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, 2006
  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
                    (if
                      applicable))
              (I.R.S.
                    Employer
                  Identification
                      Number
                    (if
                      Applicable))
 **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)**Andrews
                        Kurth LLP**
                      **600
                        Travis****Suite
                        4200****Houston,
                        Texas 77002**(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**
                New
                      York 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:
 Trust
              Units outstanding at December 31, 2006: 188,978,637
 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,
                  2006;(b)
              Management's
                  Discussion and Analysis of Financial Condition
                  and Results of Operations for the fiscal year ended December 31,
                  2006
                  and(c)
              Consolidated
                  Financial Statements for the fiscal year ended December 31, 2006*(Note 18
                  to the Consolidated Financial Statements relates to United States
                  Accounting Principles and Reporting (U.S.
                  GAAP)).*


TABLE
          OF CONTENTS
 **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, 2006, 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 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, 2006, 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).
 TABLE
              OF CONTENTS
  **Code
          of Ethics** .
 
 The
          registrant has adopted a “code of ethics” (as that term is 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 Ethics is available for viewing on the registrant’s website at
          www.providentenergy.com.
  Since
          the
          adoption of the Code of Ethics, there have not been any amendments to the
          Code
          of Ethics or waivers, including implicit waivers, from any provision of
          the Code
          of Ethics.
  **Principal
          Accountant Fees and Services.**
  A
          table
          summarizing fees is included under the heading *Audit
          Committee Information* in
          the
          Renewal Annual Information Form included as part of this form.
  Audit
          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
          2004 and
          2003, the services provided in this category included due diligence reviews
          in
          connection with acquisitions, research of accounting and audit-related
          issues,
          review of reserves disclosure 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 2006, the services provided in this category included
          assistance and advice in relation to the preparation of corporate income
          tax
          returns.
  All
          Other Fees .
          Not
          applicable.
  **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).
                    Subject to the next paragraph, 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.
  TABLE
              OF CONTENTS
 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$100,000. Amounts exceeding
                    Cdn.100,000 must be pre-approved by the full audit committee.
  Prohibited
                    services may not be pre-approved by the audit committee or pursuant
                    to
                    Delegated Authority.****
  (b)  Of
          the
          fees reported in this Annual Report on Form 40-F under the heading “Principal
          Accountant Fees and Services”, nil of the fees billed by PricewaterhouseCoopers
          LLP were approved by the audit committee of the registrant pursuant to
          the *de
          minimus* exception provided by Section (c)(7)(i)(C) of Rule 2-01 of Regulation
          S-X.
  **Off-Balance
          Sheet Arrangements.**
  There
          are
          no off balance sheet arrangements.
  **Tabular
          Disclosure of Contractual Obligations.**
  (CDN$
                    millions)
                
                **Payment
                    due by period****Contractual
                    Obligations**
                **Total**
                **Less
                    than 1**
                  **Year**
                **1
                    to 3**
                  **Years**
                **3
                    to 5**
                  **Years**
                **More
                    than**
                  **5
                    years**Long-Term
                    Debt Obligations
                988.8
                -
                752.8
                142.9
                93.1Capital
                    (Finance) Lease Obligations
                -
                -
                -
                -
                -Operating
                    Lease Obligations
                196.0
                16.6
                36.8
                27.9
                114.7Purchase
                    Obligations
                -
                -
                -
                -
                -Other
                    Long-Term Liabilities Reflected on the Registrant's Balance Sheet
                    under
                    Canadian GAAP
                143.7
                -
                60.7
                23.2
                59.8Total
                1,328.5
                16.6
                850.3
                194.0
                267.6
  TABLE
              OF CONTENTS
  **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.
 
 TABLE
          OF CONTENTS


**RENEWAL
        ANNUAL INFORMATION FORM**
  For
        the
        year ended December 31, 2006
  
  March
        28,
        2007


TABLE
            OF CONTENTS


**TABLE
      OF CONTENTS**




**Page**
              
              **Page**GLOSSARY
                  OF TERMS
              1
              General
              24ABBREVIATIONS,
                  TERMS AND
              
              Risk
                  Management
              24CONVERSIONS
              4
              OIL
                  AND NATURAL GASPRESENTATION
                  OF OIL AND GAS
              
              OPERATIONS
              29RESERVES
                  AND
              
              NATURAL
                  GAS MIDSTREAM, NGLPRODUCTION
              
              PROCESSING
                  ANDINFORMATION
              5
              MARKETING
                  OPERATIONS
              30NON-GAAP
                  MEASURES
              5
              General
              30NOTE
                  REGARDING FORWARD
              
              NGL
                  Extraction
              30LOOKING
                  STATEMENTS
              6
              NGL
                  Fractionation
              31INCORPORATION
                  AND
              
              NGL
                  Transportation
              31STRUCTURE
              8
              NGL
                  Storage
              31The
                  Trust
              8
              NGL
                  Marketing
              31Provident
              8
              Commercial
                  Arrangements
              32Provident
                  Holdings Trust
              8
              Midstream
                  services andProvident
                  Acquisitions L.P
              8
              marketing
                  assets
              33Provident
                  Midstream L.P
              9
              MARKET
                  FOR SECURITIES
              35Provident
                  Acquisitions Inc
              9
              RECORD
                  OF CASH DISTRIBUTIONS
              37Provident
                  Midstream Inc
              9
              DIRECTORS
                  AND OFFICERS
              39Pro
                  Holding Company
              9
              AUDIT
                  COMMITTEEBreitBurn
                  Energy Company L.P
              9
              INFORMATION
              44BreitBurn
                  Energy Partners L.P
              10
              INFORMATION
                  CONCERNING THEINTERCORPORATE
              
              OIL
                  AND GAS INDUSTRY
              46RELATIONSHIPS
              10
              RISK
                  FACTORS
              48INFORMATION
                  CONCERNING THE
              
              Oil
                  and Gas Production RiskTRUST,
                  PROVIDENT AND
              
              Factors
              49CERTAIN
                  SUBSIDIARIES
              11
              Natural
                  Gas Midstream, NGLProvident
                  Energy Trust
              11
              Processing
                  andProvident
                  Energy Ltd
              17
              Marketing
                  BusinessProvident
                  Holdings Trust,
              
              Risk
                  Factors
              51Provident
                  Acquisitions
              
              General
                  Risk Factors
              54L.P.,
                  Provident
              
              INTERESTS
                  OF MANAGEMENTMarketing
                  L.P. and
              
              AND
                  OTHERS IN MATERIALProvident
                  Midstream
              
              TRANSACTIONS
              59L.P
              19
              TRANSFER
                  AGENT ANDProvident
                  Acquisitions Inc
              19
              REGISTRAR
              59Provident
                  Midstream Inc
              19
              INTERESTS
                  OF EXPERTS
              59Pro
                  Holding Company
              19
              MATERIAL
                  CONTRACTS
              59BreitBurn
                  Energy Company L.P
              19
              DOCUMENTS
                  INCORPORATED BYBreitBurn
                  Energy Partners L.P
              20
              REFERENCE
              60GENERAL
                  DEVELOPMENT OF THE
              
              PRINCIPAL
                  HOLDERS OF TRUSTBUSINESS
                  OF THE TRUST
              
              UNITS
              60AND
                  PROVIDENT
              20
              ADDITIONAL
                  INFORMATION
              60CORPORATE
                  STRATEGY AND RISKMANAGEMENT
              24SCHEDULE
                  A - AUDIT COMMITTEE INFORMATION




TABLE
          OF CONTENTS


**GLOSSARY
      OF TERMS**




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




" **8.75
      Percent Debentures** "
      means
      the 8.75 percent 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.;




" **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);




" **AJM** "
      means
      AJM Petroleum Consultants, independent petroleum engineers;




" **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";




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




" **BEC
      L.P. Properties** "
      means
      the oil and gas properties held by BEC L.P. in the State of California and
      in
      the State of Wyoming;




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




" **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
      MLP** "
      means
      BreitBurn Energy Partners L.P., a publicly traded Delaware limited
      partnership;




" **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 Percent Debentures** "
      means
      the 6.5 percent 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;




" **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; ****




" **NSAI** "
      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 BEC L.P.
      pursuant to a membership interest purchase and sale agreement dated February
      9,
      2005 among BEC L.P. and all of the membership interest holders of Nautilus;




" **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 BEC 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 BEC L.P. and an arm's
      length third party vendor;




" **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 BEC L.P. pursuant to the Orcutt Hill
      Acquisition;




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


-
            2 -
 TABLE
            OF CONTENTS




" **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 Energy (Canada) Inc. 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 Energy (Canada) Inc.;




" **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 percent 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 percent 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;




" **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;  -
              3 -
 TABLE
              OF CONTENTS




and
      in
      the case of the Trust, includes Provident;




" **Supplemental
      6.5 Percent Debentures** "
      means
      the 6.5 percent 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;




" **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;




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




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




" **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.




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.




**ABBREVIATIONS,
      TERMS AND CONVERSIONS**




In
      this
      Renewal Annual Information Form, the abbreviations and terms set forth below
      have the meanings indicated.  -
            4 -
 TABLE
            OF CONTENTS




**Oil
                and Natural Gas Liquids**
            **Natural
                Gas**bbls
            barrels
            mcf
            thousand
                cubic feetboed
                or boe/d
            barrels
                of oil equivalent per day
            bcf/d
            billion
                cubic feet per daybpd
                or bbl/d
            barrels
                of oil per day
            m3
            cubic
                metresmmbbls
            million
                barrels
            mmbtu
            million
                British Thermal UnitsNGLs
            natural
                gas liquids
            gj
            gigajouleSTB
            stock
                tank barrel of oil**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.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 Renewal 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.




**NON-GAAP** **MEASURES**




In
      this
      Renewal 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.** Management also 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"). 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.


-
            5 -
 TABLE
            OF CONTENTS


**NOTE
      REGARDING FORWARD LOOKING STATEMENTS**




This
      Renewal 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
      Renewal Annual Information Form 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 Renewal 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
      Renewal Annual Information Form and the documents incorporated by reference
      herein include, but are not limited to, statements with respect to:


-
            6 -
 TABLE
            OF CONTENTS




·
              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;


·
            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 associated with the NGL services, processing and marketing
                business;


·
            fluctuations
                in the price of crude oil, natural gas and natural gas
                liquids;


·
            uncertainties
                associated with estimating
                reserves;


·
            royalties
                payable in respect of oil and gas
                production;


·
            interest
                payable on notes issued in connection with
                acquisitions;


·
            income
                tax legislation relating to income trusts, including the effect of
                proposed taxation of trust
                distributions;


·
            governmental
                regulation in North America 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 realize the anticipated benefits of
              acquisitions;


·
            competition for, among other things, capital reserves,
              undeveloped lands and skilled personnel; ·
            failure
                to obtain industry partner and other third party consents and approvals,
                when required;


·
            risks
                associated with foreign ownership;


·
            third
                party performance of obligations under contractual arrangements;
                and


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




-
            7 -
 TABLE
            OF CONTENTS




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 Renewal
      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 Renewal
      Annual Information Form to conform such statements to actual results or to
      changes in the Trust's expectations.




**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 percent limited partnership interest in the limited
      partnerships, Provident Acquisitions L.P. and Provident Marketing L.P. and
      an
      interest in 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 percent interest in the
        partnership. Holdings Trust is the limited partner of Provident Acquisitions
        L.P. with a 99 percent 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.




-
            8 -
 TABLE
            OF CONTENTS


**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 Provident GP
      Inc. which holds a 1 percent interest in the partnership. Holdings Trust and
      PMI
      are the limited partners of Provident Midstream L.P. with a 99 percent total
      interest in the partnership. Provident Midstream L.P. also holds a 98.5 percent
      partnership interest in Empress NGL Partnership, a general partnership formed
      under the laws of Alberta, which in turn holds a 99 percent partnership interest
      in Kinetic Resources LPG, a general partnership formed under the laws of
      Alberta. 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. 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 asset and also holds an interest in Provident
      Midstream L.P. 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 percent
      of
      the outstanding partnership interests in BEC 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. PHC also owns all of the common shares
      of
      PMI. 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. BEC 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
        percent **** of
        the
        outstanding partnership interests in BEC L.P. with the remaining partnership
        interests held by BreitBurn's co-founders and co-chief executive officers.
        The
        head and principal offices of BEC L.P. are located at 515 S. Flower Street,
        Suite 4800, Los Angeles, California. The registered office of BEC L.P. is
        2711
        Centerville Road, Suite 400, Wilmington, Delaware.


-
            9 -
 TABLE
            OF CONTENTS


**BreitBurn
        Energy Partners L.P.**




BreitBurn
      Energy Partners L.P. is a publicly traded Delaware limited partnership formed
      on
      March 23, 2006. BreitBurn MLP is managed by BreitBurn GP LLC, which has a
      board of directors comprised of 3 directors or officers of Provident, as well
      as
      4 independent directors. The Trust, through Pro Holding Company, Pro LP Corp.
      and Pro GP Corp., currently holds approximately 66 percent of the outstanding
      partnership interests in BreitBurn MLP. The head and principal offices of
      BreitBurn MLP are located at 515 S. Flower Street,
      Suite 4800, Los Angeles, California. The registered office of
      BreitBurn MLP is 2711 Centerville Road, Suite 400, Wilmington,
      Delaware.




**INTERCORPORATE
      RELATIONSHIPS**




The
      following diagram of the Trust, Provident and the Trust's material subsidiaries
      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.










-
            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


***8.75
        Percent Debentures***




In
      September 2003, the Trust issued $75.0 million aggregate principal amount of
      convertible unsecured subordinated debentures. The 8.75 Percent Debentures
      mature on December 31, 2008 and bear interest at a rate of 8.75 percent per
      annum, payable semi-annually in arrears on June 30 and December 31 in each
      year.
      The 8.75 Percent 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 Percent Debentures in whole or in part from time to time
      at
      a price of $1,050 per 8.75 Percent Debenture from January 1, 2007 until January
      1, 2008 and at a price of $1,025 per 8.75 Percent Debenture thereafter until
      maturity, in each case plus accrued and unpaid interest. On redemption or
      maturity of the 8.75 Percent 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 Percent Debenture holder. As of March 19, 2007,
      there was $25.7 million aggregate principal amount of 8.75 Percent Debentures
      outstanding.




***8
      Percent Debentures***




In
      July
      2004, the Trust issued 50.0 million aggregate principal amount of convertible
      unsecured subordinated debentures. The 8 Percent Debentures mature on July
      31,
      2009 and bear interest at a rate of 8
      percent
      per annum, payable semi-annually in arrears on July 31 and January 31 in each
      year. The 8 Percent 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 Percent Debentures in whole or in part from time to time at a price of
      $1,050 per 8 Percent Debenture from July 31, 2007 until July 31, 2008 and at
      a
      price of $1,025 per 8 Percent Debenture thereafter until maturity, in each
      case
      plus accrued and unpaid interest. On redemption or maturity of the 8 Percent
      Debentures, the Trust may, subject to regulatory approval, elect to satisfy
      the
      redemption price or principal amount by issuing Trust Units to the 8 Percent
      Debenture holder. As of March 19, 2007, there was $25.1 million aggregate
      principal amount of 8 Percent Debentures outstanding.


***Initial
        6.5 Percent Debentures***
  In
        March
        2005, the Trust issued $100.0 million aggregate principal amount of convertible
        unsecured subordinated debentures. The Initial 6.5 Percent Debentures mature
        on
        August 31, 2012 and bear interest at a rate of 6.5 percent per annum,
        payable semi-annually in arrears on August 31 and February 28 in each
        year. The Initial 6.5 Percent 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 Percent Debentures in whole or in part from
        time to time at a price of $1,050 per Initial 6.5 Percent Debenture from
        August 31, 2008 until August 31, 2009, at a price of $1,025 per
        Initial 6.5 Percent Debenture after August 31, 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 Percent Debenture, in each case plus accrued
        and
        unpaid interest. On redemption or maturity of the Initial 6.5 Percent
        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
        Percent Debenture holder. As of March 19, 2007, there was $99.0 million
        aggregate principal amount of Initial 6.5 Percent Debentures
        outstanding.  -
              12 -
 TABLE
              OF CONTENTS


***Supplemental
        6.5 Percent Debentures***




In
      November 2005, the Trust issued $150.0 million aggregate principal amount of
      convertible unsecured subordinated debentures. The Supplemental 6.5 Percent
      Debentures mature on April 30, 2011 and bear interest at a rate of 6.5
      percent per annum, payable semi-annually in arrears on April 30 and
      October 31 in each year, commencing April 30, 2006. The Supplemental
      6.5 Percent 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 Percent Debentures in whole or in part from time
      to
      time at a price of $1,050 per 6.5 Percent Debenture from October 31, 2008 until
      October 31, 2009, at a price of $1,025 per Supplemental 6.5 Percent 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
      Percent 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 Percent Debenture holder. As of March 19, 2007, there was
      $150.0 million aggregate principal amount of Supplemental 6.5 Percent 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
        percent 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 percent of the Trust
        Units; (b) a quorum of 50 percent 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 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.  -
              13 -
 TABLE
              OF CONTENTS




***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 28, 2007. As of March 19, 2007, there were
      1,631,918 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 percent 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 percent of the monthly cash
      distribution, or (c) purchase new Trust Units under the optional unit purchase
      plan at a subscription price of 100 percent 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.




**Taxation
      of the Trust**




The
      Trust
      is a unit trust and a mutual fund trust for purposes of the Tax Act. As such,
      until the proposals made by the Federal Minister of Finance on October 31,
      2006
      (the "October 31 Proposals") as reflected in the Notice of Ways and Means Motion
      released on March 27, 2007 become law, the Trust is only taxable on any taxable
      income not allocated to Unitholders.




Pursuant
      to the October 31 Proposals, commencing January 1, 2011 (provided the Trust
      only
      experiences "normal growth" and no "undue expansion" before then) certain
      distributions from the Trust which would have otherwise been taxed as ordinary
      income generally will be characterized as dividends in addition to being subject
      to tax at the Trust level at rates of tax comparable to the combined federal
      and
      provincial tax rates. Returns of capital generally are (and under the October
      31
      Proposals will continue to be) tax-deferred for Unitholders who are resident
      in
      Canada for purposes of the Tax Act (and reduce such Unitholder's adjusted cost
      base in the Trust Unit for purposes of the Tax Act). Distributions, whether
      of
      income or capital to a Unitholder who is not resident in Canada for purposes
      of
      the Tax Act, or that is a partnership that is not a "Canadian partnership"
      for
      purposes of the Tax Act, generally will be subject to Canadian withholding
      tax.
      See "Risk Factors - Changes in Legislation".




***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.


-
            14 -
 TABLE
            OF CONTENTS


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.




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 percent 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 percent
      of the trust's property has at any time consisted of "taxable Canadian
      property".


-
          15 -
 TABLE
          OF CONTENTS








***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 percent 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 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.  -
            16 -
 TABLE
            OF CONTENTS




***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.





**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
      670 employees, consultants and contract operators at its head office location
      and in several field offices within the core areas of Lloydminster, Northwest
      Alberta, 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.




-
          17 -
 TABLE
          OF CONTENTS






***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
      certain defined thresholds; (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 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.




***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 2005 - $0.30; in 2004
      and
      2003 - $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 PMI to the Trust by way of interest payments
      and principal repayments on notes issued to the Trust.




-
          18 -
 TABLE
          OF CONTENTS






**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 all limited growth units in Provident Midstream L.P., and a 99 percent
      interest in Provident Marketing L.P. and Provident Acquisitions 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 Resources Corp. PAI is managed by Provident and has 67 percent
      interest in 10101150 Saskatchewan Ltd. and a 0.00001 percent interest in Meota
      (2000) Partnership. 10101150 Saskatchewan Ltd. holds the remaining 99.9999
      percent 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. The Trust receives cash flow generated by
      PMI
      by way of interest and principal payments on debt owing from PMI to the Trust.




**Pro
      Holding Company**




PHC
      owns
      all of the outstanding shares of Pro LP Corp. and Pro GP Corp. which in turn
      own
      approximately **** 96
      percent **** of
      the
      outstanding partnership interests in BEC L.P. and approximately 66 percent
      of
      the outstanding partnership interests of BreitBurn MLP. 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. PHC also owns all of the common shares
      of
      PMI.




**BreitBurn
      Energy Company L.P.**




BEC L.P.
      holds certain of the BEC L.P. Properties acquired pursuant to the BreitBurn
      Acquisition and the Orcutt Hill Properties acquired pursuant to the Orcutt
      Hill
      Acquisition. The Trust currently indirectly holds approximately 96 percent
      of
      the outstanding partnership interests of BEC L.P. with the remaining
      approximately 4 percent **** 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 BEC L.P. is distributed to BEC 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, debt repayments and interest payments on
      intercompany debt.




-
          19 -
 TABLE
          OF CONTENTS






BEC
      L.P.
      continues to operate and report as a business line of the Trust.




**BreitBurn
      Energy Partners L.P.**




The
      assets of BreitBurn MLP consist primarily of crude oil reserves in the Los
      Angeles basin in California and the Wind River and Big Horn basins in central
      Wyoming. BreitBurn MLP also holds the membership interests of Nautilus, which
      holds oil and gas producing properties in the State of Wyoming. BreitBurn MLP
      is
      a publicly traded master limited partnership managed by its general partner,
      BreitBurn GP LLC, whose board of directors consists of 3 directors or officers
      of Provident and 4 independent directors.




The
      Trust
      indirectly holds approximately 66 percent of the outstanding partnership
      interests in BreitBurn MLP. The co-founders and co-chief executive officers
      of
      BEC L.P. hold approximately 3 percent of the partnership interests in BreitBurn
      MLP, with the public holding the remaining 31 percent of the partnership
      interests in BreitBurn MLP. The limited partnership units are listed for trading
      on the NASDAQ.




Cash
      flow
      from the assets held by BreitBurn MLP is distributed to Pro LP Corp. and Pro
      GP
      Corp. and from Pro LP Corp. and Pro GP Corp. to the Trust (via PHC) in the
      form
      of dividends, debt repayments and interest payments.





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




The
      following information describes the development of the business of the Trust
      and
      its material subsidiaries over the last three completed financial
      years.




On
      January 12, 2004, the Trust announced the appointment of Dr. Robert W.
      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 $50.4 million. 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.


-
            20 -
 TABLE
            OF CONTENTS




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 $155.0 million in cash and the assumption of approximately
      $35.0 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 BEC L.P., a Delaware limited partnership. The BreitBurn Acquisition was
      completed on June 15, 2004 and resulted in the Trust indirectly holding 92
      percent of the outstanding partnership interests of BEC L.P. as of that date,
      with the remaining 8 percent of the outstanding partnership interests of BEC
      L.P. retained by BreitBurn's co-founders and co-chief executive officers for
      an
      aggregate purchase price of $13.7 million.




In
      connection with the BreitBurn Acquisition, the Trust completed a public offering
      on July 6, 2004 of 13,100,000 Trust Units and $50.0 million aggregate
      principal amount of 8 Percent Debentures for gross proceeds of $186.2 million.
      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, BEC L.P., entered into a purchase and sale agreement
      with an arm's length third party vendor pursuant to which BEC 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$45.0 million 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
        $125.7 million. 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, BEC L.P., entered into a membership interest purchase and
        sale agreement with all of the holders of membership interests in Nautilus
        pursuant to which BEC L.P. agreed to acquire all membership interests in
        Nautilus for an aggregate purchase price of US$75.0 million, subject to
        adjustment. The Nautilus Acquisition was completed on March 2, 2005.
  In
        connection with the Nautilus Acquisition, the Trust completed a public offering
        on March 1, 2005 of 8,400,000 Trust Units and $100.0 million aggregate
        principal amount of Initial 6.5 Percent Debentures for gross proceeds of
        $200.0
        million. 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 Mr. Hugh A. Fergusson to
        the
        Board of Directors of Provident.
  On
        May
        31, 2005, all outstanding 10.5 percent convertible unsecured subordinated
        debentures of the Trust (the "10.5 Percent 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 Percent Debenture. An aggregate of $3.0 million
        was paid on redemption of the 10.5 Percent Debentures. An aggregate of 3,507,570
        Trust Units were issued upon conversion of the then outstanding 10.5 Percent
        Debentures prior to the redemption of such debentures.  -
              21 -
 TABLE
              OF CONTENTS




On
      June
      28, 2005, the Trust announced that Mr. Daniel J. 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 D. Billing was stepping
      down
      as Chairman of the board of directors of Provident. Mr. John B. 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 was built at Provident's NGL fractionation plant
      at Redwater, Alberta. The existing Redwater plant has been expanded to offload
      and re-deliver an additional 60,000 barrels per day of condensate for EnCana
      Oil
& Gas Partnership and other heavy oil producers. The expansion also included
      a new multi-product truck loading facility. These new terminals complement
      the
      existing pipeline connections to and from the plant and were completed 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
      percent.




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 $773.0 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
        $150.0 million aggregate principal amount of Supplemental 6.5 Percent Debentures
        for gross proceeds of approximately $425.0 million. 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 $750.0 million of lending capacity related to its Canadian assets and
        US$100.0 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 Mr. 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.  -
              22 -
 TABLE
              OF CONTENTS




On
      May
      12, 2006, the Trust announced that BreitBurn MLP filed a Form S-1
      registration statement with the U.S. Securities and Exchange Commission in
      order
      to pursue an initial public offering.




BreitBurn MLP's
      assets consist primarily of producing and non-producing crude oil reserves
      located in the Los Angeles Basin in California and the Wind River and Big Horn
      Basins in Wyoming, which were transferred into BreitBurn MLP from
      BEC L.P. The Los Angeles based management team continues to operate both
      BreitBurn MLP and BEC L.P. The Trust used the net proceeds of U.S.
      $115.2 million from the initial public offering of BreitBurn MLP to pay
      down debt in Canada and the U.S.





Effective
      June 30, 2006, Randall J. Findlay, the President of Provident, retired from
      his
      management responsibilities with Provident. Mr. Findlay remains on the board
      of
      directors of Provident. Thomas W. Buchanan was appointed President of Provident
      following Mr. Findlay's resignation.




On
      July
      11, 2006, Provident entered into a purchase and sale agreement (the "Purchase
      and Sale Agreement"), as well as certain related agreements, with a privately
      owned U.S. based oil and gas company and certain of its affiliates, which
      provided for the acquisition of certain oil and natural gas properties (the
      "Rainbow Assets"), through a series of steps which included the acquisition
      of
      certain partnership interests and the subsequent distribution of the Rainbow
      Assets to Provident out of such partnerships, for a purchase price of
      approximately $473.0 million. The acquisition closed on August 31,
      2006.




The
      Rainbow Assets consist of oil, natural gas and natural gas liquids assets
      located in northwestern Alberta with production weighted approximately 90
      percent natural gas and 10 percent light oil and NGLs, which as at June 1,
      2006
      were producing approximately 33 million cubic feet of gas equivalent per day
      (5,500 barrels of oil equivalent per day), before deduction of royalties owed
      to
      others (comprised of approximately 30.5 million cubic feet per day of natural
      gas and 420 barrels per day of oil and NGLs).




Provident
      has estimated that the Rainbow Assets have approximately 22.2 million barrels
      of
      oil equivalent of proved plus probable reserves effective June 1, 2006.




Included
      in the Rainbow Assets were approximately 126,100 gross (81,139 net) acres of
      undeveloped land at an average 64 percent working interest as well as
      proprietary and licensed seismic (approximately 4,901 kilometres of 2D seismic
      data and 673 square kilometres of 3D seismic data) to assist Provident in
      ongoing identification and evaluation of upside potential associated with the
      Rainbow Assets.




The
      acquisition of the Rainbow Assets was partially funded by the Trust's public
      offering of 16,325,000 subscription receipts at a price of $13.85 per
      subscription receipt for proceeds of $226.1 million, which closed on July 31,
      2006. Upon the closing of the acquisition, holders of subscription receipts
      received one Trust Unit for each subscription receipt held and, as a reduction
      to the purchase price in respect of such subscription receipts, $0.12 per
      subscription receipt held.




On
      October 4, 2007, BreitBurn MLP priced its initial public offering of
      6,900,000 common units at U.S. $18.50 per limited partnership unit and the
      units
      began trading October 4, 2006 on the NASDAQ Global Select Market under the
      ticket symbol "BBEP." The Trust owns approximately 96 percent of the general
      partner of BreitBurn MLP (which holds 2 percent of the partnership
      interests in BreitBurn MLP) and approximately 66 percent of the limited
      partnership units of BreitBurn MLP.




On
      October 31, 2006, the federal Finance Minister announced the October 31
      Proposals to apply a tax at the trust level on distributions of certain income
      from publicly traded mutual fund trusts at rates of tax comparable to the
      combined federal and provincial corporate tax and to treat such distributions
      as
      dividends to the Unitholders. The Finance Minister said existing trusts would
      have a four year transition period and would not be subject to the new rules
      until 2011 (provided the Trust only experiences "normal growth" and no "undue
      expansion" before then). On December 21, 2006, the Finance Minister released
      draft legislation to implement the proposal. See "General Risk Factors - Changes
      in Legislation" for further discussion of the October 31
      Proposals.


-
            23 -
 TABLE
            OF CONTENTS


**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 six 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, which is 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 relatively small maintenance capital
      requirements. 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
        disciplined integrated risk management strategy is employed by Provident,
        focusing on stabilizing cash flow.. To this end, Provident uses both financial
        and physical contracts to reduce the volatility of crude, natural gas and
        NGL
        prices.
  **Risk
        Management**
  Provident
        has a comprehensive Enterprise Risk Management program that is designed to
        identify and manage risks that could negatively affect its business, operations
        or results. The program's activities include risk identification, assessment,
        response, control, monitoring and communication.
  Provident's
        Risk Management group executes the program with oversight from the Risk
        Management Committee ("RMC"), which provides regular reports to the Board
        of
        Directors.
  Provident's
        Risk Management group monitors risk exposure by generating and reviewing
        counterparty credit exposure and mark-to-market reports of its outstanding
        derivative contracts. Provident's monitoring activities also include reviewing
        available hedging structures, regulatory changes and bank, analyst and legal
        reports.
  The
        status of key risk exposures is regularly communicated to Provident's executive
        and business lines. External audiences receive regular risk updates through
        quarterly and annual reports.
  ***Commodity
        Price Risk Management Program***
  The
        decisions to enter into hedge positions and to execute risk management strategy
        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.  -
              24 -
 TABLE
              OF CONTENTS




***Oil
      and Natural Gas Hedging***




Provident's
      hedging program employs derivative instruments, such as puts, participating
      swaps and costless collars, to protect a floor level of Provident's EBITDA
      (earnings before interest, taxes, depletion, depreciation, accretion and other
      non-cash items) on a portion of the oil and gas sold. At the same time, these
      instruments enable Provident to retain various levels of participation to the
      extent oil and gas prices rise. Provident may also use fixed price derivative
      instruments for its oil and natural gas business lines to protect acquisition
      economics.




The
      major
      identified risks for the oil and natural gas business lines (COGP and USOGP)
      are
      commodity price volatility and market location differentials. Provident
      addresses these risks using hedging program designed to protect a portion of
      its
      cash flow in order to support continued unitholder distributions, capital
      programs and bank financing.




During
      2006 for the oil and gas business units, Provident paid **** $5.7
      million ($0.97 per barrel) to settle various crude oil hedge contracts.
      Provident received $7.6 million ($0.25 per gj), to settle various natural gas
      hedge contracts resulting in a combined net gain total of $1.9 million or
      $0.16 per boe.




