005 product sales and services revenues were $295.6 million,
        compared to $251.9 million in the fourth quarter of 2004. The fourth quarter
        of
        2005 includes $67.2 million in product sales and services revenue associated
        with the Midstream NGL Acquisition. Excluding this additional amount, revenue
        declined by $23.5 million when compared to the fourth quarter of 2004. The
        reduction in revenue is due to the sale of certain crude oil marketing contracts
        on May 1, 2005 partially offset by higher product prices. Revenue figures
        are
        after elimination of intersegment transactions and include product sales
        related
        to transportation and fractionation (T&F), extraction, processing and
        marketing, additional fee for service revenues generated through storage
        and
        distribution services, and for the 2004 comparative quarter crude oil sales
        generated through oil marketing activities.
 
 **Cost
        of goods sold**
  The
        cost
        of goods sold was $245.0 million for the fourth quarter of 2005 compared
        to
        $221.6 million in the fourth quarter of 2004. The fourth quarter of 2005
        includes $58.1 million in cost of goods sold associated with the Midstream
        NGL
        Acquisition. Excluding this additional amount, the cost of goods sold declined
        by $34.7 million when compared to the fourth quarter of 2004. This reduction
        in
        cost of goods sold is due to the sale of certain crude oil marketing contracts
        on May 1, 2005 offset by higher product prices. These figures are after
        elimination of intersegment transactions and relate to NGL product sales
        revenue
        included in the product sales and services revenue, where Provident has
        purchased natural gas liquids and for the comparative 2004 quarter for oil
        purchased pursuant to oil marketing activities. The NGL costs would be
        applicable to the T&F and marketing contracts and a small percentage of
        volume delivered from the Younger facility on which Provident manages extraction
        economics.
 
 **Product
        margin**
 
 Product
        margin is the revenue less the cost of good sold and is representative of
        the
        margins obtained on marketed products, however it is affected by fee for
        service
        revenues that are grouped in with product sales and service revenues. In
        the
        fourth quarter of 2005, $50.6 million or a 17 percent product margin was
        generated on $295.6 million of product sales and service revenues compared
        to
        $30.3 million or a 12 percent product margin generated on $251.9 million
        of 2004
        fourth quarter product sales and service revenues. The 2005 fourth quarter
        product margin would be expected to be higher than the comparable fourth
        quarter
        of 2004 which included the lower margin crude oil marketing activities. In
        future quarters the product margin will be subject to a wider range of
        variability driven by the Midstream NGL Acquisition that increases exposure
        to
        extraction economics.
  18
 TABLE
            OF CONTENTS
  **Fractionation
        Spread Support Program**
  As
        part
        of the Midstream NGL Acquisition the vendor provided a fractionation support
        agreement that is more fully described in the 2005 year over year Management’s
        Discussion and Analysis section. The impact of the agreement on the fourth
        quarter of 2005 was a receipt of $5.2 million that resulted in a reduction
        in
        the cost of goods available for sale with no comparative for the fourth quarter
        of 2004.
 
 **Other
        expenses**
  Fourth
        quarter 2005 operating costs of $11.7 million (2004 - $10.1 million) represent
        normal operations and includes end December operating costs for the
        Empress/Sarnia system as well as the Redwater assets. General and administrative
        expenses were $5.8 million for the fourth quarter 2005 (2004 - $2.5 million).
        Increases in general and administrative expenses in the fourth quarter of
        2005
        as compared to 2004 resulted from allocation of costs and increased direct
        costs
        resulting from the Midstream NGL Acquisition which was negotiated, announced
        and
        closed in the fourth quarter 2005. Depreciation expense was $4.2 million
        for the
        three months ended December 31, 2005 (2004 - $2.8 million).
 
 
 **Earnings
        before interest, taxes, depletion, depreciation, accretion, and other non-cash
        items (“EBITDA”)**  **and
        cash flow from operations**
 
 The
        fourth quarter of 2005 results for the Midstream services and marketing business
        unit reflected in EBITDA, cash flow and net income benefited from efficient
        operations, marketing opportunities, increased revenues associated with storage
        and distribution services, the fractionation support agreement and 19 days
        of
        operating activities for the NGL Acquisition. Fourth quarter 2005 EBITDA
        of
        $29.6 million increased 64 percent
        from $18.0 million in the year ago quarter. Cash flow for the fourth quarter
        of
        2005 quarter was $ 28.3 million 71 percent
        above the $16.6 million for the fourth quarter 2004. About half of this increase
        is attributable to the Midstream NGL Acquisition with the remainder the result
        of increased product premiums in 2005 over 2004. Fourth quarter net income
        at
        $ 24.1 million
        was 123 percent above the $10.8 million of net income recorded in the fourth
        quarter of 2004.
 
 Management
        uses EBITDA to analyze the operating performance of the Midstream business
        unit.
        EBITDA as presented does not have any standardized meaning prescribed by
        Canadian GAAP and therefore it may not be comparable with the calculation
        of
        similar measures for other entities. EBITDA as presented is not intended
        to
        represent operating cash flow or operating profits for the period nor should
        it
        be viewed as an alternative to cash flow from operating activities, net earnings
        or other measures of financial performance calculated in accordance with
        Canadian GAAP. All references to EBITDA throughout this report are based
        on
        Earnings before interest, taxes, depletion, depreciation, accretion, and
        other
        non-cash items (“EBITDA”).
 
 **Capital
        expenditures**
  Midstream
        capital expenditures, excluding corporate acquisitions, for the fourth quarter
        of 2005 totaled $16.5 million. Included in this was $15.5 million of growth
        capital spent on new product handling facilities including the new condensate
        offloading and terminalling facilities announced in October 2005 as well
        as
        truck loading and a rail yard expansion. The remaining capital was spent
        on
        pipelines and in the Younger extraction plant. Capital spending amounted
        to $1.2
        million in the fourth quarter of 2004.
  19
 TABLE
            OF CONTENTS
  **2005
        Year end results**
  **Consolidated
        cash flow from operations and cash distributions**
 **Year
                    ended December 31,**($
                    000s, except per unit data)
                
                **2005**
                
                
                2004
                %
                    Change(Restated)**Revenue,
                    Cash Flow and Distributions**Revenue
                    (net of royalties and financial derivative instruments - see
                    Note 9 to the
                    consolidated financial statements)
                **$**
                **1,360,274**
                
                $
                1,109,857
                23Cash
                    flow from operations before changes in working capital and site
                    restoration expenditures
                **$**
                **311,188**
                
                $
                185,246
                68Per
                    weighted average unit - basic(1)
                **$**
                **1.95**
                
                $
                1.63
                20Per
                    weighted average unit - diluted(2)
                **$**
                **1.95**
                
                $
                1.63
                20Declared
                    distributions
                **$**
                **230,714**
                
                $
                164,628
                40Per
                    Unit(1)
                
                **1.44**
                
                
                1.44
                -Percent
                    of cash flow distributed
                
                **74%**
                
                
                89%
                (17)(1)Excludes
                    exchangeable shares(2)Includes
                    dilutive impact of unit options, exchangeable shares and convertible
                    debentures.
 
 For
        the
        year ended December 31, 2005, cash flow increased 68 percent or $126.0 million
        to $311.2 million from $185.2 million for 2004 (per unit in 2005 - $1.95;
        2004 -
        $1.63). COGP generated $185.1 million, USOGP $59.8 million, and Midstream
        $66.3
        million of cash flow during 2005. During 2004 COGP generated cash flow of
        $121.1
        million, USOGP $21.5 million, and Midstream $42.6 million.
 
 Canadian
        oil and gas operations contributed $64.0 million of the cash flow increase,
        a
        result of a 23 percent increase in realized crude oil and natural gas liquids
        price and a 28 percent increase in realized natural gas prices, offset by
        8
        percent lower production due to natural declines and a September property
        disposition of 2,100 boed outweighing incremental production adds brought
        on
        through capital expenditures. The U.S. oil and gas operations provided increased
        cash flow of $38.3 million in 2005, compared to 2004, representing a full
        year
        of production in 2005 from the U.S. operations that were acquired on June
        15,
        2004, as well as the contribution of the Nautilus properties, acquired in
        March
        of 2005. The Midstream segment accounted for $23.7 million of the increase
        in
        cash flow reflecting the marketing opportunity afforded by selling NGL’s into a
        rising market, increased fee for service revenues for storage and distribution
        and a $6.2 million contribution from 19 days of operations from the Midstream
        NGL Acquisition.
 
 Declared
        distributions in 2005 totaled $ 230.7 million, 74 percent of cash flow from
        operations. This compares to $164.6 million of declared distributions in
        2004,
        89 percent of cash flow from operations. Provident’s objective is to provide
        stable distributions to its unitholders. Distributions for 2006 are budgeted
        to
        be maintained at their current level.
 
 Management
        uses cash flow (before changes in non-cash working capital and site restoration
        expenditures) to analyze operating performance. Provident also reviews cash
        flow
        in setting monthly distributions and takes into account cash required for
        debt
        repayment and/or capital programs in establishing the amount to be distributed.
        Historically Provident has paid out between 74 percent and 102 percent of
        its
        annual cash flow as distributions to unitholders.
 
 Cash
        flow
        as presented does not have any standardized meaning prescribed by Canadian
        generally accepted accounting principles (GAAP) and therefore it may not
        be
        comparable with the calculation of similar measures for other entities. Cash
        flow as presented is not intended to represent operating cash flow or operating
        profits for the period nor should it be viewed as an alternative to cash
        flow
        from operating activities, net earnings or other measures of financial
        performance calculated in accordance with Canadian GAAP. All references to
        cash
        flow throughout this report are based on cash flow before changes in non-cash
        working capital and site restoration expenditures.
  20
 TABLE
            OF CONTENTS
 
 **Distributions**
  The
        following table summarizes distributions paid or declared by the Trust since
        inception:
 **Distribution Amount****Record
                    Date**
                
                **Payment
                    Date**
                
                **(Cdn$)**
                **(US$)***2005January
                    20, 2005
                
                February
                    15, 2005
                $
                0.12
                0.10February
                    18, 2005
                
                March
                    15, 2005
                
                0.12
                0.10March
                    21, 2005
                
                April
                    15, 2005
                
                0.12
                0.10April
                    20, 2005
                
                May
                    13, 2005
                
                0.12
                0.10May
                    19, 2005
                
                June
                    15, 2005
                
                0.12
                0.10June
                    20, 2005
                
                July
                    15, 2005
                
                0.12
                0.10July
                    20, 2005
                
                August
                    15, 2005
                
                0.12
                0.10August
                    19, 2005
                
                September
                    15, 2005
                
                0.12
                0.10September
                    20, 2005
                
                October
                    14, 2005
                
                0.12
                0.10October
                    21, 2005
                
                November
                    15, 2005
                
                0.12
                0.10November
                    21, 2005
                
                December
                    15, 2005
                
                0.12
                0.10December
                    20, 2005
                
                January
                    13, 2006
                
                0.12
                0.102005
                    Cash Distributions paid as declared
                
                
                $
                1.44
                1.202004
                    Cash Distributions paid as declared
                
                
                
                1.44
                1.102003
                    Cash Distributions paid as declared
                
                
                
                2.06
                1.472002
                    Cash Distributions paid as declared
                
                
                
                2.03
                1.292001
                    Cash Distributions paid as declared
                  -
                    March 2001 - December 2001
                
                
                
                2.54
                1.64Inception
                    to December 31, 2005 - Distributions paid as declared
                $
                9.51
                6.70*exchange
                    rate based on the Bank of Canada noon rate on the payment date.
   For
        Canadian tax purposes, 2005 distributions were determined to be 76.5 percent
        taxable and 23.5 percent a tax-deferred return of capital in the hands of
        Canadian unitholders. The 2004 comparables were 71 percent and 29 percent
        respectively. Distributions received by U.S. resident unitholders in 2005
        are
        classified as 94.4 percent qualified dividend and 5.6 percent tax deferred
        return of capital. The 2004 comparables were 83 percent and 17 percent
        respectively. In both Canada and the U.S., the tax-deferred portion would
        usually be treated as an adjustment to the cost base of the units. Unitholders
        or potential unitholders should consult their own legal or tax advisors as
        to
        their particular income tax consequences of holding Provident
        units.
  
 **Net
        Income**
  Year
                    ended December 31,($
                    000s, except per unit data)
                
                **2005**
                
                
                2004(3)
                %
                    Change(Restated)Net
                    income (loss)
                **$**
                **96,926**
                
                $
                21,225
                357Per
                    weighted average unit
                  -
                    basic(1)
                
                **0.61**
                
                
                0.19
                221Per
                    weighted average unit
                  -
                    diluted(2)
                
                **0.61**
                
                
                0.19
                221
 (1)Based on weighted average number of trust units outstanding(2)Based
                  on weighted average number of trust units outstanding including
                  the
                  dilutive impact of the unit option plan, exchangeable shares and
                  convertible debentures.(3)Restated
                  - note 3.
  21
 TABLE
            OF CONTENTS
  Year
                  ended December 31,($
                  000s)
              
              **2005**
              
              
              2004
              %
                  Change(Restated)COGP
                  net income (loss)
              **$**
              **35,352**
              
              $
              (20,059)
              276USOGP
                  net income
              
              **5,422**
              
              
              9,482
              (43)Total
                  oil and gas net income
              
              **40,774**
              
              
              (10,577)
              485Midstream
                  net income
              
              **56,152**
              
              
              31,802
              77Net
                  Income
              **$**
              **96,926**
              
              $
              21,225
              357
  For
        the year ended December 31, 2005, consolidated earnings of $96.9 million
        resulted from oil and gas net income of $40.8 million and Midstream net income
        of $56.1 million.
 
 The
        combined net income for COGP and USOGP of $41.8 million for 2005 compares
        to a
        loss of $10.6 million in 2004. Higher commodity prices in Canada and the
        United
        States combined with a full year of production in the U.S. resulted in a
        66
        percent improvement in earnings before interest, taxes, depletion, depreciation,
        and accretion and other non-cash items. Also, in 2004 Provident recorded
        a
        non-cash revenue reduction of $22.4 million in its oil and gas operations,
        largely due to the implementation of CICA Accounting Guideline 13, “Hedging
        relationships”. The comparable figure for 2005 was a revenue increase of $9.2
        million, resulting mainly from unrealized gains on financial derivative
        instruments. The Midstream segment contributed $56.1million of net income
        in
        2005, a 77 percent increase over 2004. The increase is due to higher product
        premiums in 2005 as well as an increase in product prices over the
        period.
 
 **Taxes**
 Year
                    ended December 31,($
                    000s)
                
                **2005**
                
                
                2004
                %
                    ChangeCapital
                    taxes
                $
                **4,780**
                
                $
                5,921
                (19)Current
                    and withholding taxes
                
                **5,628**
                
                
                1,282
                339Future
                    income tax expense (recovery)
                
                **17,793**
                
                
                (40,577)
                144$
                **28,201**
                
                $
                (33,374)
                184
  Future
        income taxes arise as a result of the difference between the accounting and
        tax
        bases of the operating companies and subsidiaries. Payments to the Trust
        by
        these subsidiaries are deductible for income taxes. The Trust is a taxable
        entity under the Income Tax Act (Canada) and is taxable only on income that
        is
        not distributed or distributable to the unitholders. As the Trust distributes
        all of its taxable income to the unitholders and meets the requirements of
        the
        Income Tax Act (Canada) applicable to the Trust, no provision for income
        taxes
        has been made in the Trust.
 
 Capital
        taxes include the Saskatchewan Resource surcharge and federal and provincial
        large corporation taxes. Current and withholding taxes reflect U.S. taxes
        that
        are incurred on operations associated with Provident’s June 15, 2004 acquisition
        of U.S. based BreitBurn Energy. U.S. operations are subject to U.S. federal
        and
        state income taxes. Payments from U.S. entities to Canadian entities are
        subject
        to withholding taxes if the distributions are characterized by U.S. tax
        authorities as dividends or interest.
 
 The
        2005
        future income tax expense of $17.8 million compares to a $40.6 million recovery
        for the comparable 2004 period. The future tax expense in 2005 resulted from
        changes to estimated tax pools in both Canada and the U.S.A, partially offset
        by
        increases in estimated royalty and interest charges by the Trust to subsidiaries
        which reduced estimated tax pool claims.
 
 
 **Reconciliation
        of non-GAAP measure**
  The
        Trust
        calculates earnings before interest, taxes, depletion, depreciation and
        accretion, and other non-cash items (EBITDA) within its segment disclosure.
        EBITDA is a non-GAAP measure. A reconciliation between EBITDA and income
        (loss)
        before taxes and non-controlling interests follows:
  22
 TABLE
            OF CONTENTS
  EBITDA
                  Reconciliation
              **Year
                  ended December 31,**($
                  000s)
              
              **2005**
              
              
              2004
              %
                  Change**EBITDA**
              $
              **349,181**
              
              $
              218,065
              60Adjusted
                  for:Interest
                  and non-cash expenses excluding unrealized gain/(loss) on financial
                  instruments
              
              **(229,372)**
              
              
              (206,781)
              11Unrealized
                  gain/(loss) on financial instruments
              
              **7,684**
              
              
              (22,053)
              135Income
                  (loss) before taxes and non-
                controlling
                  interests
              $
              **127,493**
              
              $
              (10,769)
              1,294
  **Interest
        expense**
 Year
                    ended December 31,($
                    000s, except as noted)
                
                **2005**
                
                
                2004
                %
                    ChangeInterest
                    on bank debt
                **$**
                **10,875**
                
                $
                11,816
                (8)Weighted-average
                    interest rate on bank debt
                
                **3.85%**
                
                
                3.96%
                (3)Interest
                    on 10.5% convertible debentures(3)
                
                **1,682**
                
                
                5,226
                (68)Interest
                    on 8.75% convertible debentures
                
                **4,923**
                
                
                6,421
                (23)Interest
                    on 8.0% convertible debentures(1)
                
                **3,577**
                
                
                2,153
                66Interest
                    on 6.5% convertible debentures(2)
                
                **5,393**
                
                
                -
                -Interest
                    on 6.5% convertible debentures(4)
                
                **1,219**
                
                
                -
                -Total
                    cash interest
                **$**
                **27,669**
                
                $
                25,616
                8Weighted
                    average interest rate on all long-term debt
                
                **4.91%**
                
                
                6.05%
                (19)Non
                    -cash accretion expense - convertible debentures
                
                **2,849**
                
                
                1,373
                108Total
                    interest including accretion on convertible debentures
                **$**
                **30,518**
                
                $
                26,989
                13
 (1)On
                    July 6, 2004 the Trust issued $50.0 million of unsecured subordinated
                    convertible debentures with an 8 percent coupon rate maturing
                    July 31,
                    2009.(2)On
                    March 1, 2005 the Trust issued $100.0 million of unsecured subordinated
                    convertible debentures with a 6.5 percent coupon rate maturing
                    August 31,
                    2012.(3)On
                    May 31, 2005 the Trust redeemed the 10.5 percent unsecured subordinated
                    convertible debentures issuing 3.5 million trust units and $3.0
                    million in
                    cash.(4)On November 15, 2005 the Trust issued $150.0 million of unsecured
                    subordinated convertible debentures with a 6.5 percent coupon
                    rate
                    maturing April 30, 2011.
 Interest
        expense increases for the year reflect increased debt levels as a result
        of
        corporate growth. Cash interest expense on debentures increased in 2005 as
        compared to 2004 reflecting the March 1, 2005 issue of $100.0 million of
        6.5
        percent subordinated convertible debentures and the November 15, 2005 issue
        of
        $150.0 million of 6.5 percent subordinated convertible debentures partly
        offset
        by $63.6 million of debenture conversions and the May 31 redemption of
        approximately $45.7 million of 10.5 percent subordinated convertible debentures.
        Accretion and amortization on convertible debentures has resulted from Provident
        adopting in 2004 the revised CICA Handbook section 3860 and reclassifying
        the
        bulk of its subordinated convertible debentures to long-term debt and an
        additional portion to equity.
 
 
 **Financial
        instruments**
 
 **Commodity
        price risk management program**
 
 For
        the
        year ended December 31, 2005 $66.9 million was recorded as realized loss
        on
        financial derivative instruments due to the Commodity Price Risk Management
        Program (the Program) with $64.6 million related to the combined oil and
        gas
        operations and $2.3 million associated with the Midstream
        segment.
  23
 TABLE
            OF CONTENTS
 
 In
        the
        oil and gas business units the hedging cost associated with crude oil totaled
        $59.0 million ($8.36 per barrel) and $5.6 million related to natural gas
        ($0.19
        per gj). The combined total was $64.6 million or $5.24  per
        boe.
        In 2004 the Program recorded an opportunity cost of $65.7 million or
        $5.78  per
        boe
        with $55.3 million related to crude oil ($9.03 per barrel) and $10.4 million
        related to natural gas ($0.35 per gj).
  In
        2005
        the Midstream segment recorded a hedging cost of $2.3 million primarily on
        propane and ethane price stabilization and frac-spread margin hedging
        activities. In 2004 the Program recorded a cost of $3.2 million for these
        activities.
  Realized
        gains on foreign exchange contracts which fixed the exchange rates on foreign
        currency contracts related to the Program have been presented as a component
        of
        foreign exchange gain and other and allocated to their respective business
        segments.
  On
        a per
        trust unit basis the opportunity cost of the Program decreased to $0.42 per
        trust unit in 2005 from $0.61 per trust unit in 2004.
  At
        December 31, 2005 the mark to market value of open contracts was in a loss
        position of $14.1 million based upon commodity prices prevailing at that
        date.
        This amount has been reflected in the financial statements of the Trust pursuant
        to Accounting Guideline 13 and Emerging Issues Committee Abstract 128 in
        respect
        of accounting for financial instruments.
  Provident’s
        Commodity Price Risk Management Program involves a disciplined hedging strategy
        that utilizes dervivative instruments to provide for insurance against lower
        commodity prices, protect against price volatility, secure bank financing,
        improve debt coverage and assist with more predictable and stable cash
        distributions. The hedging strategy protects a percentage of production against
        a decline in commodity prices while, with some products, allowing the Trust
        to
        participate in a rising commodity price environment. It provides price
        stabilization and protection of inventory values and fractionation spread
        margin
        associated with the midstream services and marketing business units. As well,
        the Provident hedging stategy reduces foreign exchange risk due to the exposure
        arising from the conversion of U.S. dollars into Canadian dollars.
  Provident
        will continue to execute the Program in 2006. The derivative instruments
        the
        Trust uses include puts, calls, costless collars, participating swaps, fixed
        and
        indexed referenced pricing.
 
 **Disclosure
        Controls and Procedures**
 
 Based
        on
        the requirements of Multilateral Instrument 52-109 of the Canadian Securities
        Administrators, management evaluated the effectiveness of Provident’s disclosure
        controls and procedures. Based on that evaluation, management concluded that
        Provident’s disclosure controls and procedures were effective as of December 31,
        2005.
 
 **Acquisitions**
 
 Provident
        completed two major acquisitions during 2005. On March 2, 2005 Provident
        acquired Nautilus Resources, LLC (Nautilus) for cash consideration of $90.2
        million and acquisition costs of $1.2 million. Nautilus was a private oil
        and
        gas exploration and production business active in Wyoming, U.S.A. The
        acquisition added $99.9 million to property plant and equipment. Other asset
        and
        liability accounts were also assigned values. The transaction has been accounted
        for using the purchase method.
 
 On
        December 13, 2005 Provident acquired midstream business assets (the Midstream
        NGL Acquisition) by way of the purchase of partnership interests, corporations
        and assets for $772.3 million (net of cash acquired and including acquisition
        costs). The business is comprised of NGL extraction plants, pipelines, storage
        and fractionation facilities, distribution facilities, contracts including
        supply and transportation arrangements, and ownership of Kinetic, partnerships
        which perform NGL marketing services including Kinetic’s interests in a
        distribution terminal and leases on approximately 700 rail cars. The transaction
        was accounted for using the purchase method. The purchase added $428.1 million
        to property, plant and equipment; $217.0 million to intangible assets; and
        $98.1
        million to goodwill.
  24
 TABLE
            OF CONTENTS
  The
        Midstream NGL Acquisition was financed by the issuance of 21,830,000 units
        at
        $12.60 per unit and $150.0 million of 6.5 percent convertible unsecured
        subordinated debentures. The remaining portion of the purchase price of the
        Midstream NGL Acquisition was funded through Provident’s credit
        facility.
 
 **Dispositions**
 
 On
        May 1,
        2005 Provident sold the crude oil purchase and sale contracts that underpinned
        its crude oil marketing business. Net proceeds were $5.5 million and the
        gain
        net of disposal cost was $5.2 million.
 
 On
        September 29, 2005, Provident, disposed of various non-core properties and
        land
        in Saskatchewan and Alberta for cash proceeds, net of disposition costs,
        of
        $44.6 million. The net cash proceeds were initially applied to debt and will
        mainly be used to fund Provident’s ongoing budgeted capital program. The
        disposed properties averaged approximately 2,100 boed for the period July
        1,
        2005 to September 28, 2005 and included approximately 1,010 boed of heavy
        oil.
        Proved plus probable reserves totaled 6,397 mboe and approximately 87,850
        net
        acres of undeveloped land were also included. The disposition resulted in
        a
        $13.6 million reduction to Provident’s future asset retirement obligation, which
        represented the discounted future cash flows to settle the asset retirement
        obligations related to these properties. Under full cost accounting rules,
        unless the disposed oil and gas assets result in a greater than 20 percent
        impact on the depletion rate, no gain or loss is recognized.
 
 On
        December 29, 2005 the USOGP business unit disposed of a parcel of land in
        California for net proceeds of $23.8 million and recorded a deferred gain
        of
        $1.0 million.
 
 **Goodwill**
 
 Goodwill
        represents **** the
        excess of the cost of an acquired enterprise over the net of the amounts
        assigned to assets acquired and liabilities assumed **,** goodwill
        arose from the acquisitions of Richland Petroleum Corporation, $13.3 million,
        and Meota Resources Corp., $89.1 million in 2002 and from Olympia Energy
        Inc.,
        $106.5 million, and Viracocha Energy Inc., $122.0 million in 2004. In 2005,
        the
        Midstream NGL Acquisition resulted in additional goodwill of $98.1
        million.
 
 Goodwill
        is assessed for impairment at least annually, and if an impairment exists,
        it
        would be charged to income in the period in which the impairment occurs.
        Provident engaged an independent accounting firm to assist in performing
        an
        impairment test at year end. The impairment test includes, amongst other
        variables, a comparison of the net book value of the Trust’s assets to the
        market value of the Trust’s equity. Goodwill is not amortized.
 
 **Liquidity
        and capital resources**
 December
                    31,($
                    000s)
                
                **2005**
                
                
                2004
                %
                    ChangeLong-term
                    debt - revolving term credit facility
                **$**
                **586,597**
                
                $
                262,750
                123Long-term
                    debt - convertible debentures
                
                **298,007**
                
                
                169,456
                76Working
                    capital deficit
                
                **-**
                
                
                38,677
                (100)Net
                    debt
                
                **884,604**
                
                
                470,883
                88Equity
                    (at book value)
                
                **1,404,826**
                
                
                1,009,048
                39Total
                    capitalization at book value
                **$**
                **2,289,430**
                
                $
                1,479,931
                55Net
                    debt as a percentage of total book value capitalization
                
                **39%**
                
                
                32%
                22
  Provident
        operates three business units with similar but not identical monthly cash
        settlement cycles. Provident’s working capital position is impacted by seasonal
        fluctuations that reflect commodity price changes, drilling cycles in its
        oil
        and gas operations and inventory balances in its midstream business unit.
        Provident relies on cash flow from operations, external lines of credit and
        access to equity markets to fund capital programs and acquisitions.
  25
 TABLE
            OF CONTENTS
  **Long-term
        debt and working capital**
  As
        at
        December 31, 2005 Provident had drawn on 68 percent of its term credit
        facilities of $750 million and USD $100 million as compared to 64 percent
        drawn
        on its $410.0 million term credit facility as at December 31, 2004. The increase
        in the level of bank debt was due to the increase scale of operations primarily
        due to acquisitions. The increased percentage of the credit facilities drawn
        reflects the Midstream NGL Acquisition that closed on December 13,
        2005.
 
 At
        December 31, 2005 Provident had letters of credit guaranteeing Provident’s
        performance under certain commercial and other contracts that totaled $45.1
        million, increasing bank line utilization to 73 percent. The guarantees at
        December 31, 2004 totaled $31 million.
 
 Provident’s
        working capital increased by $113.1 million from a deficit of $38.7 million
        to a
        surplus of $74.4 million as at December 31, 2005. Of this increase $7.7 million
        was due to unrealized hedging gains, a $93.5 million increase in petroleum
        product inventory, of which $85.6 million was added by the Midstream NGL
        Acquisition, and a $5.2 million increase in declared distributions payable
        while
        the balance was due to changes in other accounts reflecting the increased
        scale
        of activities including capital activities.
 