***Midstream
      Services***




Commodity
      price volatility and market location differentials also affect the Midstream
      business. In addition, Midstream is exposed to possible price declines between
      the time Provident purchases natural gas
      liquid (NGL) feedstock and sells NGL products, and to narrowing frac spreads.
      Frac spread is the margin between the price paid for the natural gas feedstock
      from which Provident extracts NGLs, and the absolute price at which Provident
      sells NGL products (propane, butane and condensate).  Provident
        responds to these risks using a hedging program that protects a margin or
        floor
        level of EBITDA on a portion of its NGL inventory and production, while
        retaining some ability to participate in a widening margin environment. For
        longer-term hedges, Provident hedges crude oil in place of NGLs. Provident
        may
        replace these hedges with actual NGL hedges as market conditions allow. This
        strategy enables Provident to effectively mitigate commodity price risk related
        to its NGL production business up to five years into the future.
  In
        2006,
        Provident paid $15.4 million to settle various midstream hedge contracts.
  ***Foreign
        Currency & Interest Rates***
  Provident
        receives both Canadian and U.S. dollars for oil, natural gas and NGL sales,
        exposing it to both positive and negative effects of fluctuations in the
        exchange rate. Provident manages this exposure by matching a significant
        portion
        of the cash costs that it expects with revenues in the same currency. As
        well,
        Provident uses derivative instruments to manage the U.S. cash requirements
        of
        its U.S. and Canadian business lines. Provident can also manage the associated
        risk of higher interest rates using derivative instruments.
  Provident's
        foreign exchange hedging strategy reduced the effect of the 6 percent
        appreciation of the Canadian dollar relative to the U.S. dollar in 2006.
        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.  -
              25 -
 TABLE
              OF CONTENTS




The
      derivative hedging contracts in place at December 31, 2006 are summarized in
      the
      following tables:




**COGP**


**Volume****Year**
            **Product**
            **(Buy)**
            **Sell**
            **Terms**
            **Effective
                Period**




**2007**
            **Crude
                Oil**
            750
            Bpd
            Participating
                Swap US $60.00 per bbl (62 percent above the floor price)
            January
                1 - December 31750
            Bpd
            Puts
                US $60.00 per bbl
            January
                1 - December 31**Natural
                Gas**
            2,500
            Gjpd
            Participating
                Swap Cdn $6.50 per gj (65 percent above the floor price)
            January
                1 - August 312,000
            Gjpd
            Participating
                Swap Cdn $6.50 per gj (max to 100 percent above the floor
                price)
            January
                1 - August 315,000
            Gjpd
            Participating
                Swap Cdn $7.00 per gj (max to 82 percent above the floor
                price)
            January
                1 - March 311,500
            Gjpd
            Participating
                Swap Cdn $7.00 per gj (max to 80 percent above the floor
                price)
            January
                1 - March 31,
              November
                1 - December 314,000
            Gjpd
            Participating
                Swap Cdn $6.44 per gj (max to 100 percent above the floor
                price)
            April
                1 - August 311,500
            Gjpd
            Participating
                Swap Cdn $6.50 per gj (max to 61 percent above the floor
                price)
            April
                1 - August 313,000
            Gjpd
            Participating
                Swap Cdn $6.33 per gj (max to 100 percent above the floor
                price)
            April
                1 - October 31


3,000
              Gjpd
              Participating
                  Swap Cdn $6.33 per gj (max to 90 percent above the floor
                  price)
              April
                  1 - October 316,000
              Gjpd
              Participating
                  Swap Cdn $6.30 per gj (max to 95 percent above the floor
                  price)
              April
                  1 - October 312,000
              Gjpd
              Participating
                  Swap Cdn $6.13 per gj (max to 68 percent above the floor
                  price)
              April
                  1 - October 311,000
              Gjpd
              Participating
                  Swap Cdn $6.00 per gj (max to 66 percent above the floor
                  price)
              April
                  1 - October 316,500
              Gjpd
              Costless
                  Collar Cdn $6.31 floor, Cdn $12.93 ceiling
              January
                  1 - March 317,500
              Gjpd
              Costless
                  Collar Cdn $6.42 floor, Cdn $9.63 ceiling
              January
                  1 - August 314,000
              Gjpd
              Costless
                  Collar Cdn $6.75 floor, Cdn $8.56 ceiling
              April
                  1 - August 315,000
              Gjpd
              Puts
                  Cdn $6.85 per gj
              January
                  1 - December 312,000
              Gjpd
              Puts
                  Cdn $6.75 per gj
              January
                  1 - March 319,500
              Gjpd
              Puts
                  Cdn $6.89 per gj
              January
                  1 - March 31,
                November
                  1 - December 314,000
              Gjpd
              Puts
                  Cdn $6.75 per gj
              November
                  1 - December 31




**USOGP**


**Volume****Year**
              **Product**
              **(Buy)**
              **Sell**
              **Terms**
              **Effective
                  Period****2007**
              **Crude
                  Oil**
              250
              Bpd
              Puts
                  US $60.00 per bbl
              January
                  1 - December 31250
              Bpd
              Participating
                  Swap US $55.00 per bbl (max to 84 percent above the floor
                  price)
              January
                  1 - December 313,500
              Bpd
              US
                  $67.84 per bbl
              January
                  1 - June 302,650
              Bpd
              US
                  $68.44 per bbl
              July
                  1 - December 31250
              Bpd
              Costless
                  Collar US $66.00 floor, US $69.25 ceiling
              July
                  1 - December 31250
              Bpd
              Costless
                  Collar US $66.00 floor, US $71.50 ceiling
              July
                  1 - December 31**2008**
              **Crude
                  Oil**
              2,650
              Bpd
              US
                  $68.44 per bbl
              January
                  1 - June 30250
              Bpd
              Costless
                  Collar US $66.00 floor, US $69.25 ceiling
              January
                  1 - June 30250
              Bpd
              Costless
                  Collar US $66.00 floor, US $71.50 ceiling
              January
                  1 - June 302,500
              Bpd
              Participating
                  Swap US $60.00 per bbl (max to 53.3 percent above the floor
                  price)
              July
                  1 - September 314,500
              Bpd
              Participating
                  Swap US $60.00 per bbl (avg to 56 percent above the floor
                  price)
              October
                  1 - December 31**2009**
              **Crude
                  Oil**
              500
              Bpd
              Participating
                  Swap US $60.00 per bbl (max to 55.5 percent above the floor
                  price)
              January
                  1 - September 302,000
              Bpd
              Participating
                  Swap US $60.00 per bbl (max to 59 percent above the floor
                  price)
              January
                  1 - September 30




-
            26 -
 TABLE
            OF CONTENTS




**Midstream**




**Volume****Year**
            **Product**
            **(Buy)**
            **Sell**
            **Terms**
            **Effective
                Period**




**2007**
              **Crude
                  Oil**
              250
              Bpd
              Costless
                  Collar US $64.50 floor, US $69.20 ceiling
              January
                  1 - December 312,000
              Bpd
              Costless
                  Collar US $72.43 floor, US $80.29 ceiling
              April
                  1 - December 3110,077
              Bpd
              Cdn
                  $77.02 per bbl
              January
                  1 - December 31(7,643)
              Bpd
              US
                  $64.35 per bbl(4)
              January
                  1 - March 31(1,122)
              Bpd
              Cdn
                  $80.81 per bbl(4)
              January
                  1 - March 31**Natural
                  Gas**
              3,000
              Gjpd
              Cdn
                  $8.28 per gj
              January
                  1 - January 31(1,350)
              Gjpd
              Costless
                  Collar Cdn $8.62 floor, Cdn $9.10 ceiling
              January
                  1 - December 31(3,201)
              Gjpd
              Cdn
                  $7.70 per gj
              January
                  1 - March 31(22,196)
              Gjpd
              Cdn
                  $8.17 per gj
              April
                  1 - December 31
 (48,493)
                Gjpd
                Cdn
                    $8.20 per gj
                January
                    1 - December 31**Propane**
                9,328
                Bpd
                US
                    $0.9841 per gallon(4)
                    (6)
                January
                    1 - March 31806
                Bpd
                US
                    $0.965 per gallon(6) (8)
                January
                    1 - February 281,666
                Bpd
                US
                    $0.9668 per gallon(6) (8)
                January
                    1 - March 31948
                Bpd
                Cdn
                    $1.2081 per gallon(4) (6)
                January
                    1 - March 31**Normal
                    Butane**
                1,808
                Bpd
                US
                    $1.1135 per gallon(4)
                    (7)
                January
                    1 - March 31306
                Bpd
                Cdn
                    $1.3788 per gallon(4) (7)
                January
                    1 - March 31**Foreign
                    Exchange**
                
                
                Sell
                    US $817,163 per month @ 1.1434(5)
                January
                    1 - December 31Sell
                    US $968,486 per month @ 1.1013(5)
                April
                    1 - December 31**2008**
                **Crude
                    Oil**
                2,250
                Bpd
                Costless
                    Collar US $68.50 floor, US $73.72 ceiling
                January
                    1 - December 31500
                Bpd
                Costless
                    Collar US $73.00 floor, US $80.00 ceiling
                January
                    1 - June 30500
                Bpd
                Costless
                    Collar US $64.00 floor, US $74.50 ceiling
                January
                    1 - September 30250
                Bpd
                US
                    $65.60 per bbl
                January
                    1 - December 318,521
                Bpd
                Cdn
                    $76.65 per bbl
                January
                    1 - December 31**Natural
                    Gas**
                (56,824)
                Gjpd
                Cdn
                    $8.34 per gj
                January
                    1 - December 31(13,123)
                Gjpd
                Cdn
                    $8.60 per gj
                January
                    1 - June 30(2,965)
                Gjpd
                Cdn
                    $7.94 per gj
                January
                    1 - September 30(8,760)
                Gjpd
                Cdn
                    $7.94 per gj
                July
                    1 - December 31**Foreign
                    Exchange**
                
                
                Sell
                    US $599,652 per month @ 1.1172(5)
                January
                    1 - December 31Sell
                    US $1,107,166 per month @ 1.1035(5)
                January
                    1 - June 30Sell
                    US $974,222 per month @ 1.1255(5)
                January
                    1 - September 30
  -
              27 -
 TABLE
              OF CONTENTS
 **2009**
                **Crude
                    Oil**
                2,500
                Bpd
                Costless
                    Collar US $65.00 floor, US $69.23 ceiling
                January
                    1 - December 31500
                Bpd
                Costless
                    Collar US $70.00 floor, US $79.00 ceiling
                January
                    1 - June 301,500
                Bpd
                Cdn
                    $81.44 per bbl
                January
                    1 - June 30
 250
                Bpd
                Cdn
                    $77.37 per bbl
                January
                    1 - March 31500
                Bpd
                Cdn
                    $75.10 per bbl
                July
                    1 - December 31250
                Bpd
                Cdn
                    $76.70 per bbl
                July
                    1 - September 30250
                Bpd
                US
                    $64.60 per bbl
                January
                    1 - December 313,374
                Bpd
                Cdn
                    $74.26 per bbl
                January
                    1 - December 31**Natural
                    Gas**
                (35,261)
                Gjpd
                Cdn
                    $8.28 per gj
                January
                    1 - December 31(1,481)
                Gjpd
                Cdn
                    $8.74 per gj
                January
                    1 - March 31(14,714)
                Gjpd
                Cdn
                    $8.32 per gj
                January
                    1 - June 30(1,481)
                Gjpd
                Cdn
                    $7.59 per gj
                July
                    1 - September 30(2,776)
                Gjpd
                Cdn
                    $7.75 per gj
                July
                    1 - December 31**Foreign
                    Exchange**
                
                
                Sell
                    US $522,154 per month @ 1.1093(5)
                January
                    1 - December 31Sell
                    US $1,055,833 per month @ 1.099(5)
                January
                    1 - June 30**2010**
                **Crude
                    Oil**
                1,500
                Bpd
                Costless
                    Collar US $62.90 floor, US $67.48 ceiling
                January
                    1 - December 314,688
                Bpd
                Cdn
                    $72.98 per bbl
                January
                    1 - December 31**Natural
                    Gas**
                (35,273)
                Gjpd
                Cdn
                    $8.03 per gj
                January
                    1 - December 31(1,485)
                Gjpd
                Cdn
                    $7.09 per gj
                April
                    1 - December 31
 **Foreign
                      Exchange**
                  
                  
                  Sell
                      US $472,828 per month @ 1.1078(5)
                  January
                      1 - December 31**2011**
                  **Crude
                      Oil**
                  500
                  Bpd
                  Costless
                      Collar US $65.00 floor, US $75.00 ceiling
                  January
                      1 - June 30250
                  Bpd
                  Costless
                      Collar US $60.00 floor, US $68.10 ceiling
                  July
                      1 - September 30250
                  Bpd
                  Costless
                      Collar US $60.00 floor, US $67.30 ceiling
                  July
                      1 - September 30500
                  Bpd
                  Costless
                      Collar US $56.00 floor, US $75.25 ceiling
                  July
                      1 - September 30500
                  Bpd
                  Costless
                      Collar US $58.00 floor, US $76.20 ceiling
                  July
                      1 - September 30500
                  Bpd
                  Costless
                      Collar US $60.00 floor, US $71.60 ceiling
                  July
                      1 - September 303,250
                  Bpd
                  Cdn
                      $74.26 per bbl
                  January
                      1 - June 30750
                  Bpd
                  Cdn
                      $69.94 per bbl
                  January
                      1 - March 31885
                  Bpd
                  Cdn
                      $70.99 per bbl
                  January
                      1 - September 30250
                  Bpd
                  Cdn
                      $73.35 per bbl
                  January
                      1 - October 31250
                  Bpd
                  Cdn
                      $72.75 per bbl
                  January
                      1 - November 30500
                  Bpd
                  Cdn
                      $73.15 per bbl
                  April
                      1 - June 30**Natural
                      Gas**
                  (2,700)
                  Gjpd
                  Cdn
                      $8.53 per gj
                  January
                      1 - March 31(23,726)
                  Gjpd
                  Cdn
                      $7.46 per gj
                  January
                      1 - June 30(4,955)
                  Gjpd
                  Cdn
                      $7.02 per gj
                  January
                      1 - September 30(1,481)
                  Gjpd
                  Cdn
                      $7.25 per gj
                  January
                      1 - October 31(1,481)
                  Gjpd
                  Cdn
                      $7.24 per gj
                  January
                      1 - November 30(11,859)
                  Gjpd
                  Cdn
                      $6.72 per gj
                  July
                      1 - September 30(2,820)
                  Gjpd
                  Cdn
                      $6.21 per gj
                  April
                      1 - June 30**Foreign
                      Exchange**
                  
                  
                  Sell
                      US $980,417 per month @ 1.0805(5)
                  January
                      1 - June 30Sell
                      US $717,600 per month @ 1.0931(5)
                  July
                      1 - September 30


-
            28 -
 TABLE
            OF CONTENTS


(1)
                      The above table represents a number of transactions entered
                      into over an
                      extended period of time.(2)
                      Natural gas contracts are settled against AECO monthly
                      index(3)
                      Crude Oil contracts are settled against NYMEX WTI calendar
                      average(4)
                      Conversion of crude oil BTU hedges to propane(5)
                      U.S. Dollar hedge contracts settled against Bank of Canada
                      noon rate
                      average(6)
                      Propane contracts are settled against Belvieu C3 TET(7)
                      Normal butane contracts are settled against Belvieu NC4
                      NON-TET(8)
                      Midstream inventory hedges
 
 ***Credit Risk***




Provident's
      Credit Policy governs the activities undertaken to mitigate the risks associated
      with counterparty (customer) nonpayment. The policy sets predetermined credit
      limits, volumes and terms for each counterparty Provident sells to. In addition,
      the policy sets criteria to ensure that Provident has a diversified base of
      creditors. Using this policy, as well as Provident's historical credit
      relationships with its customers, Provident manages its credit exposure.




***Insurance***




Provident
      purchases property insurance, business interruption insurance,
      liability/pollution insurance and well control insurance to manage the risks
      associated with the possibility of poor asset performance. Provident also
      purchases directors & officers insurance.




Like
      other businesses, Provident is subject to government regulations in the
      jurisdictions in which it operates. Provident participates in a range of
      industry and lobby groups including the Canadian Association of Petroleum
      Producers, the Canadian Association of Income Funds, the Coalition of Canadian
      Energy Trusts, the Canadian Energy Infrastructure Group and the Independent
      Petroleum Association of America.




**OIL
      AND NATURAL GAS OPERATIONS**




Provident's
      Canadian reserves were evaluated by McDaniel and AJM effective December 31,
      2006, in accordance with NI 51-101. Provident's U.S. reserves were evaluated
      by
      NSAI effective December 31, 2006 in accordance with NI 51-101. McDaniel, AJM
      and
      NSAI are independent qualified reserves evaluators appointed pursuant to NI
      51-101. The McDaniel evaluation report is dated January 22, 2007 with a
      preparation date of December 31, 2006. The AJM evaluation report is dated
      January 24, 2007 with a preparation date of December 31, 2006 and the NSAI
      evaluation report is dated February 26, 2007 with a preparation date of
      December 31, 2006.




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 from each of McDaniel, AJM
      and NSAI dated January 22, 2007, January 24, 2007 and February 26, 2007,
      respectively and the Report of Management and Directors on Oil and Gas
      Disclosure on Form 51-101F3 dated March 7, 2007 have been filed on
      SEDAR at www.sedar.com and are incorporated by reference in this Renewal Annual
      Information Form.


-
              29 -
 TABLE
              OF CONTENTS


**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 percent
      of NGLs are a by-product of natural gas processing, with 10 percent resulting
      from the refining of crude oil. Approximately 75 percent 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.







**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 percent of propane and 80 percent
        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 percent of the 700 field plants
        in
        western Canada extract NGLs.
 -
              30 -
 TABLE
              OF CONTENTS
   **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 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
      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 significant amount of the NGLs
      transported in Alberta, with pipelines serving as the main mode of transport.
      Provident has the capacity to move NGLs throughout North America via pipeline,
      truck or rail. In addition to its extensive pipeline network, Provident has
      long
      term leases on approximately 800 rail cars.




**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 their consumption (which
      can
      vary from day to day depending on market needs); (ii) allowing NGL
      providers to store inventory to accommodate outages in gas processing and NGL
      fractionation plants; and (iii) exploiting seasonal price differentials
      that may develop over the course of a year (particularly for propane and
      butane).




Large
      NGL
      storage facilities in Canada are located in Sarnia and 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.




**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 percent 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 percent of Canadian
      propane is exported to the US.




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




Pentanes-plus,
      which represents less than 10 percent 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
      these purposes.


-
            31 -
 TABLE
            OF CONTENTS




**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 percent
      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.




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).  -
            32 -
 TABLE
            OF CONTENTS




**Midstream
      services and marketing assets**




***Midstream
      NGL acquisition***




The
      $773.0 million Midstream NGL Acquisition, which closed on December 13, 2005,
      included NGL extraction plants, pipelines, storage and fractionation facilities,
      distribution facilities, and contracts including marketing, supply and
      transportation arrangements, and NGL marketing infrastructure. This acquisition
      extended Provident's involvement in the NGL value chain. Results in 2005
      included NGL fee for service, fixed margin extraction, equity margin on marketed
      NGLs, and margin on crude oil marketing contracts. The crude oil marketing
      contracts were disposed in May 2005, thus 2006 results include an increase
      in
      fees for services, fixed margin extraction and equity margin on marketed
      NGLs.




***The
      Midstream
      business***




The
      Midstream business unit extracts, processes, stores, transports and markets
      natural gas liquids (NGL) for Provident and offers these services to third
      party
      customers. The Provident Midstream segment contains three business lines:




a)
            Empress
                East


b)
            Redwater
                West


c)
            Commercial
                Services




a)  The
      Empress East business line is comprised of the following core
      assets:




·
            Approximately
                2.0 Bcfd of extraction capacity at Empress Alberta. This is the
                combination of 67.5 percent ownership of the 1.2 Bcfd capacity Provident
                Empress NGL Extraction plant, 12.4 percent ownership in the 1.1 Bcfd
                capacity ATCO Plant, 8.3 percent ownership in the 2.4 Bcfd capacity
                Spectra Plant and 33.0 percent ownership in the 2.7 Bcfd capacity
                BP
                Empress 1 Plant.




·
            100
                percent ownership of a 50,000 bpd debutanizer at Empress
                Alberta.




·
            50
                percent ownership in the 130,000 bpd 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 a
                300,000 barrel Superior Storage staging facility and 18.3 percent
                ownership of the 6,600 bpd Superior
                Depropanizer.




·
            In
                Sarnia, Ontario, 10.3 percent ownership of an approximately 150,000
                bpd
                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. An additional 0.5 mmbbls of specification product storage
                is
                also available in the Sarnia area.




·
            A
                propane distribution terminal at Lynchburg,
                Virginia.




The
      income for this business line is primarily driven by the pricing relationship
      of
      natural gas at AECO to NGL values in Belvieu. Provident purchases the NGLs
      from
      suppliers at Empress at gas values and then extracts the NGLs from the gas
      at
      the various straddle plants. Propane, butane and condensate prices trend on
      a
      pricing relationship to crude oil. Provident sells this product and other
      acquired specification product into key market areas such as Ontario, Quebec,
      and the Eastern Seaboard. The higher the ratio of the WTI crude oil price to
      the
      natural gas price at AECO (the fractionation spread ratio "frac spread ratio"),
      the higher the gross operating margin this business line will typically deliver.
      There has also, however, historically been a differential between propane,
      butane and condensate prices and crude oil prices which can change prices
      received and margins realized for Midstream products separate from frac spread
      ratio changes.


-
            33 -
 TABLE
            OF CONTENTS




b)  The
      Redwater West business line is comprised of the following core
      assets:




·
            100
                percent ownership of the Redwater NGL Fractionation Facility,
                incorporating a 65,000 bpd fractionation, storage and transportation
                facility that includes 12 pipeline receipt and delivery points, railcar
                loading facilities with direct access to CN rail and indirect access
                to CP
                rail, two propane truck loading facilities, six million gross barrels
                of
                salt cavern storage, and a 60,000 bpd condensate rail offloading
                facility
                with a 300 railcar storage yard. The facility can process high sulphur
                NGL
                streams and is one of only two ethane-plus fractionation facilities
                in
                western Canada capable of extracting ethane from the natural gas
                liquids
                stream.




·
            Approximately
                7,000 bpd of leased fractionation and storage capacity at other
                facilities.




·
            43.3
                percent direct ownership and 100 percent control of all products
                from the
                38,500 bpd Younger NGL extraction plant located at Taylor in northeastern
                British Columbia. The Younger Plant supplies local markets as well
                as
                Provident's Redwater plant near
                Edmonton.




·
            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
      income for this business line includes the long term natural gas liquids
      purchase agreement from Taylor Gas Liquids for its share of the production
      at
      the same plant. Further, this business line includes the income generated by
      the
      supply and marketing personnel in the Calgary office which includes the
      purchasing of NGL mix from various producers transporting to Redwater/Ft.
      Saskatchewan for fractionation and sale to various markets primarily in Western
      Canada and the Western United States.




c)  The
      Commercial Services business line:




·
            The
                Commercial Services business line includes services such as fractionation,
                storage, and loading at Provident's Redwater facility on a fee basis.
                It
                also includes pipeline tariff income from Provident's ownership of
                the
                Liquids Gathering System in Northwest Alberta which flows into Pembina's
                pipeline from LaGlace to Redwater. Provident also collects tariff
                income
                from its 50 percent ownership in the Kerrobert Pipeline which transports
                NGLs from Empress to Kerrobert for injection into the Enbridge pipeline
                for delivery to Sarnia. Further, Provident owns a debutanizer at
                its
                Empress facility, which removes condensate from the NGL mix for sale
                as a
                diluent to blend with heavy oil. This service is provided to a major
                energy company on a long term cost of service basis. Earnings from
                this
                business line of the Midstream segment have little direct exposure
                to
                market prices volatility and are thus relatively stable.




***Long
      term contracts***




At
      the
      Redwater facility, a significant portion of the available propane plus capacity
      is contracted through a long term fee for service arrangement with third
      parties.


-
            34 -
 TABLE
            OF CONTENTS




In
      2006
      and early 2007, Provident commissioned a 60,000 bpd condensate rail off-loading
      terminal at Redwater, a significant portion of which is under long term
      contracts with two major energy producers.




The
      ethane produced from Provident's facilities at Empress and Redwater is largely
      sold under long term contracts.




Provident
      also has a long term contract on a cost of service basis for the majority of
      its
      50,000 bbl/d Empress debutantizer facility and a long term contract for 500,000
      barrels of specification product storage in the Sarnia area.




**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. 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 Percent Debentures, 8 Percent
      Debentures, Initial 6.5 Percent Debentures and Supplemental 6.5 Percent
      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 New York Stock
      Exchange, as applicable.




**Toronto
      Stock Exchange**




***Trust
      Units***




**Period**
            
            **High
                ($)**
            
            **Low
                ($)**
            
            **Volume
                (000's)****2006**January
            
            13.70
            
            11.79
            
            8,039February
            
            13.08
            
            11.89
            
            6,283March
            
            13.40
            
            12.10
            
            8,791April
            
            13.72
            
            12.87
            
            5,177May
            
            14.31
            
            12.95
            
            13,543June
            
            14.24
            
            12.93
            
            10,485July
            
            14.40
            
            13.25
            
            11,357August
            
            14.50
            
            13.79
            
            19,462September
            
            14.39
            
            12.07
            
            12,179October
            
            13.85
            
            11.62
            
            11,455November
            
            12.88
            
            10.05
            
            15,529December
            
            13.23
            
            12.34
            
            8,098


***8.75
      Percent Debentures***




**Period**
            
            **High
                ($)**
            
            **Low
                ($)**
            
            **Volume****2006**January
            
            120.99
            
            110.67
            
            3,390February
            
            113.62
            
            112.00
            
            1,070March
            
            123.00
            
            110.27
            
            1,940April
            
            123.19
            
            118.56
            
            5,680May
            
            126.94
            
            119.11
            
            12,620June
            
            130.00
            
            118.20
            
            4,350July
            
            129.99
            
            123.34
            
            8,980August
            
            130.25
            
            125.50
            
            3,360September
            
            130.65
            
            110.27
            
            4,630October
            
            123.00
            
            107.27
            
            6,460November
            
            113.27
            
            105.00
            
            4,170December
            
            116.67
            
            110.95
            
            2,590


-
          35 -
 TABLE
          OF CONTENTS






***8
      Percent Debentures***




**Period**
            
            **High
                ($)**
            
            **Low
                ($)**
            
            **Volume****2006**January
            
            116.00
            
            107.00
            
            36,930February
            
            111.20
            
            108.02
            
            3,030March
            
            112.67
            
            108.02
            
            1,665April
            
            113.99
            
            110.84
            
            4,740May
            
            119.00
            
            109.50
            
            45,260June
            
            118.80
            
            109.49
            
            73,440July
            
            119.59
            
            113.50
            
            7,530August
            
            120.04
            
            115.27
            
            49,690September
            
            120.25
            
            105.02
            
            141,870


October
            115.00
            105.02
            28,080November
            108.02
            102.02
            107,520December
            109.87
            106.95
            6,550




***Initial
      6.5 Percent Debentures***




**Period**
            
            **High
                ($)**
            
            **Low
                ($)**
            
            **Volume****2006**January
            
            104.75
            
            100.30
            
            59,430February
            
            104.98
            
            102.00
            
            15,530March
            
            104.98
            
            101.78
            
            13,540April
            
            105.56
            
            103.26
            
            15,410May
            
            106.00
            
            103.06
            
            22,630June
            
            105.50
            
            104.00
            
            48,370July
            
            105.00
            
            103.01
            
            16,100August
            
            105.99
            
            102.60
            
            32,770September
            
            105.95
            
            101.51
            
            30,750October
            
            104.50
            
            100.17
            
            29,580November
            
            101.50
            
            97.00
            
            49,340December
            
            101.25
            
            98.50
            
            18,480


***Supplemental
      6.5 Percent Debentures*** ****




**Period**
            
            **High
                ($)**
            
            **Low
                ($)**
            
            **Volume****2006**January
            
            107.00
            
            100.50
            
            196,691February
            
            103.00
            
            101.75
            
            72,980March
            
            103.49
            
            101.26
            
            61,160April
            
            103.43
            
            101.81
            
            66,690May
            
            103.39
            
            101.31
            
            82,710June
            
            103.09
            
            100.01
            
            43,460July
            
            102.60
            
            101.00
            
            14,720August
            
            103.29
            
            101.51
            
            36,650September
            
            102.99
            
            99.26
            
            21,310October
            
            102.19
            
            99.01
            
            15,860November
            
            99.10
            
            96.01
            
            27,699December
            
            100.97
            
            97.51
            
            36,140


**New
      York Stock Exchange**




***Trust
      Units***




**Period**
            
            **High
                (U.S.$)**
            
            **Low
                (U.S.$)**
            
            **Volume
                (000's)****2006**January
            
            11.66
            
            10.24
            
            14,614February
            
            11.15
            
            10.42
            
            10,985March
            
            11.50
            
            10.52
            
            10,440April
            
            11.99
            
            11.16
            
            9,091May
            
            12.99
            
            11.51
            
            10,940June
            
            12.89
            
            11.77
            
            9,145July
            
            12.70
            
            12.02
            
            14,126August
            
            13.04
            
            12.28
            
            7,398September
            
            11.50
            
            10.82
            
            11,854October
            
            12.16
            
            10.31
            
            9,531November
            
            11.25
            
            9.00
            
            19,099December
            
            11.80
            
            10.59
            
            6,850


-
            36 -
 TABLE
            OF CONTENTS
 **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.






**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
                - December
            
            $
            1.44
            
            $
            1.26**2007**January
            
            $
            0.12
            
            $
            0.10February
            
            $
            0.12
            
            $
            0.10March
            
            $
            0.12
            
            $
            0.10**Total
                to date for 2007**
            
            $
            0.36
            
            $
            0.30





Since
      its
      inception, the Trust has paid an aggregate of $11.31 (U.S.$8.26) in cash
      distributions to Unitholders.




**Note:**


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




**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 percent 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 percent of the monthly cash
      distribution, or (c) purchase new Trust Units under the optional unit purchase
      plan at a subscription price of 100 percent 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. Employees of Provident, including the Named Executive Officers, are
      entitled to participate in the DRIP.


-
            37 -
 TABLE
            OF CONTENTS




The
      Plan
      was implemented in May 2002. The following table provides the details of the
      DRIP since January 2005.


**Premium**
              **Distribution**
            **5
                percent Discounted Unit Price for**
              **Distribution
                Reinvestment Purchase Plans****Payable
                Date**
            **Regular**
              **Distribution**
            **102
                percent of Regular**
              **Distribution****(1)**
            **15
                Day Weighted**
              **Average
                Unit**
              **Price****(2)**
            **5
                percent Discounted**
              **Unit
                Price**15-Mar-07
            $0.12
            $0.1224
            $12.3966
            $11.776815-Feb-07
            $0.12
            $0.1224
            $12.3681
            $11.749713-Jan-07
            $0.12
            $0.1224
            $12.2272
            $11.615815-Dec-06
            $0.12
            $0.1224
            $12.6249
            $11.993715-Nov-06
            $0.12
            $0.1224
            $12.1807
            $11.571714-Oct-06
            $0.12
            $0.1224
            $12.7208
            $12.084815-Sep-06
            $0.12
            $0.1224
            $14.0002
            $13.300215-Aug-06
            $0.12
            $0.1224
            $13.9400
            $13.243015-Jul-06
            $0.12
            $0.1224
            $13.8654
            $13.172115-Jun-06
            $0.12
            $0.1224
            $13.7283
            $13.041913-May-06
            $0.12
            $0.1224
            $13.3193
            $12.653315-Apr-06
            $0.12
            $0.1224
            $13.1042
            $12.449015-Mar-06
            $0.12
            $0.1224
            $12.3241
            $11.707915-Feb-06
            $0.12
            $0.1224
            $12.3995
            $11.779514-Jan-06
            $0.12
            $0.1224
            $12.8715
            $12.227915-Dec-05
            $0.12
            $0.1224
            $13.1321
            $12.475515-Nov-05
            $0.12
            $0.1224
            $12,8775
            $12.233615-Oct-05
            $0.12
            $0.1224
            $14.0544
            $13.351715-Sep-05
            $0.12
            $0.1224
            $13.7481
            $13.060713-Aug-05
            $0.12
            $0.1224
            $13.9564
            $13.258615-Jul-05
            $0.12
            $0.1224
            $13.0940
            $12.439315-Jun-05
            $0.12
            $0.1224
            $12.5551
            $11.927314-May-05
            $0.12
            $0.1224
            $12.3348
            $11.718115-Apr-05
            $0.12
            $0.1224
            $11.9423
            $11.345215-Mar-05
            $0.12
            $0.1224
            $12.3099
            $11.694413-Feb-05
            $0.12
            $0.1224
            $11.9741
            $11.375415-Jan-05
            $0.12
            $0.1224
            $11.4208
            $10.8498


**Notes:**




(1)
            If,
                in respect of any distribution payment date, fulfilling all of the
                elections under the DRIP would result in Provident exceeding either
                the
                limit on new equity set by Provident or the aggregate annual limit
                on new
                Trust Units issuable pursuant to optional cash payments, then elections
                for the purchase of new Trust Units on that distribution payment
                date will
                be accepted: (i) first, from participants electing to reinvest their
                cash
                distributions in new Trust Units under the distribution reinvestment
                component of the DRIP; (ii) second, from participants electing to
                make
                optional cash payments; and (iii) third, from participants electing
                to
                receive the premium distributions. If Provident is not able to accept
                all
                elections in a particular category, then purchases of Trust Units
                in that
                category on the applicable distribution payment date will be prorated
                among all participants in that category according to the number of
                additional Trust Units sought to be purchased. Therefore, amounts
                shown in
                the table represent maximum amounts payable and actual amounts paid
                may be
                less due to proration.


(2)
              This
                  is the price used for purchases made under the
                  DRIP.


Materials
      relating to the DRIP are available on SEDAR at www.sedar.com or the Trust's
      website at www.providentenergy.com or by contacting Provident by phone at
      (403) 296-2233 or by mail at 800, 112 - 4 th Avenue
      S.W., Calgary, Alberta T2P 0H3.


-
              38 -
 TABLE
              OF CONTENTS


**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 below have been engaged for more than five years in their
      present principal occupation or executive position with the same or associated
      companies except as indicated below.
      Each of the directors below will remain in office until the next annual meeting
      of Unitholders scheduled on May 9, 2007.




**Name
                and Background**
            
            **Number
                of Trust Units**
              **Beneficially
                Owned**
              **or
                Controlled****John
                B. Zaozirny**(2)of
                Calgary, Alberta is Chairman of the Board. He also serves as 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, Coastal Energy Company, Computer Modelling
                Group
                Ltd., Candax Inc., Fording Canadian Coal Trust, IPSCO Inc., Pengrowth
                Energy Trust and TerraVest Income Fund.
            
            30,336**G.D.
                Billing**(2)of
                Calgary, Alberta is the Chairman and Chief Executive Officer and
                a
                director of Superior Plus Inc., a diversified trust, 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. and BreitBurn Energy Partners
                LP.
            
            63,364(4)**Thomas
                W. Buchanan**of
                Calgary, Alberta has been the Chief Executive Officer and a director
                of
                Provident since March 2001. Mr. Buchanan has also been the President
                of
                Provident since June 30, 2006. Prior thereto he was Executive Vice
                President Corporate Development and Chief Financial Officer of Founders
                Energy Ltd. from October 1999 to March 2001. He is also a director
                of
                Churchill Energy Inc. and Hawk Energy Corp., Athabasca Oilsands Corp.
                and
                BreitBurn Energy Partners LP.
            
            893,836(4)**Randall
                J. Findlay**(3)of
                DeWinton, Alberta has been a director of Provident since March 2001.
                Mr.
                Findlay was also the President of Provident from March 2001 until
                June 30,
                2006. 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,
                Pembina
                Pipelines Income Fund, Superior Plus Inc., TransAlta Power LP. and
                BreitBurn Energy Partners LP.
            
            767,378**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(4)**Norman
                R. Gish**(2)of
                Calgary, Alberta is a corporate director. Prior thereto, he was the
                President of Gish Consulting Inc., energy consultants and previously
                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 Railpower Technologies Corp.
                and
                Superior Plus Inc.
            
            7,000(4)




-
          39 -
 TABLE
          OF CONTENTS


**Bruce
                R. Libin**(1)(3)of
                Calgary, Alberta is the Executive Chairman and Chief Executive Officer
                of
                Destiny Resource Services Corp., a resource services company, since
                December 2000. 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.
            
            112,686**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., a public oil and gas company. 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.
            
            124,684(4)**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




**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)  Mr.
      Billing also holds $500,000 principal amount of the Initial 6.50 Percent
      Debentures. Mr. Buchanan also holds $100,000 of the Supplemental 6.50 Percent
      Debentures. Mr. Fergusson also holds $100,000 of the Supplemental 6.50 Percent
      Debentures. Mr. Shaikh also holds $250,000 principal amount of the
      Supplemental **** 6.50
      Percent Debentures. Mr. Gish also holds $20,000 principal amount of the 8.75
      Percent Debentures and also holds $110,000 principal amount of the Supplemental
      6.50 Percent Debentures.




***Murray
      N. Buchanan***




Co-President,
      Midstream Business Unit




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.
      Mr.
      Buchanan joined Provident in 2005 following Provident's acquisition of the
      Empress midstream assets and related marketing entity, Kinetic Resources, where
      he held the position of President for eight years. Mr. Buchanan has over 25
      years of NGL marketing and petroleum industry experience.




***Andrew
      G. Gruszecki***




Co-President,
      Midstream Business Unit




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.


-
            40 -
 TABLE
            OF CONTENTS




***David
      I. Holm***




Executive
      Vice President, Finance, Strategy 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 .
      Mr.
      Holm joined Provident in 2006.




**Gary
      R. 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. Mr. Kline 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. 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. Mr. O'Byrne held various executive
      positions with Nexen and its predecessor, Canadian Occidental Petroleum Ltd.
      from 1997 to 2005. He is also a former director of the Petroleum Technology
      Research Centre, a director of Unbridled 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 Association 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
      G. 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.


-
            41 -
 TABLE
            OF CONTENTS


***Mark
        N. Walker***




Senior
      Vice President, Finance and Chief Financial Officer




Mr. Walker
      received his Bachelor of Commerce in Accounting from the University of Calgary
      and later received his Certified Management Accountant designation. Mr. Walker
      began his oil and gas career in 1988 and held positions of increasing
      responsibility prior to joining Founders Energy in 1996 as Controller. Prior
      to
      the appointment to his current position, Mr. Walker was Vice President Finance
      and Chief Financial Officer of Provident since March 2001. Mr. Walker has over
      20 years of experience in petroleum finance and accounting.




**Committees
      of the Board**




During
      the year ended December 31, 2006, 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 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.


-
            42 -
 TABLE
            OF CONTENTS




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, Mr. Hugh A. Fergusson and Randall J. Findlay, all of whom
      are
      considered independent directors, other than Mr. Findlay, 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.




***Disclosure
      Committee***




The
      Disclosure Committee is comprised of the President and Chief Executive Officer,
      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 Vice President,
      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.  -
            43 -
 TABLE
            OF CONTENTS




**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:


**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.





-
            44 -
 TABLE
            OF CONTENTS


**Name**
              **Independent**
              **Financially**
                **Literate**
              **Relevant
                  Education and
                  Experience**


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 and
      its Canadian and U.S. subsidiaries for professional services provided by
      PricewaterhouseCoopers LLP during fiscal 2006 and 2005. PricewaterhouseCoopers
      LLP is independent in accordance with the auditor's rules of professional
      conduct in Canada.




*(CDN$)*
            
            **2006**
            
            **2005**Audit
                Fees
            
            $
            2,000,000
            
            $
            929,000Audit-Related
                Fees
            
            
            1,294,900
            
            
            30,000Tax
                Fees
            
            
            1,226,000
            
            
            776,300All
                Other Fees
            
            
            60,300
            
            
            -Total
            
            $
            4,581,200
            
            $
            1,735,300





***Audit
      Fees***




Fees
      for
      audit services totalled approximately $2.0 million **** in
      2006
      and approximately $929,000 in 2005, including fees associated with the annual
      audit, the reviews of the Trust's quarterly reports, statutory audits and
      regulatory filings. Fees in 2006 have increased as a result of a comprehensive
      audit that incorporates work undertaken by the auditors to assess management
      internal controls under Section 404 of the Sarbanes Oxley Act.


-
            45 -
 TABLE
            OF CONTENTS




***Audit-Related
      Fees***




Fees
      for
      audit-related services totalled approximately $1.3 million in 2006 and
      approximately $30,000 in 2005. Audit related services include consultations
      concerning documents filed with respect to audits in connection with proposed
      or
      successfully transacted acquisitions and for 2006 included work related to
      the
      initial public offering by BreitBurn Energy Partners L.P.




***Tax
      Fees***




Fees
      for
      tax services totalled approximately $1.2 million in 2006 and approximately
      $776,300 in 2005. Fees for tax services include tax compliance, tax planning
      and
      tax advice services.




***All
      Other Fees***




Fees
      for
      all other services totalled approximately $60,300 in 2006 and nil in
      2005.




The
      Trust
      has complied with applicable rules regulating the provision of non-audit
      services to the Trust by its external auditor. All audit and non-audit services
      provided to the Trust by PricewaterhouseCoopers llp in
      excess of $100,000 have been pre-approved by the Audit Committee. The Audit
      Committee has reviewed these services to ensure they are compatible with
      maintaining the independence of the external auditor.




**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.  -
            46 -
 TABLE
            OF CONTENTS




**The
      North American Free Trade Agreement**




On
      January 1, 1994 the North American Free Trade Agreement ("NAFTA") among the
      governments of Canada, the United States and Mexico became effective. NAFTA
      carries forward most of the material energy terms contained in the Canada-U.S.
      Free Trade Agreement. In the context of energy resources, Canada continues
      to
      remain free to determine whether exports to the U.S. or Mexico will be allowed
      provided that the restrictions are otherwise justified under certain provisions
      of the General Agreement on Tariffs and Trade and then only if any export
      restrictions do not: (i) reduce the proportion of the energy resource
      exported relative to the total supply of energy resource (based upon the
      proportions prevailing in the most recent 36 months); (ii) impose an export
      price higher than the domestic price; or (iii) disrupt normal channels of
      supply. All three countries are prohibited from imposing minimum export or
      import price requirements.




NAFTA
      contemplates the reduction of Mexican restrictive trade practices in the energy
      sector and prohibits discriminatory border restrictions and export taxes. The
      agreement also contemplates clearer disciplines on regulators to avoid
      discriminatory actions and to minimize disruption of contractual
      arrangements.




**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 $2.0 million 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 $1.0 million 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.


-
            47 -
 TABLE
            OF CONTENTS




**Environmental
      Regulation**




The
      oil
      and natural gas industry is currently subject to environmental regulations
      pursuant to provincial and federal legislation. Environmental legislation
      provides for restrictions and prohibitions on releases or emissions of various
      substances produced in association with certain oil and gas industry operations.
      In addition, legislation requires that well and facility sites be abandoned
      and
      reclaimed to the satisfaction of provincial
      authorities. A breach of such legislation may result in the imposition of fines
      and penalties, the suspension or revocation of necessary licenses and civil
      liability. Environmental legislation in Alberta has been consolidated into
      the*Environmental
      Protection and Enhancement Act*(Alberta), which took effect on September 1, 1993. The*Environmental Protection and Enhancement Act*(Alberta) imposes stricter environmental standards, requires more stringent
      compliance and reporting and significantly increases penalties for
      non-compliance.  **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:
 -
            48 -
 TABLE
            OF CONTENTS
  **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.  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 term credit facilities of $925.0 million and U.S.$158.0 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.  -
              49 -
 TABLE
              OF CONTENTS




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




***Reserves***




Although
      McDaniel, AJM, NSAI 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.  ***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.  -
              50 -
 TABLE
              OF CONTENTS




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 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.  -
              51 -
 TABLE
              OF CONTENTS




***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.




***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.


-
            52 -
 TABLE
            OF CONTENTS


***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.




***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. 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.


-
              53 -
 TABLE
              OF CONTENTS




**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 percent 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 percent 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;




(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;





-
            54 -
 TABLE
            OF CONTENTS




(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.




***Changes
      in Legislation***




There
      is
      no assurance that Canadian federal income tax laws, including the treatment
      of
      mutual fund trusts thereunder, will not be changed in a manner that affects
      Unitholders in a material adverse way. If the Trust ceases to qualify as a
      "mutual fund trust" under the Tax Act, there are various negative consequences
      as set out above under "Risks Associated With the Level of Foreign
      Ownership".




On
      March
      27, 2007 the Minister of Finance (Canada) released a Notice of Ways and Means
      Motion to implement certain legislation respecting the October 31 Proposals
      relating to the taxation of certain distributions from certain "specified
      investment flow-through" ("SIFT") trusts and SIFT partnerships. The October
      31
      Proposals would impose a tax at the entity level on distributions of certain
      income from SIFT trusts (which would include the Trust) and partnerships at
      a
      rate of tax comparable to the combined federal and provincial corporate tax
      and
      to treat such distributions as dividends to the Unitholder. Existing SIFT trusts
      will have a four-year transition period, and subject to the qualifications
      below, will not be subject to the October 31 Proposals until January 1, 2011.
      Assuming the October 31 Proposals are enacted in their current form, the
      implementation of such legislation would be expected to result in adverse tax
      consequences to the Trust and certain Unitholders, including most particularly
      Unitholders that are tax deferred trusts (such as registered retirement savings
      plans, registered retirement income funds, deferred profit sharing plans and
      registered education savings plans) and non-residents of Canada, and may impact
      cash distributions from the Trust.




Pursuant
      to the October 31 Proposals, commencing January 1, 2011 (provided the Trust
      only
      experiences "normal growth" and no "undue expansion" before then) certain
      distributions from the Trust which would have otherwise been taxed as ordinary
      income generally will be characterized as dividends in addition to being subject
      to tax at corporate rates at the Trust level. Returns of capital generally
      are
      (and under the October 31 Proposals will continue to be) tax-deferred for
      Unitholders who are resident in Canada for purposes of the Tax Act (and reduce
      such Unitholder's adjusted cost base in the Trust Unit for purposes of the
      Tax
      Act). Distributions, whether of income or capital to a Unitholder who is not
      resident in Canada for purposes of the Tax Act, or that is a partnership that
      is
      not a "Canadian partnership" for purposes of the Tax Act, generally will be
      subject to Canadian withholding tax.


-
            55 -
 TABLE
            OF CONTENTS




Management believes that the October 31 Proposals could
      impair
      the value of the Trust Units, which would be expected to increase the cost
      to
      the Trust of raising capital in the public capital markets. In addition,
      management believes that the October 31 Proposals could: (a) reduce the
      competitive advantage that the Trust and other Canadian trusts enjoy relative
      to
      their corporate peers in raising capital in a tax-efficient manner, and (b)
      place the Trust and other Canadian trusts at a competitive disadvantage relative
      to similar industry competitors such as U.S. master limited partnerships. The
      October 31 Proposals may make the Trust Units less attractive as an acquisition
      currency. As a result, it may become more difficult for the Trust to compete
      effectively for acquisition opportunities. There can be no assurance that the
      Trust will be able to reorganize its legal and tax structure to substantially
      mitigate the expected impact of the October 31 Proposals.




The
      proposals provide that there is no intention to inhibit "normal growth" of
      a
      SIFT during the transition period, but "undue expansion" could result in the
      transition period being "revisited" presumably with the loss of the benefit
      to
      the SIFT of that transitional period. As a result, the adverse tax consequences
      associated with the October 31 Proposals could be realized by the Trust sooner
      than January 1, 2011. On December 15, 2006, the Department of Finance (Canada)
      issued guidelines on the meaning of "normal growth" in this context.
      Specifically, the Department of Finance stated that "normal growth" would
      include equity growth within certain "safe harbour" limits, measured by
      reference to a SIFT trust's market capitalization as of the end of trading
      on
      October 31, 2006 (which would include the SIFT's issued and outstanding publicly
      traded trust units and not any convertible debt, options or other interests
      convertible into or exchangeable for trust units). Those safe harbour limits
      are
      40 percent for the period from November 1, 2006 to December 31, 2007, and 20
      percent for each calendar 2008, 2009 and 2010. Moreover, these limits are
      cumulative, so that any unused limit for a period carries over into the
      subsequent period. Additional details of the Department of Finance's guidelines
      include the following:




(a)
            new
                equity for these purposes includes units and debt that is convertible
                into
                units (and may include other substitutes for equity if attempts are
                made
                to develop such substitutes);




(b)
            replacing
                debt that was outstanding as of October 31, 2006 with new equity,
                whether
                by a conversion into trust units of convertible debentures or otherwise,
                will not be considered growth for these purposes and will therefore
                not
                affect the safe harbour limits;




(c)
            the
                exchange for trust units, of exchangeable partnership units or
                exchangeable shares that were outstanding on October 31, 2006 will
                not be
                considered growth for those purposes and will therefore not affect
                the
                safe harbour where the issuance of the trust units is made in satisfaction
                of the exercise of the exchange right by a person other than the
                SIFT;
                and




(d)
            the
                ability to acquire other trusts without impacting normal growth
                rules.




The
      Trust's market capitalization as of the close of trading on October 31, 2006,
      having regard only to its issued and outstanding publicly-traded Trust Units,
      was approximately $2,776 million, which means the Trust's "safe harbour"
      equity growth amount for the period ending December 31, 2007 is approximately
      $1,110 million and for each of calendar 2008, 2009 and 2010 is an additional
      approximately $555 **** million
      (in any case, not including equity issued to replace debt that was outstanding
      on October 31, 2006).




While
      these guidelines are such that it is unlikely they would affect the Trust's
      ability to raise the capital required to maintain and grow its existing
      operations in the ordinary course during the transition period, they could
      adversely affect the cost of raising capital and the Trust's ability to
      undertake more significant acquisitions.




It
      is not
      known at this time when the October 31 Proposals will be enacted by Parliament,
      if at all, or whether the October 31 Proposals will be enacted in the form
      currently proposed.


-
            56 -
 TABLE
            OF CONTENTS




***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.




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.


-
            57 -
 TABLE
            OF CONTENTS




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.




***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.


-
            58 -
 TABLE
            OF CONTENTS




***Availability
      of Credit***


As
        of
        March 15, 2007, the Trust had drawn $638.0 million against the Canadian
        credit facility and had $28.0 million of the Canadian credit facility drawn
        on letters of credit, representing 72 percent of the Canadian credit capacity.
        In addition, as of March 15, 2007, the Trust had drawn US$58.0 million
        against the U.S. credit facility and had US$4.0 million of the U.S. credit
        facility drawn on letters of credit, representing 39 percent 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 percent 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 AJM, 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.


-
            59 -
 TABLE
            OF CONTENTS


**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. 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 - 4thStreet
      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 percent of the issued
      and
      outstanding Trust Units. As at March 19, 2007, **** the
      directors and senior officers of Provident, as a group, beneficially owned,
      directly or indirectly, 2,123,241 Trust Units or approximately 1
      percent **** of
      the
      issued and outstanding Trust Units.




**ADDITIONAL
      INFORMATION**




Additional
      information related to the remuneration of the directors and officers of
      Provident for the year ended December 31, 2006, 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 28, 2007, which relates to the Annual
      Meeting of the Unitholders to be held on May 9, 2007. 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,
      2006.




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






Laurie
                StretchInvestor
                RelationsProvident
                Energy Ltd.800,
                112 - 4thStreet S.W.Calgary,
                Alberta T2P 0H3Telephone:(403)
                296-2233Fax:(403)
                261-6696




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


-
            60 -
 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.


A
            -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;




A
            -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:


A
            -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:




A
            -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 services 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




A
            -6
 TABLE
            OF CONTENTS


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;


(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;




A
            -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.




A
            -8
 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.




A
          -9
 TABLE
          OF CONTENTS


·
            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.




**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.


TABLE
            OF CONTENTS


**Provident
              Energy Trust 2006 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, 2006 compared to the
          quarter
          and year ended December 31, 2005 and should be read in conjunction with
          the
          consolidated financial statements of Provident. This analysis has been
          prepared
          using information available up to March 7, 2007.
  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 (“COGP”), United States crude oil and
          natural gas production (“USOGP”), and midstream services and marketing
          (“Midstream”). Provident’s COGP business produces crude oil and natural gas from
          six core areas in the western Canadian sedimentary basin. USOGP produces
          crude
          oil and natural gas in Southern California and in Wyoming, U.S.A. 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 and Empress
          in
          Alberta, 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:
  ·
                Provident’s
                    ability to benefit from the combination of growth opportunities
                    and the
                    ability to grow through the capital
                    markets;
 ·
                Provident’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;
 ·
                the
                    impact of Canadian governmental regulation on Provident, including
                    the
                    effect of proposed taxation of trust
                    distributions;
 ·
                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; -1-
 TABLE
                OF CONTENTS
  ·
                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 NGL services, processing
                    and
                    marketing business;
 ·
                the
                    growth opportunities associated with the NGL services, processing
                    and
                    marketing business; and
 ·
                the
                    nature of contractual arrangements with third parties in respect
                    of
                    Provident's NGL services, processing and marketing
                    business.
  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:
  ·
                general
                    economic conditions in Canada, the United States and
                    globally;
 ·
                industry
                    conditions associated with the NGL services, processing and marketing
                    business;
 ·
                fluctuations
                    in the price of crude oil, natural gas and natural gas
                    liquids;
 ·
                uncertainties
                    associated with estimating
                    reserves;
 ·
                royalties
                    payable in respect of oil and gas
                    production; ·
                interest payable on notes issued in connection
                  with
                  acquisitions; ·
                income tax legislation relating to income trusts,
                  including the effect of proposed taxation of trust
                  distributions;
 ·
                governmental
                    regulation in North America 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 realize the anticipated benefits of
                  acquisitions; ·
                competition
                  for, among other things, capital reserves, undeveloped lands and
                  skilled
                  personnel; ·
                failure
                    to obtain industry partner and other third party consents and
                    approvals,
                    when required; ·
                risks associated with foreign ownership;
                  and ·
                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**
  **Three
                      months ended December 31,**
                  **Year
                      ended December 31,**Consolidated($
                      000s except per unit data)
                  
                  
                  **2006**
                  
                  2005
                  
                  %
                      Change
                  
                  **2006**
                  
                  2005
                  
                  %
                      ChangeRevenue
                      (net of royalties and financial
                    derivative
                      instruments)
                  
                  
                  
                  **$**
                  **548,086**
                  
                  $
                  442,687
                  
                  
                  24
                  
                  **$**
                  **2,187,253**
                  
                  $
                  1,360,274
                  
                  
                  61Cash
                      flow from COGP operations(1)
                  
                  
                  
                  **$**
                  **48,574**
                  
                  $
                  51,992
                  
                  
                  (7
                  )
                  **$**
                  **185,328**
                  
                  $
                  185,129
                  
                  
                  -Cash
                      flow from USOGP operations(1)
                  
                  
                  
                  
                  **13,573**
                  
                  
                  16,014
                  
                  
                  (15
                  )
                  
                  **62,970**
                  
                  
                  59,821
                  
                  
                  5Cash
                      flow from midstream services
                    and
                      marketing(1)
                  
                  
                  
                  
                  **60,532**
                  
                  
                  28,292
                  
                  
                  114
                  
                  
                  **184,366**
                  
                  
                  66,238
                  
                  
                  178**Total
                      cash flow from operations****(1)**
                  
                  
                  
                  **$**
                  **122,679**
                  
                  $
                  96,298
                  
                  
                  27
                  
                  **$**
                  **432,664**
                  
                  $
                  311,188
                  
                  
                  39Per
                      weighted average unit – basic(2)
                  
                  
                  
                  **$**
                  **0.58**
                  
                  $
                  0.57
                  
                  
                  2
                  
                  **$**
                  **2.20**
                  
                  $
                  1.95
                  
                  
                  13Per
                      weighted average unit – diluted(3)
                  
                  
                  
                  **$**
                  **0.58**
                  
                  $
                  0.51
                  
                  
                  14
                  
                  **$**
                  **2.20**
                  
                  $
                  1.95
                  
                  
                  13Declared
                      distributions to unitholders
                  
                  
                  
                  **$**
                  **75,573**
                  
                  $
                  62,646
                  
                  
                  21
                  
                  **$**
                  **283,465**
                  
                  $
                  230,714
                  
                  
                  23Per
                      unit(2)
                  
                  
                  
                  **$**
                  **0.36**
                  
                  $
                  0.36
                  
                  
                  -
                  
                  **$**
                  **1.44**
                  
                  $
                  1.44
                  
                  
                  -Percent
                      of cash flow from operations paid
                    out
                      as declared distributions
                  
                  
                  
                  
                  **62**
                  **%**
                  
                  65
                  %
                  
                  (5
                  )
                  
                  **66**
                  **%**
                  
                  74
                  %
                  
                  (12
                  )Net
                      (loss) income
                  
                  
                  
                  **$**
                  **(25,501**
                  **)**
                  $
                  54,501
                  
                  
                  -
                  
                  **$**
                  **140,920**
                  
                  $
                  96,926
                  
                  
                  45Per
                      weighted average unit – basic(2)
                  
                  
                  
                  **$**
                  **(0.12**
                  **)**
                  $
                  0.32
                  
                  
                  -
                  
                  **$**
                  **0.72**
                  
                  $
                  0.61
                  
                  
                  18Per
                      weighted average unit – diluted(3)
                  
                  
                  
                  **$**
                  **(0.12**
                  **)**
                  $
                  0.32
                  
                  
                  -
                  
                  **$**
                  **0.72**
                  
                  $
                  0.61
                  
                  
                  18Capital
                      expenditures
                  
                  
                  
                  **$**
                  **60,911**
                  ****
                  $
                  51,011
                  
                  
                  19
                  
                  **$**
                  **190,433**
                  
                  $
                  156,499
                  
                  
                  22Midstream
                      NGL acquisition
                  
                  
                  
                  **$**
                  **(1,264**
                  **)**
                  $
                  772,303
                  
                  
                  -
                  
                  **$**
                  **1,036**
                  
                  $
                  772,303
                  
                  
                  (100
                  )Nautilus
                      acquisition
                  
                  
                  
                  **$**
                  **-**
                  
                  $
                  -
                  
                  
                  -
                  
                  **$**
                  **-**
                  
                  $
                  91,420
                  
                  
                  (100
                  )Property
                      acquisitions
                  
                  
                  
                  **$**
                  **8,649**
                  
                  $
                  1,266
                  
                  
                  583
                  
                  **$**
                  **480,357**
                  
                  $
                  586
                  
                  
                  81,872Property
                      dispositions
                  
                  
                  
                  **$**
                  **(29**
                  **)**
                  $
                  461
                  
                  
                  -
                  
                  **$**
                  **(1,268**
                  **)**
                  $
                  45,100
                  
                  
                  -Weighted
                      average trust units outstanding (000s)-
                      Basic(2)
                  
                  
                  
                  
                  **209,826**
                  
                  
                  169,609
                  
                  
                  24
                  
                  
                  **196,627**
                  
                  
                  159,316
                  
                  
                  23-
                      Diluted(3)
                  
                  
                  
                  
                  **210,113**
                  
                  
                  188,036
                  
                  
                  12
                  
                  
                  **196,914**
                  
                  
                  159,686
                  
                  
                  23
   Consolidated
                  
                  **As
                      at December 31,**($
                      000s)
                  
                  **2006**
                  
                  2005
                  
                  %
                      Change**Capitalization**Long-term
                      debt
                  
                  **$**
                  **988,785**
                  
                  $
                  884,604
                  
                  
                  12Unitholders’
                      equity
                  
                  **$**
                  **1,542,974**
                  
                  $
                  1,404,826
                  
                  
                  10(1)
                      Represents cash flow from operations before changes in working
                      capital and
                      site restoration expenditures.(2)
                      Excludes exchangeable shares.(3)Includes dilutive impact of unit options, exchangeable
                      shares and
                      convertible debentures.
 -3-
 TABLE
                OF CONTENTS
 
 **Operational
          highlights**
  **Three
                      months ended December 31,**
                  
                  **Year
                      Ended December 31,**Consolidated**2006**
                  
                  2005
                  
                  %
                      Change
                  
                  **2006**
                  
                  2005
                  
                  %
                      Change**Oil
                      and Gas Production**Daily
                      productionLight/medium
                      crude oil (bpd)
                  
                  
                  
                  
                  
                  **13,899**
                  
                  
                  14,051
                  
                  
                  (1
                  )
                  
                  **14,114**
                  
                  
                  14,979
                  
                  
                  (6
                  )Heavy
                      oil (bpd)
                  
                  
                  
                  
                  
                  **1,838**
                  
                  
                  3,195
                  
                  
                  (42
                  )
                  
                  **2,057**
                  
                  
                  4,358
                  
                  
                  (53
                  )Natural
                      gas liquids (bpd)
                  
                  
                  
                  
                  
                  **1,345**
                  
                  
                  1,653
                  
                  
                  (19
                  )
                  
                  **1,419**
                  
                  
                  1,596
                  
                  
                  (11
                  )Natural
                      gas (mcfd)
                  
                  
                  
                  
                  
                  **100,029**
                  
                  
                  73,363
                  
                  
                  36
                  
                  
                  **84,891**
                  
                  
                  77,095
                  
                  
                  10Oil
                      equivalent (boed)(1)
                  
                  
                  
                  
                  
                  **33,753**
                  
                  
                  31,126
                  
                  
                  8
                  
                  
                  **31,739**
                  
                  
                  33,782
                  
                  
                  (6
                  )**Average
                      selling price (before realized financial derivative
                      instruments)**Light/medium
                      crude oil ($/bbl)
                  
                  
                  
                  
                  **$**
                  **54.59**
                  
                  $
                  55.31
                  
                  
                  (1
                  )
                  $
                  **60.32**
                  
                  $
                  54.69
                  
                  
                  10Heavy
                      oil ($/bbl)
                  
                  
                  
                  
                  **$**
                  **25.82**
                  
                  $
                  28.62
                  
                  
                  (10
                  )
                  $
                  **36.80**
                  
                  $
                  31.33
                  
                  
                  17Corporate
                      oil blend ($/bbl)
                  
                  
                  
                  
                  **$**
                  **51.23**
                  
                  $
                  50.36
                  
                  
                  2
                  
                  $
                  **57.33**
                  
                  $
                  49.43
                  
                  
                  16Natural
                      gas liquids ($/bbl)
                  
                  
                  
                  
                  **$**
                  **47.49**
                  
                  $
                  49.44
                  
                  
                  (4
                  )
                  $
                  **51.98**
                  
                  $
                  49.09
                  
                  
                  6Natural
                      gas ($/mcf)
                  
                  
                  
                  
                  **$**
                  **6.71**
                  
                  $
                  11.44
                  
                  
                  (41
                  )
                  $
                  **6.66**
                  
                  $
                  8.43
                  
                  
                  (21
                  )Oil
                      equivalent ($/boe)(1)
                  
                  
                  
                  ****
                  **$**
                  **45.65**
                  
                  $
                  57.50
                  
                  
                  (21
                  )
                  $
                  **49.35**
                  
                  $
                  49.86
                  
                  
                  (1
                  )Field
                      netback (before realized financial derivative instruments)
                      ($/boe)
                  ****
                  **$**
                  **23.96**
                  
                  $
                  34.63
                  
                  
                  (31
                  )
                  $
                  **27.93**
                  
                  $
                  29.97
                  
                  
                  (7
                  )Field
                      netback (including realized financial derivative instruments)
                      ($/boe)
                  ****
                  **$**
                  **25.58**
                  
                  $
                  28.33
                  
                  
                  (10
                  )
                  $
                  **28.09**
                  
                  $
                  24.73
                  
                  
                  14**Midstream
                      services and marketing**Managed
                      NGL volumes (bpd)
                  
                  
                  
                  
                  
                  **145,732**
                  
                  
                  77,100
                  
                  
                  89
                  
                  
                  **153,020**
                  
                  
                  64,740
                  
                  
                  136EBITDA
                      (000s)(2)
                  
                  
                  ****
                  ****
                  **$**
                  **74,422**
                  
                  $
                  29,566
                  
                  
                  152
                  
                  $
                  **219,631**
                  
                  $
                  70,689
                  
                  
                  211(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
          2006
          results compared to the fourth quarter of 2005. 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 before changes in working capital and site restoration
          expenditures (“Cash Flow”) and cash distributions**
  Consolidated
                  
                  **Three
                      months ended December 31,**($
                      000s, except per unit data)
                  
                  
                  
                  **2006**
                  
                  2005
                  
                  %
                      Change**Revenue,
                      Cash Flow and Distributions**Revenue
                      (net of royalties and financial derivative instruments)
                  
                  
                  
                  
                  **$**
                  **548,086**
                  
                  $
                  442,687
                  
                  
                  24Cash
                      flow from operations before changes in working capital and
                      site
                      restoration expenditures
                  
                  **$**
                  **122,679**
                  
                  $
                  96,298
                  
                  
                  27Per
                      weighted average unit - basic(1)
                  
                  
                  
                  
                  **$**
                  **0.58**
                  
                  $
                  0.57
                  
                  
                  2Per
                      weighted average unit - diluted(2)
                  
                  
                  
                  
                  **$**
                  **0.58**
                  
                  $
                  0.51
                  
                  
                  14Declared
                      distributions
                  
                  
                  
                  
                  **$**
                  **75,573**
                  
                  $
                  62,646
                  
                  
                  21Per
                      Unit
                  
                  
                  
                  
                  
                  **0.36**
                  
                  
                  0.36
                  
                  
                  -Percent
                      of cash flow distributed
                  
                  
                  
                  
                  
                  **62**
                  **%**
                  
                  65
                  %
                  
                  (5
                  )(1)Excludes exchangeable shares.(2)Includes the dilutive impact of unit options, exchangeable
                      shares
                      and convertible debentures.
 
 Fourth
          quarter 2006 cash flow was $122.7 million, 27 percent above the $96.3 million
          of
          cash flow recorded in the fourth quarter of 2005. COGP 2006 fourth quarter
          cash
          flow was $48.6 million, a seven percent decrease from the $52.0 million
          recorded
          in the comparable 2005 quarter. The main drivers for the COGP decrease
          were the
          lower realized natural gas price due to the decrease in the AECO natural
          gas
          index price, and natural production declines in crude oil and liquids.
          The cash
          flow decrease was partially offset by the addition of the Rainbow assets
          acquired on August 31, 2006 which increased overall production compared
          to the
          2005 fourth quarter, as well as the successful drilling programs in Southwest
          Saskatchewan and activities in West Central and Southern Alberta core areas.
          The
          Rainbow assets represent COGP’s new core area, Northwest Alberta. The Midstream
          business unit added $60.5 million to fourth quarter 2006 cash flow, 114
          percent
          above the $28.3 million recorded in the comparable 2005 quarter. This increase
          is attributable to the Midstream NGL Acquisition in December of 2005 and
          the
          result of increased product margins in fourth quarter 2006 over 2005. Cash
          flow
          from operations in USOGP decreased 15 percent to $13.6 million compared
          to cash
          flow of $16.0 million in the comparable 2005 quarter. Improved netbacks
          were
          more than offset by increases to cash general and administrative expense
          as well
          as higher interest expense.
 
 Declared
          distributions in the fourth quarter of 2006 totaled $75.6 million, 62 percent
          of
          cash flow from operations. This compares to $62.6 million of declared
          distributions in fourth quarter 2005, 65 percent of cash flow from
          operations.
  **Net
          (loss) income**
  Consolidated
                  
                  **Three
                      months ended December 31,**($
                      000s, except per unit data)
                  
                  
                  
                  **2006**
                  
                  2005
                  
                  %
                      ChangeNet
                      (loss) income
                  
                  
                  
                  
                  **$**
                  **(25,501**
                  **)**
                  $
                  54,501
                  
                  
                  -Per
                      weighted average unit
                    –
                      basic(1)
                  
                  
                  
                  
                  **$**
                  **(0.12**
                  **)**
                  $
                  0.32
                  
                  
                  -Per
                      weighted average unit
                    –
                      diluted(2)
                  
                  
                  
                  
                  **$**
                  **(0.12**
                  **)**
                  $
                  0.32
                  
                  
                  -(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.
 -5-
 TABLE
                OF CONTENTS
  Net
          (loss) income for the fourth quarter of 2006 decreased to a loss of $25.5
          million compared to $54.5 million of net income in the comparable 2005
          quarter.
          A 36 percent increase in earnings before interest, taxes, depletion,
          depreciation, accretion and other non-cash items (EBITDA) due to the Midstream
          NGL Acquisition was more than offset by a $56.2 million change in unrealized
          loss on financial derivative instruments and higher depletion, depreciation
          and
          accretion (DD&A) charges as well as higher interest expense, both reflecting
          the larger asset base and increased capitalization due to the Midstream
          NGL
          Acquisition and the Rainbow asset acquisition.
 
 The
          COGP
          business segment had a net loss of $8.2 million compared to 2005 fourth
          quarter
          net income of $34.9 million. The net loss in the fourth quarter of 2006
          was a
          result of a lower EBITDA reflecting the lower realized natural gas price
          due to
          the decrease in the AECO natural gas index price combined with a $24.0
          million
          change in unrealized loss on financial derivative instruments.
 
 The
          Midstream segment recognized a net loss of $11.0 million in the fourth
          quarter
          of 2006, as compared to $24.1 million of net income in the fourth quarter
          of
          2005. Midstream results include EBITDA of $74.4 million in 2006 as compared
          to
          $29.6 million in fourth quarter 2005. This significant improvement in EBITDA
          is
          attributable to the Midstream NGL acquisition completed in December 2005.
          This
          acquisition has extended Provident’s participation in the NGL value chain
          through increased managed volumes. Midstream EBITDA reflects an increase
          in fees
          for services, fixed margin extraction and equity margin on marketed NGLs.
          The
          significant improvement in Midstream EBITDA is also the result of an increase
          in
          propane plus margins in 2006 over 2005. Offsetting this strong EBITDA are
          unrealized losses on outstanding financial derivative instruments amounting
          to
          $28.7 million for the fourth quarter of 2006 (2005 - $0.9 million gain).
          Under
          generally accepted accounting principles, these unrealized “mark-to-market”
amounts, which relate to financial instruments with effective periods ranging
          over the next five years from 2007 through 2011, are required to be recognized
          in the financial statements of Provident, affecting current period net
          income
          (see “Commodity price risk management program”). In addition, higher DD&A
          charges of $16.6 million compared to $4.2 million in 2005, and significantly
          higher interest expense of $9.6 million versus $1.1 million in 2005 are
          the
          result of a larger asset base and increased capitalization due to the Midstream
          NGL Acquisition.
  USOGP
          generated a net loss of $6.3 million in the fourth quarter of 2006 with
          a
          comparative net loss of $4.5 million for 2005. A five percent decrease
          in
          EBITDA, higher DD&A reflecting a fourth quarter adjustment to reserves, and
          higher non-cash unit based compensation were partially offset by a decrease
          in
          future tax expense of $13.9 million in the fourth quarter of 2006, compared
          to
          the fourth quarter of 2005.
  **Reconciliation
          of non-GAAP measure**
 
 The
          Trust
          calculates earnings before interest, taxes, depletion, depreciation, 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:
  Consolidated
                
                **Three
                    months ended December 31,**EBITDA
                    Reconciliation($
                    000s)
                
                
                
                **2006**
                
                2005
                
                %
                    Change**EBITDA**
                
                
                
                
                **$**
                **140,919**
                
                $
                103,542
                
                
                36Adjusted
                    for:Interest
                    and non-cash expenses excluding unrealized (loss) gain on financial
                    derivative instruments
                
                **(116,392**
                **)**
                
                (56,828
                )
                
                105Unrealized
                    (loss) gain on financial derivative instruments
                
                
                
                
                
                **(24,293**
                **)**
                
                31,943
                
                
                -Income
                    before taxes and non-controlling interests
                
                
                **$**
                **234**
                
                $
                78,657
                
                
                (100
                )
 -6-
 TABLE
              OF CONTENTS
   **Taxes**
  Consolidated
                  
                  **Three
                      months ended December 31,**($
                      000s)
                  
                  
                  
                  **2006**
                  
                  2005
                  
                  %
                      ChangeCapital
                      taxes
                  
                  
                  
                  
                  **$**
                  **452**
                  
                  $
                  1,103
                  
                  
                  (59
                  )Current
                      and withholding tax expense (recovery)
                  
                  
                  
                  
                  
                  **1,433**
                  
                  
                  (1,296
                  )
                  
                  -Future
                      income tax expense
                  
                  
                  
                  
                  
                  **21,253**
                  
                  
                  23,327
                  
                  
                  (9
                  )**$**
                  **23,138**
                  
                  $
                  23,134
                  
                  
                  -
  Capital
          taxes in the fourth quarter totaled $0.5  million,
          a decrease of $0.6  million
          from the $1.1 million recorded in the fourth quarter of 2005. 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 expense is $1.4  million
          in the fourth quarter of 2006 with a comparative recovery of $1.3  million
          in the fourth quarter of 2005. These taxes arise from Provident’s U.S. based
          operations and reflect an increase in 2006 income subject to tax, primarily
          in
          U.S. Midstream operations.
  The
          2006
          fourth quarter future tax expense of $21.3  million
          compares to an expense of $23.3  million
          in the fourth quarter of 2005. The future tax expense in the fourth quarter
          of
          2006 resulted from utilizing tax pools in both Canada and the U.S.A., reflecting
          the increased 2006 income subject to tax, primarily in Midstream
          operations.
  **Interest
          expense**
  Consolidated
                  
                  **Three
                      months ended December 31,**($
                      000s)
                  
                  
                  
                  **2006**
                  
                  2005
                  
                  %
                      ChangeInterest
                      on bank debt
                  
                  
                  
                  
                  **$**
                  **11,162**
                  
                  $
                  4,100
                  
                  
                  172Interest
                      on convertible debentures
                  
                  
                  
                  
                  
                  **5,146**
                  
                  
                  3,651
                  
                  
                  41Total
                      cash interest
                  
                  
                  
                  
                  **$**
                  **16,308**
                  
                  $
                  7,751
                  
                  
                  110Non-cash
                      accretion expense - convertible debentures
                  
                  
                  
                  
                  
                  **654**
                  
                  
                  (752
                  )
                  
                  -Total
                      interest including accretion on convertible debentures
                  
                  **$**
                  **16,962**
                  
                  $
                  6,999
                  
                  
                  142
  Cash
          interest expense increased for the quarter as compared to the same quarter
          in
          2005 due to the increase in the overall size of Provident, with commensurate
          increases in debt levels. Increased debt levels are a direct result of
          the
          Midstream NGL acquisition in late 2005 and the third quarter 2006 Rainbow
          asset
          acquisition.
   **Commodity
          price risk management program**
 
 The
          Trust
          continues to execute a commodity price risk management program that is
          designed
          to limit the Trust’s exposure to fluctuations in commodity prices and to protect
          monthly cash distributions and support the Trust’s capital program. Our risk
          management strategy uses structures that provide a floor price while allowing
          upside participation in a rising commodity price market.
 