 Fourth
        quarter cash flow in 2005 was $96.3 million. The ratio of debt to annualized
        fourth quarter cash flow was 2.30 to one, as compared to fourth quarter
        annualized debt to cash flow in 2004 of 1.85 to one. The 2005 annualized
        and
        fourth quarter debt to cash flow ratios are skewed upward as the debt reflects
        the full purchase price of the Midstream NGL Acquisition of $772.3 million
        but
        only 19 days of cash flow from the acquired assets.
 
 **Trust
        units and exchangeable shares**
  On
        March
        1, 2005 the Trust issued 8.4 million units at a price of $12.00 per unit
        for
        proceeds after underwriting fees of $95.6 million, concurrent with the issue
        of
        convertible debentures noted above. Proceeds from the issue were used to
        pay
        down Provident’s bank debt and to finance the Nautilus Resources, LLC
        acquisition and throughout 2005 was used to finance the company’s 2005 capital
        budget. In 2005, the Trust also issued 2.9 million units (conversion amount
        $28.4 million) on conversion of exchangeable shares to units (2004 - 1.6
        million
        units; conversion amount $15.3 million) and 9.6 million units on conversion
        and
        redemption of convertible debentures (2004 - 11,378 units). An additional
        2.3
        million units pursuant to the stock option plan were issued in 2005 (2004
        - 0.6
        million units). Details of these issues are outlined in the notes to the
        financial statements. Under Provident’s Premium Distribution, Distribution
        Reinvestment (DRIP) and Optional Unit Purchase Plan program 1.4 million units
        were elected in 2005 and will be issued or are to be issued representing
        proceeds of $18.4 million (2004 - 1.9 million units for proceeds of $19.9
        million).
 
 On
        November 15, 2005 the Trust issued 21.83 million Subscription Receipts at
        a
        price of $12.60 per Subscription Receipt for total proceeds of $275.1 million
        ($261.0 million net of issue costs). Each Subscription Receipt entitled the
        holder to receive one trust unit upon completion of the Midstream NGL
        Acquisition. The acquisition closed on December 13, 2005 at which time all
        of
        the outstanding Subscription Receipts were converted to trust units. At that
        time, the holders of the Subscription Receipts were also entitled to $0.12
        per
        trust unit, which is the equivalent of the November distribution paid in
        December. This payment was treated as a reduction to the purchase price of
        the
        units acquired through the Subscription Receipts to $12.48 per trust unit,
        reducing the amount attributed to Unitholders’ contributions by $2.6 million.
        Proceeds from the issue were used to fund the Midstream NGL Acquisition.
 
 At
        December 31, 2005 management and directors held approximately 1.2 percent
        of the
        outstanding units and exchangeable shares.
  26
 TABLE
            OF CONTENTS
  **Non-Controlling
        Interest**
  **(i)**
              **USOGP
                operations**
  Non-controlling
        interest arose from Provident’s June 15, 2004 acquisition of 92 percent of
        Breitburn Energy of Los Angeles, California. The founders of BreitBurn Energy
        beneficially own the non-controlling interest, which share in earnings or
        losses
        of BreitBurn. The non-controlling interest is reduced by
        distributions.
 **Year
                    ended December 31,**Non-controlling
                    interest USOGP ($ 000s)
                
                **2005**
                
                
                2004Opening
                    non-controlling interest, beginning of year
                **$**
                **13,649**
                
                $
                13,690Net
                    income attributable to non-controlling interest
                
                **1,596**
                
                
                923Distributions
                    to non-controlling interest holders
                
                **(3,360)**
                
                
                (964)Closing
                    non-controlling interest, end of period
                
                **11,885**
                
                
                13,649Accumulated
                    income attributable to non-controlling interest
                **$**
                **2,519**
                
                $
                923
  Additional
        investments by Provident in BreitBurn Energy LP have reduced the non-controlling
        interest percentage at December 31, 2005 to approximately 4.4
        percent.
  **(ii)**
              **Exchangeable
                shares**
  As
        at
        June 30, 2005 the Trust retroactively applied EIC-151 “Exchangeable Securities
        Issued by a Subsidiary of an Income Trust”. The non-controlling interest on the
        consolidated balance sheet consists of the fair value of the exchangeable
        shares
        upon issuance plus the accumulated earnings attributable to the non-controlling
        interest. The net income attributable to the non-controlling interest on
        the
        consolidated statement of operations represents the cumulative share of net
        income attributable to the non-controlling interest based on the trust units
        issuable for exchangeable shares in proportion to total trust units issued
        and
        issuable at each quarter end during the year.
  Following
        is a summary of the non-controlling interest - exchangeable shares for the
        years
        ended December 31, 2005 and 2004 :
 **Year
                    ended December 31,**Non-controlling
                    interest - Exchangeable shares ($ 000s)
                
                **2005**
                
                
                2004(1)Non-controlling
                    interest, beginning of period
                **$**
                **35,921**
                
                $
                20,543Exchangeable
                    shares issued
                
                **-**
                
                
                30,264Reduction
                    of book value for conversion to trust units
                
                **(28,432)**
                
                
                (15,343)Net
                    income attributable to non-controlling interest
                
                **770**
                
                
                457Non-controlling
                    interest, end of period
                **$**
                **8,259**
                
                $
                35,921Accumulated
                    income attributable to non-controlling interest
                **$**
                **2,252**
                
                $
                1,482(1)
                    Restated - note 3.
  The
        non-controlling interest percentage as at December 31, 2005 was 0.6 percent
        that
        is a decrease from the retroactively applied non-controlling interest percentage
        as at December 31, 2004 of 2.2 percent. The decrease is attributable to the
        conversion of exchangeable shares for trust units and the increase in trust
        units from other issuances.
  27
 TABLE
            OF CONTENTS
 
 **Capital
        Expenditures and Funding**
 Year
                    ended December 31,($
                    000s)
                
                **2005**
                
                
                2004
                %
                    Change**Capital
                    Expenditures and Funding****Capital
                    Expenditures**Capital
                    expenditures and reclamation fund contributions
                $
                **(159,398)**
                
                $
                (79,165)
                101Property
                    acquisitions
                
                **(586)**
                
                
                (72,745)
                (99)Corporate
                    acquisitions
                
                **(863,723)**
                
                
                (173,657)
                397Property
                    dispositions
                
                **45,100**
                
                
                10,717
                321Net
                    capital expenditures
                $
                **(978,607)**
                
                $
                (314,850)
                211**Funded
                    By**Cash
                    flow net of declared distributions to unitholders and non-controlling
                    interest
                $
                **77,114**
                
                $
                19,654
                292Increase
                    (decrease) in long-term debt
                
                **325,771**
                
                
                (77,087)
                (523)Bridge
                    Financing
                
                -
                
                
                158,184
                (100)Repayment
                    of bridge financing
                
                -
                
                
                (158,184)
                100Issue
                    of convertible debentures, net of cost
                
                **239,822**
                
                
                48,000
                400Redemption
                    of convertible debentures
                
                **(2,997)**
                
                
                -
                -Issue
                    of trust units, net of cost; excluding DRIP
                
                **377,362**
                
                
                301,110
                25DRIP
                    proceeds
                
                **18,443**
                
                
                19,866
                (7)Change
                    in working capital, including cash, payment of financial derivative
                    instruments, sale of assets
                
                **(56,908)**
                
                
                3,307
                (1,821)Net
                    capital expenditure funding
                $
                **978,607**
                
                $
                314,850
                211
  Capital
        expenditures were funded by a combination of DRIP proceeds, proceeds received
        on
        non-core property dispositions, cash flow, equity, exchangeable shares and
        debt.
        Provident’s strategy is to fund acquisitions by accessing the capital markets
        and to fund capital expenditures through DRIP and other equity if
        needed ***.***
 
 
 **Net
        asset value**
  Provident’s
        net asset value (“NAV”) as at December 31, 2005, is summarized in the table
        below. The net asset value is calculated on a diluted basis, which includes
        exchangeable shares and unit options, and is presented at eight percent and
        10
        percent discounted cash flow cases. The pricing used at both December 31,
        2005
        and December 31, 2004 is derived from the McDaniel’s report.
  28
 TABLE
            OF CONTENTS
 ($
                    000s except per unit data)
                
                **PV
                    8%**
                **PV
                    10%****Net
                    Asset Value:****Present
                    value of proved plus probable oil and natural****gas
                    reserves****(1)**
                $
                1,690,313
                $      
                    1,546,281**Midstream
                    assets**
                
                1,552,415
                1,331,409**Add:**Working
                    Capital
                
                88,504
                88,504Land(3)
                    (4)
                
                52,328
                52,328Proceeds
                    from Options
                
                35,619
                35,619Cash
                    Reserved for Future Reclamation
                
                1,872
                1,872Investments
                
                3,758
                3,758**Less:**Financial
                    Hedging Losses
                
                (14,149)
                (14,149)Long
                    Term Debt
                
                (884,604)
                (884,604)Non-controlling
                    interest - USOGP operations
                
                (11,885)
                (11,885)**Consolidated
                    Provident Net Asset Value**
                **$**
                **2,514,171**
                **$    
                    2,149,133****Consolidated
                    Provident Net Asset Value per Unit**
                **$**
                **13.04**
                **$            
                    11.15****2004
                    comparatives****Consolidated
                    Provident Net Asset Value per Unit**
                **$**
                **8.78**
                **$             
                     7.61**(1)Evaluated by McDaniel, NSA and CGA; pricing is McDaniel pricing
                    effective
                    December 31, 2005(2)The
                    Midstream assets represent discounted estimated cash flow streams
                    (EBITDA
                    less maintenance capital) for 25 years(3)Canadian land holdings evaluated by Seaton Jordan & Associates Ltd.
                    effective December 31, 2005(4)U.S. land holdings are included at the market value assigned
                    at the date
                    of acquisitions
 **Asset
        Retirement Obligation**
 Year
                    ended December 31,($
                    000s)
                
                **2005**
                
                
                2004
                %
                    ChangeCarrying
                    amount, beginning of period
                $
                **40,506**
                
                $
                33,182
                22Corporate
                    acquisitions
                
                **9,161**
                
                
                12,171
                (25)Change
                    in estimate
                
                **2,884**
                
                
                (2,429)
                219Increase
                    in liabilities incurred during the period
                
                **1,784**
                
                
                166
                975Settlement
                    of liabilities during the period
                
                **(2,614)**
                
                
                (4,971)
                47Decrease
                    in liabilities due to disposition
                
                **(13,612)**
                
                
                -
                -Accretion
                    of liability
                
                **3,024**
                
                
                2,387
                27Carrying
                    amount, end of period
                $
                **41,133**
                
                $
                40,506
                2
  The
        asset
        retirement obligation (ARO) increased by $0.6 million to $41.1 million during
        2005.
 
 The
        Trust’s asset retirement obligation is based on the Trust’s net ownership in
        wells, facilities and the midstream assets and represents management’s estimate
        of the costs to abandon and reclaim those wells, facilities and midstream
        assets
        as well as an estimate of the future timing of the costs to be incurred.
        Estimated cash flows have been discounted at the Trust’s credit-adjusted risk
        free rate of seven  percent
        and an inflation rate of two  percent.
 
 The
        total
        undiscounted amount of future cash flows required to settle asset retirement
        obligations related to oil and gas operations is estimated to be $293.0 million.
        Payments to settle oil and gas asset retirement obligations occur over the
        operating lives of the assets estimated to be from two to 50 years.
  29
 TABLE
            OF CONTENTS
 
 The
        total
        undiscounted amount of future cash flows required to settle the midstream
        asset
        retirement obligations is estimated to be $179.3 million. The estimated costs
        include such activities as dismantling, demolition and disposal of the
        facilities as well as remediation and restoration of the surface land. Payments
        to settle the Midstream asset retirement obligations are expected to occur
        subsequent to the closure of the facilities and related assets. Settlement
        from
        the balance sheet date of these obligations is expected to occur over 30
        to 45
        years.
 
 **Non-cash
        unit based compensation**
  Non-cash
        unit based compensation include expenses or recoveries associated with
        Provident’s unit option plan, restricted and performance unit plan, unit
        appreciation rights and other unit based compensation plans. Provident accounts
        for the unit option plan using the fair value of the option, at the time
        of
        issue. The other unit based compensation is recorded at the estimated fair
        value
        of the notional units granted. Compensation expense associated with the plans
        is
        deferred and recognized in earnings over the vesting periods of each plan.
        Provident recorded a non-cash expense of $9.8 million for the year ended
        December 31, 2005 (2004 -$1.8 million).
  30
 TABLE
            OF CONTENTS
  **Canadian
        OGP segment review (COGP)**
 
 **Crude
        oil price**
 
 The
        following prices are net of transportation expense.
 COGP
                **Year
                    ended December 31,**($
                    per bbl)
                
                **2005**
                
                
                2004
                %
                    ChangeOil
                    per barrelWTI
                    (US$)
                $
                **56.56**
                
                $
                41.43
                37Exchange
                    rate (from US$ to Cdn$)
                $
                **1.21**
                
                $
                1.30
                (7)WTI
                    expressed in Cdn$
                $
                **68.44**
                
                $
                53.86
                27COGP
                    realized crude oil and natural gas liquids price before hedging
                    (Cdn$)
                $
                **45.25**
                
                $
                36.81
                23COGP
                    realized light/medium oil price before hedging (Cdn$)
                $
                **52.02**
                
                $
                42.79
                22COGP
                    realized heavy oil price before hedging (Cdn$)
                $
                **31.33**
                
                $
                28.72
                9COGP
                    realized natural gas liquids price before hedging (Cdn$)
                $
                **49.15**
                
                $
                40.61
                21
 For
        the
        year ended December 31, 2005 COGP’s realized oil and natural gas liquids price,
        prior to the impact of hedging, increased by 23 percent to average $45.25
        compared to $36.81 in 2004. The 2005 increase related to a 37 percent higher
        US$
        WTI crude oil price partially offset by a stronger Canadian dollar, wider
        pricing differentials on all crude oil streams and a reduction in Provident’s
        heavy oil volumes as a percentage of its oil production mix.
 
 
 **Natural
        Gas Price**
  The
        following prices are net of transportation expense.
 COGP**Year
                    ended December 31,**($
                    per mcf)
                
                **2005**
                
                
                2004
                %
                    ChangeAECO
                    monthly index (Cdn$) per mcf
                $
                **8.49**
                
                $
                6.79
                25Corporate
                    natural gas price per mcf
                  before
                    hedging (Cdn$)
                $
                **8.42**
                
                $
                6.59
                28
 For
        the
        year ended December 31, 2005 COGP’s realized natural gas price, prior to the
        impact of hedging, increased 28 percent as compared to 2004, comparable to
        the
        increase in the benchmark AECO monthly index price.
 
 
 **Production**
 **Year
                    ended December 31,**COGP**2005**
                2004
                %Change**Daily
                    production**Crude
                    oil - Light/Medium (bpd)
                **8,058**
                7,995
                1-
                    Heavy (bpd)
                **4,358**
                6,608
                (34)Natural
                    gas liquids (bpd)
                **1,572**
                1,482
                6Natural
                    gas (mcfd)
                **74,936**
                76,174
                (2)Oil
                    equivalent (boed)(1)
                **26,477**
                28,781
                (8)(1)Provident reports equivalent production converting natural gas
                    to oil on a
                    6:1 basis.
   For
        the
        year ended December 31, 2005, COGP production averaged 26,477 boed, an eight
        percent decrease compared to 28,781 boed in 2004. The production volumes
        added
        through drilling and optimization activities were more than offset by natural
        production declines including higher than expected declines in heavy oil
        and the
        disposition of 2,100 boed of production in September 2005. COGP’s heavy oil
        production decline was higher due to
  31
 TABLE
            OF CONTENTS
  an
        increase in water production at Provident’s heavy oil field, Kiscoty. Production
        rates at Kiscoty have now stabilized and Provident’s other heavy oil fields have
        declines consistent with similar type properties. The lower percentage variance
        in light/medium oil, natural gas and natural gas liquids reflect a full year
        of
        production in the 2005 averages for the Viracocha and Olympia acquisitions
        as
        well as both a 39 percent increase in 2005 capital expenditures over 2004
        and a
        shift in capital spending towards natural gas and light/medium oil projects.
 
 Provident
        does not have any single property providing greater than 10 percent of total
        production, which mitigates exposure to production failure.
 
 Additions
        to production through internal capital replaced approximately 48 percent
        of
        proved plus probable reserves before revisions. COGP’s 2005 development
        activities were hampered by poor weather conditions in the second and third
        quarters of 2005, which delayed overall development activities.
 
 COGP’s
        production summarized by core areas is as follows:
 COGP**Year
                    ended December 31, 2005**
                West
                    Central
                  Alberta
                Southern
                  Alberta
                Southern
                  Saskatchewan
                Lloydminister
                Other
                **Total****Daily
                    production**Crude
                    oil - Light/Medium (bpd)
                1,300
                2,722
                2,559
                1,470
                7
                8,058-
                    Heavy (bpd)
                -
                -
                -
                4,358
                -
                4,358Natural
                    gas liquids (bpd)
                1,406
                149
                1
                16
                -
                1,572Natural
                    gas (mcfd)
                40,198
                26,345
                6,462
                1,909
                22
                74,936Oil
                    equivalent (boed)(1)
                9,406
                7,262
                3,636
                6,162
                11
                26,477
  COGP**Year
                    ended December 31, 2004**
                West
                    Central
                  Alberta
                Southern
                  Alberta
                Southern
                  Saskatchewan
                Lloydminister
                Other
                **Total****Daily
                    production**Crude
                    oil - Light/Medium (bpd)
                1,355
                2,581
                2,881
                1,164
                14
                7,995-
                    Heavy (bpd)
                -
                -
                -
                6,608
                -
                6,608Natural
                    gas liquids (bpd)
                1,342
                119
                2
                14
                5
                1,482Natural
                    gas (mcfd)
                44,503
                24,391
                3,180
                3,598
                502
                76,174Oil
                    equivalent (boed)(1)
                10,114
                6,765
                3,413
                8,386
                103
                28,781(1)Provident reports equivalent production converting natural gas
                    to oil on a
                    6:1 basis.
  Internal
        development activities included 132.2 net wells drilled for the year ended
        December 31, 2005. Provident’s most active area, southern Saskatchewan realized
        70.4 net wells drilled. The focus of southern Saskatchewan is a shallow gas
        drilling program that will realize production and reserve additions for several
        years. Although poor weather conditions delayed tie-in operations during
        the
        second and third quarters of 2005, Provident continued to bring these wells
        on
        production in the fourth quarter of 2005. Provident’s other core areas remain
        active with additional activity in southern Alberta where Provident is actively
        drilling shallow gas wells and in Lloydminster where Provident is drilling
        low
        risk heavy oil wells. In West Central Alberta, Provident continues its strategy
        of farming out high risk exploration land to generate cash flow with minimal
        or
        no capital outlay.
 
 As
        a
        result of the non-core properties disposition on September 29, 2005, normal
        underlying declines rates and Provident’s budgeted 2006 capital expenditure
        program, Provident expects COGP production for the full year of 2006 to average
        between 19,000 boed and 21,000 boed.
  32
 TABLE
            OF CONTENTS
  **Revenue
        and royalties**
 COGP**Year
                    ended December 31,**($
                    000s except per boe data)
                
                **2005**
                
                
                2004
                %Change**Oil**Revenue
                **$**
                **202,845**
                
                $
                194,366
                4Realized
                    loss on non-hedging derivative instruments
                
                **(42,700)**
                
                
                (54,997)
                (22)Royalties
                    (net of ARTC)
                
                **(40,067)**
                
                
                (38,885)
                3Net
                    revenue
                **$**
                **120,078**
                
                $
                100,484
                19Net
                    revenue (per barrel)
                **$**
                **26.50**
                
                $
                18.80
                41Royalties
                    as a percentage of revenue
                
                **19.8%**
                
                
                20.0%**Natural
                    gas**Revenue
                **$**
                **230,195**
                
                $
                183,704
                25Realized
                    loss on non-hedging derivative instruments
                
                **(5,608)**
                
                
                (10,369)
                (46)Royalties
                    (net of ARTC)
                
                **(48,484)**
                
                
                (40,813)
                19Net
                    revenue
                **$**
                **176,103**
                
                $
                132,522
                33Net
                    revenue (per mcf)
                **$**
                **6.44**
                
                $
                4.75
                36Royalties
                    as a percentage of revenue
                
                **21.1%**
                
                
                22.2%**Natural
                    gas liquids**Revenue
                **$**
                **28,203**
                
                $
                22,024
                28Royalties
                
                **(6,852)**
                
                
                (5,492)
                25Net
                    revenue
                **$**
                **21,351**
                
                $
                16,532
                29Net
                    revenue (per barrel)
                **$**
                **37.21**
                
                $
                30.48
                22Royalties
                    as a percentage of revenue
                
                **24.3%**
                
                
                24.9%**Total**Revenue
                **$**
                **461,243**
                
                $
                400,094
                15Realized
                    loss on non-hedging derivative instruments
                
                **(48,308)**
                
                
                (65,366)
                (26)Royalties
                    (net of ARTC)
                
                **(95,403)**
                
                
                (85,190)
                12Net
                    revenue
                **$**
                **317,532**
                
                $
                249,538
                27Net
                    revenue per boe
                **$**
                **32.86**
                
                $
                23.69
                39Royalties
                    as a percentage of revenue
                
                **20.7%**
                
                
                21.3%Note:
                    the above figures are presented net of transportation
                    expenses.
  For
        the
        year ended December 31, 2005 COGP production revenue was $461.2 million,
        an
        increase of 15 percent from $400.1 million in 2004. The increase in revenue
        is a
        result of a 23 percent increase in Provident’s realized crude oil, natural gas
        liquids and a 28 percent increase in Provident’s natural gas prices offset by
        lower production. Royalties as a percentage of revenue have remained relatively
        constant at approximately 21 percent compared to the prior year. The preceding
        factors, as well as the opportunity cost of hedging activities, account for
        net
        revenue of $317.5 million in 2005, 27 percent above the $249.5 million recorded
        in 2004.
 
 Net
        revenue per boe in 2005 increased 39 percent to $32.86 from $23.69 in 2004
        resulting primarily from the increases in realized prices described above
        and a
        reduction of lower priced heavy oil volumes to 16 percent in 2005 compared
        to 23
        percent in 2004.
  33
 TABLE
            OF CONTENTS
  **Production
        expenses**
 COGP
                **Year
                    ended December 31,**($
                    000s, except per boe data)
                
                **2005**
                
                
                2004
                %
                    ChangeProduction
                    expenses
                **$**
                **95,278**
                
                $
                90,330
                5Production
                    expenses (per boe)
                **$**
                **9.86**
                
                $
                8.58
                15
  For
        the
        year ended December 31, 2005 production expenses increased five percent to
        $95.3
        million from $90.3 million and increased by 15 percent to $9.86 per boe from
        $8.58 per boe in the prior year. Throughout 2005, operating expenses continued
        to increase in a number of categories including well servicing, maintenance,
        fluid hauling, and power and fuel and combined with lower production volumes
        resulted in higher operating costs on a per boe basis. Cost increases in
        power
        and fuel, chemicals and well servicing reflect higher commodity prices and
        labour costs.
 
 Based
        on
        the current high commodity price environment and increased levels of activity,
        Provident expects Canadian operating costs to average $11.25 boe to $11.75
        per
        boe for 2006. Commodity prices affect both the cost and demand for services.
        If
        commodity prices increase, Provident expects the price of services and labour
        to
        increase.
 
 
 **Operating
        netback**
 
 COGP
        operating netbacks have transportation expense netted against gross production
        revenue.
 COGP
                **Year
                    ended December 31,**($
                    per boe)
                
                **2005**
                
                
                2004
                %
                    Change**Netback
                    per boe**Gross
                    production revenue
                $
                **47.73**
                
                $
                37.99
                26Royalties
                    (net of ARTC)
                
                **(9.87)**
                
                
                (8.08)
                22Operating
                    costs
                
                **(9.86)**
                
                
                (8.58)
                15Field
                    operating netback
                
                **28.00**
                
                
                21.33
                31Realized
                    loss on non-hedging derivative instruments
                
                **(5.00)**
                
                
                (6.18)
                (19)Operating
                    netback after non-hedging derivative instruments
                $
                **23.00**
                
                $
                15.15
                52
  The
        2005
        field operating netback of $28.00 per boe was 31 percent above the $21.33
        per
        boe for the prior year. This reflects COGP’s higher realized prices for natural
        gas and crude oil and natural gas liquids. These prices combined with a shift
        in
        COGP’s production mix to include more high netback natural gas and less low
        netback heavy oil results in a significant improvement in the field operating
        netback. Royalties, which are price sensitive, increased by 22 percent on
        a boe
        basis reflecting higher prices, prior to the impact of hedging. The 2005
        operating netbacks after hedging increased by 52 percent to $23.00 from $15.15
        in the prior year reflecting the explanation above as well as reduced hedging
        opportunity costs of $5.00  per
        boe
        compared to $6.18 in the prior year.
  34
 TABLE
            OF CONTENTS
  **General
        and administrative**
 
 The
        following table does not incorporate the COGP portion of non-cash unit based
        compensation charges associated with Provident’s unit option plan and restricted
        and performance unit plan. A non-cash expense of $2.6 million was recorded
        in
        2005.
 COGP
                **Year
                    ended December 31,**($
                    000s, except per boe data)
                
                **2005**
                
                
                2004
                %
                    ChangeCash
                    general and administrative
                $
                **18,552**
                
                $
                16,439
                13Cash
                    general and administrative per boe
                $
                **1.92**
                
                $
                1.56
                23
 In
        2005
        COGP general and administrative expenses increased 13 percent to $18.6 million
        compared to $16.4 million in 2004. On a boe basis, general and administrative
        expenses increased 23 percent to $1.92 per boe in 2005 compared to the prior
        year. The increase in general and administrative expenses reflects additional
        costs associated with a more competitive landscape affecting the cost of
        hiring
        and compensating employees and consultants as well as increases in rent,
        insurance and compliance and reporting costs.
 
 COGP
        operations are capable of absorbing additional production, particularly in
        existing core areas, with little impact on general and administrative expenses.
        For 2006 general and administrative costs will be a focus as costs associated
        with compliance (including costs associated with the implementation of
        procedures and documentation to be in compliance with the U. S. Sarbanes-Oxley
        Act), and the increasingly competitive landscape will continue to have an
        impact.
 
 Provident’s
        accounting policies result in no capitalized general and administrative expense
        for its COGP business unit.
 
 
 **Capital
        expenditures**
 COGP**Year
                    ended December 31,**($
                    000s)
                
                **2005**
                
                
                2004**Capital
                    expenditures - by area**West
                    central and southern Alberta
                $
                **32,027**
                
                $
                24,299Southeast
                    and southwest Saskatchewan
                
                **41,643**
                
                
                25,810Lloydminster
                
                **9,865**
                
                
                10,215Office
                    and other
                
                **1,867**
                
                
                1,130Total
                    additions
                $
                **85,402**
                
                $
                61,454**Capital
                    expenditures - by category**Geological
                    and geophysical
                $
                **8,473**
                
                $
                7,725Drilling,
                    recompletions, and workovers
                
                **41,315**
                
                
                34,012Facilities
                    and equipment
                
                **33,626**
                
                
                18,604Other
                    capital
                
                **1,988**
                
                
                1,113Total
                    additions
                $
                **85,402**
                
                $
                61,454Property
                    acquisitions
                
                **586**
                
                
                5,873Property
                    dispositions
                $
                **45,100**
                
                $
                13,717
  In
        2005,
        Provident’s COGP business unit spent $9.9 million in the Lloydminster area
        primarily on drilling ($7.0 million) and facility work ($2.6 million). In
        West
        central Alberta $10.5 million was spent largely on non-operated drilling
        ($4.3
        million) and facility work ($6.0 million). In southern Alberta $21.5 million
        was
        spent on drilling activities and recompletions ($10.4 million), facility
        upgrades ($10.0 million) and seismic and mineral rights acquisitions ($1.1
        million). Provident spent $41.6 million in the southeast and southwest
        Saskatchewan core areas
  35
 TABLE
            OF CONTENTS
  on
        acquiring mineral rights for future development ($7.4 million), drilling
        for
        shallow gas and recompletions ($19.3 million), and facility work ($14.9
        million). Office and other items accounted for $1.9 million of
        capital.
 
 In
        2005
        asset dispositions of non-core assets totaled $45.1 million, primarily
        consisting of the September 29, 2005 non-core properties disposition of $44.6
        million compared to $13.7 million to the prior year. COGP will continue to
        seek
        opportunities to dispose of its non-core properties given the competitive
        property market.
 
 Provident’s
        capital expenditures are partly funded through the Premium Distribution,
        Distribution Reinvestment and Optional Unit Purchase Plan (DRIP). The DRIP
        program allows investors to reinvest distributions into trust units. Provident
        directed proceeds from the DRIP program of $18.4 million in 2005 (2004 -
        $19.9
        million), along with the proceeds from asset dispositions, towards the capital
        expenditure budget.
 
 The
        2006
        capital budget approved by the Board of Director’s for COGP is $55.0
        million.
 