 In
          accordance with the Trust’s credit policy, the Trust mitigates associated credit
          risk by limiting financial derivative transactions to counterparties within
          approved credit limits.
 
 In
          the Midstream business, production margins are impacted by the spread between
          the purchase cost of natural gas and sales price of propane, butane and
          condensate. Financial market liquidity may not provide sufficient or adequate
          opportunity to directly hedge propane, butane and condensate prices over
          the
          longer term. Prices for propane, butane and condensate historically have
          correlated with prices for crude oil. As a consequence, Provident has entered
          into natural gas and crude oil financial derivative contracts through 2011
          in
          order to protect production margins in the Midstream business. Short term
          financial derivative instruments directly fixing propane and butane prices
          have
          also been executed.  -7-
 TABLE
                OF CONTENTS
  Activity
          in the Fourth Quarter:
 **COGP****Volume****Year**
                  **Product**
                  **(Buy)/Sell**
                  **Terms**
                  **Effective
                      Period**2007
                  Crude
                      Oil
                  750
                  Bpd
                  Participating
                      Swap US $60.00 per bbl (62% above the floor price)
                  January
                      1 - December 31750
                  Bpd
                  Puts
                      US $60.00 per bbl
                  January
                      1 - December 31Natural
                      Gas
                  2,000
                  Gjpd
                  Participating
                      Swap Cdn $7.00 per gj (max to 78% above the floor price)
                  January
                      1 - March 311,500
                  Gjpd
                  Participating
                      Swap Cdn $7.00 per gj (max to 80% above the floor price)
                  January
                      1 - March 31,
                    November
                      1 - December 313,000
                  Gjpd
                  Participating
                      Swap Cdn $6.33 per gj (max to 100% above the floor price)
                  April
                      1 - October 313,000
                  Gjpd
                  Participating
                      Swap Cdn $6.33 per gj (max to 90% above the floor price)
                  April
                      1 - October 316,000
                  Gjpd
                  Participating
                      Swap Cdn $6.30 per gj (max to 95% above the floor price)
                  April
                      1 - October 311,000
                  Gjpd
                  Participating
                      Swap Cdn $6.00 per gj (max to 66% above the floor price)
                  April
                      1 - October 312,000
                  Gjpd
                  Participating
                      Swap Cdn $6.13 per gj (max to 68% above the floor price)
                  April
                      1 - October 315,000
                  Gjpd
                  Puts
                      Cdn $6.85 per gj
                  January
                      1 - December 319,500
                  Gjpd
                  Puts
                      Cdn $6.89 per gj
                  January
                      1 - March 31,
                    November
                      1 - December 314,000
                  Gjpd
                  Puts
                      Cdn $6.75 per gj
                  November
                      1 - December 31
 **USOGP****Volume****Year**
                    **Product**
                    **(Buy)/Sell**
                    **Terms**
                    **Effective
                        Period**2007
                    Crude
                        Oil
                    250
                    Bpd
                    US
                        $60.00 per bbl
                    January
                        1 - December 31250
                    Bpd
                    Participating
                        Swap US $55.00 per bbl (max to 84% above the floor price)
                    January
                        1 - December 312008
                    Crude
                        Oil
                    2,500
                    Bpd
                    Participating
                        Swap US $60.00 per bbl (max to 53.3% above the floor
                        price)
                    July
                        1 - September 312,000
                    Bpd
                    Participating
                        Swap US $60.00 per bbl (avg of 59% above the floor price)
                    October
                        1 - December 312009
                    Crude
                        Oil
                    2,000
                    Bpd
                    Participating
                        Swap US $60.00 per bbl (max to 59% above the floor price)
                    January
                        1 - September 30
 **MIDSTREAM****Volume****Year**
                  **Product**
                  **(Buy)/Sell**
                  **Terms**
                  **Effective
                      Period**2007
                  Crude
                      Oil
                  500
                  Bpd
                  Cdn
                      $74.65 per bbl
                  April
                      1 - December 311,750
                  Bpd
                  Cdn
                      $73.37 per bbl
                  January
                      1 - December 31(6,456)
                  Bpd
                  US
                      $63.76 per bbl(4)
                  January
                      1 - March 31(584)
                  Bpd
                  Cdn
                      $70.91 per bbl(4)
                  January
                      1 - March 31Natural
                      Gas
                  3,000
                  Gjpd
                  Cdn
                      $8.28 per gj
                  January
                      1 - January 31(3,201)
                  Gjpd
                  Cdn
                      $7.70 per gj
                  January
                      1 - March 31(2,869)
                  Gjpd
                  Cdn
                      $7.84 per gj
                  April
                      1 - December 31(9,812)
                  Gjpd
                  Cdn
                      $7.65 per gj
                  January
                      1 - December 31Propane
                  8,143
                  Bpd
                  US
                      $0.9648 per gallon(4) (6)
                  January
                      1 - March 31806
                  Bpd
                  US
                      $0.965 per gallon(6) (8)
                  January
                      1 - February 281,666
                  Bpd
                  US
                      $0.9668 per gallon(6) (8)
                  January
                      1 - March 31Normal
                      Butane
                  746
                  Bpd
                  US
                      $1.1044 per gallon(4) (7)
                  January
                      1 - March 31Foreign
                      Exhange
                  
                  
                  Sell
                      US $912,500 per month @ 1.1491(5)
                  January
                      1 - December 312008
                  Crude
                      Oil
                  500
                  Bpd
                  Costless
                      Collar US $64.00 floor, US $74.50 ceiling
                  January
                      1 - September 30750
                  Bpd
                  Cdn
                      $77.55 per bbl
                  January
                      1 - June 301,045
                  Bpd
                  Cdn
                      $75.31 per bbl
                  July
                      1 - December 311,750
                  Bpd
                  Cdn
                      $75.18 per bbl
                  January
                      1 - December 31Natural
                      Gas
                  (10,000)
                  Gjpd
                  Cdn
                      $7.96 per gj
                  January
                      1 - December 31(4,443)
                  Gjpd
                  Cdn
                      $8.11 per gj
                  January
                      1 - June 30(2,965)
                  Gjpd
                  Cdn
                      $7.94 per gj
                  January
                      1 - September 30(5,808)
                  Gjpd
                  Cdn
                      $7.87 per gj
                  July
                      1 - December 31Foreign
                      Exchange
                  
                  
                  Sell
                      US $974,222 per month @ 1.1255(5)
                  January
                      1 - September 302009
                  Crude
                      Oil
                  250
                  Bpd
                  Cdn
                      $77.37 per bbl
                  January
                      1 - March 31500
                  Bpd
                  Cdn
                      $77.42 per bbl
                  January
                      1 - June 30500
                  Bpd
                  Cdn
                      $75.10 per bbl
                  July
                      1 - December 31250
                  Bpd
                  Cdn
                      $76.70 per bbl
                  July
                      1 - September 30500
                  Bpd
                  Cdn
                      $72.46 per bbl
                  January
                      1 - December 31Natural
                      Gas
                  (2,962)
                  Gjpd
                  Cdn
                      $8.10 per gj
                  January
                      1 - June 30(1,481)
                  Gjpd
                  Cdn
                      $8.74 per gj
                  January
                      1 - March 31(2,700)
                  Gjpd
                  Cdn
                      $7.64 per gj
                  January
                      1 - December 31(1,481)
                  Gjpd
                  Cdn
                      $7.59 per gj
                  July
                      1 - September 30(2,776)
                  Gjpd
                  Cdn
                      $7.75 per gj
                  July
                      1 - December 31
 -8-
 TABLE
                OF CONTENTS
 **MIDSTREAM,
                      continued****Volume****Year**
                  **Product**
                  **(Buy)/Sell**
                  **Terms**
                  **Effective
                      Period**2010
                  Crude
                      Oil
                  500
                  Bpd
                  Cdn
                      $71.07 per bbl
                  January
                      1 - December 31Natural
                      Gas
                  (2,700)
                  Gjpd
                  Cdn
                      $7.35 per gj
                  January
                      1 - December 312011
                  Crude
                      Oil
                  250
                  Bpd
                  Cdn
                      $66.95 per bbl
                  January
                      1 - June 30885
                  Bpd
                  Cdn
                      $70.99 per bbl
                  January
                      1 - September 30250
                  Bpd
                  Cdn
                      $73.35 per bbl
                  January
                      1 - October 31250
                  Bpd
                  Cdn
                      $72.75 per bbl
                  January
                      1 - November 30250
                  Bpd
                  Costless
                      Collar US $60.00 floor, US $68.10 ceiling
                  July
                      1 - September 30250
                  Bpd
                  Costless
                      Collar US $60.00 floor, US $67.30 ceiling
                  July
                      1 - September 30500
                  Bpd
                  Costless
                      Collar US $56.00 floor, US $75.25 ceiling
                  July
                      1 - September 30500
                  Bpd
                  Costless
                      Collar US $58.00 floor, US $76.20 ceiling
                  July
                      1 - September 30500
                  Bpd
                  Costless
                      Collar US $60.00 floor, US $71.60 ceiling
                  July
                      1 - September 30Natural
                      Gas
                  (1,410)
                  Gjpd
                  Cdn
                      $7.12 per gj
                  January
                      1 - June 30(13,269)
                  Gjpd
                  Cdn
                      $6.72 per gj
                  July
                      1 - September 30(4,955)
                  Gjpd
                  Cdn
                      $7.02 per gj
                  January
                      1 - September 30(1,481)
                  Gjpd
                  Cdn
                      $7.25 per gj
                  January
                      1 - October 31(1,481)
                  Gjpd
                  Cdn
                      $7.24 per gj
                  January
                      1 - November 30Foreign
                      Exchange
                  
                  
                  Sell
                      US $717,600 per month @ 1.0931(5)
                  July
                      1 - September 30(1)The above table represents a number of transactions entered
                      into
                      over an extended period of time.(2)
                      Natural gas contracts settle against AECO monthly
                      index.(3)Crude oil contracts settle against NYMEX (New York Mercantile
                      Exchange) WTI (West Texas Intermediate) calendar
                      average.(4)
                      Conversion of Crude Oil BTU (British Thermal Unit) hedges to
                      Propane(5)US dollar hedge contracts settled against Bank of Canada
                      noon rate
                      average.(6)
                      Propane contracts are settled against Belvieu C3 TET (Texas
                      Eastern
                      Transmission)(7)Normal Butane contracts are settled against Belvieu NC4
                      NON-TET(8)Midstream Inventory
                      Hedges
  **Settlement
          of commodity contracts**
 
 The
          following is a summary of the net cash flow to settle Commodity contracts
          during
          the fourth quarter of 2006. For comparative purposes, the 2005 amounts
          are also
          summarized.
 
 **a)
          Crude oil**
 
 For
          the
          quarter ending December 31, 2006, Provident received $1.3 million (2005
          - $16.5
          million paid) to settle various oil market based contracts on an aggregate
          volume of 0.7 million barrels (2005 - 0.6 million barrels). As at December
          31,
          2006 the estimated value of contracts in place if settled at December 31
          market
          prices would have resulted in an opportunity gain of $7.2 million (2005
          - $7.1
          million opportunity cost).
 
 **b)
          Natural Gas**
 
 For
          the
          quarter ending December 31, 2006, Provident received $3.7 million (2005
          - $4.1
          million paid) to settle various natural gas market based contracts on an
          aggregate volume of 3.7 million gj’s (2005 - 1.5 million gj’s). As at December
          31, 2006 the estimated value of contracts in place if settled at December
          31
          market prices would have resulted in an opportunity gain of $8.6 million
          (2005 -
          $6.5 million opportunity cost).
 
 **c)
          Midstream**
 
 For
          the
          quarter ending December 31, 2006 Provident received $5.4 million (2005
          - $1.7
          million paid) on midstream margin hedging activities. As at December 31,
          2006
          the estimated value of contracts in place settled at December 31 market
          prices
          would have resulted in an opportunity cost of $68.8 million (2005 - $0.4
          million). This value represents our five year hedging plan for Midstream
          executed in 2006.
 
 **d)
          Foreign exchange contracts**
 
 As
          at
          December 31, 2006 the estimated value of contracts in place settled at
          December
          31 foreign exchange rates would have resulted in an opportunity gain of
          $0.1
          million (2005 - $0.1 million opportunity cost). The foreign exchange gains
          have
          been included as a component of foreign exchange gain and other and allocated
          to
          their respective business segments.
 
 -9-
 TABLE
                OF CONTENTS
  Provident’s
          Commodity Price Risk Management activities are also discussed in the year
          over
          year section of Management’s Discussion and Analysis and in Note 14 to the
          consolidated financial statements.
  **COGP
          segment review**
 
 **Crude
          oil price and liquids**
  COGP
                  
                  **Three
                      months ended December 31,**($
                      per bbl)
                  
                  
                  
                  **2006**
                  
                  2005
                  
                  %Change**Oil
                      per barrel**WTI
                      (US$)
                  
                  
                  
                  
                  **$**
                  **60.21**
                  
                  $
                  60.02
                  
                  
                  -Exchange
                      rate (from US$ to Cdn$)
                  
                  
                  
                  
                  
                  **1.14**
                  
                  
                  1.17
                  
                  
                  (3
                  )WTI
                      expressed in Cdn$
                  
                  
                  
                  
                  **$**
                  **68.64**
                  
                  $
                  70.22
                  
                  
                  (2
                  )**Realized
                      pricing before financial derivative instruments**Light/Medium
                      oil
                  
                  
                  
                  
                  **$**
                  **51.93**
                  
                  $
                  52.28
                  
                  
                  (1
                  )Heavy
                      oil
                  
                  
                  
                  
                  **$**
                  **25.82**
                  
                  $
                  28.62
                  
                  
                  (10
                  )Natural
                      gas liquids
                  
                  
                  
                  
                  **$**
                  **47.46**
                  
                  $
                  49.62
                  
                  
                  (4
                  )Crude
                      oil and natural gas liquids
                  
                  
                  
                  
                  **$**
                  **46.39**
                  
                  $
                  45.44
                  
                  
                  2
  The
          above
          prices are net of transportation expense.
 
 In
          the
          fourth quarter of 2006 COGP’s realized oil and natural gas liquids price, prior
          to the impact of financial derivative instruments, increased by two percent
          to
          $46.39 per barrel compared to $45.44 per barrel in the fourth quarter of
          2005.
          The 2006 increase in total liquids mix was related to lower conventional
          heavy
          oil volumes as a percentage of the total mix, resulting in a higher proportion
          of production from light/medium oil, which has a higher average price than
          heavy
          oil. This was partially offset by a stronger Canadian dollar and wider
          differentials on heavy oil pricing relative to WTI.
 
 **Natural
          gas price**
  COGP**Three
                      months ended December 31,**($
                      per mcf)
                  
                  
                  
                  **2006**
                  
                  2005
                  
                  %
                      ChangeAECO
                      monthly index (Cdn$) per mcf
                  
                  
                  
                  
                  **$**
                  **6.36**
                  
                  $
                  11.67
                  
                  
                  (46
                  )Corporate
                      natural gas price per mcf before financial derivative instruments
                    (Cdn$)
                  
                  **$**
                  **6.73**
                  
                  $
                  11.40
                  
                  
                  (41
                  )
  The
          above
          prices are net of transportation expense.
 
 COGP’s
          fourth quarter 2006 realized natural gas price, prior to the impact of
          financial
          derivative instruments, decreased 41 percent as compared to the fourth
          quarter
          of 2005, less than the decrease in the benchmark AECO index price of 46
          percent.
          Provident’s gas portfolio includes aggregator contracts sold on a term basis
          that can differ from the benchmark price 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 can therefore differ from
          benchmark indices.
 
 **Production**
 **Three
                      months ended December 31,**COGP**2006**
                  2005
                  %Change**Daily
                      production**Crude
                      oil  - Light/Medium
                      (bpd)
                  **6,569**
                  6,866
                  (4)-
                      Heavy (bpd)
                  **1,838**
                  3,195
                  (42)Natural
                      gas liquids (bpd)
                  **1,331**
                  1,617
                  (18)Natural
                      gas (mcfd)
                  **97,489**
                  71,168
                  37Oil
                      equivalent (boed)(1)
                  **25,986**
                  23,539
                  10(1)
                      Provident reports equivalent production converting natural
                      gas to oil on a
                      6:1 basis.
 
 -10-
 TABLE
                OF CONTENTS
  Production
          increased 10 percent to 25,986 boed during the fourth quarter of 2006 as
          compared to 23,539 boed in 2005. The increase was primarily a result of
          the
          additional production from the Rainbow assets acquired on August 31, 2006
          and
          the successful drilling programs in Southwest Saskatchewan and activities
          in
          West Central and Southern Alberta core areas. Plant restrictions and down
          time
          due to cold weather at Northwest Alberta’s Rainbow and Pouce Coupe fields
          resulted in 550 boed less production than expected in the fourth quarter
          of
          2006. The overall increase in production was partially offset by the natural
          production declines including higher declines in heavy oil partially offset
          by
          drilling and optimization activities. 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 2006 was weighted 63 percent natural gas, 30
          percent
          medium/light crude oil and natural gas liquids and seven percent heavy
          oil. This
          compared to fourth quarter 2005 production weighted 50 percent natural
          gas, 36
          percent medium/light oil and natural gas liquids and 14 percent heavy oil.
          Quarter-over-quarter, the change in mix reflected the Rainbow assets acquired
          on
          August 31, 2006 which was primarily natural gas production, increased capital
          spending on natural gas opportunities and natural production declines in
          the
          heavy oil areas.
 
 COGP’s
          production summarized by core areas is as follows:
  COGP**Three
                      months ended**
                    **December
                      31, 2006**
                  West
                      Central
                    Alberta
                  Southern
                    Alberta
                  Northwest
                    Alberta
                  Southeast
                    Saskatchewan
                  Southwest
                    Saskatchewan
                  Lloydminster
                  Other
                  **Total****Daily
                      production**Crude
                      oil -
                      Light/Medium (bpd)
                  1,051
                  2,172
                  149
                  1,602
                  318
                  1,245
                  32
                  **6,569**-
                      Heavy
                      (bpd)
                  -
                  -
                  -
                  -
                  -
                  1,838
                  -
                  **1,838**Natural
                      gas liquids (bpd)
                  1,111
                  101
                  94
                  -
                  -
                  22
                  3
                  **1,331**Natural
                      gas (mcfd)
                  32,913
                  22,494
                  26,928
                  152
                  13,364
                  1,347
                  291
                  **97,489**Oil
                      equivalent (boed)(1)
                  7,648
                  6,022
                  4,731
                  1,627
                  2,545
                  3,330
                  83
                  **25,986**
 COGP**Three
                      months ended**
                    **December
                      31, 2005**
                  West
                      Central
                    Alberta
                  Southern
                    Alberta
                  Northwest
                    Alberta
                  Southeast
                    Saskatchewan
                  Southwest
                    Saskatchewan
                  Lloydminster
                  Other
                  Total**Daily
                      production**Crude
                      oil - Light/Medium (bpd)
                  1,057
                  2,541
                  -
                  1,726
                  337
                  1,204
                  1
                  6,866-
                      Heavy (bpd)
                  -
                  -
                  -
                  -
                  -
                  3,195
                  -
                  3,195Natural
                      gas liquids (bpd)
                  1,418
                  179
                  -
                  -
                  1
                  19
                  -
                  1,617Natural
                      gas (mcfd)
                  38,343
                  22,722
                  -
                  196
                  8,916
                  978
                  13
                  71,168Oil
                      equivalent (boed)(1)
                  8,865
                  6,507
                  -
                  1,759
                  1,824
                  4,581
                  3
                  23,539(1)Provident reports equivalent production converting natural
                      gas to oil on a
                      6:1 basis.
  Internal
          development activities included 22.0 net wells drilled during the quarter
          ended
          December 31, 2006 with a 100 percent success rate as Provident continues
          with
          the expanded drilling program announced with the second quarter results.
          Provident’s most active area in fourth quarter 2006 was southern Saskatchewan,
          where 12.0 net wells were drilled and focused on the shallow gas drilling
          program. Southern Alberta continued with its shallow gas drilling resulting
          in
          2.1 net wells drilled. Production results to date have been strong in southern
          Alberta and Saskatchewan, exceeding internal expectations. Provident expects
          the
          production from the above net drills to be placed on production during
          the first
          and second quarters of 2007. Northwest Alberta’s activities continued to focus
          on preparation for the winter drilling program and also drilled 5.4 net
          wells in
          2006. Northwest Alberta was ahead of its planned winter drilling schedule
          due to
          effective planning and execution of the drilling program and favourable
          weather
          conditions. In Lloydminster, Provident is working to enhance the area cost
          structure through production optimization and increased water disposal
          capacity.
          In west central Alberta, Provident continues with its strategy of farming
          out
          high risk exploration land to enhance cash flow and drilled 2.3 net wells
          in low
          risk areas. The production in west central Alberta requires relatively
          less
          capital to manage its decline. In the majority of Provident’s operated fields,
          fewer weather-related disruptions were experienced than historically.
 -11-
 TABLE
              OF CONTENTS
   **Revenue
          and royalties**
  COGP
                  
                  **Three
                      months ended December 31,**($
                      000s except per boe and mcf data)
                  
                  
                  
                  **2006**
                  
                  2005
                  
                  %Change**Oil**Revenue
                  
                  
                  
                  
                  **$**
                  **35,754**
                  
                  $
                  41,440
                  
                  
                  (14
                  )Realized
                      loss on financial derivative instruments
                  
                  
                  
                  
                  
                  **(653**
                  **)**
                  
                  (11,651
                  )
                  
                  (94
                  )Royalties
                      (net of ARTC)
                  
                  
                  
                  
                  
                  **(6,651**
                  **)**
                  
                  (8,969
                  )
                  
                  (26
                  )Net
                      revenue
                  
                  
                  
                  
                  **$**
                  **28,450**
                  
                  $
                  20,820
                  
                  
                  37Net
                      revenue (per barrel)
                  
                  
                  
                  
                  **$**
                  **36.78**
                  
                  $
                  22.49
                  
                  
                  64Royalties
                      as a percentage of revenue
                  
                  
                  
                  
                  
                  **18.6**
                  **%**
                  
                  21.6
                  %**Natural
                      gas**Revenue
                  
                  
                  
                  
                  **$**
                  **60,337**
                  
                  $
                  74,623
                  
                  
                  (19
                  )Realized
                      gain (loss) on financial derivative instruments
                  
                  
                  
                  
                  
                  **3,802**
                  
                  
                  (1,521
                  )
                  
                  -Royalties
                      (net of ARTC)
                  
                  
                  
                  
                  
                  **(11,680**
                  **)**
                  
                  (15,503
                  )
                  
                  (25
                  )Net
                      revenue
                  
                  
                  
                  
                  **$**
                  **52,459**
                  
                  $
                  57,599
                  
                  
                  (9
                  )Net
                      revenue (per mcf)
                  
                  
                  
                  
                  **$**
                  **5.85**
                  
                  $
                  8.80
                  
                  
                  (34
                  )Royalties
                      as a percentage of revenue
                  
                  
                  
                  
                  
                  **19.4**
                  **%**
                  
                  20.8
                  %**Natural
                      gas liquids**Revenue
                  
                  
                  
                  
                  **$**
                  **5,811**
                  
                  $
                  7,382
                  
                  
                  (21
                  )Royalties
                  
                  
                  
                  
                  
                  **(1,229**
                  **)**
                  
                  (2,013
                  )
                  
                  (39
                  )Net
                      revenue
                  
                  
                  
                  
                  **$**
                  **4,582**
                  
                  $
                  5,369
                  
                  
                  (15
                  )Net
                      revenue (per barrel)
                  
                  
                  ****
                  ****
                  **$**
                  **37.42**
                  
                  $
                  36.09
                  
                  
                  4Royalties
                      as a percentage of revenue
                  
                  
                  
                  
                  
                  **21.1**
                  **%**
                  
                  27.3
                  %**Total**Revenue
                  
                  
                  
                  
                  **$**
                  **101,902**
                  
                  $
                  123,445
                  
                  
                  (17
                  )Realized
                      gain (loss) on financial derivative instruments
                  
                  
                  
                  
                  
                  **3,149**
                  
                  
                  (13,172
                  )
                  
                  -Royalties
                      (net of ARTC)
                  
                  
                  
                  
                  
                  **(19,560**
                  **)**
                  
                  (26,485
                  )
                  
                  (26
                  )Net
                      revenue
                  
                  
                  
                  
                  **$**
                  **85,491**
                  
                  $
                  83,788
                  
                  
                  2Net
                      revenue per boe
                  
                  
                  ****
                  ****
                  **$**
                  **35.76**
                  
                  $
                  38.69
                  
                  
                  (8
                  )Royalties
                      as a percentage of revenue
                  
                  
                  
                  
                  
                  **19.2**
                  **%**
                  
                  21.5
                  %Note:
                      the above revenue, net revenue and net revenue per boe figures
                      are
                      presented net of transportation
                      expense.
  Quarter
          over quarter, 2006 COGP production revenue was $101.9 million, a decrease
          of 17
          percent from $123.4 million in 2005. The decrease in revenue is a result
          of a 41
          percent decrease in Provident’s realized natural gas price due to the decrease
          in the AECO natural gas index price offset by higher overall production
          resulting from the addition of the Rainbow assets acquired on August 31,
          2006.
          Total royalties as a percentage of revenue decreased to 19.2 percent primarily
          due to a reduction in rates from capital spending incentives. The preceding
          factors, as well as the change in realized gain of financial derivative
          instruments account for net revenue of $85.5 million in the fourth quarter
          of
          2006, two percent above the $83.8 million recorded in the fourth quarter
          of
          2005. Net revenue per boe in the fourth quarter of 2006 was $35.76 per
          boe, a
          decrease of eight percent from $38.69 per boe in the fourth quarter of
          2005. The
          per boe decrease was a result of the preceding factors.
 
 **Production
          expenses**
  COGP
                  
                  **Three
                      months ended December 31,**($
                      000s, except per boe data)
                  
                  
                  
                  **2006**
                  
                  2005
                  
                  %
                      ChangeProduction
                      expenses
                  
                  
                  
                  
                  **$**
                  **28,302**
                  
                  $
                  23,437
                  
                  
                  21Production
                      expenses (per boe)
                  
                  
                  
                  
                  **$**
                  **11.84**
                  
                  $
                  10.82
                  
                  
                  9
 
 Fourth
          quarter 2006 production expenses increased 21 percent to $28.3 million
          from
          $23.4 million in the comparable 2005 quarter due to increased production
          volumes
          primarily as a result of the Rainbow acquisition. However, on a boe basis
          quarter over quarter production expenses have increased by nine percent
          to
          $11.84 per boe from $10.82 per boe in the comparable 2005 quarter. Cost
          increases included higher than expected costs for  -12-
 TABLE
                OF CONTENTS
  electricity
          and adjustments related to prior periods by operators on non-operated
          properties. In addition, costs have increased in fuel, chemicals, well
          servicing, maintenance and fluid hauling to reflect higher commodities
          prices
          and labour costs.
 
 **Operating
          netback**
 COGP
                  
                  **Three
                      months ended December 31,**($
                      per boe)
                  
                  
                  
                  **2006**
                  
                  2005
                  
                  %
                      Change**Netback
                      per boe**Gross
                      production revenue
                  
                  
                  
                  
                  **$**
                  **42.62**
                  
                  $
                  57.00
                  
                  
                  (25
                  )Royalties
                      (net of ARTC)
                  
                  
                  
                  
                  
                  **(8.18**
                  **)**
                  
                  (12.23
                  )
                  
                  (33
                  )Operating
                      costs
                  
                  
                  
                  
                  
                  **(11.84**
                  **)**
                  
                  (10.82
                  )
                  
                  9Field
                      operating netback
                  
                  
                  
                  
                  **$**
                  **22.60**
                  
                  $
                  33.95
                  
                  
                  (33
                  )Realized
                      gain (loss) on financial derivative instruments
                  
                  
                  
                  
                  
                  **1.32**
                  
                  
                  (6.08
                  )
                  
                  -Operating
                      netback after realized financial derivative instruments
                  
                  
                  
                  
                  **$**
                  **23.92**
                  
                  $
                  27.87
                  
                  
                  (14
                  )
 
 COGP
          operating netbacks have transportation expense netted against gross production
          revenue.
  The
          fourth quarter 2006 field operating netback of $22.60 per boe was 33 percent
          below the $33.95 per boe in the comparable quarter in 2005. The field operating
          netback reflects COGP’s lower realized price for natural gas and increased
          operating costs combined with a shift in COGP’s production mix to include more
          natural gas. Royalties, which are price sensitive, decreased by 33 percent
          on a
          boe basis reflecting the lower prices, prior to the impact of hedging.
          The
          fourth quarter 2006 operating netback after financial derivative instruments
          decreased by 14 percent to $23.92 from $27.87 reflecting the preceding
          factors
          as well as the 2006 fourth quarter gains on financial derivative instruments
          of
          $1.32 per boe compared to a loss of $6.08 per boe in the comparable quarter
          in
          2005.
 
 **General
          and administrative**
  COGP
                  
                  **Three
                      months ended December 31,**($
                      000s, except per boe data)
                  
                  
                  
                  **2006**
                  
                  2005
                  
                  %
                      ChangeCash
                      general and administrative
                  
                  
                  
                  
                  **$**
                  **6,410**
                  
                  $
                  3,727
                  
                  
                  72Non-cash
                      unit based compensation
                  
                  
                  
                  
                  
                  **1,182**
                  
                  
                  1,885
                  
                  
                  (37
                  )**$**
                  **7,592**
                  
                  $
                  5,612
                  
                  
                  35Cash
                      general and administrative (per boe)
                  
                  
                  
                  
                  **$**
                  **2.68**
                  
                  $
                  1.72
                  
                  
                  56
 
 Cash
          general and administrative expenses for COGP in the fourth quarter increased
          72
          percent to $6.4 million from $3.7 million recorded in the 2005 comparable
          quarter. On a boe basis the cash general and administrative expenses recorded
          in
          fourth quarter 2006 increased 56 percent to $2.68 from $1.72 in the fourth
          quarter of 2005. The increase in cash 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, including
          costs
          relating to implementation of procedures and documentation in connection
          with
          the U.S. Sarbanes-Oxley Act.
 
 COGP
          operations are capable of absorbing additional production, particularly
          in
          existing core areas, with little impact on cash general and administrative
          expenses.
 -13-
 TABLE
              OF CONTENTS
   **Capital
          expenditures**
  COGP
                  **Three
                      months ended December 31,**($
                      000s)
                  
                  
                  **2006**
                  
                  2005**Capital
                      expenditures - by area**West
                      central Alberta
                  
                  
                  
                  **$**
                  **3,968**
                  
                  $
                  2,282Southern
                      Alberta
                  
                  
                  
                  
                  **3,000**
                  
                  
                  4,977Northwest
                      Alberta
                  
                  
                  
                  
                  **4,598**
                  
                  
                  -Southeast
                      Saskatchewan
                  
                  
                  
                  
                  **384**
                  
                  
                  1,006Southwest
                      Saskatchewan
                  
                  
                  
                  
                  **4,006**
                  
                  
                  10,925Lloydminster
                  
                  
                  
                  
                  **1,738**
                  
                  
                  2,497Office
                      and other
                  
                  
                  
                  
                  **581**
                  
                  
                  (13
                  )Total
                      additions
                  
                  
                  
                  **$**
                  **18,275**
                  
                  $
                  21,674**Capital
                      expenditures - by category**Geological,
                      geophysical and land
                  
                  
                  
                  **$**
                  1,067
                  
                  $
                  141Drilling,
                      recompletions, and workovers
                  
                  
                  
                  
                  **14,988**
                  
                  
                  12,006Facilities
                      and equipment
                  
                  
                  
                  
                  **1,365**
                  
                  
                  9,449Other
                      capital
                  
                  
                  
                  
                  **855**
                  
                  
                  78Total
                      additions
                  
                  
                  
                  **$**
                  **18,275**
                  
                  $
                  21,674Property
                      acquisitions
                  
                  
                  
                  **$**
                  **8,649**
                  
                  $
                  1,266Property
                      dispositions
                  
                  
                  
                  **$**
                  **(29**
                  **)**
                  $
                  461
 
 In
          the
          fourth quarter of 2006, Provident’s COGP business unit spent $18.3 million on
          capital expenditures. COGP spent $4.6 million in the new area, Northwest
          Alberta, primarily on drilling activities associated with the winter drilling
          program which was ahead of schedule due to favourable weather conditions
          and
          advanced planning. In the Southeast and Southwest Saskatchewan core areas
          $4.4
          million was spent primarily on shallow gas drilling. Facility work ($0.3
          million) in the area focused on infrastructure to tie-in future shallow
          gas
          production in Southwest Saskatchewan. In Southern Alberta $3.0 million
          was spent
          on drilling activities and recompletions ($2.3 million) and mineral rights
          acquisitions ($0.6 million). In West central Alberta $4.0 million was spent
          largely on non-operated drilling ($2.6 million) and facility work ($0.8
          million). In the Lloydminster core area $1.7 million was spent primarily
          on
          drilling and recompletion activities.
  In
          the
          fourth quarter of 2006, COGP also spent $8.6 million on property acquisitions
          primarily on acquiring additional working interests in Northwest Alberta
          ($6.7
          million) and in Southern Alberta ($1.7 million).
 