 
 **Depletion,
        depreciation and accretion (DD&A)**
 
 COGP
              
              
              **Year
                  ended December 31,**($
                  000s, except per boe data)
              
              
              
              
              
              **2005**
              
              
              2004DD&A
              
              
              
              
              **$**
              **155,929**
              
              $
              160,271DD&A
                  per boe
              
              
              
              
              **$**
              **16.13**
              
              $
              15.21
  The
        COGP
        DD&A rate of $16.13 per boe increased six percent for 2005 compared to $
        15.21 per boe in 2004. The increase is mainly due to incorporating a full
        year
        of higher cost reserves in the 2005 DD&A rate related to the second quarter
        2004 acquisitions. The proved reserves were acquired at a higher cost than
        COGP’s historical asset base. The cost of acquiring or drilling proved reserves
        in western Canada in an environment with higher commodity prices and increased
        drilling costs will be reflected in the DD&A rate going forward.
 
 In
        2005
        DD&A also includes accretion expense associated with asset retirement
        obligation of $2.5 million (2004 - $2.5 million).
  36
 TABLE
            OF CONTENTS
  **United
        States OGP segment review (USOGP)**
 
 The
        USOGP
        segment incorporates activities from Provident’s subsidiary, BreitBurn Energy LP
        (BreitBurn), an oil and gas exploitation and production business based in
        Los
        Angeles, California. BreitBurn was purchased June 15, 2004.
 
 On
        March
        2, 2005 Breitburn acquired Nautilus Resources, LLC, a U.S. private company
        with
        operations focused in the Big Horn and Wind River basins of Wyoming for cash
        consideration of $90.2 million.
 
 **Crude
        oil price**
 USOGP
                **Year
                    ended December 31,**($
                    per bbl)
                
                **2005**
                
                
                2004
                %
                    Change**Oil
                    per barrel**WTI
                    (US$)
                **$**
                **56.56**
                
                $
                41.43
                37Exchange
                    rate (from US$ to Cdn$)
                **$**
                **1.21**
                
                $
                1.30
                (7)WTI
                    expressed in Cdn$
                **$**
                **68.44**
                
                $
                53.86
                27USOGP
                    realized crude oil and natural gas liquids price before hedging
                    (Cdn$)
                **$**
                **57.76**
                
                $
                53.24
                8USOGP
                    realized light/medium oil price before hedging (Cdn$)
                **$**
                **57.80**
                
                $
                52.42
                10USOGP
                    realized natural gas liquids price before hedging (Cdn$)
                **$**
                **45.12**
                
                $
                49.33
                (9)
  The
        majority of USOGP oil production is light, sweet crude that attracts smaller
        differentials to benchmark prices relative to heavier blends. However, oil
        production from the Nautilus properties is heavier and attracts slightly
        wider
        differentials. Production from the former Nautilus properties represents
        approximately 26 percent of 2005 production.
 
 **Production**
 **Year
                    ended December 31,**USOGP
                
                **2005**
                
                2004
                %
                    Change**Daily
                    production - by product**Crude
                    oil - Light/Medium (bpd)
                
                **6,921**
                
                3,954
                75Natural
                    gas liquids (bpd)
                
                **24**
                
                23
                4Natural
                    gas (mcfd)
                
                **2,159**
                
                1,559
                38Oil
                    equivalent (boed)(1)
                
                **7,305**
                
                4,237
                72(1)Provident reports equivalent production converting natural gas
                    to oil on a
                    6:1 basis.
  
 **Year
                  ended December 31,**USOGP
              
              **2005**
              
              2004
              %
                  Change**Daily
                  Production - by area (boed)****(1)**Los
                  Angeles
              
              **3,949**
              
              3,513
              12Santa
                  Maria
              
              **1,393**
              
              630
              121Wyoming
              
              **1,963**
              
              94
              1,988**7,305**
              
              4,237
              72(1)Provident reports equivalent production converting natural gas
                  to oil on a
                  6:1 basis.
   Production
        for the year ended December 31, 2005 was 3,068 boed or 72 percent higher
        than
        the period June 16 to December 31, 2004. The increase is primarily attributable
        to a full year of Orcutt production included in 2005 results as well as the
        contribution of the former Nautilus properties for the period March 2 to
        December 31, 2005. Production for the former Nautilus properties was 2,260
        boed
        for the period of March 2 to December 31, 2005 while production from Orcutt
        was
        1,393 boed. The exit production rate for 2005 was approximately 7,450 boe
        per
        day.
 
 The
        2004
        daily production figures in this section are for the June to December period.
  37
 TABLE
            OF CONTENTS
  Excluding
        the Orcutt acquisition, USOGP production increased by approximately 4percent
        or
        158 boe per day in the period June 15 to December 31, 2004. The increase
        in base
        production is primarily attributable to drilling and optimization programs
        at
        West Pico and Santa Fe Springs offset by natural production declines. The
        Orcutt
        acquisition added 1,425 boe per day for the period October 4, to December
        31,
        2004.
 
 
 **Revenue
        and royalties**
 The
        following table outlines USOGP revenue and royalties by product line. The
        table
        excludes revenues earned from operating certain properties ($1.0 million
        in 2005
        and $0.6 million in 2004) on behalf of third parties .
 USOGP
                **Year
                    Ended December 31,**($
                    000s, except per boe and mcf amounts)
                **2005**
                
                
                2004
                %
                    Change**Oil**Revenue
                **$**
                **146,306**
                
                $
                41,983
                248Realized
                    loss on non-hedging derivative instrument
                
                **(16,323)**
                
                
                (425)
                3,741Royalties
                
                **(14,022)**
                
                
                (4,009)
                250Net
                    revenue
                **$**
                **115,961**
                
                $
                37,549
                209Net
                    revenue (per bbl)
                **$**
                **45.90**
                
                $
                47.72
                (4)Royalties
                    as a percentage of revenue
                
                **9.6%**
                
                
                9.5%**Natural
                    gas**Revenue
                **$**
                **7,101**
                
                $
                2,482
                186Royalties
                
                **(988)**
                
                
                **-**
                -Net
                    revenue
                **$**
                **6,113**
                
                $
                2,482
                146Net
                    revenue (per mcf)
                **$**
                **7.76**
                
                $
                8.00
                (3)Royalties
                    as a percentage of revenue
                
                **13.9%**
                
                
                0.0%**Natural
                    gas liquids**Revenue
                **$**
                **395**
                
                $
                223
                77Royalties
                
                **(9)**
                
                
                **-**
                -Net
                    revenue
                **$**
                **386**
                
                $
                223
                73Net
                    revenue (per bbl)
                **$**
                **44.05**
                
                $
                49.28
                (11)Royalties
                    as a percentage of revenue
                
                **2.4%**
                
                
                0.0%**Total**Revenue
                **$**
                **153,802**
                
                $
                44,688
                244Realized
                    loss on non-hedging derivative instrument
                
                **(16,323)**
                
                
                (425)
                3,741Royalties
                
                **(15,019)**
                
                
                (4,009)
                275Net
                    revenue
                **$**
                **122,460**
                
                $
                40,254
                204Net
                    revenue (per boe)
                **$**
                **45.93**
                
                $
                47.74
                (4)Royalties
                    as a percentage of revenue
                
                **9.8%**
                
                
                9.0%
  Royalty
        rates in the U.S. are significantly lower than in Canada.
 
 Revenue
        for the year ended December 31, 2005 is $153.8 million or 244 percent higher
        than the period from June 16 to December 31, 2004. The increase is attributable
        to a full year of operations in 2005, increases in commodity prices as well
        as a
        full year of production from the Orcutt field acquired in October of 2004
        and
        the Wyoming properties acquired in March of 2005. Net revenue is $122.5 million
        or 204 percent higher than the $40.3 million of net revenue in the period
        from
        June 16 to December 31, 2004. Increases in net revenue from a full year of
        operations, high commodity prices, production from the Orcutt field and the
        acquired Wyoming fields were offset by realized losses on non-hedging derivative
        instruments. Royalties as a percentage of revenue are up slightly as royalties
        on the acquired Wyoming properties are slightly higher than those incurred
        in
        Southern California operations.
  38
 TABLE
            OF CONTENTS
  **Production
        expenses**
 **Year
                    ended December 31,**USOGP($
                    000s, except per boe amounts)
                
                **2005**
                
                
                2004
                %
                    ChangeProduction
                    expenses
                **$**
                **39,513**
                
                $
                13,173
                200Production
                    expenses (per boe)
                **$**
                **14.82**
                
                $
                15.62
                (5)
  Production
          expenses increased $26.3 million or 200 percent to $39.5 million in the
          year
          ended December 31, 2005 compared to the period June 16 to December 31,
          2004. The
          increase is attributable to a full year of operations from the Orcutt field
          acquisition in October of 2004 and the acquired Wyoming properties in March
          of
          2005. Production expenses per boe for the year ended December 31, 2005
          are $0.80
          or five percent lower than the period June 16 to December 31, 2004. The
          decrease
          is primarily attributable to the addition of the former Nautilus properties
          in
          Wyoming. These properties have lower production expenses than the production
          from Southern California.
 
 **General
        and administrative**
 
 The
        following table does not incorporate the USOGP portion of non-cash unit based
        compensation expense associated with the USOGP unit appreciation rights plan
        and
        an internal management charge. A year to date non-cash expense for the unit
        appreciation rights plan and the internal management charge of $6.1 million
        and
        $1.7 million respectively has been recorded in 2005.
 **Year
                    ended December 31,**USOGP($
                    000s, except per boe amounts)
                
                **2005**
                
                
                2004
                %
                    ChangeCash
                    general and administrative
                **$**
                **11,490**
                
                $
                4,113
                179Cash
                    general and administrative per boe
                **$**
                **4.31**
                
                $
                4.88
                (12)
  Cash
        general and administrative expenses increased $7.4 million or 179 percent
        in the
        year ended December 31, 2005 compared to the period June 16 to December 31,
        2005. This increase is primarily attributable to a full year of operations.
        Cash
        general and administrative expenses for the year ended December 31, 2005
        declined $0.57 per boe or 12 percent compared to the period June 16 to December
        31, 2004. This is primarily attributed to the additions of Orcutt and the
        former
        Nautilus properties which were acquired without a significant increase in
        cash
        general and administrative expenses.
  **Operating
        netback**
 **Year
                    ended December 31,**USOGP($
                    per boe)
                
                **2005**
                
                2004
                %
                    Change**USOGP
                    oil equivalent netback per boe**Gross
                    production revenue
                **$**
                **57.68**
                
                $
                53.00
                9Royalties
                
                **(5.63)**
                
                
                (4.76)
                18Operating
                    costs
                
                **(14.82)**
                
                
                (15.62)
                (5)Field
                    Operating Netback
                **$**
                **37.23**
                
                $
                32.62
                14Non-hedging
                    derivative instruments
                
                **(6.12)**
                
                
                (0.50)
                1,124Operating
                    netback after non-hedging derivative instruments
                **$**
                **31.11**
                
                $
                32.12
                (3)
  39
 TABLE
            OF CONTENTS
  **Year
                  ended December
                  31,**USOGP($
                  per bbl)
              
              **2005**
              
              2004
              
              %
                  ChangeUSOGP
                  crude oil and NGL's netback per bblGross
                  production revenue
              **$**
              **57.87**
              
              $
              53.33
              
              9Royalties
              
              **(5.54)**
              
              
              (5.07)
              
              9Operating
                  costs
              
              **(14.82)**
              
              
              (15.62)
              
              (5)Field
                  Operating Netback
              **$**
              **37.51**
              
              $
              32.64
              
              15Non-hedging
                    derivative instruments
              
              **(6.44)**
              
              
              (0.54)
              
              1,093Operating
                    netback after non-hedging derivative instruments
              **$**
              **31.07**
              
              $
              32.10
              
              (3)
  **Year
                    ended December
                    31,**USOGP($
                    per mcf)
                
                **2005**
                
                2004
                
                %
                    Change**USOGP
                    natural gas netback per mcf**Gross
                    production revenue
                **$**
                **9.01**
                
                $
                8.00
                
                13Royalties
                
                **(1.25)**
                
                
                -
                
                -Operating
                    costs
                
                **(2.47)**
                
                
                (2.60)
                
                (5)Field
                    and Operating Netback
                **$**
                **5.29**
                
                $
                5.40
                
                (2)
  USOGP
        operating netbacks remained strong throughout 2005 due to high commodity
        prices.
 
 
 **Income
        taxes and cash taxes**
 USOGP
                **Year
                    ended December 31,**($
                    000s)
                
                **2005**
                
                
                2004
                %
                    ChangeCurrent
                    and withholding taxes
                $
                **5,628**
                
                $
                1,201
                369Future
                    income tax expense
                
                **18,320**
                
                
                -
                -$
                **23,948**
                
                $
                1,201
                1,894
  Current
        and withholding taxes include current U.S. federal and state income taxes
        as
        well as accrued or paid U.S. withholding taxes on distributions that have
        been
        or will be made from BreitBurn Energy LP to Provident. The 2005 future income
        tax expense of $18.3 million (2004 - nil) resulted from deduction of drilling
        costs for tax purposes in 2005 which are capitalized for accounting purposes
        and
        from changes to estimated tax pools.
 
 
 **Depletion,
        depreciation and accretion (DD&A)**
 **Year
                    ended December 31,**USOGP($
                    000s, except per boe amounts)
                
                **2005**
                
                
                2004
                %
                    ChangeDD&A
                $
                **25,553**
                
                $
                7,402
                245DD&A
                    per boe
                $
                **9.58**
                
                $
                8.78
                9
  The
        USOGP’s DD&A rate is low due to the long-lived nature of the
        assets.
 
 Depletion,
        depreciation and accretion expenses are significantly greater in 2005 than
        in
        2004 due to the additions of the former Nautilus properties as well as Orcutt.
        Additionally, the 2004 period presented is from June 15 to December 31,
        2004.
  40
 TABLE
            OF CONTENTS
 
 On
        a per
        boe basis the DD&A rate is up $0.80 or nine percent from 2004. This is
        primarily associated with the Nautilus properties, the reserves which were
        more
        expensive per boe due to the shorter reserve lives than the California
        properties and thus, slightly higher depletion, depreciation and accretion
        rates.
 
 
 **Capital
        expenditures**
 USOGP**Year
                    ended December 31,**($
                    000s)
                
                **2005**
                
                
                2004**Capital
                    expenditures - by category**Geological
                    and geophysical
                $
                **4,608**
                
                $
                761Drilling,
                    recompletions, and workovers
                
                **29,470**
                
                
                10,421Facilities
                    and equipment
                
                **18,035**
                
                
                1,228Other
                    capital
                
                **784**
                
                
                **-**Total
                    additions
                $
                **52,897**
                
                $
                12,410Property
                    acquisitions
                
                **-**
                
                
                66,872Property
                    dispositions
                $
                **-**
                
                $
                **-**
  USOGP
        capital expenditures for the year ended December 31, 2005 totaled $52.9 million.
        Of this total $38.7 million related to drilling, optimization and facility
        upgrades at West Pico, Santa Fe Springs and Orcutt. $5.0 million was directed
        at
        optimization projects in Wyoming, $3.7 million was directed to the purchase
        of
        real estate adjacent to the West Pico facility, and $5.5 million was directed
        at
        optimization projects at smaller fields as well as office
        equipment.
 
 USOGP
        capital expenditures for the year ended December 31, 2004 totaled $79.3 million,
        including property acquisitions. This includes $58.5 million for the Orcutt
        property acquisition, $3.1 million to increase BreitBurn’s working interest in
        certain wells at West Pico and Sawtelle, $7.3 million on drilling, optimization
        and facility upgrades at West Pico, $5.0 million on drilling, optimization
        and
        facility upgrades at Santa Fe Springs and $5.5 million on facility upgrades
        and
        optimization programs at other USOGP properties. Optimization capital was
        partially focused at returning previously uneconomic wells to production
        due to
        the high commodity price environment.
 
 The
        capital expenditure budget for USOGP in 2006 is $51.0 million.
  41
 TABLE
            OF CONTENTS
  **Midstream
        services and marketing business segment**
  **NGL
        Acquisition**
  On
        December 13, 2005 Provident acquired NGL assets and the Kinetic marketing
        entity
        for $772.3 million, net of cash acquired, including $38.9 million of working
        capital that includes $85.5 million of inventory. The 2005 results incorporate
        the results of operations associated with these midstream assets since
        acquisition.
 
 **The
        assets**
 The
        Midstream business unit extracts, processes, stores, transports and markets
        natural gas liquids (NGL). This is accomplished within two integrated systems
        and complementary assets. The Redwater system is comprised of three core
        assets:
 
 o
              100
                  percent ownership of the Redwater NGL Fractionation Facility, a
                  65,000
                  barrels per day (bbl/d) fractionation, storage and transportation
                  facility
                  that includes 12 pipeline receipt and delivery points, railcar
                  loading
                  facilities with direct access to CN and CP rail, two propane truck
                  loading
                  facilities, and six million gross barrels of salt cavern storage.
                  The
                  facility can process high-sulphur NGL streams and is one of only
                  two
                  facilities in western Canada capable of extracting ethane from
                  the natural
                  gas liquids stream.
 
 o
              43.3
                  percent ownership of the 38,500 bbl/d Younger NGL extraction plant
                  located
                  at Taylor in northeastern British Columbia that supplies 16,700
                  bbl/d of
                  net NGLs for processing at
                  Redwater.
 
 o
              100
                  percent ownership of the 565 kilometer proprietary Liquids Gathering
                  System (“LGS”) that runs along the Alberta-British Columbia border
                  providing access to a highly active basin for liquids-rich natural
                  gas
                  exploration and exploitation. Provident also has long-term shipping
                  rights
                  on the Pembina Peace Pipeline that extends the product delivery
                  transportation network through to the Redwater fractionation
                  facility.
 
 The
        recently acquired Empress/Sarnia system is comprised of 5 core
        assets:
 
 o
              Approximately
                  2.0 Bcf/d of extraction capacity at Empress Alberta. This is the
                  combination of 60 percent ownership of the 1.2 Bcf/d capacity Provident
                  Empress NGL Extraction plant, 12.4 percent ownership in the 1.1
                  Bcf/d
                  capacity ATCO Plant, 8.3 percent ownership in the 2.4 Bcf/d capacity
                  Duke
                  Plant and 33.0 percent ownership in the 2.7 Bcf/d capacity BP Empress
                  1
                  Plant.
 
 o
              100
                  percent ownership of a 50,000 bbl/d debutanizer at Empress
                  Alberta.
 
 o
              50
                  percent ownership in the 130,000 bbl/d Kerrobert Pipeline and 2.5
                  mmbbl
                  underground storage facility near Kerrobert, Saskatchewan which
                  facilitates injection into the Enbridge Pipeline System. Along
                  the
                  Enbridge Pipeline System, Provident holds 18.3 percent ownership
                  of
                  300,000 bbls of Superior Storage staging facility and 18.3 percent
                  ownership of the 6,600 bbl/d Superior
                  Depropanizer.
 
 o
              In
                  Sarnia, Ontario, 10.3 percent ownership of an approximately 150,000
                  bbl/d
                  fractionator, 1.7 mmbbl of raw product storage capacity and 18
                  percent of
                  5.0 mmbbl of finished product storage and rail, truck and pipeline
                  terminalling.
 
 o
              49
                  percent interest in a partnership which owns the 6.9 mmbbl Marysville
                  Underground Storage Terminal
                  (MUST).
 
 Complementary
        to the above assets is the following acquisition:
 
 o
              100
                  percent ownership of the NGL marketing group Kinetic, operating
                  a fleet of
                  approximately 700 rail cars and a propane distribution terminal
                  at
                  Lynchburg, Virginia.
 
 The
        majority of the property, plant and equipment are depreciated over 40 years
        on a
        straight-line basis reflecting the long useful life of these
        assets.
  42
 TABLE
            OF CONTENTS
  **Midstream
        and marketing services**
  Provident’s
        midstream services offer customers several types of services and contractual
        arrangements, which include:
 
 Fee
        for
        service processing - (“Transportation and Fractionation - T&F”) In these
        arrangements, NGL owners (typically natural gas producers) deliver to Provident
        their NGLs and pay fees for the transportation, fractionation, short term
        storage and distribution of their NGL barrels. The NGL owner is responsible
        for
        marketing their product.
 
 Marketing
        Services: This service involves NGL owners delivering their product to Provident
        with Provident taking title and paying the NGL owner an amount that is a
        delivery price of raw NGLs that is discounted to postings. The discounted
        purchase price that Provident pays for the product covers the costs of
        transportation, fractionation, storage, and marketing of the NGLs.
 
 Storage:
        NGL owners pay fees to store their NGLs.
 
 Transport
        and Distribution: NGL owners or purchasers pay fees to transport NGLs through
        the LGS pipeline and use rail and truck loading facilities at Redwater, Sarnia,
        Marysville and Lynchburg.
 
 **The
        contracts**
 
 At
        the
        Redwater facility, approximately 75 percent of the available capacity is
        contracted through fee-for-service or fixed margin arrangements with major
        oil
        and natural gas producers and petrochemical businesses. As a result of these
        contracts, approximately 68 percent of Redwater’s system capacity is contracted
        for 10 years or longer.
 
 As
        with
        most Alberta straddle plants, all ethane produced from Provident’s collective
        Empress interests is sold under long term contracts.
 
 **Plant
        capacities and throughput**
 
 The
        Redwater facility (100 percent ownership) was constructed between 1996 and
        1998.
        It is the most modern facility of its type in Canada and is currently designed
        for throughput capacity of 65,000 bpd of NGLs with an expectation to average
        approximately 63,000 bpd.
 
 The
        Provident Empress plant (60 percent ownership) was commissioned in September
        1996 and subsequently expanded in 1999 and 2003. It is one of the newest
        and
        most cost efficient facilities at Empress. The plant has a design capacity
        of
        1.2 Bcf/d to extract ethane and propane-plus.
 
 The
        BP
        Empress 1 plant (33 percent ownership) base plant was commissioned in 1971
        with
        expansions commissioned in 1994 and 2005. The base plant has a capacity of
        1.7
        Bcf/d to extract ethane and propane-plus. The 1994 train addition has 1 Bcf/d
        capacity to extract propane-plus.
 
 The
        Duke
        plant (8.3 percent ownership) was commissioned in 1964. It has a capacity
        of 2.4
        Bcf/d. It has the following unique aspects (1) an airstrip; (2) treatment
        for
        ethane to remove CO 2 ;
        (3) a
        Ferus CO 2 plant
        hosted on a shared operating cost basis; (4) the only plant at the Empress
        Complex with full ethane-plus fractionation facilities; and (5) the ability
        to
        dispatch products by truck, rail, the IPF Jenner Pipeline, the Kerrobert
        Pipeline, and the PTC Pipeline.
 
 The
        ATCO
        Plant (12.4 percent ownership) was commissioned in 1982, and expanded in
        1999,
        and has an extraction capacity of 1.1 Bcf/d.
 
 The
        Provident Debutanizer (100 percent ownership) was commissioned at the end
        of
        2005. It has a design capacity of 50,000 bbl/d of propane-plus and will remove
        condensate currently delivered to the Kerrobert Pipeline.
 
 The
        Kerrobert Pipeline (50 percent ownership) is an NEB regulated pipeline
        constructed in 1971 to deliver propane-plus product from the Empress Comples
        to
        Kerrobert Storage near Kerrobert, Saskatchewan. It has a capacity of 130,000
        bbl/d. Kerrobert Storage was also developed in 1971 and has a design capacity
        of
        2.5 mmbbls.
 
 Superior
        Storage (18.3 percent ownership) has a design capacity of 300,000 bbls and
        was
        built to accommodate the change in shipping rates within the Enbridge Pipeline
        system.
  43
 TABLE
            OF CONTENTS
 
 The
        Superior Depropanizer was built in 1991 and is designed to process approximately
        10,000 bbl/d of propane-plus and extract 6,600 bbl/d of propane.
 
 Sarnia
        Fractionation (10.3 percent ownership) began operations in 1970. It has an
        average capacity of approximately 150,000 bbl/d.
 
 Provident
        has a 49 percent partnership interest in the Marysville Partnership which
        owns
        the Marysville Underground Storage Terminal (“MUST”). This storage terminal has
        a capacity of approximately 6.9 MMbbls for raw and specification NGL
        product.
 
 **Operations
        - managed NGL volumes**
 
 In
        2005,
        Provident Midstream managed approximately 64,740  bpd
        compared to  57,484
        bpd in 2004 and closed the year with managed volumes of approximately 140,640
        bpd. This includes activity from the newly acquired NGL assets since acquisition
        on December 13, 2005. In addition, throughput at Redwater has improved with
        the
        completion of an operating enhancement.
 
 **Revenues**
 
 2005
        product sales and services revenues of $908.1 million after elimination of
        intersegment transactions, include product sales related to T&F processing
        and marketing, revenues generated through storage and distribution services
        and
        oil sales generated through oil marketing activities (2004 - $840.2 million).
        The increase in revenue is the result of the Midstream NGL Acquisition ($67.2
        million of revenue in 2005) as well as higher product prices offset by the
        sale
        of certain crude oil marketing contracts on May 1, 2005. The majority of
        NGL
        revenues are earned pursuant to the long-term contracts and annual evergreen
        purchase and sales commitments.
 
 **Cost
        of goods sold**
 
 The
        cost
        of goods sold of $786.6 million for 2005 relates to NGL product sales revenue
        included in the product sales and services revenue, where Provident has
        purchased natural gas liquids and to oil purchased pursuant to oil marketing
        activities (2004 - $741.6 million). The increase in cost of goods sold is
        the
        result of the Midstream NGL Acquisition ($58.1 million cost of goods sold
        in
        2005) as well as higher product prices offset by the sale of certain crude
        oil
        marketing contracts of May 1, 2005. The NGL costs would be applicable to
        the
        fixed margin contracts and a small percentage of volume delivered from the
        Younger facility on which Provident manages extraction economics. For 2005,
        the
        majority of the natural gas liquids were purchased pursuant to long-term
        contracts and annual evergreen purchase commitments which is consistent with
        previous years.
 
 **Product
        Margin**
 
 Product
        margin is the revenue less the cost of good sold and is representative of
        the
        margins obtained on marketed products, however it is affected by fee for
        service
        revenues that are grouped in with product sales and service revenues. In
        2005,
        $121.5 million or a 13 percent product margin was generated on $908.1 million
        of
        product sales and service revenues compared to $98.5 million or a 12 percent
        product margin generated on $840.2 million of 2004 product sales and service
        revenues. The 2005 product margin would be expected to be higher than the
        2004
        which included the lower margin crude oil marketing activities. In future
        periods the product margin will be subject to a wider range of variability
        driven by the Midstream NGL Acquisition that increases exposure to extraction
        economics.
 
 **Fractionation
        Spread Support Program**
  As
        part
        of the Midstream NGL Acquisition, the vendor has agreed to provide a near-term
        fractionation spread support program. The program provides Provident with
        up to
        $75 million of support over the next two years if fractionation spreads are
        below historic levels. This program intended to ensure that Provident achieves
        the long-term average fractionation spreads which the NGL business has attained
        historically through to November 2007. This program is intended to provide
        consistent and stable cash flow and distributions for Unitholders. In certain
        circumstances, the vendor will have the ability to recover the amounts provided
        under the support program until October 31, 2008, if fractionation spreads
        exceed historic levels. Provident’s long term risk management strategy is
        focused on locking in fractionation spread margins, with the objective of
        stabilizing cash flow over the longer term.
  44
 TABLE
            OF CONTENTS
 
 The
        impact of the agreement on 2005 was a receipt of $5.2 million that resulted
        in a
        reduction in the cost of goods available for sale with no comparative for
        2004.
 
 **Other
        expenses**
 
 The
        Redwater plant is still the newest and most cost effective compared to other
        North American facilities of this type. In 2005, operating costs of $36.4
        million (2004 - $38.0 million) reflect cost reductions at the Younger NGL
        extraction plant. General and administrative expenses of $11.6 million for
        2005
        (2004 - $6.6 million), interest of $4.9 million for 2005 (2004 - $7.2 million),
        and depreciation of $11.8  million
        for 2005 (2004 - $9.6 million). Increases in general and administrative expenses
        reflect additional costs associated with a more competitive landscape affecting
        the cost of hiring and compensating employees and consultants as well as
        increases in rent, insurance and compliance and reporting costs. Increases
        in
        general and administrative expenses in 2005 resulted from allocation of costs
        in
        the fourth quarter resulting from the Midstream NGL Acquisition which was
        negotiated, announced and closed in fourth quarter 2005 and increased direct
        costs.
 
 
 **Earnings
        before interest, taxes, depletion, depreciation, accretion, and other non-cash
        items (“EBITDA”)**  **and
        cash flow from operations**
 
 For
        2005,
        Provident’s Midstream business unit generated EBITDA of $70.7 million and cash
        flow from operations of $66.3 million. Actual EBITDA performance exceeded
        management’s 2005 EBITDA forecast of $40.0 million. These results compare to
        2004 EBITDA of $50.1 million and cash flow of $42.6 million. The increase
        over
        2004 is primarily due to stronger product premiums in 2005 as well as an
        increase in product prices over the period.
 