 Provident’s
          COGP business unit spent $21.7 million in the fourth quarter of 2005 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)
                  
                  
                  **2006**
                  
                  2005
                  
                  %
                      ChangeDD&A
                  
                  
                  
                  **$**
                  **58,617**
                  
                  $
                  33,809
                  
                  
                  73DD&A
                      (per boe)
                  
                  
                  
                  **$**
                  **24.52**
                  
                  $
                  15.61
                  
                  
                  57
  The
          COGP
          DD&A rate of $24.52 per boe for the fourth quarter of 2006 increased by 57
          percent compared to $15.61 per boe for the fourth quarter of 2005. The
          increase
          was primarily as a result of the Rainbow asset acquisition. Additions to
          property, plant and equipment of $660.4 million for the acquisition include
          $185.7 million due to the recording of future income taxes. This, combined
          with
          higher net per boe reserve acquisition costs, resulted in increased per
          boe
          DD&A.
 
 Accretion
          expense associated with asset retirement obligations was $0.5 million in
          the
          fourth quarter of 2006 compared to $0.5 million in the fourth quarter of
          2005.
 -14-
 TABLE
                OF CONTENTS
  **USOGP
          Segment Review**
 
 The
          USOGP
          business unit incorporates activities from certain Provident subsidiaries
          comprising an oil and gas exploitation and production organization based
          in Los
          Angeles, California.
 
 In
          the
          fourth quarter of 2006, Provident, through its USOGP subsidiaries, completed
          its
          initial public offering (“IPO”) of 6.9 million units at U.S. $18.50 per unit of
          BreitBurn Energy Partners, L.P. (the “MLP”). This master limited partnership
          (NASDAQ-BBEP) is a U.S. public, tax flow-through entity similar to Canadian
          royalty and income trusts such as Provident. Selected producing assets
          in the
          Los Angeles basin in California and in Wyoming were transferred to the
          MLP. The
          MLP operates approximately two-thirds of existing USOGP production and
          approximately one-half of USOGP reserves. The previously existing subsidiary
          (“BreitBurn”) continues to operate some Los Angeles basin assets at West Pico
          and the Orcutt field (which is the site of the steam-assisted diatomite
          pilot
          project). At December 31, 2006 the Trust indirectly owns approximately
          66
          percent of the MLP and 96 percent of BreitBurn. The MLP and BreitBurn continue
          to be managed by the management team which operated the USOGP business
          unit
          prior to the IPO. The USOGP segment includes the consolidated results of
          the MLP
          and BreitBurn. Non-controlling interests include the public ownership in
          the
          MLP, the ownership interests of the managers in the MLP and BreitBurn,
          as well
          as third party investment in USOGP’s land development project which commenced in
          the second quarter of 2006.
 
 **USOGP
          Pricing**
  **Three
                      month ended December 31,**USOGP
                  
                  
                  
                  **2006**
                  
                  2005
                  
                  %
                      Change**Realized
                      pricing before financial derivative instruments**Light/medium
                      crude oil and natural gas liquids (Cdn$ per bbl)
                  
                  
                  
                  
                  **$**
                  **56.96**
                  
                  $
                  58.11
                  
                  
                  (2
                  )Natural
                      gas (Cdn$ per mcf)
                  
                  
                  
                  
                  **$**
                  **5.87**
                  
                  $
                  12.97
                  
                  
                  (55
                  )
 
 The
          majority of USOGP oil production is light, sweet crude that attracts smaller
          differentials to benchmark prices relative to heavier blends. Realized
          crude oil
          and natural gas liquids pricing before financial derivative instruments
          in the
          fourth quarter of 2006 was comparable with the fourth quarter of 2005.
          WTI in
          the fourth quarter of 2006 was U.S. $60.21 compared to U.S. $60.02 in the
          fourth
          quarter of 2005. Oil production from the Wyoming properties is a heavier
          blend
          of crude oil that attracts wider differentials from WTI pricing. Production
          from
          Wyoming properties represents approximately 32 percent of fourth quarter
          2006
          production.
 
 Realized
          natural gas pricing saw a 55 percent decrease to $5.87 per mcf in the fourth
          quarter of 2006 when compared to the fourth quarter of 2005. Natural gas
          represents approximately five percent of total boe production of
          USOGP.
 
 **Production**
 **Three
                        months ended December 31,**USOGP
                    
                    **2006**
                    
                    2005
                    
                    %
                        Change**Daily
                        production - by product**Crude
                        oil - Light/Medium (bpd)
                    
                    
                    
                    **7,330**
                    
                    
                    7,185
                    
                    
                    2Natural
                        gas liquids (bpd)
                    
                    
                    
                    **14**
                    
                    
                    36
                    
                    
                    (61
                    )Natural
                        gas (mcfd)
                    
                    
                    
                    **2,540**
                    
                    
                    2,195
                    
                    
                    16Oil
                        equivalent (boed)(1)
                    
                    
                    
                    **7,767**
                    
                    
                    7,587
                    
                    
                    2(1)
                        Provident reports equivalent production converting natural
                        gas to oil on a
                        6:1 basis.
 **Three
                      months ended December 31,**USOGP
                  
                  **2006**
                  
                  2005
                  
                  %
                      Change**Daily
                      Production - by area (boed)****(1)**Los
                      Angeles
                  
                  
                  
                  **3,772**
                  
                  
                  3,974
                  
                  
                  (5
                  )Santa
                      Maria - Orcutt
                  
                  
                  
                  **1,528**
                  
                  
                  1,356
                  
                  
                  13Wyoming
                  
                  
                  
                  **2,467**
                  
                  
                  2,257
                  
                  
                  9**7,767**
                  
                  
                  7,587
                  
                  
                  2(1)
                      Provident reports equivalent production converting natural
                      gas to oil on a
                      6:1 basis.
 -15-
 TABLE
                OF CONTENTS
  USOGP
          production increased 180 boe per day or two percent in the fourth quarter
          of
          2006 when compared to the fourth quarter of 2005. The increase is primarily
          attributable to successful optimization and drilling projects partially
          offset
          by the low natural declines that reflect the long life nature of these
          assets.
 
 **Revenue
          and royalties**
 
 The
          following table outlines USOGP revenue and royalties by product line. The
          table
          excludes revenues earned from operating certain properties ($0.2 million
          in 2006
          and $0.3 million in 2005) on behalf of third parties.
  USOGP
                  
                  **Three
                      months ended December 31,**($
                      000s, except per boe and mcf amounts)
                  
                  
                  
                  **2006**
                  
                  2005
                  
                  %
                      Change**Oil**Revenue
                  
                  
                  
                  
                  **$**
                  **38,546**
                  
                  $
                  38,583
                  
                  
                  -Realized
                      gain (loss) on financial derivative instruments
                  
                  
                  
                  
                  
                  **1,892**
                  
                  
                  (4,875
                  )
                  
                  -Royalties
                  
                  
                  
                  
                  
                  **(3,771**
                  **)**
                  
                  (3,703
                  )
                  
                  2Net
                      revenue
                  
                  
                  
                  
                  **$**
                  **36,667**
                  
                  $
                  30,005
                  
                  
                  22Net
                      revenue (per bbl)
                  
                  
                  
                  
                  **$**
                  **54.37**
                  
                  $
                  45.39
                  
                  
                  20Royalties
                      as a percentage of revenue
                  
                  
                  
                  
                  
                  **9.8**
                  **%**
                  
                  9.6
                  %**Natural
                      gas**Revenue
                  
                  
                  
                  
                  **$**
                  **1,373**
                  
                  $
                  2,620
                  
                  
                  (48
                  )Royalties
                  
                  
                  
                  
                  
                  **(184**
                  **)**
                  
                  (370
                  )
                  
                  (50
                  )Net
                      revenue
                  
                  
                  
                  
                  **$**
                  **1,189**
                  
                  $
                  2,250
                  
                  
                  (47
                  )Net
                      revenue (per mcf)
                  
                  
                  
                  
                  **$**
                  **5.09**
                  
                  $
                  11.14
                  
                  
                  (54
                  )Royalties
                      as a percentage of revenue
                  
                  
                  
                  
                  
                  **13.4**
                  **%**
                  
                  14.1
                  %**Natural
                      gas liquids**Revenue
                  
                  
                  
                  
                  **$**
                  **64**
                  
                  $
                  135
                  
                  
                  (53
                  )Royalties
                  
                  
                  
                  
                  
                  **(2**
                  **)**
                  
                  (3
                  )
                  
                  (33
                  )Net
                      revenue
                  
                  
                  
                  
                  **$**
                  **62**
                  
                  $
                  132
                  
                  
                  (53
                  )Net
                      revenue (per bbl)
                  
                  
                  
                  
                  **$**
                  **48.14**
                  
                  $
                  40.06
                  
                  
                  20Royalties
                      as a percentage of revenue
                  
                  
                  
                  
                  
                  **3.1**
                  **%**
                  
                  2.1
                  %**Total**Revenue
                  
                  
                  
                  
                  **$**
                  **39,983**
                  
                  $
                  41,338
                  
                  
                  (3
                  )Realized
                      gain (loss) on financial derivative instruments
                  
                  
                  
                  
                  
                  **1,892**
                  
                  
                  (4,875
                  )
                  
                  -Royalties
                  
                  
                  
                  
                  
                  **(3,957**
                  **)**
                  
                  (4,076
                  )
                  
                  (3
                  )Net
                      revenue
                  
                  
                  
                  
                  **$**
                  **37,918**
                  
                  $
                  32,387
                  
                  
                  17Net
                      revenue (per boe)
                  
                  
                  
                  
                  **$**
                  **53.06**
                  
                  $
                  46.40
                  
                  
                  14Royalties
                      as a percentage of revenue
                  
                  
                  
                  
                  
                  **9.9**
                  **%**
                  
                  9.9
                  %
 
 Total
          production revenue for the fourth quarter of 2006 was $40.0 million or
          three
          percent lower than the $41.3 million of revenue in the fourth quarter of
          2005.
          The decrease was primarily driven by lower realized natural gas prices
          in the
          fourth quarter of 2006 when compared to the fourth quarter of 2005. Total
          net
          revenue increased $5.5 million or 17 percent in the fourth quarter of 2006
          compared to the fourth quarter of 2005 primarily driven by a $6.8 million
          positive change in realized gains on financial derivative
          instruments.
 
 **Production
          expenses**
 USOGP
                  **Three
                      months ended December 31,**($
                      000s, except per boe amounts)
                  
                  
                  **2006**
                  
                  2005
                  
                  %
                      ChangeProduction
                      expenses
                  
                  
                  
                  **$**
                  **15,534**
                  
                  $
                  11,510
                  
                  
                  35Production
                      expenses (per boe)
                  
                  
                  
                  **$**
                  **21.74**
                  
                  $
                  16.49
                  
                  
                  32
 -16-
 TABLE
                OF CONTENTS
  Production
          expenses increased 35 percent to $15.5 million in the fourth quarter of
          2006
          compared to $11.5 million for the comparable quarter in 2005. Operating
          costs
          per boe have increased 32 percent to $21.74 in the fourth quarter of 2006
          from
          $16.49 in the comparable quarter in 2005. 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.
  **Operating
          netback**
  USOGP
                  
                  **Three
                      months ended December 31,**($
                      per boe)
                  
                  
                  
                  
                  
                  2006
                  
                  2005
                  
                  %
                      Change**Netback
                      per boe**Gross
                      production revenue
                  
                  
                  
                  
                  
                  
                  
                  **$**
                  **55.95**
                  
                  $
                  59.22
                  
                  
                  (6
                  )Royalties
                  
                  
                  
                  
                  
                  
                  
                  
                  **(5.54**
                  **)**
                  
                  (5.84
                  )
                  
                  (5
                  )Operating
                      costs
                  
                  
                  
                  
                  
                  
                  
                  
                  **(21.74**
                  **)**
                  
                  (16.49
                  )
                  
                  32Field
                      Operating Netback
                  
                  
                  
                  
                  
                  
                  
                  **$**
                  **28.67**
                  
                  $
                  36.89
                  
                  
                  (22
                  )Realized
                      gain (loss) on financial derivative instruments
                  
                  
                  
                  
                  
                  
                  
                  
                  **2.65**
                  
                  
                  (6.98
                  )
                  
                  -Operating
                      netback after realized financial derivative instruments
                  
                  
                  
                  
                  
                  
                  
                  **$**
                  **31.32**
                  
                  $
                  29.91
                  
                  
                  5
  The
          fourth quarter 2006 field operating netback of $28.67 per boe was 22 percent
          below the $36.89 per boe in the comparable quarter of 2005. The reduction
          reflects lower realized natural gas prices and increased operating costs.
          The
          fourth quarter 2006 operating netback after realized financial derivative
          instruments of $31.32 per boe is five percent higher than the $29.91 per
          boe for
          the fourth quarter of 2005 reflecting the preceding factors offset by realized
          gains on financial derivative instruments.
 
 **General
          and administrative**
 USOGP
                  **Three
                      months ended December 31,**($
                      000s, except per boe amounts)
                  
                  
                  **2006**
                  
                  2005
                  
                  %
                      ChangeCash
                      general and administrative
                  
                  
                  
                  **$**
                  **6,839**
                  
                  $
                  4,525
                  
                  
                  51Non-cash
                      unit based compensation
                  
                  
                  
                  
                  **7,800**
                  
                  
                  2,000
                  
                  
                  290**$**
                  **14,639**
                  
                  $
                  6,525
                  
                  
                  124Cash
                      general and administrative (per boe)
                  
                  
                  
                  **$**
                  **9.57**
                  
                  $
                  6.48
                  
                  
                  48
 
 Cash
          general and administrative expenses in the fourth quarter of $6.8 million
          or
          $9.57 per boe is 51 percent higher than the fourth quarter of 2005. The
          increase
          is due to increased 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), increased corporate general and administrative
          allocations to USOGP operations and increased staffing levels, as well
          as legal
          and consulting costs in connection with the initial public offering of
          the
          MLP.
 
 Non-cash
          unit based compensation expense was $7.8 million in the fourth quarter
          of 2006
          compared to $2.0 million in the fourth quarter of 2005. The increase in
          incentive plan costs is primarily driven by the initial public offering
          of the
          MLP completed in the fourth quarter of 2006.
 -17-
 TABLE
              OF CONTENTS
   **Capital
          expenditures**
  USOGP
                  
                  **Three
                      months ended December 31,**($
                      000s)
                  
                  
                  
                  **2006**
                  
                  2005**Capital
                      expenditures - by category**Geological,
                      geophysical and land
                  
                  
                  
                  
                  **$**
                  **104**
                  
                  $
                  409Drilling,
                      recompletions, and workovers
                  
                  
                  
                  
                  
                  **6,796**
                  
                  
                  5,169Facilities
                      and equipment
                  
                  
                  
                  
                  
                  **5,365**
                  
                  
                  5,802Other
                      capital
                  
                  
                  
                  
                  
                  **2,049**
                  
                  
                  144Total
                      additions
                  
                  
                  
                  
                  **$**
                  **14,314**
                  
                  $
                  11,524**Capital
                      expenditures - by area (boed)**Los
                      Angeles
                  
                  
                  
                  
                  
                  **2,631**
                  
                  
                  6,125Santa
                      Maria - Orcutt
                  
                  
                  
                  
                  
                  **7,378**
                  
                  
                  2,122Wyoming
                  
                  
                  
                  
                  
                  **2,157**
                  
                  
                  2,718Other
                      capital
                  
                  
                  
                  
                  
                  **2,148**
                  
                  
                  559**14,314**
                  
                  
                  11,524Property
                      acquisitions
                  
                  
                  
                  
                  **$**
                  -
                  
                  $
                  -Property
                      dispositions
                  
                  
                  
                  
                  **$**
                  -
                  
                  $
                  -
 USOGP
          capital expenditures for the fourth quarter of 2006 totaled $14.3 million.
          Of
          this total, $9.1 million was directed at drilling, optimization and facility
          upgrades at West Pico, Santa Fe Springs and Orcutt. $2.2 million was directed
          at
          drilling and optimization work in Wyoming. $1.3 million was directed at
          optimization projects at smaller fields as well as head office related
          capital
          expenditures and $1.7 million was directed at a real estate development
          project
          initiated in the second quarter.
 
 **Depletion,
          depreciation and accretion (DD&A)**
 USOGP
                  
                  **Three
                      months ended December 31,**($
                      000s, except per boe amounts)
                  
                  
                  
                  **2006**
                  
                  2005
                  
                  %
                      ChangeDD&A
                  
                  
                  
                  
                  **$**
                  **9,269**
                  
                  $
                  6,622
                  
                  
                  40DD&A
                      (per boe)
                  
                  
                  
                  
                  **$**
                  **12.97**
                  
                  $
                  9.49
                  
                  
                  37
 
 The
          USOGP’s DD&A rate is low due to the long-lived nature of the
          assets.
 
 On
          a per
          boe basis the DD&A rate is up $3.48 or 37 percent from the fourth quarter of
          2005. This is primarily associated with a year-end depletion rate adjustment
          reflecting 2006 capital expenditures as well as changes in
          reserves.
  **Midstream
          services and marketing business segment review**
 
 **Midstream
          NGL acquisition**
 
 The
          $773
          million Midstream NGL Acquisition, which closed on December 13, 2005, included
          NGL extraction plants, pipelines, storage and fractionation facilities,
          distribution facilities, and contracts including marketing, supply and
          transportation arrangements, and NGL marketing infrastructure. This acquisition
          has extended Provident’s involvement in the NGL value chain. Results in 2005
          included NGL fee for service, fixed margin extraction, equity margin on
          marketed
          NGLs, and margin on crude oil marketing contracts. The crude oil marketing
          contracts were disposed in May 2005, thus 2006 results include an increase
          in
          fees for services, fixed margin extraction and equity margin on marketed
          NGLs.
 -18-
 TABLE
              OF CONTENTS
   **Operations
          - managed NGL volumes**
  Provident
          managed 145,732 bpd over the fourth quarter of 2006, an 89 percent increase
          over
          the 77,100 bpd managed in the fourth quarter of 2005. Managed volumes are
          NGL
          products that have been purchased or received for further processing and/or
          sale. The significant increase in 2006 is a result of the Midstream NGL
          Acquisition.
 
 **Revenues**
  For
          the
          fourth quarter of 2006 product sales and services revenues were $441.8
          million
          (2005 - $295.6 million). Revenue figures are after elimination of intersegment
          transactions. The significant increase in revenue over 2005 is a result
          of the
          Midstream NGL Acquisition, and the commissioning of the condensate loading
          and
          terminalling facilities in the second quarter of 2006. Product sales relate
          to
          the marketing of NGLs and transportation and fractionation contracts (T&F),
          while service revenue relates to fees earned through NGL processing, marketing,
          storage and distribution. The majority of NGL revenues are earned pursuant
          to
          both long-term contracts and annual evergreen purchase and sales commitments.
 
 In
          addition to the increased product sales and service revenue, Midstream
          revenue
          was increased by $5.4 million in the fourth quarter of 2006 (2005 - $2.6
          million
          loss) due to realized gains on financial derivative instruments. Midstream
          enters into derivative contracts to assist with margin stabilization on
          marketed
          products.
 
 **Expenses**
  The
          cost
          of goods sold (COGS) was $360.0 million for the fourth quarter of 2006
          (2005 -
          $245.0 million). Cost of goods sold relates to NGL product sales revenue
          included in product sales and services revenue. COGS include all costs
          incurred
          in the production and purchase of NGL specification product for sale. The
          majority of the natural gas liquids are purchased pursuant to long-term
          contracts and annual evergreen purchase commitments. The significant increase
          in
          COGS over 2005 is a result of the Midstream NGL Acquisition which has resulted
          in an increased level of activity.
 
 Operating
          and maintenance expenses were $3.1 million for the fourth quarter of 2006
          (2005
          - $11.7 million). Fourth quarter 2006 costs include operating costs incurred
          to
          process NGLs, and to provide T&F and storage and distribution services to
          third parties. In prior quarters, operating costs also included costs incurred
          at the Younger and Redwater facilities for Provident’s own production. These
          costs are now included in the determination of inventory and cost of goods
          sold,
          reflecting the integration of operations after the Midstream NGL
          Acquisition.
 
 General
          and administrative expenses were $10.5 million  for
          the
          fourth quarter of 2006 (2005 - $6.8 million) representing increased costs
          for
          compliance activities including costs related to implementation of procedures
          and documentation in connection with the U.S. Sarbanes-Oxley Act and an
          increased number of employees since the Midstream NGL Acquisition. Interest
          expense for the fourth quarter of 2006 was $9.6 million (2005 - $1.1 million)
          reflecting an increase in capitalization associated with the Midstream
          NGL
          Acquisition. Depreciation expense was $16.6 million for the three months
          ended
          December 31, 2006 (2005 - $4.2 million) reflecting the larger asset base
          acquired through the Midstream NGL Acquisition and a $5.8 million impairment
          write down of capitalized inventory.
 
 **Earnings
          before interest, taxes, depletion, depreciation, accretion, and other non-cash
          items (“EBITDA”)**  **and
          cash flow from operations**
 
 Fourth
          quarter 2006 EBITDA of $74.4 million increased $44.8 million or 152 percent
          from
          $29.6 million in the fourth quarter of 2005. Cash flow for the fourth quarter
          of
          2006 was $60.5 million, an increase of $32.2 million or 114 percent above
          the
          $28.3 million for the fourth quarter 2005. Through the Midstream NGL
          Acquisition, Provident has expanded its participation in the NGL value
          chain,
          which has made a significant contribution to the overall increase in EBITDA
          and
          cash flow. In addition, Midstream EBITDA and cash flow benefited from an
          increase in product margin in the fourth quarter of 2006 over the comparable
          quarter in 2005.
 
 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”).
 -19-
 TABLE
                OF CONTENTS
  **Capital
          expenditures**
  Midstream
          capital expenditures for the fourth quarter of 2006 totaled $28.3 million.
          $6.0
          million of the capital was spent on the new condensate offloading facilities
          and
          truck terminals at Redwater. An additional $9.2 million was spent on the
          initial
          drilling of two new Redwater storage caverns expected to be completed in
          2009.
          $11.3 million was also spent to acquire an additional 7.5% interest in
          the
          Provident Empress NGL Extraction plant. The remaining $1.8 million relates
          to
          sustaining capital requirements.
 -20-
 TABLE
              OF CONTENTS
   **2006
          Year end results**
  **Consolidated
          cash flow from operations before changes in working capital and site restoration
          expenditures (“Cash Flow”) and cash distributions**
  Consolidated
                  
                  **Year
                      ended December 31,**($
                      000s, except per unit data)
                  
                  
                  
                  **2006**
                  
                  2005
                  
                  %
                      Change**Revenue,
                      Cash Flow and Distributions**Revenue
                      (net of royalties and financial derivative instruments -
                    see
                      Note 8 to the consolidated financial statements)
                  **$**
                  **2,187,253**
                  
                  $
                  1,360,274
                  
                  
                  61Cash
                      flow from operations before changes in working capital and
                      site
                    restoration
                      expenditures
                  
                  **$**
                  **432,664**
                  
                  $
                  311,188
                  
                  
                  39Per
                      weighted average unit - basic(1)
                  
                  
                  
                  
                  **$**
                  **2.20**
                  
                  $
                  1.95
                  
                  
                  13Per
                      weighted average unit - diluted(2)
                  
                  
                  
                  
                  **$**
                  **2.20**
                  
                  $
                  1.95
                  
                  
                  13Declared
                      distributions
                  
                  
                  
                  
                  **$**
                  **283,465**
                  
                  $
                  230,714
                  
                  
                  23Per
                      Unit(1)
                  
                  
                  
                  
                  
                  **1.44**
                  
                  
                  1.44
                  
                  
                  -Percent
                      of cash flow distributed
                  
                  
                  
                  
                  
                  **66**
                  **%**
                  
                  74
                  %
                  
                  (12
                  )(1)Excludes exchangeable shares(2)Includes dilutive impact of unit options, exchangeable
                      shares and
                      convertible debentures.
 
 For
          the
          year ended December 31, 2006, cash flow increased 39 percent or $121.5
          million
          to $432.7 million from $311.2 million for 2005 (per unit in 2006 - $2.20;
          2005 -
          $1.95). COGP generated $185.3 million, USOGP $63.0 million, and Midstream
          $184.4
          million of cash flow during 2006. During 2005 COGP generated cash flow
          of $185.1
          million, USOGP $59.8 million, and Midstream $66.3 million.
 
 Canadian
          oil and gas operations cash flow contributed $185.3 million in 2006, virtually
          flat when compared with $185.1 million from 2005. The 2006 results reflect
          increased production from the Rainbow assets acquired on August 31, 2006,
          incremental production adds from the successful capital drilling programs
          in the
          core areas and higher realized crude oil and natural gas liquids prices,
          as well
          as realized gains on financial derivative instruments. These factors were
          offset
          by natural production declines, a lower realized natural gas price due
          to a
          decrease in the AECO natural gas index price, and higher general and
          administrative expenses when compared to 2005.
 
 The
          Mids tream
          business unit added $184.4 million to 2006 cash flow, 178  percent
          above the $66.3  million
          recorded in the year ended December 31, 2005. Midstream cash flow has benefited
          from the Midstream NGL Acquisition completed in December 2005. This acquisition
          has extended Provident’s participation in the NGL value chain. Midstream cash
          flow reflects an increase in fees for services, fixed margin extraction
          and
          equity margin on marketed NGLs. Midstream cash flow from marketed NGLs
          benefited
          from an increase in propane plus prices in the year ended December 31,
          2006 over
          2005 accompanied by a reduction in associated product costs, mostly due
          to
          reduced natural gas prices.
 
 The
          U.S.
          oil and gas operations provided increased cash flow of $63.0 million in
          2006,
          compared to $59.8 million in 2005, resulting from a full year of production
          in
          2006 from the Nautilus properties, acquired in March of 2005, and higher
          crude
          oil prices, partially offset by higher production expenses and general
          and
          administrative costs.
 
 Declared
          distributions in 2006 totaled $283.5 million, 66 percent of cash flow.
          This
          compares to $230.7 million of declared distributions in 2005, 74 percent
          of cash
          flow. In previous years, Provident has paid out between 74 percent and
          102
          percent of its annual cash flow as distributions to unitholders. Provident’s
          objective is to provide stable distributions to its unitholders. ****
 
 Management
          uses cash flow from operations (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.
 
 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.
 -21-
 TABLE
                OF CONTENTS
  **Distributions**
  The
          following table summarizes distributions paid as declared by the Trust
          since
          inception:
 
 **Distribution
                      Amount****Record
                      Date**
                  
                  **Payment Date**
                  
                  **(Cdn$)**
                  **(US$)***2006January
                      23, 2006
                  
                  
                  February
                      15, 2006
                  
                  $
                  0.12
                  
                  0.10February
                      23, 2006
                  
                  
                  March
                      15, 2006
                  
                  
                  0.12
                  
                  0.10March
                      22, 2006
                  
                  
                  April
                      13, 2006
                  
                  
                  0.12
                  
                  0.10April
                      24, 2006
                  
                  
                  May
                      15, 2006
                  
                  
                  0.12
                  
                  0.11May
                      25, 2006
                  
                  
                  June
                      15, 2006
                  
                  
                  0.12
                  
                  0.11June
                      22, 2006
                  
                  
                  July
                      14, 2006
                  
                  
                  0.12
                  
                  0.11July
                      21, 2006
                  
                  
                  August
                      15, 2006
                  
                  
                  0.12
                  
                  0.11August
                      22, 2006
                  
                  
                  September
                      15, 2006
                  
                  
                  0.12
                  
                  0.11September
                      22, 2006
                  
                  
                  October
                      13, 2006
                  
                  
                  0.12
                  
                  0.11October
                      23, 2006
                  
                  
                  November
                      15, 2006
                  
                  
                  0.12
                  
                  0.10November
                      22, 2006
                  
                  
                  December
                      15, 2006
                  
                  
                  0.12
                  
                  0.10December
                      22, 2006
                  
                  
                  January
                      15, 2007
                  
                  
                  0.12
                  
                  0.102006
                      Cash Distributions paid as declared
                  
                  
                  
                  
                  $
                  1.44
                  
                  1.262005
                      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, 2006 – Distributions paid as declared
                  
                  
                  $
                  10.95
                  
                  7.96*exchange
                      rate based on the Bank of Canada noon rate on the payment date.
 
 For
          Canadian tax purposes, 2006 distributions were determined to be 93.2 percent
          taxable and 6.8 percent tax-deferred return of capital in the hands of
          Canadian
          unitholders. The 2005 comparables were 76.5 percent and 23.5 percent,
          respectively. Distributions received by U.S. resident unitholders in 2006
          are
          classified as 97.7 percent qualified dividend and 2.3 percent tax deferred
          return of capital. The 2005 comparables were 94.4 percent and 5.6 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.
 
 **Proposed
          taxation of trust distributions**
 
 The
          Canadian government made an unexpected announcement on October 31, 2006,
          stating
          its intention to introduce a substantial new 31.5 percent tax on income
          trust
          distributions beginning in 2011. This announcement caused a severe negative
          market reaction early in November. The government remains committed to
          this
          course of action in spite of compelling evidence of the very positive impact
          that energy trusts in particular have on the Canadian energy industry,
          on the
          economy in general, and on government tax revenues.
  Since
          the
          original announcement, the government has also clarified the rules around
          the
          extent to which a trust is allowed to grow before 2011 without triggering
          immediate taxable status. A trust can double in size before 2011, and trusts
          can
          merge without penalty. This is positive, suggesting that Provident’s near term
          business plan and growth objectives will not be affected by the taxation
          announcement.
  Provident
          remains active in the efforts to try to convince the government to modify
          its
          proposal or to exempt energy trusts. As well as working with government,
          management is also actively engaged in strategic planning to determine
          the best
          course of action for Provident under the proposed new tax regime. With
          diverse
          businesses and a history of innovation, the Trust is well positioned to
          identify
          creative solutions. While it will take time to fully examine all options,
          management remains committed to making Provident a premier energy income
          and
          growth investment.
 -22-
 TABLE
                OF CONTENTS
  **Net
          income**
  Consolidated
                  
                  **Year
                      ended December 31,**($
                      000s, except per unit data)
                  
                  
                  
                  **2006**
                  
                  2005
                  
                  %
                      ChangeNet
                      income
                  
                  
                  
                  
                  **$**
                  **140,920**
                  
                  $
                  96,926
                  
                  
                  45Per
                      weighted average unit
                    –
                      basic(1)
                  
                  
                  
                  
                  
                  **0.72**
                  
                  
                  0.61
                  
                  
                  18Per
                      weighted average unit
                    –
                      diluted(2)
                  
                  
                  
                  
                  
                  **0.72**
                  
                  
                  0.61
                  
                  
                  18(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.
  **Year
                      ended December
                      31,**($
                      000s)
                  
                  
                  
                  
                  
                  **2006**
                  
                  
                  2005
                  
                  
                  %
                      ChangeCOGP
                      net income
                  
                  
                  
                  
                  **$**
                  **83,453**
                  
                  $
                  35,352
                  
                  
                  136USOGP
                      net income
                  
                  
                  
                  
                  
                  **2,598**
                  
                  
                  5,422
                  
                  
                  (52
                  )Total
                      oil and gas net income
                  
                  
                  
                  
                  
                  **86,051**
                  
                  
                  40,774
                  
                  
                  111Midstream
                      net income
                  
                  
                  
                  
                  
                  **54,869**
                  
                  
                  56,152
                  
                  
                  (2
                  )Consolidated
                      net income
                  
                  
                  
                  
                  **$**
                  **140,920**
                  
                  $
                  96,926
                  
                  
                  45
 Net
          income for the year ended December 31, 2006 increased to $140.9 million
          compared
          to $96.9 million of income in the comparable 2005 period.
 
 The
          COGP
          business segment’s net income was $83.4 million **,** a $48.0
          million improvement over the year ended December 31, 2005 net income of
          $35.4
          million. The increase was mainly due to a higher future income tax recovery
          and
          an increased unrealized gain on financial derivative instruments partially
          offset by increased depletion, depreciation, and accretion (DD&A) expense
          and a decrease in earnings before interest, taxes, depletion, depreciation,
          accretion and other non-cash items (EBITDA) driven by lower realized natural
          gas
          prices due to the decrease in the AECO natural gas index price, and lower
          production compared to 2005.
 
 The
          Midstream unit recorded net income of $54.9 million as compared to $56.1
          million
          in the year ended December 31, 2005. The increase reflects higher EBITDA
          in
          2006. The Midstream business unit had EBITDA of $219.6 million in 2006
          as
          compared to $70.7 million in 2005. This significant improvement in EBITDA
          is
          attributable to the Midstream NGL acquisition completed in December 2005.
          This
          acquisition has extended Provident’s participation in the NGL value chain
          through increased managed volumes. Midstream EBITDA reflects an increase
          in fees
          for services, fixed margin extraction and equity margin on marketed NGLs.
          The
          significant improvement in Midstream EBITDA is also the result of an increase
          in
          propane plus prices in 2006 over 2005 accompanied by a reduction in associated
          product costs, mostly due to reduced natural gas prices. Partially offsetting
          this increase is unrealized losses on outstanding financial derivative
          instruments amounting to $68.3 million in 2006 (2005 - $1.6 million). Under
          generally accepted accounting principles, these unrealized “mark-to-market”
amounts, which relate to financial instruments with effective periods ranging
          over the next five years from 2007 through 2011, are required to be recognized
          in the financial statements of Provident, affecting current period net
          income
          (see “Commodity price risk management program”). In addition, higher DD&A of
          $49.1 million compared to $11.8 million in 2005, and higher interest charges
          of
          $32.1 million versus $4.9 million in 2005 are the result of a larger asset
          base
          and increased capitalization due to the Midstream NGL Acquisition.
 