 Management
        uses EBITDA to analyze the operating performance of the midstream business
        unit.
        EBITDA as presented does not have any standardized meaning prescribed by
        Canadian GAAP and therefore it may not be comparable with the calculation
        of
        similar measures for other entities. EBITDA as presented is not intended
        to
        represent operating cash flow or operating profits for the period nor should
        it
        be viewed as an alternative to cash flow from operating activities, net earnings
        or other measures of financial performance calculated in accordance with
        Canadian GAAP. All references to EBITDA throughout this report are based
        on
        Earnings before interest, taxes, depletion, depreciation, accretion, and
        other
        non-cash items (“EBITDA”).
 
 **Gain
        on sale of marketing contracts**
 
 On
        May 1,
        2005 the Trust disposed of certain crude oil marketing contracts for net
        proceeds of $5.5 million and recorded a gain of $5.2 million net of disposal
        costs. The sale of these contracts will not materially impact cash flows
        and has
        been recognized through the Midstream services and marketing segment. During
        2004 the crude oil marketing business generated $203.0 million in revenues.
        For
        the four months period ended April 30, 2005 the crude oil marketing business
        generated $105.7 million in revenues. The sale of these contracts is not
        expected to have a material impact on the cash flow or net income of the
        Midstream segment.
 
 **Capital
        expenditures**
 
 Midstream
        capital expenditures, excluding corporate acquisitions, for 2005 totaled
        $18.2
        million. $17.0 million of the capital was spent on new product handling
        facilities including the new condensate offloading and terminalling facilities
        recently announced as well as truck loading facilities and a rail yard
        expansion. The remainder of the capital was spent on pipeline integrity and
        on
        the Younger plant as well as on enhancing the overall efficient and safe
        operations of the fractionation plant. This compared to $3.0 million spent
        in
        2004 on pipeline integrity, efficiency and safety projects and $0.7 million
        spent on product handling expansion.
  45
 TABLE
            OF CONTENTS
  **Foreign
        ownership**
 
 Based
        on
        information received from our transfer agent and financial intermediaries
        in
        March 2006, an estimated 85 percent of our outstanding trust units are held
        by
        non-residents. However, this estimate may not be accurate as it is based
        on
        certain assumptions and data from the security industry that does not have
        a
        well-defined methodology to determine the residency of beneficial holders
        of
        securities.
 
 The
        Trust
        qualifies as a Mutual Fund Trust under the Canadian Income Tax Act because
        substantially all the value of its asset portfolio is derived from non-taxable
        Canadian properties, comprised principally of royalties and inter-company
        debt.
        Provident monitors on an ongoing basis the value of its asset portfolio to
        confirm that substantially all of the value of its asset portfolio is derived
        from non-taxable Canadian properties.
 
 On
        September 17, 2003 Canadian unitholders approved an amendment to the Trust’s
        Trust Indenture providing that residency restriction provisions need not
        be
        enforced while the Trust continues to qualify as a Mutual Fund Trust under
        Canadian tax legislation. To allow Provident to remain a Mutual Fund Trust
        and
        to execute a business plan that maximizes unitholder returns without regard
        to
        the types of assets the Trust may hold, the approved amendment provides for
        Provident’s board of directors to have sole discretion to determine whether and
        when it is appropriate to reduce or limit the number of trust units held
        by
        non-residents of Canada.
 
 
 **Related
        party**
 **Property
        sale**
 
 On
        December 30, 2004, at the conclusion of a competitive process, Provident
        sold
        properties to a private company on whose board two of the directors of Provident
        sit and in which they own shares. The properties were sold for consideration
        of
        $3.5 million of which $0.5 million was cash and $3.0 million consisted of
        10,000,000 common shares valued at $0.30 per share. The carrying value of
        these
        shares are included in investments on the balance sheet. The transaction
        was
        recorded at fair value.
 
 **Business
        prospects**
 
 Provident
        intends to execute a balanced portfolio strategy. In the COGP business internal
        development projects with a board approved capital budget of $55.0 **** million
        are planned. Acquisitions of interest in properties close to properties already
        owned or partially owned by Provident will be pursued. In the USOGP business
        internal development projects are planned with a board approved capital budget
        of $51.0 **** million.
        Major corporate or property acquisitions are and will be evaluated. In the
        Midstream Services business Provident will expand and build upon the business
        and evaluate additional infrastructure assets with a goal of adding quality
        assets at reasonable prices. The goal of these strategies is to maintain
        and
        increase per unit distributable cash flow and net asset value.
 
 **Critical
        accounting policies**
 
 Provident’s
        accounting policies are described in note 2 to the consolidated financial
        statements. Certain accounting policies are identified as critical accounting
        policies because they form an integral part of Provident’s financial position.
        They also require management to make judgments and estimates based on conditions
        and assumptions that are inherently uncertain. These accounting policies
        could
        result in materially different results should the underlying assumptions
        or
        conditions change.
 
 Management
        assumptions are based on Provident’s historical experience, management’s
        experience, and other factors that, in management’s opinion, are relevant and
        appropriate. Management assumptions may change over time, as further experience
        is gained or as operating conditions change.
 
 Details
        of Provident’s critical accounting policies are as follows:
 
 **Property,
        plant and equipment**
 
 Provident
        follows the full cost method of accounting, whereby all costs associated
        with
        the acquisition and development of oil and natural gas reserves are capitalized.
        Utilization of the full cost method of accounting
  46
 TABLE
            OF CONTENTS
  requires
        the use of management estimates and assumptions for amounts recorded for
        depletion and depreciation of property, plant and equipment as well as for
        the
        ceiling test.
 
 The
        provision for depletion and depreciation is calculated using the unit of
        production method based on current production divided by Provident’s share of
        estimated total proved oil and natural gas reserve volumes before royalties.
        The
        recoverability of a cost centre is tested by comparing the carrying value
        of the
        cost centre to the sum of the undiscounted cash flows expected from the cost
        centre. If the carrying value is not recoverable the cost centre is written
        down
        to its fair value.
 
 Proved
        reserves are an estimate, under existing reserve evaluation polices, of volumes
        that can reasonably be expected to be economically recoverable under existing
        technology and economic conditions. Changes in underlying assumptions or
        economic conditions could have a material impact on Provident’s financial
        results. To mitigate these risks management utilizes McDaniel & Associates
        Consultants Ltd., an independent engineering firm, to evaluate Provident’s
        Canadian reserves. For Provident’s U.S. based assets management utilizes Cawley,
        Gillespie & Associates, Inc. and Netherland, Sewell & Associates, Inc.,
        independent engineering firms, to evaluate reserves.
 
 Estimates
        of future production, oil and natural gas prices and future costs used in
        the
        ceiling test are, by their very nature, subject to uncertainty and changes
        in
        underlying assumptions could have a material impact on Provident’s financial
        results.
 
 **Asset
        retirement obligation**
 
 Under
        the
        asset retirement obligation (ARO) standard, the fair value of asset retirement
        obligations is recorded as a liability on a discounted basis, when incurred.
        The
        value of the related assets are increased by the same amount as the liability
        and depreciated over the useful life of the asset. Over time the liability
        is
        adjusted for the change in present value of the liability or as a result
        of
        changes to either the timing or amount of the original estimate of undiscounted
        future cash flows.
 
 Asset
        retirement obligation requires that management make estimates and assumptions
        regarding future liabilities and cash flows involving environmental reclamation
        and remediation. Such assumptions are inherently uncertain and subject to
        change
        over time due to factors such as historical experience, changes in environmental
        legislation or improved technologies. Changes in underlying assumptions,
        based
        on the above noted factors, could have a material impact on Provident’s
        financial results.
 
 
 **Change
        in accounting policies**
 
 The
        following change in accounting policy was adopted by Provident in
        2005.
 
 **Exchangeable
        securities - non-controlling interest**
 
 The
        Canadian Institute of Chartered Accountants issued an amendment to EIC abstract
        151 "Exchangeable Securities Issued by Subsidiaries of Income Trusts" that
        states that exchangeable securities issued by a subsidiary of an income trust
        should be reflected as either non-controlling interest or debt on the
        consolidated balance sheet unless they meet certain criteria. The exchangeable
        shares issued by Provident Acquisitions Inc. and Provident Energy Ltd. corporate
        subsidiaries of the Trust are considered under this standard to be transferable
        to third parties. EIC-151 states that if the exchangeable shares are
        transferable to a third party, they should be reflected as non-controlling
        interest. Previously, the exchangeable shares were reflected as a component
        of
        unitholders' equity.
 
 As
        a result of this change in accounting policy, the Trust has reflected
        non-controlling interest of $8.3 million and $35.9 million, respectively,
        on the
        Trust's consolidated balance sheet as at December 31, 2005 and December 31,
        2004. Consolidated net income or loss has been adjusted for the earnings
        attributable to the non-controlling interest of $0.8 million for the year
        ended
        December 31, 2005 and $0.5 million for the year ended December 31, 2004.
        As at
        June 30, 2005 unitholders' equity was reduced by $11.2 million and
        non-controlling interest on the consolidated balance sheet increased by $13.0
        million. In accordance with the transitional provisions of EIC-151, retroactive
        application has been applied with restatement of prior periods. The retroactive
        application of this abstract as at December 31, 2004 was an accumulated loss
        of
        $1.5 million. The retroactive accumulated loss adjustments represent the
        cumulative net income attributable to the non controlling interest for prior
        periods. Cash flow was not affected by this change.
  47
 TABLE
            OF CONTENTS
  **Recent
        accounting pronouncements**
 
 The
        following new accounting guidelines or standards are applicable to Provident
        but
        have not been implemented.
 
 **Financial
        Instruments, Hedges and Comprehensive Income**
 
 In
        2005, the CICA issued Section 3855 “Financial instruments-recognition and
        measurement,” Section 3865 “Hedges,” and Section 1530 “Comprehensive Income.”
Under these Sections, standards for recognizing and measuring financial assets,
        financial liabilities and non-financial derivatives have been established.
        The
        standards will require the majority of derivatives to be classified as held
        for
        trading and will be measured at fair value with gains and losses recognized
        in
        net income in the periods in which they arise unless they are part of a hedging
        relationship. For hedges, the existing requirements for hedge accounting
        under
        Accounting Guideline 13 “Hedging relationships” are maintained, with the
        majority of hedging relationships being stated at fair value with a gain
        or loss
        from remeasuring the foreign currency component of its carrying amount being
        recognized in net income in the period of change together with the offsetting
        loss or gain on the hedged item attributable to the hedged risk. These new
        standards also require an entity to present comprehensive income and its
        components, as well as net income, in its financial statements. This will
        include certain gains or losses, including foreign currency translation and
        other amounts arising from changes in fair value. These Sections apply to
        interim and annual financial statements relating to fiscal years beginning
        on or
        after October 1, 2006. The Trust has not evaluated the effect that this standard
        might have on the consolidated financial statements.
 
 **Equity**
 
 In
        2005, the CICA issued Section 3251 “Equity”. This Section replaces Section 3250
“Surplus” and establishes standards for the presentation of equity and changes
        in equity during the reporting period. The Section requires an entity to
        present
        separately each of the changes in equity during the period, including
        comprehensive income, as well as components of equity at the end of the period.
        This Section applies to interim and annual financial statements relating
        to
        fiscal years beginning on or after October 1, 2006. The Trust has not evaluated
        the effect that this standard might have on the consolidated financial
        statements.
 
 **Non-Monetary
        Transactions**
 
 In
        2005, the CICA issued Section 3831 “Non-Monetary Transactions”. In this new
        standard, a commercial substance test replaces the culmination of earnings
        test
        as criteria for fair value measurement. This new requirement is effective
        for
        non-monetary transactions initiated in periods beginning on or after January
        1,
        2006. The Trust does not expect the adoption of this abstract to have a material
        impact on its financial statements.
 
 **Conditional
        Asset Retirement Obligations**
 
 In
        2005,
        the CICA issued EIC 159 “Conditional Asset Retirement Obligations”. This
        abstract clarifies that the term conditional asset retirement obligation
        as used
        in CICA 3110 refers to a legal obligation to perform an asset retirement
        activity in which the timing and/or method of settlement are conditional
        on a
        future event that may or may not be within the control of the entity. The
        obligation to perform the asset retirement activity is unconditional even
        though
        uncertainty exists about the timing and/or method of settlement. Thus, the
        timing and/or method of settlement may be conditional on a future event.
        Accordingly, an entity is required to recognize a liability for the fair
        value
        of a conditional asset retirement obligation if the fair value of the liability
        can be reasonably estimated. This abstract is to be applied retroactively,
        with
        restatement of prior periods, to all financial statements for interim and
        annual
        reporting periods ending after March 31, 2006. The Trust does not expect
        the
        adoption of this abstract to have a material impact on its financial
        statements .
 
 48
 TABLE
            OF CONTENTS
  **Business
        risks**
 
 The
        oil
        and natural gas trust industry is subject to numerous risks that can affect
        the
        amount of cash flow available for distribution to unitholders and the ability
        to
        grow. These risks include but are not limited to:
 
 o
              fluctuations
                  in commodity price, exchange rates and interest
                  rates;
 o
              government
                  and regulatory risk in respect of royalty and income tax
                  regimes;
 o
              operational
                  risks that may affect the quality and recoverability of
                  reserves;
 o
              geological
                  risk associated with accessing and recovering new quantities of
                  reserves;
 o
              transportation
                  risk in respect of the ability to transport oil and natural gas
                  to
                  market;
 o
              capital
                  markets risk and the ability to finance future
                  growth;
 o
              marketability
                  of oil and natural gas;
 o
              income
                  tax legislation relating to income trusts;
                  and
 o
              environmental,
                  health and safety risks.
 
 The
        midstream industry is also subject to risks that can affect the amount of
        cash
        flow available for distribution to unitholders and the ability to grow. These
        risks include but are not limited to:
 
 o
              operational
                  matters and hazards including the breakdown or failure of equipment,
                  information systems or processes, the performance of equipment
                  at levels
                  below those originally intended, operator error, labour disputes,
                  disputes
                  with owners of interconnected facilities and carriers and catastrophic
                  events such as natural disasters, fires, explosions, fractures,
                  acts of
                  eco-terrorists and saboteurs, and other similar events, many of
                  which are
                  beyond the control of the Trust or
                  Provident;
 o
              the
                  Midstream NGL assets are subject to competition from other gas
                  processing
                  plants, and the pipelines and storage, terminal and processing
                  facilities
                  are also subject to competition from other pipelines and storage,
                  terminal
                  and processing facilities in the areas they serve, and the gas
                  products
                  marketing business is subject to competition from other marketing
                  firms;
 o
              exposure
                  to commodity price fluctuations;
 o
              regulatory
                  intervention in determining processing fees and tariffs;
                  and
 o
              reliance
                  on significant customers.
 
 Provident
        strives to minimize these business risks by:
 
 o
              employing
                  and empowering management and technical staff with extensive industry
                  experience;
 o
              adhering
                  to a strategy of acquiring, developing and optimizing quality,
                  low-risk
                  reserves in areas where we have technical and operational
                  expertise;
 o
              developing
                  a diversified, balanced asset portfolio that generally offers developed
                  operational infrastructure, year-round access and close proximity
                  to
                  markets;
 o
              adhering
                  to a consistent and disciplined Commodity Price Risk Management
                  Program to
                  mitigate the impact that volatile commodity prices have on cash
                  flow
                  available for distribution.
 o
              marketing
                  crude oil and natural gas to a diverse group of customers, including
                  aggregators, industrial users, well-capitalized third-party marketers
                  and
                  spot market buyers;
 o
              marketing
                  natural gas liquids and related services to selected, credit worthy
                  customers at competitive rates;
 o
              maintaining
                  a low cost structure to maximize cash flow and
                  profitability;
 o
              maintaining
                  prudent financial leverage and developing strong relationships
                  with the
                  investment community and capital
                  providers;
 o
              adhering
                  to strict guidelines and reporting requirements with respect to
                  environmental, health and safety practices;
                  and
 o
              maintaining
                  an adequate level of property, casualty, comprehensive and directors’ and
                  officers’ insurance coverage.
  49
 TABLE
            OF CONTENTS
   **Unit
        trading activity**
 
 Provident
        has moved to the New York Stock Exchange as of December 16, 2005. The following
        table summarizes the unit trading activity of the Provident units for the
        four
        quarters ended December 31, 2005 on both the Toronto Stock Exchange and the
        American Stock Exchange:
 **Q1**
                
                **Q2**
                
                **Q3**
                
                **Q4****TSE
                    - PVE.UN (Cdn$)**High
                $
                12.60
                $
                13.05
                $
                14.29
                $
                14.42Low
                $
                11.17
                $
                11.82
                $
                12.91
                $
                12.29Close
                $
                11.98
                $
                12.82
                $
                14.14
                $
                12.55Volume
                    (000s)
                
                26,122
                
                15,951
                
                22,375
                
                30,786**AMEX/NYSE
                    - PVX (US$)**High
                $
                10.40
                $
                10.55
                $
                12.19
                $
                12.38Low
                $
                9.15
                $
                9.48
                $
                10.65
                $
                10.37Close
                $
                9.89
                $
                10.49
                $
                12.19
                $
                10.81Volume
                    (000s)
                
                64,223
                
                46,548
                
                55,372
                
                55,981
 **Additional
        information**
 
 Additional
        information concerning Provident can be accessed under Provident’s public
        filings at www.sedar.com and on
        Provident’s website at www.providentenergy.com .
 
 
 **Selected
        annual financial measures**
 ($
                    000s except per unit data)
                
                **2005**
                
                2004
                
                2003Restated(1)
                
                Restated(1)Revenue
                    (net of royalties and financial derivative instruments)
                **$**
                **1,360,274**
                $
                1,109,857
                $
                406,329Net
                    income
                
                **96,926**
                
                21,225
                
                22,497Net
                    income per unit-basic
                
                **0.61**
                
                0.19
                
                0.35Net
                    income per unit-diluted
                
                **0.61**
                
                0.19
                
                0.35Total
                    assets
                
                **2,792,270**
                
                1,813,582
                
                1,142,955Long-term
                    financial liabilities(2)
                
                **925,737**
                
                472,712
                
                389,755Declared
                    Distributions per unit
                **$**
                **1.44**
                $
                1.44
                $
                2.06(1)see
                    note 3 to consolidated financial statements(2)includes long term debt and asset retirement obligation
  50
 TABLE
            OF CONTENTS
  **Quarterly
        table**
 ($
                    000s except for per unit amounts)
                **2005**First
                
                Second
                
                Third
                
                Fourth
                
                YTDQuarter(1)
                
                Quarter
                
                Quarter
                
                Quarter
                
                Total**Financial
                    - consolidated**Revenue
                
                
                $
                322,023
                
                $
                300,504
                
                $
                295,060
                
                $
                442,687
                
                $
                1,360,274Cash
                    flow
                
                
                $
                64,137
                
                $
                64,435
                
                $
                86,318
                
                $
                96,298
                
                $
                311,188Net
                    income (loss)
                
                
                $
                (2,783
                )
                $
                26,822
                
                $
                18,386
                
                $
                54,501
                
                $
                96,926Net
                    income (loss) per unit - basic and diluted
                
                
                $
                (0.02
                )
                $
                0.17
                
                $
                0.11
                
                $
                0.32
                
                $
                0.61Unitholder
                    distributions
                
                
                $
                51,734
                
                $
                57,001
                
                $
                59,333
                
                $
                62,646
                
                $
                230,714Distributions
                    per unit
                
                
                $
                0.36
                
                $
                0.36
                
                $
                0.36
                
                $
                0.36
                
                $
                1.44**Oil
                    and gas production**Cash
                    revenue
                
                
                $
                100,447
                
                $
                104,478
                
                $
                124,073
                
                $
                117,710
                
                $
                446,708Earnings
                    before interest, DD&A, taxes
                  and
                    other non-cash items
                
                
                $
                59,262
                
                $
                63,584
                
                $
                81,670
                
                $
                73,976
                
                $
                278,492Cash
                    flow
                
                
                $
                48,937
                
                $
                53,868
                
                $
                74,139
                
                $
                68,006
                
                $
                244,950Net
                    income (loss)
                
                
                $
                (15,046
                )
                $
                14,681
                
                $
                10,702
                
                $
                30,437
                
                $
                40,774**Midstream
                    services and marketing**Cash
                    revenue
                
                
                $
                245,338
                
                $
                186,635
                
                $
                180,875
                
                $
                293,034
                
                $
                905,882Earnings
                    before interest, DD&A, taxes
                
                
                $
                16,380
                
                $
                11,765
                
                $
                12,978
                
                $
                29,566
                
                $
                70,689and
                    other non-cash itemsCash
                    flow
                
                
                $
                15,200
                
                $
                10,567
                
                $
                12,179
                
                $
                28,292
                
                $
                66,238Net
                    income
                
                
                $
                12,263
                
                $
                12,141
                
                $
                7,684
                
                $
                24,064
                
                $
                56,152**Operating**Oil
                    and gas productionLight/medium
                    oil (bpd)
                
                
                
                14,388
                
                
                15,891
                
                
                15,583
                
                
                14,051
                
                
                14,979Heavy
                    oil (bpd)
                
                
                
                5,547
                
                
                4,644
                
                
                4,075
                
                
                3,195
                
                
                4,358Natural
                    gas liquids (bpd)
                
                
                
                1,756
                
                
                1,454
                
                
                1,523
                
                
                1,653
                
                
                1,596Natural
                    gas (mcfd)
                
                
                
                80,466
                
                
                79,126
                
                
                75,523
                
                
                73,363
                
                
                77,095Oil
                    equivalent (boed)
                
                
                
                35,102
                
                
                35,177
                
                
                33,768
                
                
                31,126
                
                
                33,782**(Cdn
                    $)****Average
                    selling price net of**
                  **transportation
                    expense**Light/medium
                    oil per bbl
                
                
                $
                49.32
                
                $
                51.20
                
                $
                62.95
                
                $
                55.31
                
                $
                54.69(before
                    hedges)Light/medium
                    oil per bbl
                
                
                $
                40.93
                
                $
                42.18
                
                $
                49.82
                
                $
                42.52
                
                $
                43.90(including
                    hedges)Heavy
                    oil per bbl
                
                
                $
                25.85
                
                $
                26.03
                
                $
                46.74
                
                $
                28.62
                
                $
                31.33(before
                    hedges)Heavy
                    oil per bbl
                
                
                $
                25.78
                
                $
                26.03
                
                $
                46.74
                
                $
                28.62
                
                $
                31.31(including
                    hedges)Natural
                    gas liquids per barrel
                
                
                $
                45.30
                
                $
                47.75
                
                $
                54.27
                
                $
                49.44
                
                $
                49.09Natural
                    gas per mcf
                
                
                $
                6.76
                
                $
                7.29
                
                $
                8.43
                
                $
                11.44
                
                $
                8.43(before
                    hedges)Natural
                    gas per mcf
                
                
                $
                6.74
                
                $
                7.13
                
                $
                8.03
                
                $
                11.22
                
                $
                8.23(including
                    hedges)**Midstream
                    services and marketing**Managed
                    volumes (bpd)
                
                
                
                61,590
                
                
                58,200
                
                
                61,760
                
                
                77,100
                
                
                64,740(1)Restated
                    - note 3
 51
 TABLE
            OF CONTENTS
 **Quarterly
        table**
 ($
                    000s except per unit amounts)
                **2004****(1)**First
                    Quarter
                
                Second
                    Quarter
                
                Third
                    Quarter
                
                Fourth
                    Quarter
                
                YTDQuarter
                
                Quarter
                
                Quarter
                
                Quarter
                
                Total**Financial
                    - consolidated**Revenue
                $
                234,947
                
                $
                218,304
                
                $
                287,171
                
                $
                369,435
                
                $
                1,109,857Cash
                    flow
                $
                36,269
                
                $
                36,530
                
                $
                54,076
                
                $
                58,371
                
                $
                185,246Net
                    income (loss)
                $
                (5,995
                )
                $
                (6,873
                )
                $
                (4,221
                )
                $
                38,314
                
                $
                21,225Net
                    income (loss) per unit - basic and diluted
                $
                (0.07
                )
                $
                (0.07
                )
                $
                (0.03
                )
                $
                0.27
                
                $
                0.19Unitholder
                    distributions
                $
                31,036
                
                $
                35,039
                
                $
                46,489
                
                $
                52,064
                
                $
                164,628Distributions
                    per unit
                $
                0.36
                
                $
                0.36
                
                $
                0.36
                
                $
                0.36
                
                $
                1.44**Oil
                    and gas production**Cash
                    revenue
                $
                54,865
                
                $
                59,316
                
                $
                89,129
                
                $
                91,569
                
                $
                294,879Earnings
                    before interest, DD&A, taxes
                  and
                    other non-cash items
                $
                30,741
                
                $
                34,974
                
                $
                51,767
                
                $
                50,498
                
                $
                167,980Cash
                    flow
                $
                26,386
                
                $
                29,593
                
                $
                44,825
                
                $
                41,798
                
                $
                142,602Net
                    income (loss)
                $
                (9,761
                )
                $
                (10,950
                )
                $
                (17,356
                )
                $
                27,490
                
                $
                (10,577
                )**Midstream
                    services and marketing**Cash
                    revenue
                $
                233,031
                
                $
                218,388
                
                $
                287,679
                
                $
                288,768
                
                $
                1,027,866Earnings
                    before interest, DD&A, taxes
                $
                12,197
                
                $
                8,945
                
                $
                10,986
                
                $
                17,957
                
                $
                50,085and
                    other non-cash items
                
                
                
                
                
                
                
                
                
                
                
                
                $Cash
                    flow
                $
                9,883
                
                $
                6,937
                
                $
                9,251
                
                $
                16,573
                
                
                42,644Net
                    income
                $
                3,766
                
                $
                4,077
                
                $
                13,135
                
                $
                10,824
                
                $
                31,802**Operating**Oil
                    and gas productionLight/medium
                    oil (bpd)
                
                5,965
                
                
                7,861
                
                
                12,674
                
                
                14,012
                
                
                10,146Heavy
                    oil (bpd)
                
                6,588
                
                
                6,537
                
                
                6,770
                
                
                6,536
                
                
                6,608Natural
                    gas liquids (bpd)
                
                1,130
                
                
                1,267
                
                
                1,803
                
                
                1,770
                
                
                1,494Natural
                    gas (mcfd)
                
                63,859
                
                
                68,007
                
                
                88,642
                
                
                87,339
                
                
                77,022Oil
                    equivalent (boed)
                
                24,326
                
                
                27,000
                
                
                36,021
                
                
                36,874
                
                
                31,085**(Cdn
                    $)****Average
                    selling price net of**
                  **transportation
                    expense**Light/medium
                    oil per bbl(before
                    hedges)
                $
                39.00
                
                $
                42.28
                
                $
                48.59
                
                $
                45.83
                
                $
                45.01Light/medium
                    oil per bbl(including
                    hedges)
                $
                26.15
                
                $
                29.97
                
                $
                38.00
                
                $
                33.88
                
                $
                33.29Heavy
                    oil per bbl(before
                    hedges)
                $
                26.84
                
                $
                28.26
                
                $
                34.23
                
                $
                25.33
                
                $
                28.72Heavy
                    oil per bbl(including
                    hedges)
                $
                22.80
                
                $
                23.26
                
                $
                25.72
                
                $
                22.17
                
                $
                23.51Natural
                    gas liquids per barrel
                $
                37.03
                
                $
                40.55
                
                $
                40.88
                
                $
                42.80
                
                $
                40.68Natural
                    gas per mcf(before
                    hedges)
                $
                6.40
                
                $
                7.01
                
                $
                6.47
                
                $
                6.56
                
                $
                6.60Natural
                    gas per mcf(including
                    hedges)
                $
                6.31
                
                $
                6.26
                
                $
                6.05
                
                $
                6.31
                
                $
                6.23**Midstream
                    services and marketing**Managed
                    volumes (bpd)
                
                67,279
                
                
                51,393
                
                
                58,400
                
                
                52,870
                
                
                57,484(1)Restated - note 3


52
 TABLE
          OF CONTENTS











**PricewaterhouseCoopers
        LLP**
 **Chartered
        Accountants**
 111
        5th Avenue SW, Suite 3100
 Calgary,
        Alberta
 Canada
        T2P 5L3
 Telephone
        +1 (403) 509 7500
 Facsimile
        +1 (403) 781 1825
  **Auditors’
        Report**
  **To
        the Unitholders of Provident Energy Trust**
  We
        have audited the consolidated balance sheets of **Provident
        Energy Trust** as
        at December 31, 2005 and 2004 and the consolidated statements of operations
        and
        accumulated earnings and cash flows for each of the years ended December
        31,
        2005 and 2004. These consolidated financial statements are the responsibility
        of
        the management of Provident. Our responsibility is to express an opinion
        on
        these financial statements based on our audits.
  We
        conducted our audits in accordance with Canadian generally accepted auditing
        standards. Those standards require that we plan and perform an audit to obtain
        reasonable assurance whether the financial statements are free of material
        misstatement. An audit includes examining, on a test basis, evidence supporting
        the amounts and disclosures in the financial statements. An audit also includes
        assessing the accounting principles used and significant estimates made by
        management, as well as evaluating the overall financial statement presentation.
  In
        our opinion, these consolidated financial statements present fairly, in all
        material respects, the financial position of the Trust as at December 31,
        2005
        and 2004 and the results of its operations and its cash flows for the years
        ended December 31, 2005 and 2004 in accordance with Canadian generally accepted
        accounting principles.