 For
          the
          year ended December 31, 2006, USOGP net income was $2.6 million as compared
          to
          $5.4 million in the year ended December 31, 2005. USOGP generated a seven
          percent increase in EBITDA resulting from a full year of production in
          2006 from
          the Nautilus properties, acquired in March of 2005 as well as higher crude
          oil
          prices. In addition, unrealized gains on financial derivative instruments
          were
          $7.7 million in 2006, compared to a loss of $1.9 million in 2005. These
          factors
          were offset by higher DD&A charges and increased non-cash unit based
          compensation in 2006.
  -23-
 TABLE
              OF CONTENTS
   **Reconciliation
          of non-GAAP measure**
  The
          Trust
          calculates earnings before interest, taxes, depletion, depreciation, accretion
          and other non-cash items (EBITDA) within its segment disclosure. EBITDA
          is a
          non-GAAP measure. A reconciliation between EBITDA and income before taxes
          and
          non-controlling interests follows:
  ConsolidatedEBITDA
                      Reconciliation
                  **Year
                      ended December 31,**($
                      000s)
                  
                  **2006**
                  
                  2005
                  
                  %
                      Change**EBITDA**
                  
                  **$**
                  **495,889**
                  
                  $349,181
                  
                  42Adjusted
                      for:Interest
                      and non-cash expenses excluding unrealized (loss) gain on
                    financial
                      derivative instruments
                  
                  **(335,079**
                  **)**
                  
                  (229,372
                  )
                  
                  46Unrealized
                      (loss) gain on financial derivative instruments
                  
                  
                  **(43,314**
                  **)**
                  
                  7,684
                  
                  
                  -Income
                      before taxes and non-controlling interests
                  
                  **$**
                  **117,496**
                  
                  $
                  127,493
                  
                  
                  (8
                  )
   Reconciliation
                      of cash flow distribution
                  
                  **Year
                      ended December 31,****2006**
                  
                  2005
                  
                  %
                      Change
 Cash
                    provided by operating activities
                  
                  **$**
                  **414,349**
                  
                  $
                  257,363
                  
                  
                  61Change
                      in non-cash operating working capital
                  
                  
                  **13,693**
                  
                  
                  51,344
                  
                  
                  (73
                  )Site
                      restoration expenditures
                  
                  
                  **4,622**
                  
                  
                  2,481
                  
                  
                  86Cash
                      flow from operations before changes in working capital and
                      site
                      restoration expenditures
                  
                  
                  **432,664**
                  
                  
                  311,188
                  
                  
                  39Cash
                      withheld for financing and investing activities
                  
                  
                  **(149,199**
                  **)**
                  
                  (80,474
                  )
                  
                  85Cash
                      distributions to unitholders
                  
                  
                  **283,465**
                  
                  
                  230,714
                  
                  
                  23Accumulated
                      cash distributions, beginning of period
                  
                  
                  **643,360**
                  
                  
                  412,646
                  
                  
                  56**Accumulated
                      cash distributions, end of period**
                  
                  **$**
                  **926,825**
                  
                  $
                  643,360
                  
                  
                  44**Cash
                      distributions per unit**
                  
                  **$**
                  **1.44**
                  
                  $
                  1.44
                  
                  
                  -
  Cash
          withheld for financing and investing activities is a discretionary amount
          and
          represents the difference between cash flow from operations (before changes
          in
          working capital and site restoration expenditures) and
          distributions.
 
 **Taxes**
  Year
                      ended December 31,($
                      000s)
                  
                  **2006**
                  
                  2005
                  
                  %
                      ChangeCapital
                      taxes
                  
                  **$**
                  **1,314**
                  
                  $
                  4,780
                  
                  
                  (73
                  )Current
                      and withholding taxes
                  
                  
                  **5,829**
                  
                  
                  5,628
                  
                  
                  4Future
                      income tax (recovery) expense
                  
                  
                  **(34,316**
                  **)**
                  
                  17,793
                  
                  
                  -**$**
                  **(27,173**
                  **)**
                  $
                  28,201
                  
                  
                  -
  For
          the
          year ended December 31, 2006, the expected income tax expense was $40.7
          million
          on income before taxes and non-controlling interests of $117.5 million.
          The
          difference from the expected expense and the total tax recovery of $27.2
          million
          is primarily a result of deductions allowed when computing taxable income
          of the
          Trust for distributions made to unitholders. The Trust is a taxable entity
          under
          Canadian income tax law and is taxable only on income that is not distributed
          or
          distributable to the unitholders. If the Trust distributes all of its taxable
          income to the unitholders, no provision for taxes is required by the Trust.
          Since inception, the Trust has distributed all of its taxable income to
          the
          unitholders. Additionally, interest and royalties are charged by the Trust
          to
          its subsidiaries, which are deductible in the computation of taxable income
          at
          the incorporated subsidiary level reducing tax pool claims in certain
          subsidiaries and potentially creating tax loss carry-forwards that result
          in
          future income tax recoveries.
 
 Capital
          taxes in the year ended December 31, 2006 totaled an expense of $1.3 million,
          a
          reduction from $4.8 million recorded in the year ended December 31, 2005.
          The
          reduction is due to the elimination of the federal large corporation tax
          effective January 1, 2006. This legislation was enacted on June 22,
          2006.
 -24-
 TABLE
                OF CONTENTS
  The
          current and withholding taxes total $5.8 million in the year ended December
          31,
          2006, an increase of $0.2 million over the comparable 2005 period. These
          taxes
          arise from Provident’s U.S. based operations, which are subject to U.S. federal
          and state income taxes. Also, payments from U.S. entities to Canadian entities
          are subject to withholding taxes if the distributions are characterized
          as
          dividends or interest.
 
 In
          2006,
          future income tax recovery totaled $34.3 million compared to an expense
          of $17.8
          million in 2005. The recovery was generated by interest and royalty charges
          to
          incorporated subsidiaries from the Trust as well as tax rate reductions
          enacted
          in the second quarter of 2006.
 
 **Interest
          expense**
  Consolidated
                  
                  
                  
                  **Year
                      ended December 31,**($
                      000s, except as noted)
                  
                  
                  
                  **2006**
                  
                  2005
                  
                  %
                      ChangeInterest
                      on bank debt
                  
                  
                  
                  
                  **$**
                  **34,666**
                  
                  $
                  10,875
                  
                  
                  219Weighted-average
                      interest rate on bank debt
                  
                  
                  
                  
                  
                  **5.30**
                  **%**
                  
                  3.85
                  %
                  
                  38Interest
                      on 10.5% convertible debentures(2)
                  
                  
                  
                  
                  
                  **-**
                  
                  
                  1,682
                  
                  
                  (100
                  )Interest
                      on 8.75% convertible debentures
                  
                  
                  
                  
                  
                  **2,573**
                  
                  
                  4,923
                  
                  
                  (48
                  )Interest
                      on 8.0% convertible debentures
                  
                  
                  
                  
                  
                  **2,500**
                  
                  
                  3,577
                  
                  
                  (30
                  )Interest
                      on 6.5% convertible debentures(1)
                  
                  
                  
                  
                  
                  **6,437**
                  
                  
                  5,393
                  
                  
                  19Interest
                      on 6.5% convertible debentures(3)
                  
                  
                  
                  
                  
                  **9,715**
                  
                  
                  1,219
                  
                  
                  697Total
                      cash interest
                  
                  
                  
                  
                  **$**
                  **55,891**
                  
                  $
                  27,669
                  
                  
                  102Weighted
                      average interest rate on all long-term debt
                  
                  
                  
                  
                  
                  **5.81**
                  **%**
                  
                  4.91
                  %
                  
                  18Non-cash
                      accretion expense - convertible debentures
                  
                  
                  
                  
                  
                  **2,694**
                  
                  
                  2,849
                  
                  
                  (5
                  )Total
                      interest including accretion on convertible debentures
                  
                  
                  
                  
                  **$**
                  **58,585**
                  
                  $
                  30,518
                  
                  
                  92(1)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.(2)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.(3)
                      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
          on bank debt increased in 2006 compared to 2005 due to increased capitalization
          including debt levels that resulted from the $773 million Midstream NGL
          Acquisition in the fourth quarter of 2005 and the $473 million Rainbow
          asset
          acquisition in the third quarter of 2006. As well, increases in the Canadian
          prime rate and the U.S. LIBOR rate have resulted in higher interest rates
          on
          bank debt.
  Cash
          interest expense on debentures increased in 2006 compared to 2005 reflecting
          the
          March 1, 2005 issue of $100 million of 6.5 percent subordinated convertible
          debentures and the November 15, 2005 issue of $150 million of 6.5 percent
          subordinated convertible debentures, partly offset by redemptions and
          conversions of subordinated convertible debentures.
 
 **Financial
          instruments**
 
 **Commodity
          price risk management program**
 
 For
          the
          year ended December 31, 2006 $13.5 million was recorded as a realized loss
          on
          financial derivative instruments due to the Commodity Price Risk Management
          Program (the Program) with $1.9  million
          related to the combined oil and gas operations as a realized gain and a
          realized
          loss of $15.4  million
          associated with the Midstream segment.
  In
          the
          oil and gas business units the realized loss in 2006 associated with crude
          oil
          totaled $5.7  million
          ($0.97 per barrel) and a realized gain of $7.6  million
          related to natural gas ($0.25 per gj). The combined total was a gain of
          $1.9  million
          or $0.16  per
          boe.
          In 2005 the Program recorded a realized loss of $64.6  million
          or $5.24  per
          boe
          with $59.0  million
          related to crude oil ($8.36  per
          barrel) and $5.6  million
          related to natural gas ($0.19  per
          gj).
 -25-
 TABLE
                OF CONTENTS
  In
          2006
          the Midstream segment recorded a realized loss of $15.4  million
          primarily on propane and ethane price stabilization and frac-spread margin
          hedging activities. In 2005 the Program recorded a realized loss of
          $2.3  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
          $0.07  per
          trust
          unit in 2006 from $0.42  per
          trust
          unit in 2005.
  At
          December 31, 2006 the mark to market value of open contracts was in a net
          loss
          position of $52.9 million based upon commodity prices prevailing at that
          date.
          Under generally accepted accounting principles, these unrealized
“mark-to-market” opportunity costs, which relate to hedging positions with
          effective periods ranging over the next five years from 2007 through 2011,
          are
          required to be recognized in the financial statements of Provident, affecting
          current period net income. These unrealized opportunity costs relate to
          financial derivative instruments which were entered into in order to manage
          commodity prices and protect future Midstream product margins. Fluctuations
          in
          the market value of these instruments have no impact on cash flow until
          the
          instruments are settled.
 
 Provident’s
          commodity price risk management program includes a consistent, active and
          disciplined hedging program that utilizes derivative instruments to provide
          for
          insurance against lower commodity prices and price volatility. The program
          provides support for stable cash distributions, capital programs and bank
          financing. The hedging strategy protects a percentage of Provident’s oil and
          natural gas 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 a percentage
          of
          inventory values and fractionation spread margin associated with the midstream
          services and marketing business unit. As well, the Provident hedging strategy
          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 2007. The derivative instruments
          the
          Trust uses include puts, calls, costless collars, participating swaps,
          fixed and
          indexed referenced pricing.
 
 **Disclosure
          Controls and Procedures: U.S. Sarbanes-Oxley Act**
 
 In
          2002,
          the United States Congress enacted the Sarbanes-Oxley Act (SOX), which
          stipulated that corporations publicly traded on U.S. financial exchanges
          must
          have assessed the effectiveness of their internal controls over financial
          reporting by December 31, 2006. As a foreign filer listed on the New York
          Stock
          Exchange, Provident was required to conduct the assessment.
 
 Based
          on
          their evaluation as of December 31, 2006, Provident’s chief executive officer
          and chief financial officer concluded that Provident’s disclosure controls and
          procedures (as defined in Rules 13(a)-15(e) and 15(d)-15(e) under the United
          States Securities Exchange Act of 1934 (the Exchange Act) are effective
          to
          ensure that information required to be disclosed by Provident in reports
          that it
          files or submits under the Exchange Act is recorded, processed, summarized
          and
          reported within the time periods specified in the United States Securities
          and
          Exchange Commission rules and forms. In addition, other than as described
          below,
          as of December 31, 2006, there were no changes in Provident’s internal controls
          over financial reporting that occurred during 2006 that have materially
          affected, or are reasonably likely to materially affect its internal controls
          over financial reporting.
 
 Provident
          will continue to periodically evaluate its disclosure controls and procedures
          and internal controls over financial reporting and will make any modifications
          from time to time as deemed necessary.
 
 The
          Trust
          has undertaken a comprehensive review of the effectiveness of its internal
          control over financial reporting as part of the reporting, certification
          and
          attestation requirements of Section 404 of the U.S. Sarbanes-Oxley Act
          of 2002.
          For the year ended December 31, 2006, the company’s internal controls were found
          to be operating free of any material weaknesses.
 -26-
 TABLE
                OF CONTENTS
  **Property
          Acquisitions**
 
 On
          August
          31, 2006 Provident acquired a package of natural gas producing assets in
          the
          Rainbow and Peace River Arch areas of northwestern Alberta. The assets
          provide
          daily production of approximately 5,500 barrels of oil equivalent, over
          90
          percent of which is natural gas, and over 200 identified drilling locations.
  The
          purchase price was $472.8 million (including acquisition costs) and was
          financed
          by the issuance of 16,325,000 units at $13.85 per unit and Provident’s credit
          facilities (see note 3 to consolidated financial statements).
 
 In
          the
          fourth quarter of 2006, Provident spent $8.6 million on oil and gas property
          acquisitions primarily on acquiring additional working interests in Northwest
          Alberta ($6.7 million) and in Southern Alberta ($1.7 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. In 2005, the Midstream
          NGL
          Acquisition resulted in additional goodwill of $100.4 million (as adjusted
          in
          2006. See note 3 to the consolidated financial statements). Goodwill of
          $330.9
          million arose from COGP acquisitions in 2002 and 2004.
 
 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**
  Consolidated
                  
                  
                  
                  **December
                      31,**($
                      000s)
                  
                  
                  
                  **2006**
                  
                  2005
                  
                  %
                      ChangeLong-term
                      debt - revolving term credit facilities
                  
                  
                  
                  
                  **$**
                  **702,993**
                  
                  $
                  586,597
                  
                  
                  20Long-term
                      debt - convertible debentures
                  
                  
                  
                  
                  
                  **285,792**
                  
                  
                  298,007
                  
                  
                  (4
                  )Total
                      debt
                  
                  
                  
                  
                  
                  **988,785**
                  
                  
                  884,604
                  
                  
                  12Equity
                      (at book value)
                  
                  
                  
                  
                  
                  **1,542,974**
                  
                  
                  1,404,826
                  
                  
                  10Total
                      capitalization at book value
                  
                  
                  
                  
                  **$**
                  **2,531,759**
                  
                  $
                  2,289,430
                  
                  
                  11Total
                      debt as a percentage of total book value capitalization
                  
                  
                  
                  
                  
                  **39**
                  **%**
                  
                  39
                  %
                  
                  -
 
 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.
 
 **Long-term
          debt and working capital**
 
 As
          at
          December 31, 2006 Provident had drawn on 63 percent of its term credit
          facilities of $925 million and U.S. $158 million as compared to 68 percent
          drawn
          on its $750 million and U.S. $100 million term credit facilities as at
          December
          31, 2005. The increase in the level of bank debt was due to the increased
          scale
          of operations primarily due to acquisitions.
 
 At
          December 31, 2006 Provident had letters of credit guaranteeing Provident’s
          performance under certain commercial and other contracts that totaled $31.9
          million, increasing bank line utilization to 66 percent. The guarantees
          at
          December 31, 2005 totaled $45.1 million.
 
 Provident’s
          working capital decreased by $23.6 million from $79.4 million to $55.8
          million
          as at December 31, 2006. Of the decrease, $24.8 million is due to a reduction
          in
          inventory and $21.8 million due to a reduction in cash and cash equivalents.
          These decreases in working capital are partially offset by a $14.7 million
          reduction in accounts
          payable and accrued liabilities and a $4.4 million reduction in net current
          financial derivative instrument liability.
 
 -27-
 TABLE
                OF CONTENTS
  The
          ratio
          of debt to cash flow in 2006 was 2.3 to one, compared to 2.8 to one in
          2005.
          Fourth quarter cash flow in 2006 was $122.7 million. The ratio of debt
          to
          annualized fourth quarter cash flow was 2.0 to one, as compared to 2005
          fourth
          quarter annualized debt to cash flow of 2.3 to one. The reduction in debt
          to
          cash flow figures is due to increased cash flows as a result of the Midstream
          NGL Acquisition.
 
 **Trust
          units and exchangeable shares**
  On
          July
          31, 2006 the Trust issued 16,325,000 Subscription Receipts at a price of
          $13.85
          per Subscription Receipt for total proceeds of $226.1 million ($214.2 million
          net of issue costs). Each Subscription Receipt entitled the holder to receive
          one trust unit upon completion of the Rainbow asset acquisition. The acquisition
          closed on August 31, 2006 at which time all the outstanding Subscription
          Receipts were converted into 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 August distribution paid in September. This payment was
          treated as a reduction to the proceeds received for the units issued through
          the
          Subscription Receipts to $13.73 per trust unit, reducing the amount attributed
          to Unitholders’ contributions by $2.0 million. Proceeds from the issue were used
          to fund the Rainbow asset acquisition.
 
 In
          2006,
          0.9 million units were issued on conversion of exchangeable shares with
          a value
          of $9.0 million (2005 - 3.0 million units; conversion amount $28.4 million).
          For
          the year ended December 31, 2006 the Trust issued 1.3 million units on
          conversion of convertible debentures (2005 - 9.6 million units). An additional
          0.9 million units pursuant to the unit option plan were issued for the
          year
          ended December 31, 2006 (2005 - 2.3 million units). Under Provident’s Premium
          Distribution, Distribution Reinvestment (DRIP) and Optional Unit Purchase
          Plan
          program 3.0 million units were elected in 2006 and were issued or are to
          be
          issued representing proceeds of $36.9 million (2005 - 1.4 million units
          for
          proceeds of $18.4 million).
 
 At
          December 31, 2006 management and directors held approximately 1.0 percent
          of the
          outstanding units and exchangeable shares.
 
 **Non-Controlling
          Interest**
  **(i)**
                **USOGP
                    operations**
 **Year
                      ended December 31,**Non-controlling
                      interest USOGP ($ 000s)
                  
                  
                  
                  **2006**
                  
                  2005Non-controlling
                      interest, beginning of year
                  
                  
                  
                  
                  **$**
                  **11,885**
                  
                  $
                  13,649Net
                      income attributable to non-controlling interest
                  
                  
                  
                  
                  
                  **2,995**
                  
                  
                  1,596Distributions
                      to non-controlling interest holders
                  
                  
                  
                  
                  
                  **(6,523**
                  **)**
                  
                  (3,360
                  )Investments
                      by non-controlling interest
                  
                  
                  
                  
                  
                  **72,754**
                  
                  
                  -Non-controlling
                      interest, end of year
                  
                  
                  
                  
                  
                  **81,111**
                  
                  
                  11,885Accumulated
                      income attributable to non-controlling interest
                  
                  
                  **$**
                  **5,514**
                  
                  $
                  2,519
  A
          non-controlling interest arose from Provident’s June 15, 2004 acquisition of 92
          percent of BreitBurn Energy Company L.P. (BreitBurn) of Los Angeles, California.
          Additional investments since June 2004 by Provident in BreitBurn have reduced
          the non-controlling interest percentage at December 31, 2006 to approximately
          4.4 percent (2005 - 4.4 percent). Contributions by this non-controlling
          interest
          total $0.5 million in 2006 (2005 - nil).
 
 In
          the
          second quarter of 2006, a USOGP subsidiary began a land development project
          with
          a partner. The subsidiary has a 20 percent interest, with the partner holding
          80
          percent. Because the subsidiary stands to receive a majority share of the
          future
          proceeds, Provident is consolidating the results in its statements, with
          non-controlling interest. Contributions by the non-controlling interest
          total
          $3.7 million in 2006.
 
 In
          the
          fourth quarter of 2006, Provident’s subsidiary, BreitBurn Energy Partners, L.P.
          (the “MLP”) completed its initial public offering. BreitBurn transferred oil and
          gas properties comprising approximately half of its proved reserves and
          two
          thirds of its daily production to the MLP. The offering, including an
          underwriter’s option, of 6,900,000 common units at U.S. $18.50 per unit,
          resulted in approximately 34 percent of the MLP held by partners not controlled
          by Provident. Contributions by this non-controlling interest total $131.6
          million in 2006. Non-controlling interest was increased by $68.5 million
          as a
          result of this transaction. The difference of $63.1 million has been recorded
          against property, plant and equipment in accordance with full cost accounting
          principles.
 -28-
 TABLE
                OF CONTENTS
  **(ii)**
                **Exchangeable
                    shares**
 
 Following
          is a summary of the non-controlling interest - exchangeable shares for
          the years
          ended December 31, 2006 and 2005:
 Non-controlling
                      interest - Exchangeable shares ($ 000s)
                  
                  **2006**
                  
                  2005Non-controlling
                      interest, beginning of year
                  
                  **$**
                  **8,259**
                  
                  $
                  35,921Reduction
                      of book value for conversion to trust units
                  
                  
                  **(9,013**
                  **)**
                  
                  (28,432
                  )Net
                      income attributable to non-controlling interest
                  
                  
                  **754**
                  
                  
                  770Non-controlling
                      interest, end of year
                  
                  **$**
                  -
                  
                  $
                  8,259Accumulated
                      income attributable to non-controlling interest
                  
                  **$**
                  -
                  
                  $
                  2,252
  In
          2006,
          all outstanding exchangeable shares were converted into Provident trust
          units.
 
 **Capital
          expenditures and funding**
 
 Consolidated
                  
                  **Year
                      ended December 31,**($
                      000s)
                  
                  **2006**
                  
                  2005
                  
                  %
                      Change**Capital
                      Expenditures and Funding****Capital
                      Expenditures**Capital
                      expenditures and reclamation fund contributions
                  
                  **$**
                  **(193,183**
                  **)**
                  $
                  (159,398
                  )
                  
                  21Property
                      acquisitions
                  
                  
                  **(480,357**
                  **)**
                  
                  (586
                  )
                  
                  81,872Corporate
                      acquisitions
                  
                  
                  **(1,036**
                  **)**
                  
                  (863,723
                  )
                  
                  (100
                  )Property
                      dispositions
                  
                  
                  **(1,268**
                  **)**
                  
                  45,100
                  
                  
                  -Net
                      capital expenditures
                  
                  **$**
                  **(675,844**
                  **)**
                  $
                  (978,607
                  )
                  
                  (31
                  )**Funded
                      By**Cash
                      flow net of declared distributions to unitholders and non-controlling
                      interest
                  
                  **$**
                  **142,676**
                  
                  $
                  77,114
                  
                  
                  85Increase
                      in long-term debt
                  
                  
                  **117,385**
                  
                  
                  325,771
                  
                  
                  (64
                  )Issue
                      of convertible debentures, net of issue costs
                  
                  
                  **-**
                  
                  
                  239,822
                  
                  
                  (100
                  )Redemption
                      of convertible debentures
                  
                  
                  **-**
                  
                  
                  (2,997
                  )
                  
                  (100
                  )Issue
                      of trust units, net of issue costs; excluding DRIP
                  
                  
                  **220,225**
                  
                  
                  377,362
                  
                  
                  (42
                  )DRIP
                      proceeds
                  
                  
                  **36,851**
                  
                  
                  18,443
                  
                  
                  100Contributions
                      by non-controlling interests
                  
                  
                  **135,829**
                  
                  
                  -
                  
                  
                  -Change
                      in working capital, including cash, payment of financial
                    derivative
                      instruments and sale of assets
                  
                  
                  **22,878**
                  
                  
                  (56,908
                  )
                  
                  -Net
                      capital expenditure funding
                  
                  **$**
                  **675,844**
                  
                  $
                  978,607
                  
                  
                  (31
                  )
 
 Capital
          expenditures were funded by a combination of cash flow, debt and equity
          issued
          from treasury through public offerings, the DRIP program and contributions
          by
          non-controlling interest. Provident’s strategy is to fund acquisitions by
          accessing the capital markets and to fund capital expenditures through
          cash
          flow, DRIP and other equity if needed ***.***
 
 **Net
          asset value**
  Provident’s
          net asset value (“NAV”) as at December 31, 2006, 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,
          2006
          and December 31, 2005 is derived from a report prepared by McDaniel &
Associates Consultants Ltd., independent engineers.
 
 -29-
 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)
                    (2)**
                **$**
                **1,933,338**
                
                $
                1,726,538**Midstream
                    assets****(3)**
                
                
                **1,737,905**
                
                
                1,493,039**Add:**Working
                    Capital
                
                
                **65,500**
                
                
                65,500Land(4)
                    (5)
                
                
                **48,923**
                
                
                48,923Proceeds
                    from Options
                
                
                **20,283**
                
                
                20,283Cash
                    Reserved for Future Reclamation
                
                
                **-**
                
                
                -Investments
                
                
                **4,320**
                
                
                4,320**Less:**Financial
                    Hedging Losses(2)
                
                
                **27,769**
                
                
                26,290Long
                    Term Debt
                
                
                **(988,785**
                **)**
                
                (988,785
                )Other
                    long-term liabilities
                
                
                **(16,305**
                **)**
                
                (16,305
                )Non-controlling
                    interest - USOGP operations
                
                
                **(81,111**
                **)**
                
                (81,111
                )**Consolidated
                    Provident Net Asset Value**
                
                **$**
                **2,751,837**
                
                **$**
                **2,298,692****Consolidated
                    Provident Net Asset Value per Unit**
                
                **$**
                **12.90**
                
                **$**
                **10.77****2005
                    comparatives****Consolidated
                    Provident Net Asset Value per Unit**
                
                **$**
                **13.04**
                
                **$**
                **11.15**(1)
                    Evaluated by McDaniel and NSA.(2)
                    Pricing is based on McDaniel pricing effective December 31,
                    2006.(3)The Midstream assets represent discounted estimated cash
                    flow
                    streams (EBITDA less maintenance capital) for 25 years.(4)
                    Canadian land holdings evaluated by Seaton Jordan & Associates Ltd.
                    effective December 31, 2006.
  **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 $23.1 million for the year ended
          December 31, 2006 (2005 - $9.8 million) included in general and administrative
          expense. At December 31, 2006, the current portion of the liability totaled
          $18.2 million and the long-term portion totaled $16.3 million.
 
 **Outlook**
 
 With
          a
          $170 million capital budget, Provident is expecting another active year
          in 2007.
          Weakening commodity prices early in the year impacted cash flow, although
          management is taking advantage of the stronger forward commodity prices
          to add
          some additional hedging to protect a floor level of EBITDA in each of the
          business units.
 
 In
          the
          Canadian Oil and Gas Production business (COGP), Provident intends to spend
          $72
          million across its six operating areas in 2007. Over half of that capital
          will
          be deployed on the recently-acquired assets in Northwest Alberta and the
          organic
          shallow gas play in Southwest Saskatchewan. The planned divestiture of
          heavy oil
          assets in Lloydminster that was mentioned in the third quarter press release
          did
          not take place. Provident did not receive bids of sufficient value to warrant
          a
          transaction, reflecting the uncertainty in the marketplace late in the
          year
          caused by the government taxation announcement.
 
 Provident
          expects COGP production to average 22,000 to 24,000 boed in 2007. Operating
          costs should stay reasonably consistent with 2006 levels. In 2007, COGP
          will
          continue to focus on strengthening internal operating capability, and
          specifically on applying the shallow gas knowledge gained in Southwest
          Saskatchewan to the new natural gas assets in Northwest Alberta.
 
 In
          the
          U.S. Oil and Gas Production business (USOGP), Provident plans to spend
          $53
          million in 2007, a significant portion of which will be used for Orcutt
          and
          other growth opportunities. The MLP will continue to pursue acquisition
          opportunities that fit its successful business model, such as the Permian
          Basin
          acquisition that was completed early in 2007. Production is expected to
          average
          8,000 to 8,500 boed in 2007, which includes both the
 -30-
 TABLE
                OF CONTENTS
  MLP
          and
          the pre-existing business. These numbers assume initial production from
          the
          Orcutt diatomite project late in 2007. Operating costs are expected to
          stay
          fairly consistent with 2006 levels, as weaker commodity prices have not
          yet
          translated into lower costs in that business.
 
 In
          the
          Midstream business, Provident plans to spend $42 million in capital expenditures
          in 2007, of which only $6 million is required for sustaining capital. The
          remainder is planned for growth projects including further expansion of
          the
          condensate rail offloading terminal and new storage caverns at Redwater.
 
 2007
          Midstream EBITDA will depend on the business environment. Thus far in the
          first
          quarter, frac spreads have weakened from their 2006 highs, and lower commodity
          prices have reduced product margins in absolute terms. However, propane
          demand
          has been strong in Eastern North America, effectively drawing down Provident’s
          substantial winter propane inventories.
 
 The
          remaining $3 million in capital is intended for corporate purposes. In
          addition,
          the Trust will incur one-time net expenditures of approximately $23 million
          in
          2007 and 2008 related to a move of the Calgary head office into a new building.
          These expenditures will be amortized over the 14 year term of the lease.
          As a
          result of Provident’s growth, employees are currently housed in two buildings,
          both of which are full to capacity. The planned 2008 move into Livingston
          Place,
          an office complex currently under construction, will accommodate growth
          and
          improve efficiency by consolidating all employees into a single location.
 
 With
          respect to corporate priorities for 2007, Provident management will continue
          to
          develop strategy in response to the government taxation announcement in
          2007, as
          well as evaluate acquisition opportunities that may arise as the energy
          trust
          sector adjusts to the planned tax changes. As always, Provident’s primary focus
          is on delivering long-term value and sustainability for unitholders. In
          2006,
          the Trust delivered a total return for investors of 13.8 percent, which
          was
          among the very best of the energy trusts in a challenging year.
  **COGP
          segment review**
  **Crude
              oil and liquids price**
 COGP
                  
                  
                  **Year
                      ended December 31,**($
                      per bbl)
                  
                  
                  **2006**
                  
                  2005
                  
                  %
                      Change**Oil
                      per barrel**WTI
                      (US$)
                  
                  
                  
                  **$**
                  **66.22**
                  
                  $
                  56.56
                  
                  
                  17Exchange
                      rate (from US$ to Cdn$)
                  
                  
                  
                  
                  **1.13**
                  
                  
                  1.21
                  
                  
                  (7
                  )WTI
                      expressed in Cdn$
                  
                  
                  
                  **$**
                  **74.83**
                  
                  $
                  68.44
                  
                  
                  9**Realized
                      pricing before financial derivative instruments**Light/Medium
                      oil
                  
                  
                  
                  **$**
                  **57.18**
                  
                  $
                  52.02
                  
                  
                  10Heavy
                      oil
                  
                  
                  
                  **$**
                  **36.80**
                  
                  $
                  31.33
                  
                  
                  17Natural
                      gas liquids
                  
                  
                  
                  **$**
                  **51.91**
                  
                  $
                  49.15
                  
                  
                  6Crude
                      oil and natural gas liquids
                  
                  
                  
                  **$**
                  **52.38**
                  
                  $
                  45.25
                  
                  
                  16
 The
          above
          prices are net of transportation expense.
 
 For
          the
          year ended December 31, 2006 COGP’s realized crude oil and natural gas liquids
          price, prior to the impact of financial derivative instruments, increased
          by 16
          percent to average $52.38 compared to $45.25 in 2005. The 2006 increase
          related
          to a 17 percent higher US$ WTI crude oil price, narrower pricing differentials
          on all crude oil streams and a reduction in Provident’s heavy oil volumes as a
          percentage of its oil production mix price partially offset by a stronger
          Canadian dollar.
 
 **Natural
          gas price**
  COGP**Year
                      ended December 31,**($
                      per mcf)
                  
                  
                  **2006**
                  
                  2005
                  
                  %
                      ChangeAECO
                      monthly index (Cdn$ per mcf)
                  
                  
                  
                  $
                  6.98
                  
                  $
                  8.49
                  
                  
                  (18
                  )Corporate
                      natural gas price per mcf
                    before
                      financial derivative instruments
                  
                  
                  
                  $
                  6.66
                  
                  $
                  8.42
                  
                  
                  (21
                  )
 -31-
 TABLE
                OF CONTENTS
  The
          above
          prices are net of transportation expense.
 
 For
          the
          year ended December 31, 2006 COGP’s realized natural gas price, excluding
          financial derivative instruments, decreased 21 percent as compared to 2005,
          comparable to the decrease in the benchmark AECO monthly index price. Provident
          markets approximately 17 percent of its natural gas to aggregators and
          mainly
          sells to the market on daily indices, receiving prices that are based on
          the
          heat content of the natural gas. Provident’s realized prices and changes in
          prices can therefore differ from benchmark indices.
 
 **Production**
 **Year
                      ended December 31,**COGP**2006**
                  
                  2005
                  
                  %Change**Daily
                      production**Crude
                      oil - Light/Medium (bpd)
                  
                  
                  **6,815**
                  
                  
                  8,058
                  
                  
                  (15
                  )-
                      Heavy (bpd)
                  
                  
                  **2,057**
                  
                  
                  4,358
                  
                  
                  (53
                  )Natural
                      gas liquids (bpd)
                  
                  
                  **1,401**
                  
                  
                  1,572
                  
                  
                  (11
                  )Natural
                      gas (mcfd)
                  
                  
                  **82,469**
                  
                  
                  74,936
                  
                  
                  10Oil
                      equivalent (boed)(1)
                  
                  
                  **24,018**
                  
                  
                  26,477
                  
                  
                  (9
                  )(1)Provident reports equivalent production converting natural
                      gas to oil on a
                      6:1 basis.
  For
          the
          year ended December 31, 2006, COGP production averaged 24,018 boed, a nine
          percent decrease compared to 26,477 boed in 2005. The additional production
          from
          the Rainbow assets acquired on August 31, 2006 and the production volumes
          added
          through drilling and optimization activities were more than offset by the
          disposition of 2,100 boed of production in September 2005 and natural production
          declines.
 
 Provident
          does not have any single property providing greater than 10 percent of
          total
          production, which mitigates exposure to production failure.
 