Chartered
        Accountants
 Calgary,
        Alberta
 March
        3, 2006
  **Comments
        by Auditor for U.S. readers on Canada - U.S. reporting
        differences**
 In
        the United States, reporting standards for auditors require the addition
        of an
        explanatory paragraph
        (following the opinion paragraph) when there is change in accounting principles
        that has a material effect on the comparability of the Trust’s financial
        statements, such as the changes described in Note 3 and Note 21(i) to the
        Consolidated Financial Statements. Our report to the Unitholders
        dated March 3, 2005 is expressed in accordance with Canadian reporting standards
        which do not require a reference to such a change in accounting principles
        in
        the Auditors’ Report when the change is properly accounted for and adequately
        disclosed in the financial statements.


Chartered
          Accountants
 Calgary,
          Alberta
 March
          3, 2006
  PricewaterhouseCoopers
          refers to the Canadian firm of PricewaterhouseCoopers LLP and the other
          member
          firms of PricewaterhouseCoopers International Limited, each of which is
          a
          separate and independent legal entity.
  TABLE
              OF CONTENTS


**PROVIDENT
                  ENERGY TRUST****CONSOLIDATED
                  BALANCE SHEETS**Canadian
                  dollars (000s)**As
                  at**
              
              
              As
                  at**December
                  31,**
              
              
              December
                  31,**2005**
              
              
              2004(restated note 3)**Assets**Current
                  assetsCash
                  and cash equivalents
              **$**
              **32,113**
              
              $
              244Accounts
                  receivable
              
              **267,246**
              
              
              143,142Petroleum
                  product inventory
              
              **110,638**
              
              
              17,151Deferred
                  derivative loss (note 17)
              
              **-**
              
              
              2,144Prepaid
                  expenses
              
              **14,326**
              
              
              10,265**424,323**
              
              
              172,946Cash
                  reserve for future site reclamation (note 18)
              
              **1,872**
              
              
              1,454Investments
                  (note 16)
              
              **3,758**
              
              
              3,000Deferred
                  financing charges
              
              **14,710**
              
              
              5,584Property,
                  plant and equipment (note 6)
              
              **1,702,689**
              
              
              1,299,654Intangible
                  assets (note 7)
              
              **215,850**
              
              
              -Goodwill
                  (note 4)
              
              **429,068**
              
              
              330,944**$**
              **2,792,270**
              
              $
              1,813,582**Liabilities**Current
                  liabilitiesAccounts
                  payable and accrued liabilities
              **$**
              **314,723**
              
              $
              171,412Cash
                  distributions payable
              
              **20,644**
              
              
              15,416Distributions
                  payable to non-controlling interests
              
              **452**
              
              
              271Financial
                  derivative instruments
              
              **14,149**
              
              
              24,524**349,968**
              
              
              211,623Long-term
                  debt - revolving term credit facilities (note 8)
              
              **586,597**
              
              
              262,750Long-term
                  debt - convertible debentures (note 8)
              
              **298,007**
              
              
              169,456Asset
                  retirement obligation (note 10)
              
              **41,133**
              
              
              40,506Future
                  income taxes (note 15)
              
              **91,595**
              
              
              70,629Non-controlling
                  interestsUSOGP
                  operations
              
              **11,885**
              
              
              13,649Exchangeable
                  shares (note 11)
              
              **8,259**
              
              
              35,921**Unitholders’
                  equity**Unitholders’
                  contributions (note 12)
              
              **1,971,707**
              
              
              1,438,393Convertible
                  debentures equity component
              
              **19,301**
              
              
              9,785Contributed
                  surplus (note 13)
              
              **1,675**
              
              
              2,002Cumulative
                  translation adjustment
              
              **(41,785)**
              
              
              (28,848)Accumulated
                  income
              
              **97,288**
              
              
              362Accumulated
                  cash distributions (note 14)
              
              **(643,360)**
              
              
              (412,646)**1,404,826**
              
              
              1,009,048**$**
              **2,792,270**
              
              $
              1,813,582


/s/
              
              
              /s/Name:
Tom
                Buchanan, CATitle: Director
              
              
              Name:M.H.
                (Mike) Shaikh, CATitle: Director


1
 TABLE
          OF CONTENTS




**PROVIDENT
                    ENERGY TRUST****CONSOLIDATED
                    STATEMENT OF OPERATIONS AND ACCUMULATED INCOME**Canadian
                    dollars (000s except per unit amounts)**Year
                    ended**
                  **December
                    31,****2005**
                
                
                2004(restated
                    note 3)**Revenue**(note
                    9)Revenue
                $
                **1,419,450**
                
                $
                1,200,854Realized
                    loss on financial derivative instruments
                
                **(66,860)**
                
                
                (68,944)Unrealized
                    gain/(loss) on financial derivative instruments
                
                **7,684**
                
                
                (22,053)**1,360,274**
                
                
                1,109,857**Expenses**Cost
                    of goods sold
                
                **786,564**
                
                
                741,641Production,
                    operating and maintenance
                
                **171,193**
                
                
                141,493Transportation
                
                **6,932**
                
                
                5,087Depletion,
                    depreciation and accretion
                
                **193,236**
                
                
                177,282General
                    and administrative
                
                **41,608**
                
                
                27,104Non-cash
                    unit based compensation (note 13)
                
                **9,753**
                
                
                1,819Interest
                    on bank debt
                
                **10,875**
                
                
                11,816Interest
                    and accretion on convertible debentures
                
                **19,643**
                
                
                15,173Amortization
                    of deferred financing charges
                
                **1,409**
                
                
                1,435Foreign
                    exchange gain and other
                
                **(3,293)**
                
                
                (2,224)Loss
                    on redemption of convertible debentures (note 8)
                
                **49**
                
                
                -Gain
                    on sale of assets (note 5)
                
                **(5,188)**
                
                
                -**1,232,781**
                
                
                1,120,626Income
                    (loss) before taxes and non-controlling interests
                
                **127,493**
                
                
                (10,769)Capital
                    taxes
                
                **4,780**
                
                
                5,921Current
                    and withholding taxes
                
                **5,628**
                
                
                1,282Future
                    income tax expense (recovery) (note 15)
                
                **17,793**
                
                
                (40,577)**28,201**
                
                
                (33,374)**Net
                    income before non-controlling interests**
                
                **99,292**
                
                
                22,605Non-controlling
                    interestsUSOGP
                    operations
                
                **1,596**
                
                
                923Exchangeable
                    shares (note 11)
                
                **770**
                
                
                457**Net
                    income**
                
                **96,926**
                
                
                21,225Accumulated
                    income (loss), beginning of year
                $
                **1,844**
                
                $
                (19,838)Retroactive
                    application of changes in
                  accounting
                    policies (note 3)
                
                **(1,482)**
                
                
                (1,025)Accumulated
                    income (loss), beginning of year, restated
                
                **362**
                
                
                (20,863)Accumulated
                    income, end of year
                $
                **97,288**
                
                $
                362Net
                    income per unit - basic
                $
                **0.61**
                
                $
                0.19Net
                    income per unit - diluted
                $
                **0.61**
                
                $
                0.19


2
 TABLE
          OF CONTENTS


**PROVIDENT
                  ENERGY TRUST****CONSOLIDATED
                  STATEMENT OF CASH FLOWS**Canadian
                  Dollars (000s)**Year
                  ended**
                **December
                  31,****2005**
              
              
              2004(restated
                  note 3)**Cash
                  provided by operating activities**Net
                  income for the year
              $
              **96,926**
              
              $
              21,225Add
                  (deduct) non-cash items:Depletion,
                  depreciation and accretion
              
              **193,236**
              
              
              177,282Debenture
                  accretion and amortization of deferred charges
              
              **4,090**
              
              
              2,808Non-cash
                  unit based compensation (note 13)
              
              **9,753**
              
              
              1,819Unrealized
                  (gain) loss on financial derivative instruments (note 9)
              
              **(7,684)**
              
              
              22,053Unrealized
                  foreign exchange gain
              
              **(405)**
              
              
              (744)Future
                  income tax expense (recovery) (note 15)
              
              **17,793**
              
              
              (40,577)Equity
                  in loss of investee
              
              **252**
              
              
              -Net
                  income attributable to non-controlling interests
              
              **2,366**
              
              
              1,380Loss
                  on redemption of convertible debentures (note 8)
              
              **49**
              
              
              -Gain
                  on sale of assets (note 5)
              
              **(5,188)**
              
              
              -Cash
                  flow from operations before changes in working capital
                and
                  site restoration expenditures
              
              **311,188**
              
              
              185,246Site
                  restoration expenditures (note 18)
              
              **(2,481)**
              
              
              (3,219)Change
                  in non-cash operating working capital
              
              **(51,344)**
              
              
              5,796**257,363**
              
              
              187,823**Cash
                  used for financing activities**Increase
                  (decrease) in long-term debt
              
              **325,771**
              
              
              (77,087)Proceeds
                  of bridge financing
              
              **-**
              
              
              158,184Repayment
                  of bridge financing
              
              **-**
              
              
              (158,184)Declared
                  distributions to unitholders
              
              **(230,714)**
              
              
              (164,628)Declared
                  distributions to non-controlling interest
              
              **(3,360)**
              
              
              (964)Issue
                  of trust units, net of issue costs
              
              **395,805**
              
              
              320,976Issue
                  of debentures, net of costs
              
              **239,822**
              
              
              48,000Redemption
                  of debentures, net of costs
              
              **(2,997)**
              
              
              -Change
                  in non-cash financing working capital
              
              **(50)**
              
              
              8,213**724,277**
              
              
              134,510**Cash
                  used for investing activities**Net
                  capital expenditures
              
              **(156,499)**
              
              
              (76,321)Acquisition
                  of Midstream NGL business (note 4)
              
              **(772,303)**
              
              
              -Acquisition
                  of Nautilus (note 4)
              
              **(91,420)**
              
              
              -Acquisition
                  of Breitburn Energy (note 4)
              
              **-**
              
              
              (165,649)Acquisition
                  of Olympia Energy Inc. (note 4)
              
              **-**
              
              
              (4,715)Acquisition
                  of Viracocha Energy Inc. (note 4)
              
              **-**
              
              
              (1,993)Acquisition
                  of Redwater
              
              **-**
              
              
              (1,300)Acquisition
                  of investment
              
              **(1,010)**
              
              
              -Oil
                  and gas property acquisitions
              
              **(586)**
              
              
              (72,745)Proceeds
                  from property dispositions
              
              **45,100**
              
              
              10,717Proceeds
                  on sale of assets (note 5)
              
              **29,295**
              
              
              -Reclamation
                  fund contributions
              
              **(2,899)**
              
              
              (2,844)Reclamation
                  fund withdrawals
              
              **2,481**
              
              
              3,219Payment
                  of financial derivative instruments
              
              **(7,192)**
              
              
              (23,302)Change
                  in non-cash investing working capital
              
              **5,262**
              
              
              12,799**(949,771)**
              
              
              (322,134)**Increase
                  in cash**
              
              **31,869**
              
              
              199**Cash
                  and cash equivalents beginning of year**
              
              **244**
              
              
              45**Cash
                  and cash equivalents end of year**
              $
              **32,113**
              
              $
              244Supplemental
                  disclosure of cash flow informationCash
                  interest paid including debenture interest
              $
              **23,946**
              
              $
              23,619Cash
                  taxes paid
              $
              **12,026**
              
              $
              6,483


3
 TABLE
          OF CONTENTS


**NOTES
      TO THE CONSOLIDATED FINANCIAL STATEMENTS**




**(Tabular
      amounts in Cdn$ 000’s, except unit and per unit amounts)**




**December
      31, 2005**





**1.**
            **Structure
                of the Trust**




Provident
      Energy Trust (the “Trust”) is an open-end unincorporated investment trust
      created under the laws of Alberta pursuant to a trust indenture dated January
      25, 2001, amended from time to time. The beneficiaries of the Trust are the
      unitholders. The Trust was established to hold, directly and indirectly, 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.
      The Trust commenced operations March 6, 2001.




Cash
      flow
      is provided to the Trust from properties owned and operated by Provident Energy
      Ltd. and directly and indirectly owned subsidiaries and partnerships of the
      Trust (“Provident”). Cash flow is paid from Provident to the Trust by way of
      royalty payments, interest payments and principal repayments. The cash payments
      received by the Trust are subsequently distributed to the unitholders
      monthly.








**2.**
            **Significant
                accounting policies**




(i)
            **Principles
                of consolidation and
                investments**




The
      consolidated financial statements include the accounts of the Trust and
      Provident, including the subsidiary Breitburn Energy Company LP (Breitburn),
      and
      are presented in accordance with Canadian generally accepted accounting
      principles. Investments are accounted for using the cost method. Certain
      comparative numbers have been restated to conform with the current year
      presentation.





(ii)
            **Financial
                derivative instruments**




All
      derivative financial instruments are recorded on the balance sheet at fair
      value
      and changes in fair value are recognized in income as unrealized gains or losses
      on financial derivative instruments in the period in which the change occurs.
      Actual gains or losses are recorded as realized gains or losses on financial
      derivative instruments in the period that the instrument is
      settled.




(iii)
            **Property,
                plant & equipment**




The
      Trust
      follows the full cost method of accounting for oil and natural gas exploration
      and development activities, whereby all costs associated with the acquisition
      and development of oil and natural gas reserves are capitalized. Such costs
      include lease acquisition, lease rentals on non-producing properties, geological
      and geophysical activities, drilling of productive and non-productive wells,
      and
      tangible well equipment. Gains or losses on the disposition of oil and gas
      properties are not recognized unless the resulting change to the depletion
      and
      depreciation rate is 20 percent or more. All other property, plant and
      equipment, including midstream assets, are recorded at cost. Expenditures
      relating to renewals or betterments that improve the productive capacity or
      extend the life of property, plant and equipment are capitalized. Maintenance
      and repairs are expensed as incurred. Products required to fill in cavern
      bottoms and pipelines are presented as part of property, plant and equipment
      and
      stated at historical cost and are not depreciated.




a)****
            **Depletion,
                depreciation and accretion**




The
      provision for depletion and depreciation for oil and natural gas assets is
      calculated using the unit-of-production method based on current production
      divided by the Trust’s share of estimated total proved oil and natural gas
      reserve volumes, before royalties. Production and reserves of natural gas and
      associated liquids are converted at the energy equivalent ratio of 6,000 cubic
      feet of natural gas to one barrel of oil. In determining its depletion base,
      the
      Trust includes estimated future costs for developing proved reserves, and
      excludes estimated salvage values of tangible equipment and the cost of unproved
      properties.


4
 TABLE
          OF CONTENTS


Midstream
      facilities, including natural gas liquids storage facilities and natural gas
      liquids processing and extraction facilities are carried at cost and depreciated
      on a straight-line basis over the estimated service lives of the assets, which
      range from 30 to 40 years. Intangible assets are amortized over the estimated
      useful lives of the assets, which range from two to 15 years. Capital assets
      related to pipelines are carried at cost and depreciated using the straight-line
      method over their economic lives.


(b)****
              **Ceiling
                    test**


The
      ceiling test calculation is performed by comparing the carrying value of the
      cost centre to the sum of the undiscounted proved reserve cash flows expected
      from the cost centre by country using future price estimates. If the carrying
      value is not recoverable, the cost centre is written down to its fair value.
      Fair value is determined by the future cash flows from the proved plus probable
      reserves discounted at the Trust’s risk free interest rate. Any excess carrying
      value of the assets on the balance sheet above fair value would be recorded
      in
      depletion, depreciation and accretion expense as a permanent
      impairment.




(iv)****
            **Joint
                Venture**




Provident
      conducts many of its activities through joint ventures and the accounts reflect
      only Provident’s proportionate interest in such activities.




(v)
            **Inventory**




Inventories
      of products are valued at the lower of average cost and net realizable value
      based on market prices.




(vi)****
            **Goodwill**




Goodwill,
      which represents the excess of cost of an acquired enterprise over the net
      of
      the amounts assigned to assets acquired and liabilities assumed, is assessed
      at
      least annually for impairment. To assess impairment, the fair value of the
      reporting unit is determined and compared to the book value of the reporting
      unit. If the fair value is less than the book value, then a second test is
      performed to determine the amount of the impairment. The amount of the
      impairment is determined by deducting the fair value of the reporting unit’s
      assets and liabilities from the fair value of the reporting unit to determine
      the implied fair value of goodwill and comparing that amount to the book value
      of the reporting unit’s goodwill. Any excess of the book value of goodwill over
      the implied fair value of goodwill is the impaired amount. Goodwill is not
      amortized.


(vii)****
              **Asset
                    retirement
                    obligation**


Under
      the
      asset retirement obligation (“ARO”) standard the fair value of a liability for
      an ARO is recorded in the period where a reasonable estimate of the fair value
      can be determined. When the liability is recorded, the carrying amount of the
      related asset is increased by the same amount of the liability. The asset
      recorded is depleted over the useful life of the asset. Additions to asset
      retirement obligations due to the passage of time are recorded as accretion
      expense. Actual expenditures incurred are charged against the
      obligation.




(viii)****
            **Unit
                based compensation**




The
      Trust
      uses the fair value method of valuing compensation expense associated with
      the
      Trust’s unit option plan (“the Plan”). Provident has applied this method to
      options issued after January 1, 2003, the effective date for implementing stock
      based compensation. Under fair value method the amount to be recognized as
      expense is determined at the time the options are issued and is deferred and
      recognized in earnings over the vesting period of the options with a
      corresponding increase in contributed surplus.




The
      Trust
      has established other unit based compensation plans whereby notional units
      are
      granted to employees. The fair value of these notional units is estimated and
      recorded as an expense to non-cash unit based compensation with an offsetting
      amount to accrued liabilities. A realization of the expense and a resulting
      reduction in cash provided by operating activities occurs when a cash payment
      is
      made.




5
 TABLE
          OF CONTENTS




(ix)****
              **Trust
                  unit calculations**


The
      Trust
      applies the treasury stock method to determine the dilutive effect of trust
      unit
      rights and trust unit options. Under the treasury stock method, outstanding
      and
      exercisable instruments that will have a dilutive effect are included in per
      unit - diluted calculations, ordered from most dilutive to least
      dilutive.





The
      dilutive effect of exchangeable shares and convertible debentures is determined
      using the "if-converted" method whereby the outstanding exchangeables and
      debentures at the end of the period are assumed to have been exchanged or
      converted at the beginnning of the period or at the time of issuance if issued
      during the year. Amounts charged to income or loss relating to the outstanding
      exchangeable shares and debentures are added back to net income for the diluted
      calculation. The units issued upon exchange or conversion are included in the
      denominator of per unit - basic calculations from the date of
      issue.




(x)
            **Future
                income taxes**




Provident
      follows the liability method for calculating income taxes. Differences between
      the amounts reported in the financial statements of the corporate subsidiaries
      and their respective tax bases are applied to tax rates in effect to calculate
      the future tax liability. The effect of any change in income tax rates is
      recognized in the current period income.





The
      Trust
      is a taxable entity under the Income Tax Act (Canada) and is taxable only on
      income that is not distributed or distributable to the unitholders. As the
      Trust
      distributes all of its taxable income to the unitholders and meets the
      requirements of the Income Tax Act (Canada) applicable to the Trust, no
      provision for income taxes has been made in the Trust.




(xi)****
            **Revenue
                recognition**




Revenue
      associated with the sales of Provident’s natural gas, natural gas liquids
      (“NGL’s) and crude oil owned by Provident is recognized when title passes from
      Provident to its customer.





Marketing
      revenues and purchased product are recorded on a gross basis as Provident takes
      title to product and has the risks and rewards of ownership.





Revenues
      associated with the services provided where Provident acts as agent are recorded
      when the services are provided. Revenues associated with the sale of natural
      gas
      liquids storage services are recognized when the services are
      provided.




(xii)
            **Use
                of estimates**




The
      preparation of financial statements requires management to make estimates based
      on currently available information. In particular, management makes estimates
      for amounts recorded for depletion and depreciation of the property, plant
      and
      equipment, and asset retirement obligation. The ceiling test uses factors such
      as estimated reserves, production rates, estimated future petroleum and natural
      gas prices and future costs. Due to the inherent limitations in metering and
      the
      physical properties of storage caverns and pipelines, the determination of
      precise volumes of natural gas liquids held in inventory at such locations
      is
      subject to estimation. Actual inventories of natural gas liquids can only be
      determined by draining of the caverns. By their very nature, these estimates
      are
      subject to measurement uncertainty and the effect on the financial statements
      of
      future periods could be material.





The
      estimation of oil and gas reserves is a subjective process. Forecasts are based
      on engineering data, projected future rates of production, estimated commodity
      prices, and consider the timing of future expenditures. The Trust expects
      reserve estimates to be revised based on the results of future drilling
      activity, testing, production levels, and economics of recovery based on cash
      flow forecasts.




6
 TABLE
          OF CONTENTS


**3.**
            **Changes
                in accounting policies and
                practices**




**Exchangeable
      securities - non-controlling interest**




Effective
      June 30, 2005, the Canadian Institute of Chartered Accountants issued an
      amendment to EIC abstract 151 "Exchangeable Securities Issued by Subsidiaries
      of
      Income Trusts" that states that exchangeable securities issued by a subsidiary
      of an income trust should be reflected as either non-controlling interest or
      debt on the consolidated balance sheet unless they meet certain criteria. The
      exchangeable shares issued by Provident Acquisitions Inc. and Provident Energy
      Ltd. corporate subsidiaries of the Trust are considered under this standard
      to
      be transferable to third parties. EIC-151 states that if the exchangeable shares
      are transferable to a third party, they should be reflected as non-controlling
      interest. Previously, the exchangeable shares were reflected as a component
      of
      unitholders' equity.





As
      a
      result of this change in accounting policy, the Trust has reflected
      non-controlling interest of $8.3 million and $35.9 million, respectively, on
      the
      Trust's consolidated balance sheet as at December 31, 2005 and December 31,
      2004. Consolidated net income or loss has been adjusted for the earnings
      attributable to the non-controlling interest of $0.8 million for the year ended
      December 31, 2005 and $0.5 million for the year ended December 31, 2004. As
      at
      June 30, 2005 unitholders' equity was reduced by $11.2 million and
      non-controlling interest on the consolidated balance sheet increased by $13.0
      million. In accordance with the transitional provisions of EIC-151, retroactive
      application has been applied with restatement of prior periods. The retroactive
      application of this abstract as at December 31, 2004 was an accumulated loss
      of
      $1.5 million. The retroactive accumulated loss adjustments represent the
      cumulative net income attributable to the non controlling interest for prior
      periods. Cash flow was not affected by this change.








**4.**
            **Acquisitions**




(i)
            **Acquisition
                of Midstream NGL Assets**




On
      December 13, 2005 Provident acquired midstream business assets (the Midstream
      NGL Acquisition) from EnCana Corporation by way of the purchase of partnership
      interests, corporations and assets. The business comprises NGL extraction
      plants, pipelines, storage and fractionation facilities, distribution
      facilities, contracts including supply and transportation arrangements, and
      ownership of Kinetic Resources, two partnerships which perform NGL marketing
      services including Kinetic’s interests in a distribution terminal and leases on
      approximately 700 rail cars. The transaction was accounted for using the
      purchase method with the allocation of the purchase as follows:


Net
                    assets acquired and liabilities assumedProperty,
                    plant and equipment
                
                $
                428,066Working
                    capital, net of cash acquired
                
                
                38,937Intangible
                    asset - contracts and customer relationships
                
                183,100Intangible
                    asset - fractionation spread support agreement
                
                17,600Intangible
                    assets - other
                
                
                16,308Goodwill
                
                
                
                98,124Financial
                    derivative instruments
                
                
                945Asset
                    retirement obligation
                
                
                (7,604)Future
                    income taxes
                
                
                (3,173)$
                772,303ConsiderationAcquisition
                    costs
                
                $
                12,620Cash,
                    net of cash acquired
                
                
                759,683$
                772,303
 The
        Midstream NGL Acquisition was financed by the issuance of 21,830,000 units
        at
        $12.60 per unit and $150 million of 6.5 percent convertible unsecured
        subordinated debentures. The remaining portion of the purchase price of the
        Midstream NGL Acquisition was funded through Provident’s credit
        facility.


7
 TABLE
          OF CONTENTS





(ii)
            **Acquisition
                of  Nautilus**




On
      March
      2, 2005 Provident acquired Nautilus Resources, LLC (“Nautilus”) for cash
      consideration of $90.2 million and acquisition costs of $1.2 million. Nautilus
      was a private oil and gas exploration and production company active in Wyoming,
      USA. The transaction has been accounted for using the purchase method with
      the
      allocation of the purchase price as follows:


Net
                  assets acquired and liabilities assumedProperty,
                  plant and equipment
              
              $
              99,877Working
                  capital
              
              
              
              1,237Asset
                  retirement obligation
              
              
              (1,557)Financial
                  derivative instrument
              
              
              (8,137)$
              91,420ConsiderationAcquisition
                  costs
              
              
              $
              1,237Cash
              
              
              
              
              90,183$
              91,420




The
      result of this acquisition was the non-controlling interest on USOGP operations
      decreased by 1.4 percent from 5.8 to 4.4 percent.





(iii)
            **Acquisition
                of Olympia**




On
      June
      1, 2004 Provident acquired Olympia Energy Inc. for consideration of 13,385,579
      Trust units with an ascribed value of $152.9 million and 1,325,000 exchangeable
      shares with an ascribed value of $15.1 million plus acquisition costs which
      when
      netted with option proceeds total $4.7 million. Olympia was a public oil and
      gas
      exploration and production company active in the Western Canadian sedimentary
      basin. The transaction has been accounted for using the purchase method with
      the
      allocation of the purchase price as follows:


Net
                  assets acquired and liabilities assumedProperty,
                  plant and equipment
              
              $
              162,352Goodwill
              
              
              
              
              106,499Working
                  capital deficiency
              
              
              (326)Bank
                  debt
              
              
              
              
              (53,852)Asset
                  retirement obligation
              
              
              (1,909)Non-hedging
                  derivative instrument
              
              
              (947)Future
                  income taxes
              
              
              
              (39,107)$
              172,710ConsiderationAcquisition
                  costs
              
              
              $
              8,700Option
                  proceeds
              
              
              
              (3,985)Exchangeable
                  shares issued (note 11)
              
              
              15,132Trust
                  units issued (note 12)
              
              
              152,863$
              172,710




(iv)
            **Acquisition
                of Viracocha**




On
      June
      1, 2004 Provident acquired Viracocha Energy Inc. for consideration of 12,758,386
      Trust units with an ascribed value of $145.7 million and 1,325,000 exchangeable
      shares with an ascribed value of $15.1 million and acquisition costs **** which
      when netted with option proceeds total $2.0 million. Viracocha was a public
      oil
      and gas exploration and production company active in the Western Canadian
      sedimentary basin. The transaction has been accounted for using the purchase
      method with the allocation of the purchase price as follows:


8
 TABLE
          OF CONTENTS




Net
                    assets acquired and liabilities assumedProperty,
                    plant and equipment
                
                $
                109,907Goodwill
                
                
                
                122,002Working
                    capital
                
                
                2,172Bank
                    debt
                
                
                
                (49,891)Capital
                    lease obligation
                
                
                (77)Deferred
                    lease obligation
                
                
                (98)Asset
                    retirement obligation
                
                
                (7,895)Future
                    income taxes
                
                
                (13,294)$
                162,826ConsiderationAcquisition
                    costs
                
                $
                9,000Option
                    and warrant proceeds
                
                
                (7,007)Exchangeable
                    shares issued (note 11)
                
                
                15,132Trust
                    units issued (note 12)
                
                
                145,701$
                162,826


(v)
            **Acquisition
                of Breitburn**




On
      June
      15, 2004 Provident acquired 92 percent of Breitburn Energy LLC (Breitburn)
      for
      consideration of $157.4 million and acquisition costs of $8.2 million. Breitburn
      is a private company (now a limited partnership) active in the oil and gas
      exploitation and production business in the Los Angeles basin, USA. The
      transaction has been accounted for using the purchase method with the allocation
      of the purchase price as follows :


Net
                  assets acquired and liabilities assumedProperty,
                  plant and equipment
              
              $
              214,261Working
                  capital deficiency
              
              
              (8,402)Non-hedging
                  derivative instruments
              
              
              (25,181)Other
                  assets
              
              
              
              1,028Asset
                  retirement obligation
              
              
              (2,367)Non-controlling
                  interest
              
              
              (13,690)$
              165,649ConsiderationAcquisition
                  costs
              
              
              $
              8,214Cash
              
              
              
              
              157,435$
              165,649




On
      October 4, 2004, the Trust funded Breitburn $58.5 million (US $45 million)
      for
      the Orcutt property acquisition.