 COGP’s
          production summarized by core areas is as follows:
 COGP**Year
                      ended December 31, 2006**
                  
                  West
                      Central Alberta
                  
                  Southern
                    Alberta
                  
                  Northwest
                    Alberta
                  
                  Southeast
                      Saskatchewan
                  
                  Southwest
                      Saskatchewan
                  
                  Lloydminster
                  
                  Other
                  
                  **Total****Daily
                      production**Crude
                      oil - Light/Medium (bpd)
                  
                  
                  1,109
                  
                  
                  2,244
                  
                  
                  58
                  
                  
                  1,704
                  
                  
                  321
                  
                  
                  1,322
                  
                  
                  57
                  
                  
                  6,815-
                      Heavy (bpd)
                  
                  
                  -
                  
                  
                  -
                  
                  
                  -
                  
                  
                  -
                  
                  
                  -
                  
                  
                  2,057
                  
                  
                  -
                  
                  
                  2,057Natural
                      gas liquids (bpd)
                  
                  
                  1,227
                  
                  
                  127
                  
                  
                  24
                  
                  
                  -
                  
                  
                  -
                  
                  
                  22
                  
                  
                  1
                  
                  
                  1,401Natural
                      gas (mcfd)
                  
                  
                  34,989
                  
                  
                  23,195
                  
                  
                  8,778
                  
                  
                  164
                  
                  
                  13,820
                  
                  
                  1,324
                  
                  
                  199
                  
                  
                  82,469Oil
                      equivalent (boed)(1)
                  
                  
                  8,168
                  
                  
                  6,237
                  
                  
                  1,545
                  
                  
                  1,731
                  
                  
                  2,624
                  
                  
                  3,622
                  
                  
                  91
                  
                  
                  24,018
 
 COGP**Year
                      ended December 31, 2005**
                  
                  West
                      Central Alberta
                  
                  Southern
                    Alberta
                  
                  Northwest
                    Alberta
                  
                  Southeast
                      Saskatchewan
                  
                  Southwest
                      Saskatchewan
                  
                  Lloydminster
                  
                  Other
                  
                  Total**Daily
                      production**Crude
                      oil - Light/Medium (bpd)
                  
                  
                  1,300
                  
                  
                  2,722
                  
                  
                  -
                  
                  
                  1,714
                  
                  
                  845
                  
                  
                  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
                  
                  
                  -
                  
                  
                  202
                  
                  
                  6,260
                  
                  
                  1,909
                  
                  
                  22
                  
                  
                  74,936Oil
                      equivalent (boed)(1)
                  
                  
                  9,406
                  
                  
                  7,262
                  
                  
                  -
                  
                  
                  1,747
                  
                  
                  1,889
                  
                  
                  6,162
                  
                  
                  11
                  
                  
                  26,477(1)Provident reports equivalent production converting natural
                      gas to oil on a
                      6:1 basis.
  Internal
          development activities included 59.0 net wells drilled for the year ended
          December 31, 2006 with a 98 percent success rate. Provident’s most active areas,
          southeast and southwest Saskatchewan realized 31.5 net wells drilled. The
          focus
          of southern Saskatchewan is a shallow gas drilling program that will realize
          production and reserve additions for several years. Provident’s other core areas
          remain active with additional activity in southern Alberta where Provident
          is
          actively drilling shallow gas wells resulting in 14.3 net wells drilled
          and in
          Lloydminster
 -32-
 TABLE
                OF CONTENTS
  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. COGP’s new area, Northwest
          Alberta, drilled 5.4 net wells in 2006 as it began the winter drilling
          program,
          which was ahead of its planned 2007 drilling schedule due to favourable
          weather
          conditions and advanced planning. Additions to proved plus probable reserves
          before revisions through internal capital replaced approximately 42 percent
          of
          annual production.
 
 **Revenue
          and royalties**
 COGP**Year
                      ended December 31,**($
                      000s except per boe and mcf data)
                  
                  
                  
                  **2006**
                  
                  2005
                  
                  %Change**Oil**Revenue
                  
                  
                  
                  
                  **$**
                  **169,852**
                  
                  $
                  202,845
                  
                  
                  (16
                  )Realized
                      loss on financial derivative instruments
                  
                  
                  
                  
                  
                  **(3,193**
                  **)**
                  
                  (42,700
                  )
                  
                  (93
                  )Royalties
                      (net of ARTC)
                  
                  
                  
                  
                  
                  **(32,567**
                  **)**
                  
                  (40,067
                  )
                  
                  (19
                  )Net
                      revenue
                  
                  
                  
                  
                  **$**
                  **134,092**
                  
                  $
                  120,078
                  
                  
                  12Net
                      revenue (per barrel)
                  
                  
                  
                  
                  **$**
                  **41.41**
                  
                  $
                  26.50
                  
                  
                  56Royalties
                      as a percentage of revenue
                  
                  
                  
                  
                  
                  **19.2**
                  **%**
                  
                  19.8
                  %**Natural
                      gas**Revenue
                  
                  
                  
                  
                  **$**
                  **200,584**
                  
                  $
                  230,195
                  
                  
                  (13
                  )Realized
                      gain (loss) on financial derivative instruments
                  
                  
                  
                  
                  
                  **7,564**
                  
                  
                  (5,608
                  )
                  
                  -Royalties
                      (net of ARTC)
                  
                  
                  
                  
                  
                  **(42,200**
                  **)**
                  
                  (48,484
                  )
                  
                  (13
                  )Net
                      revenue
                  
                  
                  
                  
                  **$**
                  **165,948**
                  
                  $
                  176,103
                  
                  
                  (6
                  )Net
                      revenue (per mcf)
                  
                  
                  
                  
                  **$**
                  **5.51**
                  
                  $
                  6.44
                  
                  
                  (14
                  )Royalties
                      as a percentage of revenue
                  
                  
                  
                  
                  
                  **21.0**
                  **%**
                  
                  21.1
                  %**Natural
                      gas liquids**Revenue
                  
                  
                  
                  
                  **$**
                  **26,545**
                  
                  $
                  28,203
                  
                  
                  (6
                  )Royalties
                  
                  
                  
                  
                  
                  **(6,458**
                  **)**
                  
                  (6,852
                  )
                  
                  (6
                  )Net
                      revenue
                  
                  
                  
                  
                  **$**
                  **20,087**
                  
                  $
                  21,351
                  
                  
                  (6
                  )Net
                      revenue (per barrel)
                  
                  
                  
                  
                  **$**
                  **39.28**
                  
                  $
                  37.21
                  
                  
                  6Royalties
                      as a percentage of revenue
                  
                  
                  
                  
                  
                  **24.3**
                  **%**
                  
                  24.3
                  %**Total**Revenue
                  
                  
                  
                  
                  **$**
                  **396,981**
                  
                  $
                  461,243
                  
                  
                  (14
                  )Realized
                      gain (loss) on financial derivative instruments
                  
                  
                  
                  
                  
                  **4,371**
                  
                  
                  (48,308
                  )
                  
                  -Royalties
                      (net of ARTC)
                  
                  
                  
                  
                  
                  **(81,225**
                  **)**
                  
                  (95,403
                  )
                  
                  (15
                  )Net
                      revenue
                  
                  
                  
                  
                  **$**
                  **320,127**
                  
                  $
                  317,532
                  
                  
                  1Net
                      revenue (per boe)
                  
                  
                  
                  
                  **$**
                  **36.52**
                  
                  $
                  32.86
                  
                  
                  11Royalties
                      as a percentage of revenue
                  
                  
                  
                  
                  
                  **20.5**
                  **%**
                  
                  20.7
                  %Note:
                      the above revenue, net revenue and net revenue per boe figures
                      are
                      presented net of transportation
                      expenses.
 For
          the
          year ended December 31, 2006 COGP production revenue was $397.0 million,
          a
          decrease of 14 percent from $461.2 million in 2005. The decrease in revenue
          is a
          result of lower realized natural gas price and lower crude oil and natural
          gas
          liquids production partially offset by higher realized crude oil and natural
          gas
          liquids prices and the additional natural gas production from the Rainbow
          assets
          acquired on August 31, 2006. Royalties as a percentage of revenue have
          remained
          relatively constant at approximately 20.5 percent compared to the prior
          year.
          The preceding factors, as well as the $4.4 million realized gain on financial
          derivative instruments compared to a $48.3 million loss in 2005, account
          for net
          revenue of $320.1 million in 2006, one percent higher than the $317.5 million
          recorded in 2005.
 -33-
 TABLE
                OF CONTENTS
  Net
          revenue per boe in 2006 increased 11 percent to $36.52 from $32.86 in 2005
          resulting primarily from a higher realized gain on financial derivative
          instruments and a reduction of lower priced heavy oil volumes to nine percent
          of
          total production in 2006 compared to 16 percent in 2005 and increases in
          realized crude oil and natural gas liquids prices. These price increases
          were
          more than offset by lower realized natural gas prices as described above
          combined with the increased proportion of natural gas production to 57
          percent
          of total production in 2006 compared to 47 percent in 2005.
 
 **Production
          expenses**
 COGP
                  
                  
                  **Year
                      ended December 31,**($
                      000s, except per boe data)
                  
                  
                  
                  **2006**
                  
                  2005
                  
                  %
                      ChangeProduction
                      expenses
                  
                  
                  
                  
                  **$**
                  **97,626**
                  
                  $
                  95,278
                  
                  
                  2Production
                      expenses (per boe)
                  
                  
                  
                  
                  **$**
                  **11.14**
                  
                  $
                  9.86
                  
                  
                  13
 
 For
          the
          year ended December 31, 2006 production expenses increased two percent
          to $97.6
          million from $95.3 million and increased by 13 percent to $11.14 per boe
          from
          $9.86 per boe in the prior year. Throughout 2006, 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 included
          higher than expected costs for electricity and adjustments related to prior
          periods operating costs by operators on non-operated properties. Cost increases
          in power and fuel, chemicals and well servicing reflect higher commodity
          prices
          and labour costs.
 
 **Operating
          netback**
 COGP
                  
                  
                  **Year
                      ended December 31,**($
                      per boe)
                  
                  
                  
                  **2006**
                  
                  2005
                  
                  %
                      Change**Netback
                      per boe**Gross
                      production revenue
                  
                  
                  
                  
                  **$**
                  **45.29**
                  
                  $
                  47.73
                  
                  
                  (5
                  )Royalties
                      (net of ARTC)
                  
                  
                  
                  
                  
                  **(9.27**
                  **)**
                  
                  (9.87
                  )
                  
                  (6
                  )Operating
                      costs
                  
                  
                  
                  
                  
                  **(11.14**
                  **)**
                  
                  (9.86
                  )
                  
                  13Field
                      operating netback
                  
                  
                  
                  
                  
                  **24.88**
                  
                  
                  28.00
                  
                  
                  (11
                  )Realized
                      gain (loss) on financial derivative instruments
                  
                  **0.50**
                  
                  
                  (5.00
                  )
                  
                  -Operating
                      netback after realized financial derivative instruments
                  **$**
                  **25.38**
                  
                  $
                  23.00
                  
                  
                  10
  COGP
          operating netbacks have transportation expense netted against gross production
          revenue.
 
 The
          2006
          field operating netback of $24.88 per boe was 11 percent below the $28.00
          per
          boe for the prior year. This reflects COGP’s lower realized natural gas prices
          due to the decrease in benchmark AECO monthly index price combined with
          the
          increased proportion of natural gas production to 57 percent of total production
          from 47 percent in 2005. This was partially offset by increased realized
          crude
          oil and natural gas liquids prices and a decrease in COGP’s production mix of
          low netback heavy oil to nine percent in 2006 from 16 percent in 2005.
          Royalties, which are price sensitive, decreased by six percent on a boe
          basis
          reflecting lower prices, prior to the impact of financial derivative
          instruments. The 2006 operating netbacks after financial derivative instruments
          increased by 10 percent to $25.38 from $23.00 in the prior year due to
          the
          preceding factors as well as a realized gain on financial derivative instruments
          of $0.50 per boe compared to losses of $5.00 per boe in the prior
          year.
 
 **General
          and administrative**
 COGP
                  
                  
                  **Year
                      ended December 31,**($
                      000s, except per boe data)
                  
                  
                  
                  **2006**
                  
                  2005
                  
                  %
                      ChangeCash
                      general and administrative
                  
                  
                  
                  
                  **$**
                  **24,065**
                  
                  $
                  18,552
                  
                  
                  30Non-cash
                      unit based compensation
                  
                  
                  
                  
                  
                  **4,320**
                  
                  
                  2,640
                  
                  
                  64**$**
                  **28,385**
                  
                  $
                  21,192
                  
                  
                  34Cash
                      general and administrative (per boe)
                  
                  
                  
                  
                  **$**
                  **2.75**
                  
                  $
                  1.92
                  
                  
                  43
 In
          2006
          COGP cash general and administrative expenses increased 30 percent to $24.1
          million compared to $18.6 million in 2005. On a boe basis, cash general
          and
          administrative expenses increased 43 percent to $2.75 per boe in  -34-
 TABLE
                OF CONTENTS
  2006
          compared to the $1.92 per boe in the prior year. The increase in cash 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, including costs related to the implementation of procedures
          and
          documentation in connection with the U.S. Sarbanes-Oxley Act.
 
 COGP
          operations are capable of absorbing additional production, particularly
          in
          existing core areas, with little impact on cash general and administrative
          expenses.
 
 Non-cash
          unit based compensation increased 64 percent to $4.3 million in 2006 from
          $2.6
          million in 2005. The increase reflects a more competitive landscape affecting
          the cost of hiring and compensating employees and increased incentives
          due to
          performance of the Trust on specific performance indicators.
 
 **Capital
          expenditures**
 COGP
                  
                  
                  **Year
                      ended December 31,**($
                      000s)
                  
                  
                  
                  **2006**
                  
                  2005**Capital
                      expenditures - by area**West
                      central Alberta
                  
                  
                  
                  
                  **$**
                  **11,280**
                  
                  $
                  10,514Southern
                      Alberta
                  
                  
                  
                  
                  
                  **17,619**
                  
                  
                  21,513Northwest
                      Alberta
                  
                  
                  
                  
                  
                  **4,883**
                  
                  
                  -Southeast
                      Saskatchewan
                  
                  
                  
                  
                  
                  **1,941**
                  
                  
                  3,147Southwest
                      Saskatchewan
                  
                  
                  
                  
                  
                  **25,677**
                  
                  
                  38,496Lloydminster
                  
                  
                  
                  
                  
                  **7,262**
                  
                  
                  9,865Office
                      and other
                  
                  
                  
                  
                  
                  **1,426**
                  
                  
                  1,867Total
                      additions
                  
                  
                  
                  
                  **$**
                  **70,088**
                  
                  $
                  85,402**Capital
                      expenditures - by category**Geological,
                      geophysical and land
                  
                  
                  
                  
                  **$**
                  **4,508**
                  
                  $
                  8,473Drilling,
                      recompletions, and workovers
                  
                  
                  
                  
                  
                  **56,807**
                  
                  
                  41,315Facilities
                      and equipment
                  
                  
                  
                  
                  
                  **6,353**
                  
                  
                  33,626Other
                      capital
                  
                  
                  
                  
                  
                  **2,420**
                  
                  
                  1,988Total
                      additions
                  
                  
                  
                  
                  **$**
                  **70,088**
                  
                  $
                  85,402Property
                      acquisitions
                  
                  
                  
                  
                  **$**
                  **482,369**
                  
                  $
                  586Property
                      dispositions
                  
                  
                  
                  
                  **$**
                  **(1,264**
                  **)**
                  $
                  45,100
 In
          2006,
          Provident’s COGP segment spent $27.6 million in the Southeast and Southwest
          Saskatchewan core areas on acquiring mineral rights for future development
          ($3.2
          million), drilling for shallow gas and recompletions ($21.5 million), and
          facility work ($2.9 million). In Southern Alberta $17.6 million was spent
          on
          drilling activities and recompletions ($15.5 million), facility upgrades
          ($0.9
          million) and seismic and mineral rights acquisitions ($1.1 million). In
          West
          central Alberta $11.3 million was spent largely on non-operated drilling
          ($8.5
          million) and facility work ($2.2 million). COGP’s new area, Northwest Alberta,
          spent $4.9 million primarily on drilling activities and preparation for
          the
          winter drilling program which was ahead of its planned winter drilling
          schedule
          at year end. Provident spent $7.3 million in the Lloydminster area primarily
          on
          drilling and recompletion activities ($6.9 million) and facility work ($0.3
          million). Office and other items accounted for $1.4 million of capital.
 
 On
          August
          31, 2006 Provident acquired a package of natural gas producing assets in
          the
          Rainbow and Peace River Arch areas of northwestern Alberta. The assets
          are
          expected to provide daily production of approximately 5,500 barrels of
          oil
          equivalent, over 90 percent of which is natural gas, and over 200 identified
          drilling locations.
  The
          purchase price was $472.8 million (including acquisition costs) and was
          financed
          by the issuance of 16,325,000 units at $13.85 per unit and Provident’s credit
          facilities (see note 3 to consolidated financial statements).
 
 In
          the
          fourth quarter of 2006, COGP also spent $8.6 million on property acquisitions
          primarily on acquiring additional working interests in Northwest Alberta
          ($6.7
          million) and in Southern Alberta ($1.7 million).
 -35-
 TABLE
                OF CONTENTS
  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. COGP will continue to seek opportunities to dispose of its non-core
          properties given the competitive property market.
 
 **Depletion,
          depreciation and accretion (DD&A)**
 COGP
                  
                  
                  **Year
                      ended December 31,**($
                      000s, except per boe data)
                  
                  
                  
                  **2006**
                  
                  2005
                  
                  %
                      ChangeDD&A
                  
                  
                  
                  
                  **$**
                  **168,953**
                  
                  $
                  155,929
                  
                  
                  8DD&A
                      per boe
                  
                  
                  
                  
                  **$**
                  **19.27**
                  
                  $
                  16.13
                  
                  
                  19
 
 The
          COGP
          DD&A rate of $19.27 per boe increased 19 percent for 2006 compared to $16.13
          per boe in 2005. The increase was primarily as a result of the Rainbow
          asset
          acquisition. Additions to property, plant and equipment of $660.4 million
          for
          the acquisition include $185.7 million due to the recording of future income
          taxes. This, combined with higher net per boe reserve acquisition costs,
          resulted in increased per boe DD&A. 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
          2006
          DD&A also includes accretion expense associated with asset retirement
          obligation of $1.9 million (2005 - $2.5 million).
 
 As
          part
          of the reconciliation of Provident’s financial statements to United States
          generally accepted accounting principles (U.S. GAAP), disclosed in note
          18 to
          consolidated financial statements, the Trust has reflected additional depletion
          in 2006 of $382.2 million (2005 - nil) and a related future income tax
          recovery
          of $114.7 million as a result of the application of the U.S. GAAP ceiling
          test.
          These changes were not required under Canadian generally accepted
          principles.
  **USOGP
          segment review**
 
 The
          USOGP
          business unit incorporates activities from certain Provident subsidiaries
          comprising an oil and gas exploitation and production organization based
          in Los
          Angeles, California.
 
 In
          the
          fourth quarter of 2006, Provident, through its USOGP subsidiaries, completed
          its
          initial public offering (“IPO”) of 6.9 million units at U.S. $18.50 per unit of
          BreitBurn Energy Partners, L.P. (the “MLP”). This master limited partnership
          (NASDAQ-BBEP) is a U.S. public, tax flow-through entity similar to Canadian
          royalty and income trusts such as Provident. Selected producing assets
          in the
          Los Angeles basin in California and in Wyoming were transferred to the
          MLP. The
          MLP operates approximately two-thirds of existing USOGP production and
          approximately one-half of USOGP reserves. The previously existing subsidiary
          (“BreitBurn”) continues to operate some Los Angeles basin assets at West Pico
          and the Orcutt field (which is the site of the steam-assisted diatomite
          pilot
          project). At December 31, 2006 the Trust indirectly owns approximately
          66
          percent of the MLP and 96 percent of BreitBurn. The MLP and BreitBurn continue
          to be managed by the management team which operated the USOGP business
          unit
          prior to the IPO. The USOGP segment includes the consolidated results of
          the MLP
          and BreitBurn. Non-controlling interests include the public ownership in
          the
          MLP, the ownership interests of the managers in the MLP and BreitBurn,
          as well
          as third party investment in USOGP’s land development project which commenced in
          the second quarter of 2006.
 -36-
 TABLE
                OF CONTENTS
  **Crude
          oil, natural gas liquids and natural gas pricing**
 USOGP
                  
                  
                  
                  **Year
                      ended December 31,**($
                      per bbl, except as noted)
                  
                  
                  
                  **2006**
                  
                  2005
                  
                  %
                      Change**Oil
                      per barrel**WTI
                      (US$)
                  
                  
                  
                  
                  **$**
                  **66.22**
                  
                  $
                  56.56
                  
                  
                  17Exchange
                      rate (from US$ to Cdn$)
                  
                  
                  
                  
                  
                  **1.13**
                  
                  
                  1.21
                  
                  
                  (7
                  )WTI
                      expressed in Cdn$
                  
                  
                  
                  
                  **$**
                  **74.83**
                  
                  $
                  68.44
                  
                  
                  9**Realized
                      pricing before financial derivative instruments**Light/Medium
                      oil (Cdn$)
                  
                  
                  
                  
                  **$**
                  **63.25**
                  
                  $
                  57.80
                  
                  
                  9Natural
                      gas liquids (Cdn$)
                  
                  
                  
                  
                  **$**
                  **57.07**
                  
                  $
                  45.12
                  
                  
                  26Natural
                      gas (Cdn$ per mcf)
                  
                  
                  
                  
                  **$**
                  **6.58**
                  
                  $
                  9.01
                  
                  
                  (27
                  )Crude
                      oil and natural gas liquids (Cdn$)
                  
                  
                  
                  
                  **$**
                  **63.24**
                  
                  $
                  57.76
                  
                  
                  9
 
 The
          increase in crude oil realized pricing reflects higher market prices in
          2006,
          compared to 2005. Production from California properties is generally light,
          sweet crude that attracts smaller differentials to benchmark prices relative
          to
          heavier blends. Production from Wyoming properties primarily acquired through
          the acquisition of Nautilus on March 2, 2005 is heavier and attracts wider
          differentials. Production from California properties also receives better
          prices
          than Canadian or Wyoming production because of the proximity to refineries
          and
          ultimate market. Production from California properties for the year ended
          December 31, 2006 represented approximately 70 percent of total production
          while
          production from Wyoming properties represented approximately 30 percent
          of total
          production.
 
 **Production**
 **Year
                      ended December 31,**USOGP
                  
                  
                  
                  **2006**
                  
                  2005
                  
                  %
                      Change**Daily
                      production - by product**Crude
                      oil - Light/Medium (bpd)
                  
                  
                  
                  
                  
                  **7,299**
                  
                  
                  6,921
                  
                  
                  5Natural
                      gas liquids (bpd)
                  
                  
                  
                  
                  
                  **18**
                  
                  
                  24
                  
                  
                  (25
                  )Natural
                      gas (mcfd)
                  
                  
                  
                  
                  
                  **2,422**
                  
                  
                  2,159
                  
                  
                  12Oil
                      equivalent (boed)(1)
                  
                  
                  
                  
                  
                  **7,721**
                  
                  
                  7,305
                  
                  
                  6(1)Provident reports equivalent production converting natural
                      gas to oil on a
                      6:1 basis.
 
 **Year
                      ended December 31,**USOGP
                  
                  
                  
                  **2006**
                  
                  2005
                  
                  %
                      Change**Daily
                      Production - by area (boed)****(1)**Los
                      Angeles
                  
                  
                  
                  
                  
                  **3,901**
                  
                  
                  3,949
                  
                  
                  (1
                  )Santa
                      Maria - Orcutt
                  
                  
                  
                  
                  
                  **1,491**
                  
                  
                  1,393
                  
                  
                  7Wyoming
                  
                  
                  
                  
                  
                  **2,329**
                  
                  
                  1,963
                  
                  
                  19**7,721**
                  
                  
                  7,305
                  
                  
                  6(1)Provident reports equivalent production converting natural
                      gas to oil on a
                      6:1 basis.
 
 Production
          for the year ended December 31, 2006 was 7,721 boed or six percent higher
          than
          the year ended December 31, 2005. The increase is primarily attributable
          to a
          full year of production from the Wyoming properties acquired in the Nautilus
          acquisition on March 2, 2005. In total, the Wyoming properties acquired
          on March
          2, 2005 added 2,254 boed to production in the year ended December 31, 2006
          (2005
          - 1,888 boed). In 2005, the acquired properties added 2,260 boed for the
          period
          from acquisition on March 2 to December 31, 2005.
 
 **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 2006
          and 2005) on behalf of third parties .  -37-
 TABLE
                OF CONTENTS
 USOGP
                  
                  
                  **Year
                      Ended December 31,**($
                      000s, except per boe and mcf amounts)
                  
                  
                  
                  **2006**
                  
                  2005
                  
                  %
                      Change**Oil**Revenue
                  
                  
                  
                  
                  **$**
                  **168,954**
                  
                  $
                  146,306
                  
                  
                  15Realized
                      loss on financial derivative instruments
                  
                  
                  
                  
                  
                  **(2,505**
                  **)**
                  
                  (16,323
                  )
                  
                  (85
                  )Royalties
                  
                  
                  
                  
                  
                  **(16,546**
                  **)**
                  
                  (14,022
                  )
                  
                  18Net
                      revenue
                  
                  
                  
                  
                  **$**
                  **149,903**
                  
                  $
                  115,961
                  
                  
                  29Net
                      revenue (per bbl)
                  
                  
                  
                  
                  **$**
                  **56.27**
                  
                  $
                  45.90
                  
                  
                  23Royalties
                      as a percentage of revenue
                  
                  
                  
                  
                  
                  **9.8**
                  **%**
                  
                  9.6
                  %**Natural
                      gas**Revenue
                  
                  
                  
                  
                  **$**
                  **5,820**
                  
                  $
                  7,101
                  
                  
                  (18
                  )Royalties
                  
                  
                  
                  
                  
                  **(761**
                  **)**
                  
                  (988
                  )
                  
                  (23
                  )Net
                      revenue
                  
                  
                  
                  
                  **$**
                  **5,059**
                  
                  $
                  6,113
                  
                  
                  (17
                  )Net
                      revenue (per mcf)
                  
                  
                  
                  
                  **$**
                  **5.72**
                  
                  $
                  7.76
                  
                  
                  (26
                  )Royalties
                      as a percentage of revenue
                  
                  
                  
                  
                  
                  **13.1**
                  **%**
                  
                  13.9
                  %**Natural
                      gas liquids**Revenue
                  
                  
                  
                  
                  **$**
                  **368**
                  
                  $
                  395
                  
                  
                  (7
                  )Royalties
                  
                  
                  
                  
                  
                  **(8**
                  **)**
                  
                  (9
                  )
                  
                  (11
                  )Net
                      revenue
                  
                  
                  
                  
                  **$**
                  **360**
                  
                  $
                  386
                  
                  
                  (7
                  )Net
                      revenue (per bbl)
                  
                  
                  
                  
                  **$**
                  **54.79**
                  
                  $
                  44.05
                  
                  
                  24Royalties
                      as a percentage of revenue
                  
                  
                  
                  
                  
                  **2.2**
                  **%**
                  
                  2.4
                  %**Total**Revenue
                  
                  
                  
                  
                  **$**
                  **175,142**
                  
                  $
                  153,802
                  
                  
                  14Realized
                      loss on financial derivative instruments
                  
                  
                  
                  
                  
                  **(2,505**
                  **)**
                  
                  (16,323
                  )
                  
                  (85
                  )Royalties
                  
                  
                  
                  
                  
                  **(17,315**
                  **)**
                  
                  (15,019
                  )
                  
                  15Net
                      revenue
                  
                  
                  
                  
                  **$**
                  **155,322**
                  
                  $
                  122,460
                  
                  
                  27Net
                      revenue (per boe)
                  
                  
                  
                  
                  **$**
                  **55.12**
                  
                  $
                  45.93
                  
                  
                  20Royalties
                      as a percentage of revenue
                  
                  
                  
                  
                  
                  **9.9**
                  **%**
                  
                  9.8
                  %
 
 Royalty
          rates in the U.S. are significantly lower than in Canada.
 
 Revenue
          for the year ended December 31, 2006 was $175.1 million or 14 percent higher
          than the year ended December 31, 2005. The increase is attributable to
          the
          acquisition of the Wyoming properties on March 2, 2005 combined with increased
          crude oil prices. Net revenue was $155.3 million or 27 percent higher than
          the
          $122.5 million of net revenue in 2005. A full year of production in 2006
          from
          the Wyoming properties combined with increased crude oil prices and lower
          realized losses on financial derivative instruments all contribute to the
          increase. Royalties as a percentage of revenue for the year ended December
          31,
          2006 were consistent with royalty rates for the year ended December 31,
          2005.
 
 **Production
          expenses**
 **Year
                      ended December 31,**USOGP($
                      000s, except per boe amounts)
                  
                  
                  
                  **2006**
                  
                  2005
                  
                  %
                      ChangeProduction
                      expenses
                  
                  
                  
                  
                  **$**
                  **52,008**
                  
                  $
                  39,513
                  
                  
                  32Production
                      expenses (per boe)
                  
                  
                  
                  
                  **$**
                  **18.45**
                  
                  $
                  14.82
                  
                  
                  24
 
 Production
          expenses increased 32 percent to $52.0 million in 2006 compared to $39.5
          million
          in 2005. Production expenses per boe have increased 24 percent to $18.45
          in 2006
          from $14.82 in 2005. 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 continuing strong crude oil prices.
 -38-
 TABLE
                OF CONTENTS
  **Operating
          netback**
 USOGP
                  
                  
                  **Year
                      ended December 31,**($
                      per boe)
                  
                  
                  
                  **2006**
                  
                  2005
                  
                  %
                      Change**USOGP
                      oil equivalent netback per boe**Gross
                      production revenue
                  
                  
                  
                  
                  **$**
                  **62.15**
                  
                  $
                  57.68
                  
                  
                  8Royalties
                  
                  
                  
                  
                  
                  **(6.14**
                  **)**
                  
                  (5.63
                  )
                  
                  9Operating
                      costs
                  
                  
                  
                  
                  
                  **(18.45**
                  **)**
                  
                  (14.82
                  )
                  
                  24Field
                      operating netback
                  
                  
                  
                  
                  **$**
                  **37.56**
                  
                  $
                  37.23
                  
                  
                  1Realized
                      loss on financial derivative instruments
                  
                  **(0.89**
                  **)**
                  
                  (6.12
                  )
                  
                  (85
                  )Operating
                      netback after realized financial derivative instruments
                  **$**
                  **36.67**
                  
                  $
                  31.11
                  
                  
                  18
 USOGP
          operating netbacks remained strong throughout 2006 due to high commodity
          prices
          and lower realized losses on financial derivative instruments when compared
          to
          2005 partially offset by increased production costs.
 
 **General
          and administrative**
 **Year
                      ended December 31,**USOGP($
                      000s, except per boe amounts)
                  
                  
                  
                  
                  
                  **2006**
                  
                  
                  2005
                  
                  
                  %
                      ChangeCash
                      general and administrative
                  
                  
                  
                  
                  **$**
                  **26,519**
                  
                  $
                  11,490
                  
                  
                  131Non-cash
                      unit based compensation
                  
                  
                  
                  
                  
                  **12,476**
                  
                  
                  6,098
                  
                  
                  105**$**
                  **38,995**
                  
                  $
                  17,588
                  
                  
                  122Cash
                      general and administrative (per boe)
                  
                  
                  
                  
                  **$**
                  **9.41**
                  
                  $
                  4.31
                  
                  
                  118
 Cash
          general and administrative expenses were $26.5 million or $9.41 per boe
          in 2006,
          compared to $11.5 million, or $4.31 per boe in 2005. Cash general and
          administrative expense in 2006 includes $5.0 million payments of incentive
          plans, representing $1.75 per boe compared to $2.3 million in 2005 or $0.85
          per
          boe. Also included in cash general and administrative expense in 2006 is
          $1.5
          million (2005 - nil) of due diligence expenditures relating to a real estate
          development project representing $0.53 per boe (2005 - nil). The remaining
          increase is costs associated with compliance (including costs associated
          with
          the implementation of procedures and documentation to be in compliance
          with U.S.
          Sarbanes-Oxley Act) and increased staffing levels, as well as legal and
          consulting costs in connection with the initial public offering of the
          MLP.
 
 Non-cash
          unit based compensation increased 105 percent to $12.5 million from $6.1
          million
          in 2005. This increase in incentive plan costs is primarily driven by the
          initial public offering of the MLP, completed in the fourth quarter of
          2006.
 -39-
 TABLE
              OF CONTENTS
   **Capital
          expenditures**
 USOGP**Year
                      ended December 31,**($
                      000s)
                  
                  
                  
                  **2006**
                  
                  2005**Capital
                      expenditures - by category**Geological,
                      geophysical and land
                  
                  
                  
                  
                  **$**
                  **104**
                  
                  $
                  4,608Drilling,
                      recompletions, and workovers
                  
                  
                  
                  
                  
                  **30,943**
                  
                  
                  29,470Facilities
                      and equipment
                  
                  
                  
                  
                  
                  **18,486**
                  
                  
                  18,035Other
                      capital
                  
                  
                  
                  
                  
                  **4,804**
                  
                  
                  784Total
                      additions
                  
                  
                  
                  
                  **$**
                  **54,337**
                  
                  $
                  52,897**Capital
                      expenditures - by area**Los
                      Angeles
                  
                  
                  
                  
                  
                  **17,886**
                  
                  
                  33,848Santa
                      Maria - Orcutt
                  
                  
                  
                  
                  
                  **16,579**
                  
                  
                  8,528Wyoming
                  
                  
                  
                  
                  
                  **15,023**
                  
                  
                  5,183Other
                      capital
                  
                  
                  
                  
                  
                  **4,849**
                  
                  
                  5,338**54,337**
                  
                  
                  52,897Property
                      acquisitions
                  
                  
                  
                  
                  **$**
                  **(2,012**
                  **)**
                  $
                  -Property
                      dispositions
                  
                  
                  
                  
                  **$**
                  **(4**
                  **)**
                  $
                  -
  USOGP
          capital expenditures for the year ended December 31, 2006 totaled $52.3
          million
          including the second quarter adjustment of $2.0 million to reduce accrued
          acquisition transaction costs related to past acquisitions. Of this total
          $29.6
          million related to drilling, optimization and facility upgrades at West
          Pico,
          Santa Fe Springs and Orcutt. $15.0 million was directed at optimization
          projects
          in Wyoming, $3.4 million was directed to a land development project initiated
          in
          the second quarter and $6.3 million was directed at optimization projects
          at
          smaller fields as well as office equipment.
 
 **Depletion,
          depreciation and accretion (DD&A)**
 **Year
                      ended December 31,**USOGP($
                      000s, except per boe amounts)
                  
                  
                  
                  **2006**
                  
                  2005
                  
                  %
                      ChangeDD&A
                  
                  
                  
                  
                  **$**
                  **31,058**
                  
                  $
                  25,553
                  
                  
                  22DD&A
                      per boe
                  
                  
                  
                  
                  **$**
                  **11.02**
                  
                  $
                  9.58
                  
                  
                  15
 
 The
          USOGP’s DD&A rate is low due to the long-lived nature of the
          assets.
 