**5.**
            **Sale
                of assets**




On
      May 1,
      2005, certain oil purchase and sale contracts were sold for net proceeds of
      $5.5
      million and a gain recorded of $5.2 million net of disposal costs.





On
      December 29, 2005, a parcel of land in California was sold for net proceeds
      of
      $23.8 million. The sale represents surface rights for real estate development,
      with no impact on oil and gas reserves. The transaction resulted in a deferred
      gain of $1.0 million. The purchaser has agreed to complete the removal and
      relocation of oilfield infrastructure and environmental remediation work. Not
      included in the net proceeds or deferred gain is contingent proceeds, amounting
      to $2.7 million, which are held in escrow until this work is
      completed.





9
 TABLE
          OF CONTENTS




**6.**
              **Property,
                    plant and equipment**




**December
                  31, 2005**
              
              **Cost**
              
              **Accumulated
                  depletion and depreciation**
              
              **Net
                  Book**
                **value**Oil
                  and natural gas properties
              $
              1,710,998
              $
              731,336
              $
              979,662Midstream
                  assets
              
              738,835
              
              21,951
              
              716,884Office
                  equipment
              
              12,423
              
              6,280
              
              6,143Total
              $
              2,462,256
              $
              759,567
              $
              1,702,689December
                  31, 2004
              
              Cost
              
              Accumulated
                  depletion and depreciation
              
              Net
                  Book
                valueOil
                  and natural gas properties
              $
              1,567,902
              $
              555,280
              $
              1,012,622Midstream
                  assets
              
              293,616
              
              11,815
              
              281,801Office
                  equipment
              
              9,904
              
              4,673
              
              5,231Total
              $
              1,871,422
              $
              571,768
              $
              1,299,654





Costs
      associated with unproved properties excluded from costs subject to depletion
      as
      at December 31, 2005 totaled $23.8 million (December 31, 2004 - $31.2 million).
      Asset retirement costs of $38.6 million are included in the property, plant
      and
      equipment (December 31, 2004 - $36.0 million).





An
      impairment test calculation was performed on property, plant and equipment
      at
      December 31, 2005 in which the estimated undiscounted future net cash flows
      based on estimated future prices associated with the proved reserves exceeded
      the carrying amount of oil and gas property, plant and equipment.





The
      following table outlines prices used in the impairment test at December 31,
      2005:


**Oil**
              
              **Gas**
              
              **NGL****Year**
              
              **$/bbl**
              
              **$/mcf**
              
              **$/bbl**2006
              
              $
              44.50
              
              $
              10.11
              
              $
              48.352007
              
              $
              44.25
              
              $
              8.77
              
              $
              46.862008
              
              $
              45.20
              
              $
              7.86
              
              $
              46.472009
              
              $
              45.17
              
              $
              7.53
              
              $
              44.962010
              
              $
              43.99
              
              $
              7.19
              
              $
              43.31Thereafter(1)
              
              
              2.00
              %
              
              2.00
              %
              
              2.00
              %(1)Percentage change represents the increase in each year after 2010
                  to the
                  end of the reserve life.








**7.**
            **Intangible
                assets**




The
      intangible assets were acquired as part of the Midstream NGL Acquisition (note
      4).


**December
                  31, 2005**
              
              **Cost**
              
              **Accumulated**
                **amortization**
              
              **Net
                  Book**
                **value**Midstream
                  and marketing contracts and customer relationships
              
              $
              183,100
              
              $
              635
              
              $
              182,465Fractionation
                  spread support agreement
              
              
              17,600
              
              
              458
              
              
              17,142Other
                  intangible assets
              
              
              16,308
              
              
              65
              
              
              16,243Total
              
              $
              217,008
              
              $
              1,158
              
              $
              215,850




10
 TABLE
          OF CONTENTS


**8.**
            **Long-term
                debt**


**December
                  31,
                  2005**
              
              December
                  31, 2004Revolving
                  term credit facilities
              **$**
              **586,597**
              
              $
              262,750Convertible
                  debentures
              
              **298,007**
              
              
              169,456**$**
              **884,604**
              
              $
              432,206




**(i)**
              **Revolving
                    term credit
                    facilities**


Provident
      has a $750 million term credit facility with a syndicate of Canadian chartered
      banks secured by its Canadian oil and gas properties and all of its midstream
      assets. Provident may draw on the credit facility by way of Canadian prime
      rate
      loans, U.S. base rate loans, banker’s acceptances, letters of credit or LIBOR
      loans. At December 31, 2004 the facility totaled $410 million. In July 2005
      the
      facility was increased to $450 million. In October, the facility was increased
      to its current level of $750 million. At December 31, 2005, $544.1 million
      was
      drawn on this facility.





Pursuant
      to the terms of the facility agreement, each year on or after May 30, Provident
      can request the revolving period to be extended for a further 364-day period.
      If
      the lenders do not extend the revolving period, at Provident’s option, the
      credit facility is converted to a two year non-revolving term credit facility
      at
      the end of the 364 day term, with 25% of the loan balance due 12 months after
      the date of the commencement of the non-revolving term credit, 25% due 18 months
      after the date of the commencement of the non-revolving term credit, and the
      remainder of the unpaid balance due on the maturity date.





In
      July
      2005, Provident added a credit facility with a borrowing base of US $100 million
      with a syndicate of U.S. banks secured by oil and gas assets of Breitburn.
      Provident may draw upon the facility by way of U.S. base rate loans, libor
      loans
      or letters of credit. The facility has a termination date of July 11, 2009
      and
      the current borrowing base is reviewed every six month period commencing June
      1,
      2006 and each subsequent December 1 and June 1 thereafter. At December 31,
      2005,
      $42.5 million was drawn on this facility.





At
      December 31, 2005 the effective interest rate of the outstanding credit
      facilities was 4.6 percent (2004 - 4.3 percent). At December 31, 2005 Provident
      had $45.1 million in letters of credit outstanding (2004 - $31 million) that
      guarantee Provident’s performance under certain commercial and other contracts.





**(ii)**
            **Convertible
                debentures**




On
      November 15, 2005 the Trust issued $150.0 million of unsecured convertible
      subordinated debentures ($143.8 million net of issue costs) with a 6.5 percent
      coupon rate maturing April 30, 2011. Issue costs have been classified as
      deferred financing charges. The debentures may be converted into trust units
      at
      the option of the holder at a conversion price of $14.75 per trust unit prior
      to
      April 30, 2011 and may be redeemed by the Trust under certain circumstances.
      The
      unsecured subordinated convertible debentures were initially recorded at fair
      value of $141.4 million. The difference between the fair value and proceeds
      of
      $8.6 million was recorded as equity.





On
      May
      31, 2005 the Trust completed the redemption of its 10.5 percent convertible
      unsecured subordinated debentures that were originally scheduled to mature
      May
      15, 2007. A total of 3.5 million units were issued at the conversion price
      of
      $10.70 per unit. A further $3.0 million cash was paid to the remaining debenture
      holders that did not convert to trust units at $1,050 for each $1,000 of
      convertible debenture held plus accrued interest to May 31, 2005 resulting
      in a
      loss on redemption of $49,000. Unamortized deferred debt issue costs of $2.5
      million, originally incurred on the issuance of the 10.5 percent convertible
      debentures, were reclassified to trust unit issue costs as a result of the
      issuance of 3.5 million trust units.





On
      March
      1, 2005 the Trust issued $100.0 million of unsecured convertible subordinated
      debentures ($95.8 million net of issue costs) with a 6.5 percent coupon rate
      maturing August 31, 2012. Issue costs have been classified as deferred financing
      charges. The debentures may be converted into trust units at the option of
      the
      holder at a conversion price of $13.75 per trust unit prior to August 31, 2012
      and may


11
 TABLE
          OF CONTENTS


be
      redeemed by the Trust under certain circumstances. The unsecured subordinated
      convertible debentures were initially recorded at fair value of $92.6 million.
      The difference between the fair value and proceeds of $7.4 million was recorded
      as equity.





On
      July
      6, 2004 the Trust issued $50.0 million of unsecured subordinated convertible
      debentures ($48.0 million net of issue costs) with an 8.0 percent coupon rate
      maturing July 31, 2009. Issue costs have been classified as deferred financing
      charges. The debentures may be converted into trust units at the option of
      the
      holder at a conversion price of $12.00 per trust unit prior to July 31, 2009,
      and may be redeemed by the Trust under certain circumstances.





The
      Trust
      may elect to satisfy interest and principal obligations by the issuance of
      trust
      units. During 2005, $109.3 **** million
      (2004- $0.12 million) of the face value of debentures were converted to trust
      units, $63.6 million at the election of debenture holders and $45.7 million
      associated with the May 31, 2005 redemption.


**December
                  31, 2005**
              
              December
                  31, 2004**Convertible
                  Debentures**($
                  000s except conversion pricing)
              
              Carrying
                  Value(1)
              
              Face
                  Value
              
              Carrying
                  Value(1)
              
              Face
                  Value
              
              Maturity
                  Date
              
              Conversion
                  Price per unit(2)10.5%
                  Convertible Debentures
              $
              **-**
              $
              **-**
              $
              49,423
              $
              49,881
              
              May
                  15, 2007
              
              10.706.5%
                  Convertible Debentures
              
              **141,522**
              
              **150,000**
              
              -
              
              -
              
              April
                  30, 2011
              
              14.756.5%
                  Convertible Debentures
              
              **92,482**
              
              **99,179**
              
              -
              
              -
              
              Aug.
                  31, 2012
              
              13.758.0%
                  Convertible Debentures
              
              **32,382**
              
              **33,648**
              
              48,199
              
              50,000
              
              July
                  31, 2009
              
              12.008.75%
                  Convertible Debentures
              
              **31,621**
              
              **32,659**
              
              71,834
              
              74,930
              
              Dec.
                  31, 2008
              
              11.05$
              **298,007**
              $
              **315,486**
              $
              169,456
              $
              174,811(1)
                  Excluding equity component of convertible debentures(2)
                  The debentures may be converted into trust units at the option
                  of the
                  holder of the debenture at the conversion priceper
                  unit








**9.**
            **Revenue**


**Year
                  ended December 31,**Year
                  ended December 31,
              
              **2005**
              
              2004Gross
                  production revenue
              $
              **621,761**
              $
              449,869Product
                  sales and service revenue
              
              **908,111**
              
              840,184Royalties
              
              **(110,422)**
              
              (89,199)**Revenue**
              $
              **1,419,450**
              $
              1,200,854Realized
                  loss on financial derivative instruments
              
              **(66,860)**
              
              (68,944)Unrealized
                  gain (loss) on financial derivative instruments
              
              **7,684**
              
              (22,053)$
              **1,360,274**
              $
              1,109,857Change
                  in unrealized loss on financial derivative instruments
              $
              **9,828**
              $
              937Amortization
                  of loss on financial derivative instruments
              
              **(2,144)**
              
              (22,990)**Unrealized
                  gain (loss) on financial derivative instruments**
              $
              **7,684**
              $
              (22,053)





The
      realized loss on financial derivative instruments for the year ended December
      31, 2005 of $66.9 million (2004 - $68.9 million) relates to the cash settlement
      on derivative instruments.




12
 TABLE
          OF CONTENTS




**10.**
                **Asset
                        retirement
                        obligation**




The
      Trust’s asset retirement obligation is based on the Trust’s net ownership in
      wells, facilities and the midstream assets and represents management’s estimate
      of the costs to abandon and reclaim those wells, facilities and midstream assets
      as well as an estimate of the future timing of the costs to be incurred.
      Estimated cash flows have been discounted at the Trust’s credit-adjusted risk
      free rate of seven percent and an inflation rate of two percent.





The
      total
      undiscounted amount of future cash flows required to settle asset retirement
      obligations related to oil and gas operations is estimated to be $293.0 million.
      Payments to settle oil and gas asset retirement obligations occur over the
      operating lives of the assets estimated to be from two to 50 years.





The
      total
      undiscounted amount of future cash flows required to settle the midstream
      services and marketing asset retirement obligations is estimated to be $179.3
      million. The estimated costs include such activities as dismantling, demolition
      and disposal of the facilities as well as remediation and restoration of the
      surface land. Payments to settle the midstream services and marketing asset
      retirement obligations are expected to occur subsequent to the closure of the
      facilities and related assets. Settlement of these obligations is expected
      to
      occur in 30 to 45 years.




**Year
                  ended December 31,**($000s)
              
              **2005**
              
              2004Carrying
                  amount, beginning of year
              **$**
              **40,506**
              $
              33,182Business
                  acquisitions
              
              **9,161**
              
              12,171Change
                  in estimate
              
              **2,884**
              
              (2,429)Increase
                  in liabilities incurred during the period
              
              **1,784**
              
              166Settlement
                  of liabilities during the period
              
              **(2,614)**
              
              (4,971)Decrease
                  in liabilities due to disposition
              
              **(13,612)**
              
              -Accretion
                  of liability
              
              **3,024**
              
              2,387**Carrying
                  amount, end of year**
              **$**
              **41,133**
              $
              40,506


**11.**
                  **Exchangeable
                            shares - non-controlling
                            interest**


The
      Trust
      retroactively applied EIC-151 “Exchangeable Securities Issued by a Subsidiary of
      an Income Trust” as at June 30, 2005. The non-controlling interest on the
      consolidated balance sheet consists of the fair value of the exchangeable shares
      upon issuance plus the accumulated earnings attributable to the non-controlling
      interest. The net income attributable to the non-controlling interest on the
      consolidated statement of operations represents the cumulative share of net
      income attributable to the non-controlling interest based on the trust units
      issuable for exchangeable shares in proportion to total trust units issued
      and
      issuable at each quarter end during the year.





On
      June
      1, 2004 2.65 million exchangeable shares of Provident Energy Ltd. were issued
      pursuant to the acquisition transactions for Olympia Energy Inc. and Viracocha
      Energy Inc. The Exchangeable Shares will be automatically exchanged for Trust
      Units on January 15, 2006, subject to extension at the option of the issuer.
      The
      exchange ratio for these shares is calculated with reference to the
      distributions.





Following
      is a summary of the non-controlling interest - exchangeable shares for years
      ended December 31, 2005 and 2004:




Year
                  ended December 31**,**
              
              **2005**
              
              2004Non-controlling
                  interest, beginning of year
              $
              **35,921**
              **$**
              20,543Exchangeable
                  shares issued
              
              **-**
              
              30,264Reduction
                  of book value for conversion to trust units
              
              **(28,432)**
              
              (15,343)Net
                  income attributable to non-controlling interest
              
              **770**
              
              457Non-controlling
                  interest, end of year
              $
              **8,259**
              **$**
              35,921Accumulated
                  income attributable to non-controlling interest
              $
              **2,252**
              **$**
              1,482


13
 TABLE
          OF CONTENTS





The
      following table details the number of exchangeable shares converted and
      outstanding in addition to the associated book value: ****




**Year
                  ended December 31,****2005**
              
              2004**Exchangeable
                  shares****Provident
                  Acquisitions Inc.**
              **Number
                  of units**
              
              **Amount
                  (000s)**
              
              Number
                  of units
              
              Amount
                  (000s)Balance
                  at beginning of year
              **336,876**
              **$**
              **3,675**
              
              534,357
              $
              5,829Converted
                  to trust units
              **(336,876)**
              
              **(3,675)**
              
              (197,481)
              
              (2,154)Balance,
                  end of year
              **-**
              
              **-**
              
              336,876
              
              3,675Exchange
                  ratio, end of year
              **-**
              
              **-**
              
              1.42501
              
              -**Trust
                  units issuable upon conversion, end of year**
              **-**
              **$**
              **-**
              
              480,052
              $
              3,675**Exchangeable
                  shares****Provident
                  Energy Ltd.***Balance
                  at beginning of year
              **638,474**
              **$**
              **6,833**
              
              1,279,227
              $
              13,689Converted
                  to trust units
              **(174,929)**
              
              **(1,872)**
              
              (640,753)
              
              (6,856)Balance,
                  end of year
              **463,545**
              
              **4,961**
              
              638,474
              
              6,833Exchange
                  ratio, end of year
              **1.50962**
              
              **-**
              
              1.35099
              
              -**Trust
                  units issuable upon conversion, end of year**
              **699,777**
              **$**
              **4,961**
              
              862,572
              $
              6,833**Exchangeable
                  shares (Series B)**
                **Provident
                  Energy Ltd.****Balance
                  at beginning of year
              **2,095,271**
              **$**
              **23,931**
              
              -
              $
              -Issued
                  to acquire Olympia Energy Inc.
              **-**
              
              **-**
              
              1,325,000
              
              15,132Issued
                  to acquire Viracocha Energy Inc.
              **-**
              
              **-**
              
              1,325,000
              
              15,132Converted
                  to trust units
              **(2,003,951)**
              
              **(22,885)**
              
              (554,729)
              
              (6,333)Balance,
                  end of year
              **91,320**
              
              **1,046**
              
              2,095,271
              
              23,931Exchange
                  ratio, end of year
              **1.19311**
              
              **-**
              
              1.06742
              
              -**Trust
                  units issuable upon conversion, end of year**
              **108,955**
              **$**
              **1,046**
              
              2,236,534
              $
              23,931**Total
                  Trust units issuable upon conversion****of
                  all exchangeable shares, end of year**
              **808,732**
              **$**
              **6,007**
              
              3,579,158
              $
              34,439*
                  Maturity date is June 30, 2006**Maturity
                  date is January 15, 2006.


**12.**
                    **Unitholders’
                                contributions**


The
      Trust
      has authorized capital of an unlimited number of common voting trust
      units.





Trust
      units are redeemable at any time on demand by the holders thereof. Upon receipt
      of a redemption request by the Trust, the holder is entitled to receive a price
      per trust unit (the “Market Redemption Price”) equal to the lesser of: (i) 90%
      of the simple average of the closing 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 (ii) 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.





The
      aggregate Market Redemption Price payable by the 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. Total cash
      payments for redemption are limited to an annual maximum of $250,000. Any excess
      over the maximum may be satisfied by distributing notes having an aggregate
      principal amount equal to the aggregate Market Redemption Price of the trust
      units tendered for redemption.




14
 TABLE
          OF CONTENTS


(i)
            **2005 activity**




On
      March
      1, 2005 the Trust issued 8.4 million units at $12.00 per unit for proceeds
      of
      $100.8 million ($95.6 million net of issue costs) pursuant to a February 18,
      2005 public offering.





On
      November 15, 2005 the Trust issued 21.83 million Subscription Receipts at a
      price of $12.60 per Subscription Receipt for total proceeds of $275.1 million
      ($261.0 million net of issue costs). Each Subscription Receipt entitled the
      holder to receive one trust unit upon completion of the Midstream NGL
      Acquisition. The acquisition closed on December 13, 2005 at which time all
      of
      the outstanding Subscription Receipts were converted to trust units. At that
      time, the holders of the Subscription Receipts were also entitled to $0.12
      per
      trust unit, which is the equivalent of the November distribution paid in
      December. This payment was treated as a reduction to the proceeds received
      for
      the units issued through the Subscription Receipts to $12.48 per trust unit,
      reducing the amount attributed to Unitholders’ contributions by $2.6 million.
      Proceeds from the issue were used to fund the Midstream NGL Acquisition.





In
      2005
      the Trust issued 16.3 **** million
      units related to Provident’s DRIP program, conversion of exchangeable shares to
      units, conversion and redemption of convertible debentures to units and units
      issued pursuant to Provident’s Unit Option Plan. The net increase in
      unitholders’ contributions associated with these activities was
      $181.8 **** million.


(ii)
              **2004 activity**


On
      February 4, 2004 the Trust issued 4.5 million units at $11.20 per unit for
      proceeds of $50.4 million ($47.9 million net of issue costs) pursuant to a
      January 22, 2004 public offering. Proceeds from the issue were initially used
      to
      pay down Provident’s bank debt and throughout 2004 were used to finance the 2004
      capital program.





On
      June
      1, 2004 the Trust issued 13.4 million units (at an ascribed value of $152.9)
      and
      a further 12.8 million units (at an ascribed value of $145.7 million) as part
      of
      the consideration to acquire the outstanding shares of Olympia Energy Inc.
      and
      Viracocha Energy Inc. respectively.





On
      July
      6, 2004 the Trust issued 13.1 million units at $10.40 per unit for proceeds
      of
      $136.2 million ($129.4 million net of issue costs) pursuant to a June 17, 2004
      public offering. Proceeds from the issue applied to pay down the bridge
      financing used in the Breitburn Energy LLC acquisition.





On
      October 4, 2004 the Trust issued 11.48 million units at $10.95 per unit, for
      net
      proceeds (after underwriters’ fees) of $119.4 million. Proceeds were used to
      fund the acquisition of the Orcutt property in California ($57.3 million) and
      to
      repay bank debt.





In
      2004
      the Trust issued 4.2 million units related to Provident’s DRIP program,
      conversion of exchangeable shares to units, conversion of convertible debentures
      to units and units issued pursuant to Provident’s Unit Option Plan. The net
      increase in unitholders’ contributions associated with these activities was
      $40.0 million.




**Year
                  ended December 31,****2005**
              
              2004**Trust
                  Units**
              **Number
                  of units**
              
              **Amount
                  (000s)**
              
              Number
                  of units
              
              Amount
                  (000s)Balance
                  at beginning of year
              **142,226,248**
              **$**
              **1,438,393**
              
              82,824,688
              $
              803,299Issued
                  to acquire Olympia Energy Inc. (note 4)
              **-**
              
              **-**
              
              13,385,579
              
              152,863Issued
                  to acquire Viracocha Energy Ltd. (note 4)
              **-**
              
              **-**
              
              12,758,386
              
              145,701Issued
                  for cash
              **30,230,000**
              
              **373,238**
              
              29,080,000
              
              312,346Exchangeable
                  share conversions
              **2,971,217**
              
              **28,432**
              
              1,633,312
              
              15,343Issued
                  pursuant to unit option plan
              **2,265,179**
              
              **23,435**
              
              638,991
              
              4,677Issued
                  pursuant to the distribution reinvestment plan
              **1,330,156**
              
              **16,438**
              
              1,745,418
              
              18,250To
                  be issued pursuant to the distribution reinvestment plan
              **107,000**
              
              **2,005**
              
              148,496
              
              1,616Debenture
                  conversions
              **6,135,418**
              
              **64,808**
              
              11,378
              
              124Redemption
                  of the 10.5% debentures (note 8)
              **3,507,570**
              
              **46,707**
              
              -
              
              -Unit
                  issue costs
              **-**
              
              **(21,749)**
              
              -
              
              (15,826)**Balance
                  at end of year**
              **188,772,788**
              **$**
              **1,971,707**
              
              142,226,248
              $
              1,438,393


15
 TABLE
          OF CONTENTS


The
      basic
      per trust unit amounts for 2005 were calculated based on the weighted average
      number of units outstanding of 159,315,847 which excludes the shares
      exchangeable into trust units (2004 - 113,310,002). The diluted per trust unit
      amounts for 2005 are calculated including an additional 369,566 trust units
      (2004 - 179,428) for the effect of the unit option plan. Provident’s convertible
      debentures and exchangeable shares are not included in the computation of
      diluted earnings per unit as their effect is anti-dilutive.








**13.**
            **Non-cash
                unit based compensation**


**(i)**
              **Unit
                  option plan**




The
      Trust
      option plan (the “Plan”) is administered by the Board of Directors of Provident.
      Under the Plan, all directors, officers and employees of Provident, are eligible
      to participate in the Plan. There are 8,000,000 trust units reserved for the
      Trust option plan. Options are granted at a “strike price” which is not less
      than the closing price of the units on the Toronto Stock Exchange on the last
      trading day preceding the grant. In certain circumstances, based upon the cash
      distributions made on the trust units, the strike price may be reduced at the
      time of exercise of the option at the discretion of the option holder. Options
      vest six months after grant and every year thereafter in equal increments.
      In
      October 2005, a restricted/performance unit program (see (iii)) was approved.
      This program replaces the unit option plan. Unit options in existence will
      continue to be outstanding.




**Year
                  ended December 31,**
              **2005**
              
              2004**Number
                  of**
                **Options**
              
              **Weighted**
                **Average**
                **Exercise
                  Price**
              
              Number
                  of
                Options
              
              Weighted
                Average
                Exercise
                  PriceOutstanding,
                  beginning of year
              **5,200,331**
              
              **$11.01**
              
              4,008,744
              
              $11.06Granted
              **296,200**
              
              **11.73**
              
              1,909,067
              
              10.89Exercised
              **(2,265,179)**
              
              **10.97**
              
              (638,991)
              
              10.96Forfeited
              **(25,727)**
              
              **10.97**
              
              (78,489)
              
              11.25Outstanding,
                  end of year
              **3,205,625**
              
              **11.11**
              
              5,200,331
              
              11.01**Exercisable,
                  end of year**
              **2,206,801**
              
              **$11.12**
              
              2,620,941
              
              $11.05





At
      December 31, 2005, the Trust had 3,205,625 options outstanding with strike
      prices ranging between $8.91 and $12.14 per unit. The weighted average remaining
      contractual life of the options is 2.20 years and the weighted average exercise
      price is $11.11 per unit excluding average potential reductions to the strike
      prices of $1.16 per unit.





At
      December 31, 2004, the Trust had 5,200,331 options outstanding with strike
      prices ranging from $8.40 and $12.39 per unit. The weighted average remaining
      contractual life of the options was 2.71 years and the weighted average exercise
      price was $11.01 per unit excluding average potential reductions to the strike
      prices of $1.08 per unit.





On
      December 31, 2004 the Trust prospectively applied the fair value based method
      of
      accounting for the Plan. Previously, the Trust applied the intrinsic value
      methodology due to the uncertainties of future expected distributions. The
      Trust
      now uses the Black-Scholes option-pricing model to calculate the estimated
      fair
      value of the outstanding options issued on or after January 1, 2003 at their
      issue date. The Trust has reevaluated the assumptions required to calculate
      the
      fair value of options and considers the estimates required to calculate the
      fair
      value reasonably estimated at the time of the issue of the options.





In
      2005
      the Trust recorded non-cash unit based compensation expense of $1.1 million,
      for
      the 5.6 million options granted on or after January 1, 2003 (2004 - $1.0
      million).





As
      at
      December 31, 2005, the following assumptions are the weighted averages of the
      individual assumptions applied at each grant date to arrive at an estimate
      of
      fair value of all granted options on or after January 1, 2003 of
      $3.8  million:


16
 TABLE
          OF CONTENTS


**2005
                  Granted Options**
              
              2004
                  Granted Options
              
              2003
                  Granted OptionsExpected
                  annual dividend
              
              **8.00%**
              
              8.00%
              
              8.00%Expected
                  volatility
              
              **19.88%**
              
              20.18%
              
              19.46%Risk
                  - free interest rate
              
              **3.26%**
              
              3.30%
              
              3.66%Expected
                  life of option (yrs)
              
              **3.31**
              
              3.31
              
              3.31Expected
                  forfeitures
              
              **-**
              
              -
              
              -Fair
                  Value of Granted Options
              
              **$0.2
                  million**
              
              $1.2
                  million
              
              $2.4
                  million





The
      remaining fair value of the rights of $0.4 million, less any future
      cancellations, will be recognized in earnings over the remaining vesting period
      of the rights outstanding. The following table reconciles the movement in the
      contributed surplus balance.




**Year
                  ended December 31,**
              
              **2005**
              
              
              2004Contributed
                  surplus, beginning of the year
              **$**
              **2,002**
              
              **$**
              1,305Compensation
                  expense
              
              **1,055**
              
              
              1,190Benefit
                  on options exercised charged to unitholders’ equity
              
              **(1,382)**
              
              
              (493)**Contributed
                  surplus, end of year**
              **$**
              **1,675**
              
              **$**
              2,002




**(ii)**
                **Restricted/Performance
                      Units**


In
      May
      2005 the board of directors approved a program whereby certain employees of
      the
      Trust’s Canadian subsidiaries will be granted restricted trust units (RTU’s)
      and/or performance trust units (PTU’s), both of which entitle the employee to
      receive cash compensation in relation to the value of a specified number of
      underlying notional trust units. The grants are based on criteria designed
      to
      recognize the long term value of the employee to the organization. This plan
      replaces the unit options plan for 2005 and subsequent years. RTU’s vest evenly
      over a period of three years commencing one year after grant. Payments are
      made
      on the anniversary dates of the RTU to the employees entitled to receive them
      on
      the basis of a cash payment equal to the value of the underlying notional units.
      PTU’s vest three years from the date of grant and can be increased to a maximum
      of double the PTU’s granted or a minimum of nil PTU’s depending on the Trust’s
      performance vis-à-vis other trusts’ performance based on certain
      benchmarks.





As
      of
      December 31, 2005 there were 226,055 RTU’s and 464,291 PTU’s outstanding. The
      fair value estimate associated with the RTU’s and PTU’s is expensed in the
      statement of income over the vesting period. During the year ended December
      31,
      2005, the Trust recorded compensation costs of $2.6 million with respect to
      the
      expected issue of RTU’s and PTU’s (2004 - nil).


**(iii)**
                  **Unit
                          appreciation
                          rights**




During
      2004, the Trust put in place a program whereby certain employees of its U.S.
      subsidiary are granted unit appreciation rights (“UAR’s”) which entitle the
      employee to receive cash compensation in relation to the value of a specified
      number of underlying notional trust units. UAR’s vest evenly over a period of
      three years commencing one year after grant and expire after four
      years.




The
      UAR’s, upon vesting, provide certain employees entitlement to receive a cash
      payment equal to the excess of the market price of the Trust’s Units over the
      exercise price of the right less notionally accrued distributions in excess
      of
      an eight percent return. These prices are denominated in US dollars and are
      based on quoted US distributions and market prices.





The
      following table summarizes the information about UAR’s:


17
 TABLE
          OF CONTENTS


**2005**
              **2004****Number
                  of Units Appreciation Rights**
              
              **Weighted
                  Average Exercise Price (US$)**
              Number
                  of Units Appreciation Rights
              Weighted
                  Average
                Exercise
                  Price (US$)**Year
                  ended December 31,**Outstanding,
                  beginning of year
              
              
              **976,000**
              
              **$**
              **7.98**
              
              -
              $
              -Granted
              
              
              **147,000**
              
              
              **10.01**
              
              976,000
              
              7.98Exercised
              
              
              **(296,641)**
              
              
              **7.91**
              
              -Forfeited
              
              
              **(57,666)**
              
              
              **8.79**
              
              -Outstanding,
                  end of year
              
              
              **768,693**
              
              **$**
              **8.34**
              
              976,000
              $
              7.98Exerciseable,
                  end of year
              
              
              **22,704**
              
              
              **8.92**
              
              -
              
              -Weighted
                  average remaining contract life (years)
              **2.58**
              
              
              
              
              3.48Average
                  potential reductions to exercise price
              **$0.71**
              
              
              
              
              $0.29
  The
          fair
          value associated with the UAR’s is expensed in the statement of income over the
          vesting period. During the year, the Trust recorded compensation costs
          of $2.2
          million related to the outstanding UAR’s (2004 - $0.4 million). Cash payments of
          $1.0 million (2004 - nil) were recorded against general and administrative
          expense resulting in $1.2 million (2004 - $0.4 million) recorded as non-cash
          unit based compensation.


**(iv)**
            **Other
                unit based compensation**





Pursuant
      to employment agreements between Breitburn and certain employees, the employees
      are eligible to receive cash compensation in relation to the value of a
      specified number of underlying notional units. The value of each notional unit
      is determined on the basis of a valuation of Breitburn as at the end of the
      fiscal period. At December 31, 2005 there were 2,200,000 notional units
      outstanding under the key employee plan (2004 - 2,200,000) which vest one third
      three years after grant date, one third four years after grant date and one
      third five years after grant date. All units under this plan were granted in
      2004. There were 4,155,290 notional units outstanding under the phantom unit
      plan (2004 - 3,000,000) of which all notional units vest immediately and are
      payable 90 days from the fiscal year-end. For the period ended December 31,
      2005
      compensation expense of $6.2 million was recorded under the plans (2004 - $0.4
      million). Cash payments of $1.3 million (2004 - nil) were recorded against
      general and administrative expense resulting in $4.9 million (2004 - $0.4
      million) recorded as non-cash unit based compensation.








**14.**
            **Reconciliation
                of cash flow and
                distributions**


**Year
                  ended December 31,****2005**
              
              
              2004Cash
                  provided by operating activities
              **$**
              **257,363**
              
              **$**
              187,823Change
                  in non-cash operating working capital
              
              **51,344**
              
              
              (5,796)Site
                  restoration expenditures
              
              **2,481**
              
              
              3,219Cash
                  flow from operations
              
              **311,188**
              
              
              185,246Cash
                  reserved for financing and
                investing
                  activities
              
              **(80,474)**
              
              
              (20,618)Cash
                  distributions to unitholders
              
              **230,714**
              
              
              164,628Accumulated
                  cash distributions,
                beginning
                  of period
              
              **412,646**
              
              
              248,018**Accumulated
                  cash distributions, paid and declared, end of
                  period**
              $
              **643,360**
              
              $
              412,646**Cash
                  distributions per unit**
              $
              **1.44**
              
              $
              1.44





Cash
      reserved for financing and investing activities is a discretionary amount and
      represents the difference between cash flow from operations less
      distributions.




18
 TABLE
          OF CONTENTS




**15.**
            **Future
                income taxes**




Provident
      follows the liability method for calculating future income taxes. Under this
      method, future income tax assets and liabilities are recognized based on the
      estimated tax effects of temporary differences in the carrying value of assets
      and liabilities, reported in the financial statements of the corporate
      subsidiaries, and their respective tax bases, using income tax rates
      substantively enacted on the consolidated balance sheet date:


**Year
                  ended December 31,****2005**
              
              
              2004Petroleum
                  and natural gas properties, production facilities and
                  other
              $
              **89,607**
              
              $
              70,301Midstream
                  facilities
              
              **1,988**
              
              
              328$
              **91,595**
              
              $
              70,629





The
      future income tax provision differs from the expected amount calculated by
      applying the Canadian combined federal and provincial income tax rate of 37.82
      percent (2004 - 38.87 percent) as follows:


**Year
                  ended December 31,****2005**
              
              2004Expected
                  income tax expense (recovery)
              $
              **48,218**
              $
              (4,186)Increase
                  (decrease) resulting from:Non-deductible
                  Crown charges and other payments
              
              **14,285**
              
              17,087Federal
                  resource allowance
              
              **(11,489)**
              
              (7,535)Alberta
                  Royalty Tax Credit
              
              **(188)**
              
              (194)Income
                  of the Trust and other
              
              **(32,567)**
              
              (41,336)Capital
                  Taxes
              
              **4,780**
              
              5,921Witholding
                  tax and other
              
              **5,628**
              
              1,282Income
                  tax rate changes
              
              **(466)**
              
              (4,413)$
              **28,201**
              $
              (33,374)







**16.**
              **Related
                    party transactions**


On
      December 30, 2004, at the conclusion of a competitive process, Provident sold
      properties to a private company on whose board two of the directors of Provident
      sit and in which they own shares. The properties were sold for consideration
      of
      $3.5 million of which $0.5 million was cash and $3.0 million consisted of
      10,000,000 common shares valued at $0.30 per share. The carrying value of these
      shares is included in investments on the balance sheet. The transaction was
      recorded at fair value.


**17.**
                **Financial
                        instruments and
                        hedging**
 Financial
          instruments of the Trust carried on the consolidated balance sheet consist
          mainly of cash and cash equivalents, accounts receivable, reclamation fund
          investments, current liabilities, other long-term liabilities, asset retirement
          obligations, commodity and foreign currency contracts and long-term debt.
          Except
          as noted below, as at December 31, 2005 and 2004, there were no significant
          differences between the carrying value of these financial instruments and
          their
          estimated fair value.





Substantially
      all of the Trust's accounts receivable are due from customers and joint venture
      partners in the oil and gas and midstream services and marketing industries
      and
      are subject to credit risk. The Trust partially mitigates associated credit
      risk
      by limiting transactions with certain counterparties to limits imposed by the
      Trust based on the Trust’s assessment of the creditworthiness of such
      counterparties. The carrying value of accounts receivable reflects management's
      assessment of the associated credit risks. With respect to counterparties to
      financial instruments, the Trust partially mitigates associated credit risk
      by
      limiting transactions to counterparties with investment grade credit ratings
      and
      obtaining financial guarantees from certain counterparties.


19
 TABLE
          OF CONTENTS


At
      January 1, 2004 the Trust adopted CICA accounting guideline 13 “Hedging
      relationships” resulting in the recognition of an unrealized loss of $25.1
      million in deferred charges on the consolidated balance sheet that has been
      amortized to income over the same period as the corresponding losses associated
      with the hedged items.


Year
                  ended December 31,
              
              
              **2005**
              
              
              2004**Deferred
                  derivative Loss**Non-hedging
                  derivative liability, beginning of year
              
              **$**
              **2,144**
              
              $
              25,134Derivative
                  instruments amortized
              
              
              **(2,144**
              **)**
              
              (22,990
              )**Deferred
                  derivative loss, end of year**
              
              **$**
              **-**
              
              $
              2,144





Provident’s
      commodity price risk management program is intended to minimize the volatility
      of commodity prices and to assist with stabilizing cash flow and distributions.
      Provident seeks to accomplish this through the use of financial instruments
      from
      time to time to reduce its exposure to fluctuations in commodity prices and
      foreign exchange rates.





With
      respect to financial instruments, Provident could be exposed to losses if a
      counterparty fails to perform in accordance with the terms of the contract.
      This
      risk is managed by diversifying the derivative portfolio among counterparties
      meeting certain financial criteria.





**(i)**
            **Commodity
                price**




**a)**
            **Crude
                oil**




For
      2005,
      Provident paid out $59.0 million to settle various oil market based contracts
      on
      an aggregate volume of 2.6 million barrels. For 2004, Provident paid out $55.3
      million to settle various oil market based contracts on an aggregate volume
      of
      2.7 million barrels. The estimated value of contracts in place if settled at
      market prices at December 31, 2005 would have resulted in an opportunity cost
      of
      $7.1 million (2004 -$25.2 million).





**b)**
            **Natural
                Gas**




For
      2005,
      Provident paid $5.6 million to settle various natural gas market based contracts
      on an aggregate of 5.2 million gigajoules (“GJ”). For 2004, Provident paid $10.4
      million to settle various natural gas market based contracts on an aggregate
      of
      10.9 million gigajoules (“GJ”). The estimated value of contracts in place if
      settled at market prices at December 31, 2005 would have resulted in an
      opportunity cost of $6.5 million (2004 - an opportunity gain of $0.3 million).




**c)**
            **Midstream**




For
      2005,
      Provident paid $2.3 million (2004 - $3.2 million) to settle various midstream
      contracts, that were entered into to fix prices on product sales. The estimated
      value of contracts in place if settled at market prices as December 31, 2005
      would have resulted in an opportunity cost of $0.4 million (2004 - opportunity
      gain of $0.2 million).





**(ii)**
            **Foreign
                exchange contracts**




The
      estimated value of contracts in place if settled at foreign exchange rates
      at
      December 31, 2005 would have resulted in an opportunity cost of $0.1 million
      (2004 - opportunity gain of $0.2 million). The foreign exchange gains have
      been
      included in note 20 as component of foreign exchange gain and other and
      allocated to their respective business segments.




20
 TABLE
          OF CONTENTS


The
      contracts in place at December 31, 2005 are summarized in the following
      tables:


**COGP****Year**
              **Product**
              **Volume
                  (Buy)Sell**
              **Terms**
              **Effective
                  Period**2006
              Crude
                  Oil
              750
              Bpd
              Participating
                  Swaps US $51.33 per bbl (63% above floor price)(1)
                  (3)
              January
                  1 - December 31500
              Bpd
              Participating
                  Swaps US $48.00 per bbl (max to 90% above floor price)(3)
              January
                  1 - December 31750
              Bpd
              Puts
                  US $53.33 per bbl(1)
              January
                  1 - Decmeber 31Natural
                  Gas(2)
              10,000
              Gjpd
              Participating
                  Swaps Cdn $8.00 per gj (max to 90% above floor price)(1)
                  (3)
              January
                  1 - March 318,500
              Gjpd
              Participating
                  Swaps Cdn $7.32 per gj (max to 90% above floor price)(1) (3)
              January
                  1 - December 315,000
              Gjpd
              Participating
                  Swaps Cdn $6.75 per gj (max to 87% above floor price)(3)
              April
                  1 - October 315,000
              Gjpd
              Participating
                  Swaps Cdn $7.00 per gj (max to 85% above floor price)(3)
              April
                  1 - December 31Foreign
                  Exchange
              
              
              Sell
                  US $2,000,000 at 1.165(4)
              January
                  25


**USOGP
                  (Breitburn)****Year**
              **Product**
              **Volume
                  (Buy)Sell**
              **Terms**
              **Effective
                  Period**2006
              Crude
                  Oil
              1,000
              Bpd
              Participating
                  Swap US $47.25 per bbl (65% above floor price)(1) (3)
              January
                  1 - December 311,000
              Bpd
              Puts
                  US $53.00 per bbl(1)
              January
                  1 - December 31


**Midstream****Year**
              **Product**
              **Volume
                  (Buy)Sell**
              
              **Terms**
              **Effective
                  Period**2006
              Propane
              19,600
              Gpd
              Purchased
                  Calls US $0.95 per gal(8)
              January
                  1 - April 3013,017
              Gpd
              Sold
                  Put US $0.82 per gal(1)
                  (8)
              January
                  1 - February 284,500
              Gpd
              Sold
                  Put US $0.84 per gal(8)
              February
                  1 -February 281,899
              Gpd
              Sold
                  Put US $0.90 per gal(8)
              January
                  1 - March 3133,871
              Gpd
              Sold
                  Call US $1.07 per gal(8)
              Janury
                  1 - January 3117,733
              Gpd
              Sold
                  Call US $0.95 per gal(8)
              January
                  1 - April 3014,237
              Gpd
              US
                  $0.81 per usg(8)
              January
                  1 - February 28135,263
              Gpd
              US
                  $0.972 per usg(1)
                  (8)
              January
                  1 - March 312,333
              Gpd
              US
                  $0.875 per usg(8)
              January
                  1 - April 30Crude
                  Oil
              375
              Bpd
              US
                  $61.70 per bbl(6)
              January
                  1 - March 31Natural
                  Gas
              (6,350)
              Gjpd
              Cdn
                  $11.08 per gj(2)
              January
                  1 - March 314,000
              Gjpd
              Cdn
                  $13.75 per gj(2)
                  (7)
              January
                  1 - January 31(4,000)
              Gjpd
              Cdn
                  $12.75 per gj(2) (7)
              January
                  1 - January 31400,000
              Mmbtu
              US
                  $14.25 per mmbtu(10)
              February
                  1 - February 28Foreign
                  Exchange
              
              
              Sell
                  US $6,259,039 at 1.1753(5)
              January
                  1 - March 312010
              Crude
                  Oil
              250
              Bpd
              Costless
                  collar US $54.00 floor, US $61.05 ceiling(9)
              January
                  1 - December 31Natural
                  Gas
              (1,342)
              Gjpd
              Cdn
                  $6.97 per gj(2)
              January
                  1 - December 31Foreign
                  Exchange
              
              
              Sell
                  US $4,927,500 at 1.1185(5)
              January
                  1 - December 31(1)Represents
                  a number of transactions entered into over an extended period of
                  time.(2)Settled
                  against AECO monthly index.(3)Provides a floor price while allowing percentage participation
                  above
                  strike price.(4)US
                  dollar cashflow.(5)Foreign exchange contracts to hedge underlying exchange rate on
                  Cdn
                  cashflow.(6)Condensate & Butane hedged using WTI monthly calendar average as
                  proxy.(7)Ethane hedged using AECO monthly index as proxy.(8)Transactions entered into by Kinetic Resources prior to acquisition
                  by
                  Provident.(9)Propane, Butane and Condensate hedged using WTI monthly calendar
                  average
                  as proxy.(10)Settled
                  against NYMEX Henry Hub Natural Gas futures contract.(11)Offsetting
                  trades have not been included in the table.




21
 TABLE
          OF CONTENTS


**18.**
                **Cash
                        reserve for future site
                        reclamation**


Provident
      established a cash reserve effective May 1, 2001 for future site reclamation
      expenditures relating to its Canadian oil and gas production. In accordance
      with
      the royalty agreement, Provident funds the reserve by paying $0.30 per barrel
      of
      oil equivalent produced on a 6:1 basis into a segregated cash account. Actual
      expenditures incurred are then funded from the cash in this account. For the
      year ended December 31, 2005, $2.9 million was contributed to the reserve and
      actual expenditures totaled $2.5 million. For the year ended December 31, 2004,
      $2.8 million was added to the cash reserve and actual expenditures totaled
      $3.2
      million.






**19.**
            **Commitments**




Provident
      has office lease commitments that extend through April 2013. Future minimum
      lease payments for the following five years are: 2006 - $3.8 million; 2007
      -
      $4.1 million; 2008 - $4.2 million; 2009 - $4.1 million; and 2010 - $3.2
      million.





In
      relation to the midstream services and marketing segment, Provident is committed
      to minimum lease payments under the terms of various rail tank car leases for
      the following five years: 2006 - US $4.8 million; 2007 - US $3.8 million; 2008
      -
      US $2.8 million; 2009 - US $1.6 million; and 2010 - US $0.6
      million.





In
      relation to the United States oil and natural gas production segment, Provident
      has surety bonds to provide US $4.9 million of coverage to Occidental Petroleum
      Corporation related to a purchase of oil and gas producing
      properties.





In
      relation to the United States oil and natural gas production segment, Provident
      leases certain property and equipment under operating leases. Future minimum
      lease payments for the following five years are as follows: 2006 - US $0.5
      million; 2007 - US $0.5 million; 2008 - US $0.5 million; 2009 - US $0.5 million;
      and 2010 - $0.6 million.






**20.**
              **Segmented
                          information**


The
      Trust’s business activities are conducted through three business segments:
      Canadian oil and natural gas production, United States oil and natural gas
      production (USOGP) and midstream services and marketing.





Oil
      and
      natural gas production in Canada and the United States includes exploitation,
      development and production of crude oil and natural gas reserves. Midstream
      services and marketing includes processing, extraction, transportation, loading
      and storage of natural gas liquids, and marketing of natural gas
      liquids.





Geographically
      the Trust operates in Canada and the USA in the oil and gas production business
      segment. The geographic components have been presented for the oil and natural
      gas business as well as the midstream services and marketing business that
      operates in both Canada and the USA.




22
 TABLE
          OF CONTENTS


**Year
                  ended December 31,
                  2005****Canada
                  Oil and Natural Gas Production**
              
              **United
                  States Oil and**
                **Natural
                  Gas Production**
              
              **Total
                  Oil and Natural Gas Production**
              
              **Midstream
                Services and Marketing****(1)**
              
              **Inter-**
                **segment**
                **Elimination**
              
              **Total****Revenue**Gross
                  production revenue
              $
              466,945
              
              $
              154,816
              
              $
              621,761
              
              $
              -
              
              $
              -
              
              $
              621,761Royalties
              
              (95,403
              )
              
              (15,019
              )
              
              (110,422
              )
              
              -
              
              
              -
              
              
              (110,422
              )Product
                  sales and service revenue
              
              -
              
              
              -
              
              
              -
              
              
              998,531
              
              
              (90,420
              )
              
              908,111Realized
                  loss on financial derivative instruments
              
              
              
              
              
              (48,308
              )
              
              (16,323
              )
              
              (64,631
              )
              
              (2,229
              )
              
              -
              
              
              (66,860
              )323,234
              
              
              123,474
              
              
              446,708
              
              
              996,302
              
              
              (90,420
              )
              
              1,352,590**Expenses**Cost
                  of goods sold
              
              
              
              
              
              -
              
              
              -
              
              
              -
              
              
              876,984
              
              
              (90,420
              )
              
              786,564Production,
                  operating and maintenance
              
              
              
              
              
              95,278
              
              
              39,513
              
              
              134,791
              
              
              36,402
              
              
              -
              
              
              171,193Transportation
              
              
              
              
              
              5,702
              
              
              -
              
              
              5,702
              
              
              1,230
              
              
              -
              
              
              6,932Foreign
                  exchange gain and other
              
              
              
              
              
              (1,815
              )
              
              (504
              )
              
              (2,319
              )
              
              (569
              )
              
              -
              
              
              (2,888
              )General
                  and administrative
              
              
              
              
              
              18,552
              
              
              11,490
              
              
              30,042
              
              
              11,566
              
              
              -
              
              
              41,608117,717
              
              
              50,499
              
              
              168,216
              
              
              925,613
              
              
              (90,420
              )
              
              1,003,409Earnings
                  before interest, taxes, depletion, depreciation, accretion and
                  other
                  non-cash items
              
              
              
              
              
              205,517
              
              
              72,975
              
              
              278,492
              
              
              70,689
              
              
              -
              
              
              349,181**Non-cash
                  revenue**Unrealized
                  gain/(loss) on financial derivative instruments
              
              
              
              
              
              13,302
              
              
              (1,910
              )
              
              11,392
              
              
              (1,564
              )
              
              -
              
              
              9,828Amortization
                  of loss on financial derivative instruments
              
              
              
              
              
              (2,144
              )
              
              -
              
              
              (2,144
              )
              
              -
              
              
              -
              
              
              (2,144
              )11,158
              
              
              (1,910
              )
              
              9,248
              
              
              (1,564
              )
              
              -
              
              
              7,684**Other
                  expenses**Depletion,
                  depreciation and accretion
              
              
              
              
              
              155,929
              
              
              25,553
              
              
              181,482
              
              
              11,754
              
              
              -
              
              
              193,236Loss
                  on redemption of convertible debentures
              
              
              
              
              
              31
              
              
              10
              
              
              41
              
              
              8
              
              
              -
              
              
              49Interest
                  on bank debt
              
              
              
              
              
              6,833
              
              
              2,292
              
              
              9,125
              
              
              1,750
              
              
              -
              
              
              10,875Interest
                  and accretion on convertible debentures
              
              
              
              
              
              12,342
              
              
              4,141
              
              
              16,483
              
              
              3,160
              
              
              -
              
              
              19,643Amortization
                  of deferred financing charges
              
              
              
              
              
              885
              
              
              297
              
              
              1,182
              
              
              227
              
              
              -
              
              
              1,409Unrealized
                  foreign exchange gain
              
              
              
              
              
              -
              
              
              -
              
              
              -
              
              
              (405
              )
              
              -
              
              
              (405
              )Non-cash
                  unit based compensation
              
              
              
              
              
              2,640
              
              
              6,098
              
              
              8,738
              
              
              1,015
              
              
              -
              
              
              9,753Internal
                  management charge
              
              
              
              
              
              (1,695
              )
              
              1,695
              
              
              -
              
              
              -
              
              
              -
              
              
              -Gain
                  on sale of assets
              
              
              
              
              
              -
              
              
              -
              
              
              -
              
              
              (5,188
              )
              
              -
              
              
              (5,188
              )Capital
                  taxes
              
              
              
              
              
              4,780
              
              
              -
              
              
              4,780
              
              
              -
              
              
              -
              
              
              4,780Current
                  and withholding taxes
              
              
              
              
              
              -
              
              
              5,628
              
              
              5,628
              
              
              -
              
              
              -
              
              
              5,628Future
                  income tax (recovery) expense
              
              
              
              
              
              (560
              )
              
              18,320
              
              
              17,760
              
              
              33
              
              
              -
              
              
              17,793181,185
              
              
              64,034
              
              
              245,219
              
              
              12,354
              
              
              -
              
              
              257,573Non-controlling
                  interest - USOGP
              
              
              
              
              
              -
              
              
              1,596
              
              
              1,596
              
              
              -
              
              
              -
              
              
              1,596Non-controlling
                  interest - Exchangeables
              
              
              
              
              
              138
              
              
              13
              
              
              151
              
              
              619
              
              
              -
              
              
              770**Net
                  income for the year**
              
              
              
              
              $
              35,352
              
              **$**
              **5,422**
              
              **$**
              **40,774**
              
              **$**
              **56,152**
              
              **$**
              **-**
              
              **$**
              96,926(1)Included in the Midstream Services and Marketing segment is product
                  sales
                  and service revenue of $19.7 million associated with U.S.
                  operations.


23
 TABLE
          OF CONTENTS


**Year
                  ended December 31,
                  2005****Canada
                  Oil**
                **and
                  Natural Gas Production**
              
              **United
                  States Oil and**
                **Natural
                  Gas Production**
              
              **Total
                Oil and Natural Gas Production**
              
              **Midstream
                Services and Marketing**
              
              **Inter-**
                **segment**
                **Elimination**
              
              **Total****Selected
                  balance sheet items****Capital
                  Assets**Property,
                  plant and equipment net
              
              
              
              
              $
              634,732
              
              $
              351,073
              
              $
              985,805
              
              $
              716,884
              
              $
              -
              
              $
              1,702,689Intangible
                  assets
              
              
              
              
              
              -
              
              
              -
              
              
              -
              
              
              215,850
              
              
              -
              
              
              215,850Goodwill
              
              
              
              
              
              330,944
              
              
              -
              
              
              330,944
              
              
              98,124
              
              
              -
              
              
              429,068**Capital
                  Expenditures**Property,
                  plant and equipment net
              
              
              
              
              
              85,402
              
              
              52,897
              
              
              138,299
              
              
              18,200
              
              
              -
              
              
              156,499Property,
                  plant and equipment through corporate acquisitions
              
              
              
              
              
              -
              
              
              99,877
              
              
              99,877
              
              
              428,066
              
              
              -
              
              
              527,943**Goodwill
                  additions**
              
              
              
              
              
              -
              
              
              -
              
              
              -
              
              
              98,124
              
              
              -
              
              
              98,124**Working
                  capital**Accounts
                  receivable
              
              
              
              
              
              135,220
              
              
              22,310
              
              
              157,530
              
              
              109,716
              
              
              -
              
              
              267,246Petroleum
                  product inventory
              
              
              
              
              
              -
              
              
              -
              
              
              -
              
              
              110,638
              
              
              -
              
              
              110,638Accounts
                  payable and accrued liabilities
              
              
              
              
              
              177,798
              
              
              46,462
              
              
              224,260
              
              
              90,463
              
              
              -
              
              
              314,723Long-term
                  debt
              
              
              
              
              $
              238,843
              
              $
              168,075
              
              $
              406,918
              
              $
              477,686
              
              $
              -
              
              $
              884,604




24
 TABLE
          OF CONTENTS


**Year
                ended December 31, 2004****(1)****Canada
                Oil**
              **and**
              **Natural**
              **Gas**
              **Production**
            
            **United**
              **States
                Oil**
              **and**
              **Natural**
              **Gas**
              **Production**
            
            **Total
                Oil**
              **and**
              **Natural**
              **Gas**
              **Production**
            
            **Midstream**
              **Services**
              **and**
              **Marketing**
            
            **Inter-**
              **segment**
              **Elimination**
            
            **Total****Revenue**Gross
                production revenue
            $
            405,181
            
            $
            44,688
            
            $
            449,869
            
            $
            -
            
            $
            -
            
            $
            449,869Royalties
            
            (85,190
            )
            
            (4,009
            )
            
            (89,199
            )
            
            -
            
            
            -
            
            
            (89,199
            )Product
                sales and service revenue
            
            -
            
            
            -
            
            
            -
            
            
            1,031,019
            
            
            (190,835
            )
            
            840,184Realized
                loss on financial derivative instruments
            
            (65,366
            )
            
            (425
            )
            
            (65,791
            )
            
            (3,153
            )
            
            -
            
            
            (68,944
            )254,625
            
            
            40,254
            
            
            294,879
            
            
            1,027,866
            
            
            (190,835
            )
            
            1,131,910**Expenses**Cost
                of goods sold
            
            -
            
            
            -
            
            
            -
            
            
            932,476
            
            
            (190,835
            )
            
            741,641Production,
                operating and maintenance
            
            90,330
            
            
            13,173
            
            
            103,503
            
            
            37,990
            
            
            -
            
            
            141,493Transportation
            
            5,087
            
            
            -
            
            
            5,087
            
            
            -
            
            
            -
            
            
            5,087Foreign
                exchange (gain) loss and other
            
            (4
            )
            
            (2,239
            )
            
            (2,243
            )
            
            763
            
            
            -
            
            
            (1,480
            )General
                and administrative
            
            16,439
            
            
            4,113
            
            
            20,552
            
            
            6,552
            
            
            -
            
            
            27,104111,852
            
            
            15,047
            
            
            126,899
            
            
            977,781
            
            
            (190,835
            )
            
            913,845Earnings
                before interest, taxes, depletion, depreciation, accretion and other
                non-cash items
            
            142,773
            
            
            25,207
            
            
            167,980
            
            
            50,085
            
            
            -
            
            
            218,065**Non-cash
                revenue**Unrealized
                gain (loss) on non-hedging derivative instruments
            
            3,788
            
            
            (3,182
            )
            
            606
            
            
            331
            
            
            -
            
            
            937Amortization
                of loss on non-hedging derivative instruments
            
            (22,990
            )
            
            -
            
            
            (22,990
            )
            
            -
            
            
            -
            
            
            (22,990
            )(19,202
            )
            
            (3,182
            )
            
            (22,384
            )
            
            331
            
            
            -
            
            
            (22,053
            )**Other
                expenses**Depletion,
                depreciation and accretion
            
            160,271
            
            
            7,402
            
            
            167,673
            
            
            9,609
            
            
            -
            
            
            177,282Interest
                on bank debt
            
            7,380
            
            
            1,252
            
            
            8,632
            
            
            3,184
            
            
            -
            
            
            11,816Interest
                and accretion on convertible debentures
            
            9,812
            
            
            1,372
            
            
            11,184
            
            
            3,989
            
            
            -
            
            
            15,173Amortization
                of deferred financing charges
            
            947
            
            
            98
            
            
            1,045
            
            
            390
            
            
            -
            
            
            1,435Unrealized
                foreign exchange gain
            
            -
            
            
            (744
            )
            
            (744
            )
            
            -
            
            
            
            
            
            (744
            )Non-cash
                unit based compensation
            
            877
            
            
            822
            
            
            1,699
            
            
            120
            
            
            -
            
            
            1,819Capital
                taxes
            
            5,292
            
            
            -
            
            
            5,292
            
            
            629
            
            
            -
            
            
            5,921Current
                and withholding taxes
            
            -
            
            
            1,201
            
            
            1,201
            
            
            81
            
            
            -
            
            
            1,282Future
                income tax recovery
            
            (40,457
            )
            
            -
            
            
            (40,457
            )
            
            (120
            )
            
            -
            
            
            (40,577
            )144,122
            
            
            11,403
            
            
            155,525
            
            
            17,882
            
            
            -
            
            
            173,407Non-controlling
                interest - USOGP
            
            -
            
            
            923
            
            
            923
            
            
            -
            
            
            -
            
            
            923Non-controlling
                interest - Exchangeables
            
            (492
            )
            
            217
            
            
            (275
            )
            
            732
            
            
            -
            
            
            457**Net
                income (loss) for the year**
            $
            (20,059
            )
            $
            9,482
            
            $
            (10,577
            )
            $
            31,802
            
            $
            -
            
            $
            21,225




25
 TABLE
          OF CONTENTS


**Year
                ended December 31, 2004****Canada
                Oil**
              **and**
              **Natural**
              **Gas**
              **Production**
            
            **United
                States**
              **Oil**
              **and**
              **Natural**
              **Gas**
              **Production**
            
            **Total
                Oil**
              **and**
              **Natural**
              **Gas**
              **Production**
            
            **Midstream**
              **Services**
              **and**
              **Marketing**
            
            **Inter-**
              **segment**
              **Elimination**
            
            **Total****Selected
                balance sheet items****Capital
                Assets**Property,
                plant and equipment net
            $
            763,306
            
            $
            254,547
            
            $
            1,017,853
            
            $
            281,801
            
            $
            -
            
            $
            1,299,654Goodwill
            
            330,944
            
            
            -
            
            
            330,944
            
            
            -
            
            
            -
            
            
            330,944**Capital
                Expenditures**Property,
                plant and equipment net
            
            61,454
            
            
            12,410
            
            
            73,864
            
            
            2,457
            
            
            -
            
            
            76,321Property,
                plant and equipment through corporate acquisitions
            
            272,259
            
            
            214,261
            
            
            486,520
            
            
            1,300
            
            
            -
            
            
            487,820**Goodwill
                additions**
            
            228,501
            
            
            -
            
            
            228,501
            
            
            -
            
            
            -
            
            
            228,501**Working
                capital**Accounts
                receivable
            
            78,299
            
            
            11,137
            
            
            89,436
            
            
            67,017
            
            
            (13,311
            )
            
            143,142Petroleum
                product inventory
            
            -
            
            
            -
            
            
            -
            
            
            17,151
            
            
            -
            
            
            17,151Accounts
                payable and accrued liabilities
            
            101,668
            
            
            28,639
            
            
            130,307
            
            
            54,416
            
            
            (13,311
            )
            
            171,412Long-term
                debt
            $
            274,683
            
            $
            74,464
            
            $
            349,147
            
            $
            83,059
            
            $
            -
            
            $
            432,206


(1)Restated note 3




26
 TABLE
          OF CONTENTS




**21.**
              **Reconciliation
                            of Financial Statements to United States**


**Generally
      accepted Accounting Principles**




The
      consolidated financial statements have been prepared in accordance with
      accounting principles generally accepted in Canada (“Canadian GAAP”). Any
      differences in accounting principles as they pertain to the accompanying
      financial statements are not material except as described below. All adjustments
      are measurement differences. Disclosure items are not noted.






**Consolidated
                  Statements of Earnings - U.S. GAAP**For
                  the year ending December 31 (Cdn$ 000s, except per unit
                  numbers)
              
              **2005**
              
              2004(Cdn$000s,
                  except per unit numbers)Net
                  income as reported
              
              $
              96,926
              
              $
              21,225AdjustmentsDepletion,
                  depreciation and accretion (a)
              
              
              **13,697**
              
              
              5,067Depletion,
                  depreciation and accretion other (a)
              
              
              **-**
              
              
              (58,065
              )FAS
                  133 adjustment (b)
              
              
              **2,144**
              
              
              22,990Non-cash
                  general and administrative (e)
              
              
              **(1**
              **)**
              
              415Future
                  income recovery (taxes) (a) (b) (c)
              
              
              **(5,357**
              **)**
              
              9,556Accretion
                  on convertible debentures (h)
              
              
              **2,849**
              
              
              2,973Non-controlling
                  interest - Exchangeable shares (j)
              
              
              **770**
              
              
              457Net
                  Income – U.S. GAAP
              
              $
              111,028
              
              $
              4,618




**Condensed
                  Consolidated Balance Sheet**As
                  at December 31 (Cdn$ 000s)
              **2005**
              2004**Canadian**
              
              
              **US.
                  GAAP**
              
              
              Canadian
                  GAAP
              
              
              US.
                  GAAP**Assets**Deferred
                  derivative loss (b)
              $
              -
              
              $
              -
              
              $
              2,144
              
              $
              -Accounts
                  receivable (f)
              
              **267,246**
              
              
              **267,246**
              
              
              143,142
              
              
              145,442Property,
                  plant and equipment (a)
              
              **1,702,689**
              
              
              **1,646,200**
              
              
              1,299,654
              
              
              1,229,468**Liabilities
                  and unitholders’ equity**Long-term
                  debt (h)
              
              **884,604**
              
              
              **902,083**
              
              
              432,206
              
              
              437,561Future
                  income taxes (a) (b) (c) (f)
              
              **91,595**
              
              
              **73,609**
              
              
              70,629
              
              
              47,286Non-controlling
                  interest - Exchangeable shares (j)
              
              **8,259**
              
              
              **-**
              
              
              35,921
              
              
              -Units
                  subject to redemption (i) (j)
              
              **-**
              
              
              **2,236,360**
              
              
              -
              
              
              1,503,181Convertible
                  debentures equity component (h)
              
              **19,301**
              
              
              **-**
              
              
              9,785
              
              
              -Unitholders’
                  contributions (i)
              
              **1,971,707**
              
              
              **-**
              
              
              1,438,393
              
              
              -Contributed
                  surplus (e)
              
              **1,675**
              
              
              **1,675**
              
              
              2,002
              
              
              3,020Cumulative
                  translation adjustment (g)
              
              **(41,785**
              **)**
              
              **-**
              
              
              (28,848
              )
              
              -Accumulated
                  income (loss)
              
              **97,288**
              
              
              **(837,253**
              **)**
              
              362
              
              
              (485,832
              )Accumulated
                  cash distributions (i)
              
              **(643,360**
              **)**
              
              **-**
              
              
              (412,646
              )Accumulated
                  other comprehensive loss (f) (g)
              $
              -
              
              $
              (42,679
              )
              $
              -
              
              $
              (27,442
              )




(a)
            Under
                the Canadian cost recovery ceiling test the recoverability of a cost
                centre is tested by comparing the carrying value of the cost centre
                to the
                sum of the undiscounted proved reserve cash flows expected from the
                cost
                centre using future price estimates. If the carrying value is not
                recoverable, the cost centre is written down to its fair value determined
                by comparing the future cash flows from the proved plus probable
                reserves
                discounted at the Trust’s risk free interest rate. Any excess carrying
                value of the assets on the balance sheet above fair value would be
                recorded in depletion, depreciation and accretion expense as a permanent
                impairment. Under U.S. GAAP, companies utilizing the full cost method
                of
                accounting for oil and natural gas activities perform a ceiling test
                on
                each cost centre using discounted future net revenue from proved
                oil and
                natural gas reserves discounted at 10 percent. Prices used in the
                U.S.
                GAAP ceiling tests are those in effect at year-end and financing
                and
                administrative expenses are excluded from the calculation. The amounts
                recorded for depletion and




27
 TABLE
          OF CONTENTS


depreciation
                have been adjusted in the periods as a result of differences in write
                down
                amounts recorded pursuant to U.S. GAAP compared to Canadian
                GAAP.





In
      computing its consolidated net earnings for U.S. GAAP purposes, the Trust
      recorded additional depletion in 2004 as a result of the application of the
      ceiling test. These charges were not required under the Canadian GAAP ceiling
      tests. As a result of the U.S. GAAP ceiling test, there was no charge for
      ceiling test impairment for 2005.





(b)
            At
                January 1, 2004, the Trust recorded an unrealized loss of $25.1 million
                in
                deferred charges on the consolidated balance sheet that is being
                recognized in income over the term of the previously designated hedged
                items. For the period ending December 31, 2005, $2.1 million (2004
                - $23.0
                million) of this deferred charge has been amortized. Under U.S. GAAP
                the
                amortization of the deferred charge has already been captured in
                prior
                period accumulated losses. There will be no further U.S./Canadian
                GAAP
                differences related to the adoption of this
                standard.





(c)
            The
                Canadian liability method of accounting for income taxes is similar
                to the
                United States FAS 109, Accounting for Income Taxes, which requires
                the
                recognition of deferred tax assets and liabilities for the expected
                future
                tax consequences of events that have been recognized in Provident’s
                financial statements or tax returns. Pursuant to U.S. GAAP, enacted
                tax
                rates are used to calculate future taxes, whereas Canadian GAAP uses
                substantively enacted rates.





(d)
            The
                consolidated statements of cash flows and operations and accumulated
                income (loss) are prepared in accordance with Canadian GAAP and conform
                in
                all material respects with U.S. GAAP except for the following;




(i) Canadian GAAP allows for the presentation of operating cash flow before
      changes in non-cash working capital items in the consolidated statement of
      cash
      flows. This total cannot be presented under U.S. GAAP.




(ii) U.S. GAAP requires disclosure on the consolidated statement of operations
      when depreciation, depletion and amortization are excluded from cost of goods
      sold. This disclosure has not been noted on the face of the consolidated
      statement of operations.





(e)
            Provident
                harmonized its accounting treatment of unit based compensation with
                U.S.
                GAAP in 2003 by adopting CICA handbook section 3870, “Stock-based
                compensation and other stock-based payments.” For U.S. GAAP purposes
                Provident follows FAS 123, “Accounting for stock-based compensation.”
                Adoption of CICA handbook section 3870 allows for prospective application
                whereby options granted during or subsequent to 2003 are fair valued.
                Under FAS 123, all option grants are fair
                valued.





(f)
            Included
                in accounts receivable in 2004 is a marketable security that is being
                held
                for sale. The Trust follows the cost method of accounting for an
                investment in a marketable security as established by the CICA. Under
                this
                accounting policy, the investment is initially recorded at cost with
                dividends recorded as income. Under U.S. GAAP, the marketable securities
                are considered held for sale and recorded on the balance sheet at
                fair
                value. The corresponding difference between the cost method and fair
                value
                is recorded to other comprehensive loss in the current year and results
                in
                a Canadian/U.S. GAAP difference.





(g)
            U.S.
                GAAP requires gains or losses arising from the translation of
                self-sustaining operations to be included in other comprehensive
                losses.
                Canadian GAAP requires these amounts to be recorded in unitholders’
                equity.





(h)
            Effective
                December 31, 2004, the Trust retroactively adopted the revised CICA
                Handbook Section 3860 ("HB 3860"), "Financial Instruments - Presentation
                and Disclosure" for financial instruments that may be settled at
                the
                issuer's option in cash or its own equity. As a result of the
                implementation of this standard, a U.S./Canadian GAAP difference
                has
                arisen. Under U.S. GAAP, the convertible debentures are disclosed
                as
                long-term debt at their face value versus Canadian GAAP that requires
                discounting of the convertible debentures, accretion expense to represent
                the unwinding of the discounted convertible debentures and a value
                be
                assigned within equity to the conversion feature attached to the
                convertible debentures.


28
 TABLE
          OF CONTENTS





(i)
            Under
                U.S. GAAP, a redemption feature of equity instruments exercisable
                at the
                option of the holder requires that such equity be excluded from
                classification as permanent equity and be reported as a liability
                at the
                equity’s redemption value. Changes in redemption value in the period are
                charged to accumulated earnings. Under Canadian GAAP, such equity
                instruments are considered to be permanent equity and are presented
                as
                unitholder’s equity. The Trust’s units and exchangeable shares both have a
                redemption feature, which qualify them to be considered under this
                guidance.




In
      prior
      years, the Trust believed there were sufficient restrictions on the redemption
      feature that qualified the trust units and exchangeable shares as permanent
      equity for U.S. GAAP purposes (note 12). Based on a review conducted in the
      current year, it was determined that the trust units and exchangeable shares
      should be accounted for as units subject to redemption in accordance with U.S.
      GAAP. Accumulated earnings have been reduced by $463.5 million (2004 - $396.9
      million) and $2,236.4 million (2004 - $1,503.2 million) has been reclassified
      to
      units subject to redemption.





(j)
            Under
                Canadian GAAP, the Trust’s exchangeable shares are classified as
                non-controlling interest. As these exchangeable shares can be converted
                into trust units at the option of the holder, the exchangeable shares
                are
                classified as units subject to redemption along with the trust units
                for
                U.S. GAAP purposes.




29
 TABLE
          OF CONTENTS


**Recent
      U.S. Accounting Pronouncements**





Accounting
      for conditional asset retirement obligations





In
      2005,
      FASB issued Financial Interpretation 47 “Accounting for Conditional Asset
      Retirement Obligations”. This interpretation clarifies that the term conditional
      asset retirement obligation as used in FAS 143 “Accounting for Asset Retirement
      Obligations” refers to a legal obligation to perform an asset retirement
      activity in which the timing and/or method of settlement are conditional on
      a
      future event that may or may not be within the control of the entity. The
      obligation to perform the asset retirement activity is unconditional even though
      uncertainty exists about the timing and/or method of settlement. Thus, the
      timing and/or method of settlement may be conditional on a future event.
      Accordingly, an entity is required to recognize a liability for the fair value
      of a conditional asset retirement obligation if the fair value of the liability
      can be reasonably estimated. This interpretation is effective no later than
      the
      end of fiscal years ending after December 15, 2005. The adoption of this
      statement has not had a material impact on the Trust’s consolidated financial
      statements.





Accounting
      changes and error corrections





In
      2005,
      FASB issued FAS 154 “Accounting Changes and Error Corrections” which replaces
      APB Opinion 20. This statement changes the requirements for the accounting
      and
      reporting of a change in accounting principle. FAS 154 requires retrospective
      application of voluntary changes in accounting principles to prior period
      financial statements, unless it is impracticable to do so. The statement is
      effective for fiscal years beginning after December 15, 2005. The Trust does
      not
      expect the adoption of this statement to have a material impact on its financial
      statements.





Share-based
      payment





In
      2004,
      FASB issued revised FAS 123 “Share-Based Payment”. This amended statement
      eliminates the alternative to use Accounting Principles Board (“APB”) Opinion
      No. 25’s intrinsic value method of accounting, as was provided in the originally
      issued Statement 123. As a result, public entities are required to use the
      grant-date fair value of the award in measuring the cost of employee services
      received in exchange for an equity award of equity instruments. Compensation
      cost is not recognized for equity instruments for which employees do not render
      the requisite service. This amended statement is effective the beginning of
      the
      first interim or annual reporting period that begins after June 15, 2005. The
      Trust does not expect the adoption of this statement to have a material impact
      on its financial statements.





Exchange
      of non-monetary assets





In
      2004,
      FASB issued FAS 153 “Exchange of Non-monetary Assets”. This statement is an
      amendment of APB Opinion No. 29 “Accounting for Non-monetary Transactions”.
      Based on the guidance in APB Opinion No. 29, exchanges on non-monetary assets
      are to be measured based on the fair value of the assets exchanged. Furthermore,
      APB Opinion No. 29 previously allowed for certain exceptions to this fair value
      principle. FAS 153 eliminates APB Opinion No. 29’s exception to fair value for
      non-monetary exchanges of similar productive assets and replaces this with
      a
      general exception for exchange of non-monetary assets that do not have
      commercial substance. For purposes of this statement, a non-monetary exchange
      is
      defined as having commercial substance when the future cash flows of an entity
      are expected to change significantly as a result of the exchange. The provisions
      of this statement are effective for non-monetary asset exchanges that occur
      in
      fiscal periods beginning after June 15, 2005 and are to be applied
      prospectively. Earlier application is permitted for non-monetary asset exchanges
      that occur in fiscal periods beginning after the issue date of this statement.
      The Trust does not expect the adoption of this statement to have a material
      impact on its financial statements.




30


**ADDITIONAL
      DISCLOSURE**




**Certifications
      and Disclosure Regarding Controls and Procedures.**




(a)
            Certifications.
                See Exhibits 99.1 and 99.2 to this Annual Report on Form
                40-F.




(b)
            Disclosure
                Controls and Procedures.
                As of the end of the registrant’s fiscal year ended December 31, 2005, an
                evaluation of the effectiveness of the registrant’s “disclosure controls
                and procedures” (as such term is defined in Rules 13a-15(e) and 15d-15(e)
                of the Securities Exchange Act of 1934, as amended (the “Exchange Act”))
                was carried out by the management of Provident Energy Ltd., the
                administrator of the registrant, with the participation of theChief
                Executive Officer (“CEO”) and Chief Financial Officer (“CFO”) of Provident
                Energy Ltd., who also perform such functions for the registrant.Based
                upon that evaluation, the CEO and CFO have concluded that as of the
                end of
                that fiscal year, the registrant’s disclosure controls and procedures are
                effective to ensure that information required to be disclosed by
                the
                registrant in reports that it files or submits under the Exchange
                Act is
                (i) recorded, processed, summarized and reported within the time
                periods
                specified in Securities and Exchange Commission rules and forms and
                (ii)
                accumulated and communicated to the registrant’s management, including its
                principal executive officer and principal financial officer, to allow
                timely decisions regarding required disclosure.





It
      should be noted that while the CEO and CFO believe that the registrant’s
      disclosure controls and procedures provide a reasonable level of assurance
      that
      they are effective, they do not expect that the registrant’s disclosure controls
      and procedures or internal control over financial reporting will prevent all
      errors and fraud. A control system, no matter how well conceived or operated,
      can provide only reasonable, not absolute, assurance that the objectives of
      the
      control system are met.





(c)
            Changes
                in Internal Control Over Financial Reporting.
                During the fiscal year ended December 31, 2005, there were no changes
                in
                the registrant’s internal control over financial reporting that have
                materially affected, or are reasonably likely to materially affect,
                the
                registrant’s internal control over financial reporting.










**Notices
      Pursuant to Regulation BTR.**





None.





**Audit
      Committee Financial Expert.**





The
      registrant’s board of directors has determined that Mike H. Shaikh, a member of
      the registrant’s audit committee, qualifies as an “audit committee financial
      expert” (as such term is defined in Form 40-F). Mr. Shaikh is “independent” as
      that term in defined in the rules of the New York Stock Exchange.





**Code
      of Business Conduct** .





The
      registrant has adopted a “code of business conduct” (which qualifies as a Code
      of Ethics that meets the requirements as defined in Form 40-F) that applies
      to
      its principal executive officer, principal financial officer, principal
      accounting officer or controller, and persons performing similar
      functions.




The
      Code
      of Business Conduct is available for viewing on the registrant’s website at
      www.providentenergy.com.




In
      connection with the registrant’s listing on the New York Stock Exchange, the
      Code of Business Conduct was amended in March 2006 to reflect the New York
      Stock
      Exchange’s guidelines for codes of ethics. The amended Code of Business Conduct
      is filed as Exhibit 99.9 to this Annual Report on Form 40-F. Since the adoption
      of the Code of Business Conduct, there have not been any waivers, including
      implicit waivers, from any provision of the Code of Business
      Conduct.




**Principal
      Accountant Fees and Services.**




The
      required disclosure in included under the heading *Audit
      Committee Information* in
      the
      Annual Information Form included as part of this form. ****




The
      following table sets forth information about the fees billed to the Trust for
      professional services provided by PricewaterhouseCoopers LLP during fiscal
      2005
      and 2004:





*(CDN$)*
            
            **2005**
            
            **2004**Audit
                Fees
            
            $
            929,000
            
            $
            868,000Audit-Related
                Fees
            
            
            30,000
            
            
            90,750Tax
                Fees
            
            
            776,300
            
            
            375,000All
                Other Fees
            
            
            -
            
            
            -Total
            
            $
            1,735,300
            
            $
            1,333,750




Fees .
      Audit
      fees consist of fees for the audit of the registrant’s annual financial
      statements or services that are normally provided in connection with statutory
      and regulatory filings or engagements.







Audit-Related
      Fees .
      Audit-related fees consist of fees for assurance and related services that
      are
      reasonably related to the performance of the audit or review of the registrant’s
      financial statements and are not reported as Audit Fees. During fiscal 2005
      and
      2004, the services provided in this category included due diligence reviews
      in
      connection with acquisitions, research of accounting and audit-related issues
      and the completion of audits required by contracts to which the registrant
      is a
      party.




Tax
      Fees .
      Tax
      fees consist of fees for tax compliance services, tax advice and tax planning.
      During fiscal 2005 and 2004, the services provided in this category included
      assistance and advice in relation to the preparation of corporate income tax
      returns.




All
      Other Fees .
      None.




**Pre-Approval
      Policies and Procedures.**




(a)
            All
                proposed services or the fees payable in connection with such services
                that have not already been pre-approved must be pre-approved by either
                the
                audit committee or pursuant to Delegated Authority (as defined below).
                The
                audit committee has delegated authority to the chairman of the audit
                committee to pre-approve the provision of permitted services by
                PricewaterhouseCoopers LLP and not otherwise pre-approved by the
                full
                audit committee, including the fees and terms of the proposed services
                (“Delegated Authority”). All pre-approvals granted pursuant to Delegated
                Authority must be presented by the chairman to the full audit committee
                at
                its next meeting. The fees payable in connection with any particular
                service to be provided by PricewaterhouseCoopers LLP that has been
                pre-approved pursuant to Delegated Authority may not exceed Cdn.$50,000.
                Amounts exceeding Cdn.$50,000 must be pre-approved by the full audit
                committee. Prohibited services may not be pre-approved by the audit
                committee or pursuant to Delegated
                Authority.




(b)
            Of
                the fees reported in this Annual Report on Form 40-F under the heading
                “Principal Accountant Fees and Services”, nil of the fees billed by
                PricewaterhouseCoopers LLP were approved by the audit committee of
                the
                registrant pursuant to the*de
                minimus*exception provided by Section (c)(7)(i)(C) of Rule 2-01 of Regulation
                S-X.




**Off-Balance
      Sheet Arrangements.**




The
      Trust
      does not have any off-balance sheet arrangements.




**Tabular
      Disclosure of Contractual Obligations.**




(CDN$
                millions)
            
            **Payment
                due by period****Contractual
                Obligations**
            **Total**
            **Less
                than**
              **1
                Year**
            **2
                to 3**
              **Years**
            **3
                to 5**
              **Years**
            **More
                than 5 Years**Long-Term
                Debt Obligations
            884.6
            -
            618.2
            32.4
            234.0Capital
                (Finance) Lease Obligations
            -
            -
            -
            -
            -Operating
                Lease Obligations
            50.1
            9.9
            17.3
            11.2
            11.7Purchase
                Obligations
            -
            -
            -
            -
            -Other
                Long-Term Liabilities Reflected on the Registrant’s Balance Sheet under
                Canadian GAAP
            41.1
            -
            -
            -
            41.1Total
            975.8
            9.9
            635.5
            43.6
            286.8









**Identification
      of the Audit Committee.**




The
      registrant has a separately-designated standing audit committee established
      in
      accordance with section 3(a)(58)(A) of the Exchange Act. The members of the
      audit committee are: Mike H. Shaikh, Bruce Libin and Hugh A.
      Fergusson.





**Disclosure
      Pursuant to the Requirements of the New York Stock
      Exchange.**





Presiding
      Director at Meetings of Non-Management Directors





The
      registrant schedules regular executive sessions in which the registrant's
      "non-management directors" (as that term is defined in the rules of the New
      York
      Stock Exchange) meet without management participation. Mr. John Zaozirny serves
      as the presiding director (the "Presiding Director") at such sessions. Each
      of
      the registrant's non-management directors is "unrelated" as such term is used
      in
      the rules of the Toronto Stock Exchange. The Provident Board of Directors is
      responsible for determining whether or not each director is independent. In
      making this determination, the Board has adopted the definition of
      "independence" as set out in Section 1.4 of Multilateral Instrument 52-110
      Audit
      Committees ("MI-51-110"). In applying this definition, the Board considers
      all
      relationships of the directors with Provident, including business, family and
      other relationships. Provident's Board of Directors also determines whether
      each
      member of Provident's Audit Committee is independent pursuant to Sections 1.4
      and 1.5 of MI 52-110 and Rule 10A-3 of the *Securities
      Exchange Act* of 1934.
      Provident's Board of Directors has not adopted the director independence
      standards contained in Section 303A.02 of the NYSE's Listed Company
      Manual.








Communication
      with Non-Management Directors





Shareholders
      may send communications to the registrant's non-management directors by writing
      to the Presiding Director, c/o Lynn M. Rannelli, Assistant Corporate Secretary,
      Provident Energy Ltd., 800, 112-4 th Avenue
      S.W., Calgary, Alberta, Canada T2P 0H3. Communications will be referred to
      the
      Presiding Director for appropriate action. The status of all outstanding
      concerns addressed to the Presiding Director will be reported to the board
      of
      directors as appropriate.





Corporate
      Governance Guidelines





According
      to Section 303A.09 of the NYSE Listed Company Manual, a listed company must
      adopt and disclose a set of corporate governance guidelines with respect to
      specified topics. Such guidelines are required to be posted on the listed
      company's website. The registrant operates under corporate governance principles
      that are consistent with the requirements of Section 303A.09 of the NYSE Listed
      Company Manual, many of which are described under the heading "Statement of
      Corporate Governance Practices" in the registrant's Information Circular in
      connection with its 2006 Annual Meeting. However, the registrant has not
      codified its corporate governance principles into formal guidelines in order
      to
      post them on its website.










Board
      Committee Mandates





The
      Mandates of the registrant's audit committee, human resources and compensation
      committee, and nominating and corporate governance committee are each available
      for viewing on the registrant's website at www.providentenergy.com, and are
      available in print to any unitholder who requests them. Requests for copies
      of
      these documents should be made by contacting: Lynn M. Rannelli, Assistant
      Corporate Secretary, Provident Energy Ltd., 800, 112-4 th Avenue
      S.W., Calgary, Alberta, Canada T2P 0H3.


Alternatively,
      requests for these documents may be made by contacting the registrant's
      Corporate Secretarial Department at (403) 296-2233 (Fax: (403)
      205-3539).







**UNDERTAKING
      AND CONSENT TO SERVICE OF PROCESS**




**A.**  **Undertaking.**




The
      registrant undertakes to make available, in person or by telephone,
      representatives to respond to inquiries made by the Securities and Exchange
      Commission (the “Commission”) staff, and to furnish promptly, when requested to
      do so by the Commission staff, information relating to: the securities
      registered pursuant to Form 40-F; the securities in relation to which the
      obligation to file an annual report on Form 40-F arises; or transactions in
      said
      securities.




**B.**
            **Consent
                to Service of Process.**




The
      Company has previously filed a Form F-X in connection with the class of
      securities in relation to which the obligation to file this report
      arises.




Any
      change to the name or address of the agent for service of process of the
      registrant shall be communicated promptly to the Securities and Exchange
      Commission by an amendment to the Form F-X referencing the file number of the
      relevant registration statement.




**SIGNATURES**




Pursuant
      to the requirements of the Exchange Act, the registrant certifies that it meets
      all of the requirements for filing on Form 40-F and has duly caused this annual
      report to be signed on its behalf by the undersigned, thereunto duly authorized,
      on March 28, 2005.




**PROVIDENT
      ENERGY TRUST**




**By:
      Provident Energy Ltd.**




By:  /s/Thomas
      W. Buchanan


Name:
      Thomas W. Buchanan


Title:
      Chief Executive Officer







**EXHIBIT
      INDEX**





Exhibit
            Description99.1
            Certification
                of Chief Executive Officer pursuant to
                Rule 13a-14(a) or 15d-14 of the Securities Exchange Act of
                193499.2
            Certification
                of Chief Financial Officer pursuant to
                Rule 13a-14(a) or 15d-14 of the Securities Exchange Act of
                193499.3
            Section
                1350 Certification of Chief Executive
                Officer99.4
            Section
                1350 Certification of Chief Financial
                Officer99.5
            Consent
                of PricewaterhouseCoopers LLP
                (Calgary)99.6
            Consent
                of McDaniel & Associates Consultants
                Ltd.99.7
            Consent
                of Netherland Sewell & Associates
                Inc.99.8
            Consent
                of Cawley Gillespie & Associates
                Inc.99.9
            Amended
                Code of Business Conduct