 On
          a per
          boe basis the DD&A rate is up $1.44 or 15 percent from 2005. This is
          primarily associated with a year end depletion rate adjustment reflecting
          2006
          capital expenditures as well as changes in reserves.
 
 **Recent
          developments**
 
 On
          January 23, 2007, the MLP completed a purchase of certain oil and gas properties
          in the Permian Basin of Texas, including related property and equipment,
          for
          approximately U.S. $29.0 million. The acquisition was financed through
          borrowings under the MLP's existing revolving credit facility.
 -40-
 TABLE
              OF CONTENTS
   **Midstream
          services and marketing business segment review**
  **Midstream
          NGL acquisition**
 
 The
          $773
          million Midstream NGL Acquisition, which closed on December 13, 2005, included
          NGL extraction plants, pipelines, storage and fractionation facilities,
          distribution facilities, and contracts including marketing, supply and
          transportation arrangements, and NGL marketing infrastructure. This acquisition
          has extended Provident’s involvement in the NGL value chain. Results in 2005
          included NGL fee for service, fixed margin extraction, equity margin on
          marketed
          NGLs, and margin on crude oil marketing contracts. The crude oil marketing
          contracts were disposed in May 2005, thus 2006 results include an increase
          in
          fees for services, fixed margin extraction and equity margin on marketed
          NGLs.
 
 **The
          Midstream business**
 
 The
          Midstream business unit extracts, processes, stores, transports and markets
          natural gas liquids (NGL) for Provident and offers these services to third
          party
          customers. The Provident Midstream segment contains three business lines:
 a)
                Empress
                    East
 b)
                Redwater
                    West
 c)
                Commercial
                    Services
 
 a.
                The
                    Empress East business line is comprised of the following core
                    assets:
 
 ·
                Approximately
                    2.0 Bcfd of extraction capacity at Empress Alberta. This is the
                    combination of 67.5 percent ownership of the 1.2 Bcfd capacity
                    Provident
                    Empress NGL Extraction plant, 12.4 percent ownership in the 1.1
                    Bcfd
                    capacity ATCO Plant, 8.3 percent ownership in the 2.4 Bcfd capacity
                    Spectra Plant and 33.0 percent ownership in the 2.7 Bcfd capacity
                    BP
                    Empress 1 Plant.
 
 ·
                100
                    percent ownership of a 50,000 bpd debutanizer at Empress
                    Alberta.
 
 ·
                50
                    percent ownership in the 130,000 bpd 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 a
                    300,000 barrel Superior Storage staging facility and 18.3 percent
                    ownership of the 6,600 bpd Superior
                    Depropanizer.
 
 ·
                In
                    Sarnia, Ontario, 10.3 percent ownership of an approximately 150,000
                    bpd
                    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. An additional 0.5 mmbbls of specification product
                    storage is
                    also available in the Sarnia area.
 
 ·
                A
                    propane distribution terminal at Lynchburg,
                    Virginia.
 
 ·
                A
                    rail car fleet of approximately 350 rail cars.
 
 The
          income for this business line is primarily driven by the pricing relationship
          of
          natural gas at AECO to NGL values in Belvieu. Provident purchases the NGLs
          from
          suppliers at Empress at gas values and then extracts the NGLs from the
          gas at
          the various straddle plants. Propane, butane and condensate prices trend
          on a
          pricing relationship to crude oil. Provident sells this product and other
          acquired specification product into key market areas such as Ontario, Quebec,
          and the Eastern Seaboard. The higher the ratio of the WTI crude oil price
          to the
          natural gas price at AECO (the fractionation spread ratio “frac spread ratio”),
          the higher the gross operating margin this business line will typically
          deliver.
          There has also, however, historically been a differential between propane,
          butane and condensate prices and crude oil prices which can change prices
          received and margins realized for Midstream products separate from frac
          spread
          ratio changes. The margin for this business line was $133.7 million in
          2006.
 -41-
 TABLE
              OF CONTENTS
   b.
                The
                    Redwater West business line is comprised of the following core
                    assets:
 
 ·
                100
                    percent ownership of the Redwater NGL Fractionation Facility,
                    incorporating a 65,000 bpd fractionation, storage and transportation
                    facility that includes 12 pipeline receipt and delivery points,
                    railcar
                    loading facilities with direct access to CN rail and indirect
                    access to CP
                    rail, two propane truck loading facilities, six million gross
                    barrels of
                    salt cavern storage, and a 60,000 bpd condensate rail offloading
                    facility
                    with a 300 railcar storage yard. The facility can process high-sulphur
                    NGL
                    streams and is one of only two ethane-plus fractionation facilities
                    in
                    western Canada capable of extracting ethane from the natural
                    gas liquids
                    stream.
 
 ·
                Approximately
                    7,000 bpd of leased fractionation and storage capacity at other
                    facilities.
 
 ·
                43.3
                    percent direct ownership and 100% control of all products from
                    the 38,500
                    bpd Younger NGL extraction plant located at Taylor in northeastern
                    British
                    Columbia that supplies local markets and Provident in the greater
                    Fort
                    Saskatchewan area.
 
 ·
                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.
 
 ·
                A
                    rail car fleet of approximately 450 rail
                    cars.
 
 The
          income for this business line includes the long term natural gas liquids
          purchase agreement from Taylor Gas Liquids for its share of the production
          at
          the same plant. Further, this business line includes the income generated
          by the
          supply and marketing personnel in the Calgary office which includes the
          purchasing of NGL mix from various producers transporting to Redwater/Ft.
          Saskatchewan for fractionation and sale to various markets primarily in
          Western
          Canada and the Western United States. 2006 margin for this business line
          was
          $69.5 million.
 
 c.
                The
                    Commercial Services business line:
 
 The
          Commercial Services business line includes services such as fractionation,
          storage, and loading at Provident’s Redwater facility on a fee basis. It also
          includes pipeline tariff income from Provident’s ownership of the Liquids
          Gathering System in Northwest Alberta which flows into Pembina’s pipeline from
          LaGlace to Redwater. Provident also collects tariff income from its 50%
          ownership in the Kerrobert Pipeline which transports NGLs from Empress
          to
          Kerrobert for injection into the Enbridge pipeline for delivery to Sarnia.
          Further, Provident owns a debutanizer at its Empress facility, which removes
          condensate from the NGL mix for sale as a diluent to blend with heavy oil.
          This
          service is provided to a major energy company on a long term cost of service
          basis. Earnings from this business line of the Midstream segment have little
          direct exposure to market prices volatility and are thus relatively stable.
          2006
          margin for this business line was $52.8 million.
 
 **Long
          term contracts**
 
 At
          the
          Redwater facility, a significant portion of the available propane plus
          capacity
          is contracted through a long term fee for service arrangement with third
          parties.
 
 In
          2006
          Provident commissioned a 60,000 bpd condensate rail off-loading terminal
          at
          Redwater, a significant portion of which is under long term contracts with
          two
          major energy producers.
 
 The
          ethane produced from Provident’s facilities at Empress and Redwater is largely
          sold under long term contracts.
 
 Provident
          also has a long term contract on a cost of service basis for the majority
          of its
          50,000 bbl/d Empress debutantizer facility and a long term contract for
          500,000
          barrels of specification product storage in the Sarnia area.
 
 Also,
          see
          commitments disclosure in note 16 to consolidated financial
          statements.
 -42-
 TABLE
                OF CONTENTS
  **Operations
          - managed NGL volumes**
 
 In
          2006,
          Provident Midstream managed approximately 153,020 bpd compared to 64,740
          bpd in
          2005, an increase of 136 percent. Managed volumes are NGL products that
          have
          been purchased or received for further processing and/or sale. The significant
          increase in 2006 is a result of the Midstream NGL Acquisition.
 
 2006
          Midstream business unit results can be summarized as follows:
 
 Year
                      ended December 31,($
                      millions)
                  
                  **2006**Empress
                      East Margin
                  
                  $
                  133.7Redwater
                      West Margin
                  
                  
                  69.5Commercial
                      Services Margin
                  
                  
                  52.8Gross
                      operating margin
                  
                  
                  256.0Cash
                      general and administrative expenses and other
                  
                  
                  (21.0
                  )Realized
                      loss on financial derivative instruments
                  
                  
                  (15.4
                  )Midstream
                      EBITDA
                  
                  
                  219.6
 
 
 **Revenues**
  For
          2006
          product sales and services revenue were $1,764.4 million (2005 - $908.1
          million). The significant increase in revenue over 2005 is a result of
          the
          Midstream NGL Acquisition, an increase in propane plus prices in the second
          and
          third quarters of 2006 over the comparable quarters in 2005, and the
          commissioning of the condensate loading and terminalling facilities in
          the
          second quarter of 2006. Product sales relate to the marketing of NGLs and
          transportation and fractionation contracts (T&F), while service revenue
          relates to fees earned through NGL processing, marketing, storage and
          distribution. The majority of NGL revenues are earned pursuant to both
          long-term
          contracts and annual evergreen purchase and sales commitments.
 
 In
          addition to the increased product sales and service revenue, Midstream
          revenue
          was reduced by $15.4 million for the year ended December 31, 2006 (2005
          - $2.2
          million) due to realized losses on financial derivative instruments. Midstream
          enters into derivative contracts to assist with margin stabilization on
          marketed
          products.
 
 **Expenses**
  For
          2006
          the cost of goods sold (COGS) was $1,471.2 million (2005 - $786.6 million).
          Cost
          of goods sold relates to NGL product sales revenue included in product
          sales and
          services revenue. COGS include all costs incurred in the production and
          purchase
          of NGL specification product for sale. The majority of the natural gas
          liquids
          are purchased pursuant to long-term contracts and annual evergreen purchase
          commitments. The significant increase in COGS over 2005 is a result of
          the
          Midstream NGL Acquisition which has resulted in an increase in managed
          volumes.
 
 Operating
          and maintenance expenses were $22.6 million for 2006 (2005 - $36.4 million).
          Since the third quarter of 2006, costs include operating costs incurred
          to
          process NGLs, and provide T&F, and storage and distribution services to
          third parties. In prior periods, operating costs also included costs incurred
          at
          the Younger and Redwater facilities for NGLs Provident had purchased. These
          costs are now included in the determination of inventory and cost of goods
          sold,
          reflecting the integration of operations after the Midstream NGL
          Acquisition.
 
 General
          and administrative expenses were $29.9 million in 2006 (2005 - $12.6 million)
          representing an increase in the scale of segment operations and an increased
          number of employees since the Midstream NGL Acquisition. As well, there
          were
          increased costs for integration and compliance activities, including costs
          related to the implementation of procedures and documentation in connection
          with
          the U.S. Sarbanes-Oxley Act. Interest expense for 2006 was $32.1 million
          (2005 -
          $4.9 million) reflecting an increase in capitalization associated with
          the
          Midstream NGL Acquisition. Depreciation expense was $49.1 million in 2006
          (2005
          - $11.8 million) reflecting the larger asset base acquired through the
          Midstream
          NGL Acquisition. The majority of the property, plant and equipment are
          depreciated on a straight-line basis reflecting the long useful life of
          these
          assets of 30 to 40 years.
 -43-
 TABLE
                OF CONTENTS
  **Earnings
          before interest, taxes, depletion, depreciation, accretion, and other non-cash
          items (“EBITDA”)**  **and
          cash flow from operations**
 
 For
          2006
          EBITDA increased 211 percent to $219.6 million from $70.7 million in 2005.
          Annual cash flow increased 178 percent to $184.4 million from $66.3 million
          in
          2005. Through the Midstream NGL Acquisition, Provident has expanded its
          involvement in the NGL value chain and increased managed volumes by 136
          percent
          to 153,020 bpd, which has made a significant contribution to the overall
          increase in EBITDA and cash flow. In addition, Midstream EBITDA and cash
          flow
          benefited from an increase in propane plus prices in the second and third
          quarters of 2006 over the comparable quarters in 2005 accompanied by a
          reduction
          in associated product costs, mostly due to reduced natural gas
          prices.
 
 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”).
 
 **Fractionation
          spread support program**
  As
          part
          of the Midstream NGL Acquisition, the vendor agreed to provide a near-term
          fractionation spread support program. The program provides Provident with
          up to
          $75 million of support until November 2007 if the fractionation spread
          ratio is
          below historic levels. This program is intended to ensure that Provident
          achieves the long-term average fractionation spread ratio that 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 the fractionation
          spread ratio exceeds 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.
 
 The
          impact of the agreement on the 2006 results was a $5.2 million repayment
          in the
          first quarter of 2006, of an amount that was received in the fourth quarter
          of
          2005, resulting in an increase in the cost of goods available for sale
          in 2006.
 
 **Capital
          expenditures**
  Midstream
          capital expenditures for 2006 totaled $66.0 million. $42.0 million of the
          capital was spent on the new condensate offloading facilities and truck
          terminals at Redwater. $9.2 million was spent on the initial drilling of
          two new
          Redwater storage caverns expected to be completed in 2009, and $11.3 million
          was
          spent to acquire an additional 7.5% of the Provident Empress NGL Extraction
          plant. The remaining $3.5 million relates to sustaining capital
          requirements.
  **Foreign
          ownership**
 
 Based
          on
          information received from our transfer agent and financial intermediaries
          in
          January 2007, 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 securities 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 interest on
          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
 
 -44-
 TABLE
                OF CONTENTS
  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.
 
 **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 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
          Netherland, Sewell & Associates, Inc., an independent engineering firm, 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 is 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.
 -45-
 TABLE
                OF CONTENTS
  **Recent
          accounting pronouncements**
 
 **Convergence
          of Canadian GAAP with International Financial Reporting
          Standards**
 
 In
          2006,
          Canada’s Accounting Standards Board (AcSB) issued a strategic plan that will
          result in Canadian GAAP, as it applies to publicly accountable entities,
          being
          converged with International Financial Reporting Standards over a transitional
          period. The AcSB is expected to develop and release a detailed implementation
          plan with a transition period initially indicated to be five years. The
          Trust
          will consider the effect that this implementation plan might have on the
          consolidated financial statements during the transition period.
 
 **Accounting
          changes**
 
 In
          2006,
          the CICA released Section 1506 “Accounting Changes” which establishes criteria
          for changing accounting policies. Under the new section, voluntary changes
          in
          accounting policy are only made if they result in the financial statements
          providing reliable and more relevant information. Changes in accounting
          policy
          are applied retroactively unless it is impracticable to do so or the change
          in
          accounting policy is made on initial application of a primary source of
          GAAP,
          and that primary source of GAAP has specific transitional provisions. All
          material prior period errors are to be corrected retroactively. This section
          is
          effective for interim and annual financial statements for fiscal years
          beginning
          on or after January 1, 2007. The Trust does not expect the adoption of
          this
          standard to have a material impact on its financial statements.
 
 **Capital
          disclosures**
 
 In
          2006,
          the CICA released Section 1535 “Capital disclosures” which addresses the
          requirements for an entity to disclose qualitative information about its
          objectives, policies and processes for managing capital. This section also
          establishes the requirement for an entity to disclose quantitative data
          about
          what it regards as capital as well as disclose whether it has complied
          with any
          externally imposed capital requirements and, if not, the consequences of
          such
          non-compliance. This section is effective for interim and annual financial
          statements relating to fiscal years beginning on or after October 1, 2007.
          The
          Trust is currently evaluating the effect that this standard might have
          on the
          consolidated financial statements.
 
 **Discontinued
          operations**
 
 In
          April
          2006, the CICA issued EIC abstract 161 “Discontinued Operations” which
          specifically addresses issues regarding the treatment of interest expense
          to be
          allocated to a discontinued operation, general corporate overhead expenses
          allocated to a discontinued operations, and reporting the results of operations
          of a component of the enterprise classified as held for sale as discontinued
          operations if the remaining operations are insignificant. The accounting
          treatment of the abstract may be applied prospectively and should be applied
          to
          all disposal transactions initiated after the date of issue of the abstract.
          The
          adoption of this abstract has not had a material impact on the Trust’s
          consolidated financial statements.
 
 **Stock-based
          compensation for employees eligible to retire before the vesting
          date**
 
 In
          2006,
          the CICA issued EIC abstract 162 “Stock-based compensation for employees
          eligible to retire before the vesting date.” In this abstract, the CICA
          addresses the situation if an employee is eligible to receive a reward
          after the
          employee has retired and is no longer providing service to the entity.
          In this
          situation, the abstract states that the expense associated with the reward
          should be recognized over the period from the grant date to the date the
          employee becomes eligible to retire, or, in situations where the employee
          is
          eligible to retire before the grant date, the entire expense should be
          recognized on the grant date. The accounting treatment of this abstract
          should
          be applied retroactively, with restatement of prior periods in financial
          statements issued for interim and annual periods ending on or after December
          31,
          2006. The adoption of this abstract has not had a material impact on the
          Trust’s
          consolidated financial statements.
 
 **Variable
          interest entities**
 
 In
          2006,
          the CICA issued EIC abstract 163 “Determining the variability to be considered
          in applying AcG-15” which provides guidance on how an entity should determine
          the variability to be considered in applying AcG-15- Consolidation of Variable
          Interest Entities. The abstract is to be applied prospectively to all entities
          with which an enterprise first becomes involved, and to all entities previously
          required to be analyzed under AcG-15 when a
 -46-
 TABLE
                OF CONTENTS
  reconsideration
          event has occurred, beginning the first day of the first interim or annual
          reporting period beginning on or after January 1, 2007. The Trust does
          not
          expect the adoption of this abstract to have a material impact on its financial
          statements.
 
 **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 is currently evaluating the effect that
          these
          standards might have on the consolidated financial statements.
 
 In
          conjunction with the above standards, the CICA issued Section 3862 “Financial
          Instruments- Disclosures” and Section 3863 “Financial Instruments-Presentation.”
Section 3862 requires entities to provide disclosures in their financial
          statements that enable users to evaluate the significance of financial
          instruments to the entity’s financial position and performance. It also requires
          that entities disclose the nature and extent of risks arising from financial
          instruments and how the entity manages those risks. Section 3863 establishes
          presentation guidelines for financial instruments and non-financial derivatives
          and addresses the classification of financial instruments, from the perspective
          of the issuer, between liabilities and equity, the classification of related
          interest, dividends, losses and gains, and circumstances in which financial
          assets and financial liabilities are offset. These two sections are effective
          for annual and interim periods beginning on or after October 1, 2007. The
          Trust
          is currently evaluating the effect that these standards 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 is currently
          evaluating the effect that this standard might have on the consolidated
          financial statements.
 
 **Business
          risks**
 
 The
          trust
          industry is 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:
  ·  capital
          markets risk and the ability to finance future growth; and
  ·  the
          impact of Canadian governmental regulation on Provident, including the
          effect of
          proposed taxation of trust distributions.
 
 The
          oil
          and natural gas 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:
  ·
                fluctuations
                    in commodity price, exchange rates and interest
                    rates;
  ·
                government
                    and regulatory risk in respect of royalty and income tax
                    regimes;
  ·
                operational
                    risks that may affect the quality and recoverability of
                    reserves;
  ·
                geological
                    risk associated with accessing and recovering new quantities
                    of
                    reserves;
  -47-
 TABLE
                OF CONTENTS
  ·
                transportation
                    risk in respect of the ability to transport oil and natural gas
                    to
                    market;
  ·
                marketability
                    of oil and natural gas;
  ·
                the
                    ability to attract and retain employees;
                    and
  ·
                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:
  ·
                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;
  ·
                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;
  ·
                exposure
                    to commodity price fluctuations;
  ·
                the
                    ability to attract and retain
                    employees;
  ·
                regulatory
                    intervention in determining processing fees and tariffs;
                    and
  ·
                reliance
                    on significant customers.
  Provident
          strives to minimize these business risks by:
  ·
                employing
                    and empowering management and technical staff with extensive
                    industry
                    experience and providing competitive
                    remuneration;
  ·
                adhering
                    to a strategy of acquiring, developing and optimizing quality,
                    low-risk
                    reserves in areas where we have technical and operational
                    expertise;
  ·
                developing
                    a diversified, balanced asset portfolio that generally offers
                    developed
                    operational infrastructure, year-round access and close proximity
                    to
                    markets;
  ·
                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;
  ·
                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;
  ·
                marketing
                    natural gas liquids and related services to selected, credit
                    worthy
                    customers at competitive rates;
  ·
                maintaining
                    a low cost structure to maximize cash flow and
                    profitability;
  ·
                maintaining
                    prudent financial leverage and developing strong relationships
                    with the
                    investment community and capital
                    providers;
  ·
                adhering
                    to strict guidelines and reporting requirements with respect
                    to
                    environmental, health and safety practices;
                    and
  ·
                maintaining
                    an adequate level of property, casualty, comprehensive and directors’ and
                    officers’ insurance coverage.
 
 **Unit
          trading activity**
 
 The
          following table summarizes the unit trading activity of the Provident units
          for
          the four quarters ended December 31, 2006 on both the Toronto Stock Exchange
          and
          the New York Stock Exchange:
 -48-
 TABLE
                OF CONTENTS
 
 **Q1**
                
                **Q2**
                
                **Q3**
                
                **Q4****TSE
                    – PVE.UN (Cdn$)**High
                
                $
                13.70
                
                $
                14.31
                
                $
                14.50
                
                $
                13.85Low
                
                $
                11.79
                
                $
                12.87
                
                $
                12.07
                
                $
                10.05Close
                
                $
                13.04
                
                $
                14.00
                
                $
                13.02
                
                $
                12.84Volume
                    (000s)
                
                
                23,113
                
                
                29,205
                
                
                43,411
                
                
                35,081**NYSE
                    – PVX (US$)**High
                
                $
                11.66
                
                $
                12.99
                
                $
                13.04
                
                $
                12.16Low
                
                $
                10.24
                
                $
                11.16
                
                $
                10.81
                
                $
                9.00Close
                
                $
                11.32
                
                $
                12.37
                
                $
                11.75
                
                $
                10.92Volume
                    (000s)
                
                
                36,038
                
                
                29,175
                
                
                33,378
                
                
                35,480
  **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)
                  
                  **2006**
                  
                  2005
                  
                  2004Revenue
                      (net of royalties and financial derivative instruments)
                  
                  **$**
                  **2,187,253**
                  
                  $
                  1,360,274
                  
                  $
                  1,109,857Net
                      income
                  
                  
                  **140,920**
                  
                  
                  96,926
                  
                  
                  21,225Net
                      income per unit-basic
                  
                  
                  **0.72**
                  
                  
                  0.61
                  
                  
                  0.19Net
                      income per unit-diluted
                  
                  
                  **0.72**
                  
                  
                  0.61
                  
                  
                  0.19Total
                      assets
                  
                  
                  **3,435,839**
                  
                  
                  2,792,270
                  
                  
                  1,813,582Long-term
                      financial liabilities(1)
                  
                  
                  **1,132,494**
                  
                  
                  930,756
                  
                  
                  472,712Declared
                      Distributions per unit
                  
                  **$**
                  **1.44**
                  
                  $
                  1.44
                  
                  $
                  1.44(1)Includes long-term debt, asset retirement obligation, long-term
                      financial
                      derivative instruments and other long-term
                      liabilities.
  -49-
 TABLE
              OF CONTENTS
   **Quarterly
          table**
 ($
                      000s except for per unit and operating amounts)
                  
                  
                  **2006**First
                  
                  Second
                  
                  Third
                  
                  Fourth
                  
                  AnnualQuarter
                  
                  Quarter
                  
                  Quarter
                  
                  Quarter
                  
                  Total**Financial
                      - consolidated**Revenue
                  
                  
                  
                  
                  $
                  553,706
                  
                  $
                  424,439
                  
                  $
                  661,022
                  
                  $
                  548,086
                  
                  $
                  2,187,253Cash
                      flow
                  
                  
                  
                  
                  $
                  78,906
                  
                  $
                  110,990
                  
                  $
                  120,089
                  
                  $
                  122,679
                  
                  $
                  432,664Net
                      income (loss)
                  
                  
                  
                  
                  $
                  24,200
                  
                  $
                  21,371
                  
                  $
                  120,850
                  
                  $
                  (25,501
                  )
                  $
                  140,920Net
                      income (loss) per unit - basic
                  
                  
                  
                  
                  $
                  0.13
                  
                  $
                  0.11
                  
                  $
                  0.61
                  
                  $
                  (0.12
                  )
                  $
                  0.72Net
                      income (loss) per unit - diluted
                  
                  
                  
                  
                  $
                  0.13
                  
                  $
                  0.11
                  
                  $
                  0.58
                  
                  $
                  (0.12
                  )
                  $
                  0.72Unitholder
                      distributions
                  
                  
                  
                  
                  $
                  68,350
                  
                  $
                  68,572
                  
                  $
                  70,970
                  
                  $
                  75,573
                  
                  $
                  283,465Distributions
                      per unit
                  
                  
                  
                  
                  $
                  0.36
                  
                  $
                  0.36
                  
                  $
                  0.36
                  
                  $
                  0.36
                  
                  $
                  1.44**Oil
                      and gas production**Cash
                      revenue
                  
                  
                  
                  
                  $
                  114,020
                  
                  $
                  125,744
                  
                  $
                  116,682
                  
                  $
                  125,135
                  
                  $
                  481,581Earnings
                      before interest, DD&A, taxes
                    and
                      other non-cash items
                  
                  
                  
                  
                  $
                  64,313
                  
                  $
                  77,698
                  
                  $
                  67,750
                  
                  $
                  66,497
                  
                  $
                  276,258Cash
                      flow
                  
                  
                  
                  
                  $
                  52,813
                  
                  $
                  71,867
                  
                  $
                  61,471
                  
                  $
                  62,147
                  
                  $
                  248,298Net
                      income (loss)
                  
                  
                  
                  
                  $
                  36,484
                  
                  $
                  25,980
                  
                  $
                  38,117
                  
                  $
                  (14,530
                  )
                  $
                  86,051**Midstream
                      services and marketing**Cash
                      revenue
                  
                  
                  
                  
                  $
                  474,515
                  
                  $
                  367,624
                  
                  $
                  459,603
                  
                  $
                  447,244
                  
                  $
                  1,748,986Earnings
                      before interest, DD&A, taxes
                  
                  
                  
                  
                  $
                  32,813
                  
                  $
                  46,438
                  
                  $
                  65,958
                  
                  $
                  74,422
                  
                  $
                  219,631and
                      other non-cash itemsCash
                      flow
                  
                  
                  
                  
                  $
                  26,093
                  
                  $
                  39,123
                  
                  $
                  58,618
                  
                  $
                  60,532
                  
                  $
                  184,366Net
                      (loss) income
                  
                  
                  
                  
                  $
                  (12,284
                  )
                  $
                  (4,609
                  )
                  $
                  82,733
                  
                  $
                  (10,971
                  )
                  $
                  54,869**Operating**Oil
                      and gas productionLight/medium
                      oil (bpd)
                  
                  
                  
                  
                  
                  14,541
                  
                  
                  13,923
                  
                  
                  13,955
                  
                  
                  13,899
                  
                  
                  14,114Heavy
                      oil (bpd)
                  
                  
                  
                  
                  
                  2,506
                  
                  
                  2,011
                  
                  
                  2,004
                  
                  
                  1,838
                  
                  
                  2,057Natural
                      gas liquids (bpd)
                  
                  
                  
                  
                  
                  1,527
                  
                  
                  1,475
                  
                  
                  1,326
                  
                  
                  1,345
                  
                  
                  1,419Natural
                      gas (mcfd)
                  
                  
                  
                  
                  
                  78,274
                  
                  
                  80,084
                  
                  
                  80,991
                  
                  
                  100,029
                  
                  
                  84,891Oil
                      equivalent (boed)
                  
                  
                  
                  
                  
                  31,620
                  
                  
                  30,756
                  
                  
                  30,784
                  
                  
                  33,753
                  
                  
                  31,739**(Cdn
                      $)****Average
                      selling price net of transportation expense**Light/medium
                      oil per bbl
                  
                  
                  
                  
                  $
                  54.80
                  
                  $
                  69.76
                  
                  $
                  62.95
                  
                  $
                  54.59
                  
                  $
                  60.32(before
                      realized financial derivative instruments)Light/medium
                      oil per bbl
                  
                  
                  
                  
                  $
                  53.40
                  
                  $
                  68.00
                  
                  $
                  60.72
                  
                  $
                  55.56
                  
                  $
                  59.22(including
                      realized financial derivative instruments)Heavy
                      oil per bbl
                  
                  
                  
                  
                  $
                  22.87
                  
                  $
                  50.42
                  
                  $
                  48.15
                  
                  $
                  25.82
                  
                  $
                  36.80(before
                      realized financial derivative instruments)Heavy
                      oil per bbl
                  
                  
                  
                  
                  $
                  22.82
                  
                  $
                  50.42
                  
                  $
                  48.15
                  
                  $
                  25.82
                  
                  $
                  36.78(including
                      realized financial derivative instruments)Natural
                      gas liquids per barrel
                  
                  
                  
                  
                  $
                  53.91
                  
                  $
                  54.20
                  
                  $
                  52.03
                  
                  $
                  47.49
                  
                  $
                  51.98Natural
                      gas per mcf
                  
                  
                  
                  
                  $
                  8.00
                  
                  $
                  6.10
                  
                  $
                  5.88
                  
                  $
                  6.71
                  
                  $
                  6.66(before
                      realized financial derivative instruments)Natural
                      gas per mcf
                  
                  
                  
                  
                  $
                  7.85
                  
                  $
                  6.41
                  
                  $
                  6.24
                  
                  $
                  7.12
                  
                  $
                  6.91(including
                      realized financial derivative instruments)**Midstream
                      services and marketing**Managed
                      NGL volumes (bpd)
                  
                  
                  
                  
                  
                  163,420
                  
                  
                  158,941
                  
                  
                  144,279
                  
                  
                  145,732
                  
                  
                  153,020
 
 -50-
 TABLE
                OF CONTENTS
  **Quarterly
          table**
 ($
                      000s except for per unit and operating amounts)
                  
                  
                  **2005**First
                  
                  Second
                  
                  Third
                  
                  Fourth
                  
                  AnnualQuarter
                  
                  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
                      realized financial derivative instruments)Light/medium
                      oil per bbl
                  
                  
                  
                  
                  $
                  40.93
                  
                  $
                  42.18
                  
                  $
                  49.82
                  
                  $
                  42.52
                  
                  $
                  43.90(including
                      realized financial derivative instruments)Heavy
                      oil per bbl
                  
                  
                  
                  
                  $
                  25.85
                  
                  $
                  26.03
                  
                  $
                  46.74
                  
                  $
                  28.62
                  
                  $
                  31.33(before
                      realized financial derivative instruments)Heavy
                      oil per bbl
                  
                  
                  
                  
                  $
                  25.78
                  
                  $
                  26.03
                  
                  $
                  46.74
                  
                  $
                  28.62
                  
                  $
                  31.31(including
                      realized financial derivative instruments)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
                      realized financial derivative instruments)Natural
                      gas per mcf
                  
                  
                  
                  
                  $
                  6.74
                  
                  $
                  7.13
                  
                  $
                  8.03
                  
                  $
                  11.22
                  
                  $
                  8.23(including
                      realized financial derivative instruments)**Midstream
                      services and marketing**Managed
                      NGL volumes (bpd)
                  
                  
                  
                  
                  
                  61,590
                  
                  
                  58,200
                  
                  
                  61,760
                  
                  
                  77,100
                  
                  
                  64,740
 -51-
 TABLE
            OF CONTENTS






MANAGEMENTS
      RESPONSIBILITY FOR FINANCIAL STATEMENTS


The
        management of Provident is responsible for the information included in this
        Annual Report. The financial statements have been prepared in accordance
        with
        accounting principles generally accepted in Canada and in accordance with
        accounting policies detailed in the notes to the financial statements. Where
        necessary, the statements include amounts based on management  s
        informed judgments and estimates. Financial information in the Annual Report
        is
        consistent with that presented in the financial statements.
  PricewaterhouseCoopers
        LLP, Chartered Accountants, appointed by the unitholders, have audited the
        financial statements and conducted a review of internal accounting policies
        and
        procedures to the extent required by generally accepted auditing standards,
        and
        performed such tests as they deemed necessary to enable them to express an
        opinion on the financial statements.
  The
        Board
        of Directors, through its Audit Committee, is responsible for ensuring that
        management fulfills its responsibility for financial reporting and internal
        control. The Audit Committee is composed of three independent directors.
        The
        Audit Committee reviews the financial content of the Annual Report and reports
        its findings to the Board of Directors for its consideration in approving
        the
        financial statements.
 
  Thomas
                W. Buchanan
              Mark
                  N. Walker
                Chief
                    Financial OfficerChief
                  Executive Officer
 
 
 Calgary,
        Alberta
 March
        7,
        2007


TABLE
          OF CONTENTS


**MANAGEMENT** **** **S
        REPORT ON INTERNAL CONTROL OVER FINANCIAL REPORTING**
  The
        management of Provident is responsible for establishing and maintaining adequate
        internal control over financial reporting for the Trust. Under the supervision
        of our Chief Executive Officer and our Chief Financial Officer we have conducted
        an evaluation of the effectiveness of our internal control over financial
        reporting based on the Internal Control-Integrated Framework issued by the
        Committee of Sponsoring Organizations of the Treadway Commission (COSO).
        Based
        on our assessment, we have concluded that as of December 31, 2006, our internal
        control over financial reporting was effective.
  Because
        of its inherent limitations, internal control over financial reporting may
        not
        prevent or detect misstatements. Also, projections of any evaluation of
        effectiveness to future periods are subject to the risk that controls may
        become
        inadequate because of changes in conditions, or that the degree of compliance
        with the policies or procedures may deteriorate.
  Management  s
        assessment of the effectiveness of the Trust  s
        internal control over financial reporting as of December 31, 2006, has been
        audited by PricewaterhouseCoopers LLP, independent auditors, as stated in
        their
        report which appears herein.
 
 Thomas
                  W. Buchanan
                Mark
                    N. Walker
                  Chief
                      Financial OfficerChief
                    Executive Officer
 
 Calgary,
        Alberta
 March
        7,
        2007




TABLE
          OF CONTENTS





**PricewaterhouseCoopers
                LLP****Chartered
                Accountants**111
                5th Avenue SW, Suite 3100Calgary,
                AlbertaCanada
                T2P 5L3Telephone
                +1 (403) 509 7500**Independent
                Auditors’ Report**
            Facsimile
                +1 (403) 781 1825





**To
      the Unitholders of Provident Energy Trust**





We
      have
      completed an integrated audit of the consolidated financial statements and
      internal control over financial reporting of Provident Energy Trust (the Trust)
      as of December 31, 2006 and an audit of its December 31, 2005 consolidated
      financial statements. Our opinions, based on our audits, are presented
      below.





**Consolidated
      financial statements**





We
      have
      audited the accompanying consolidated balance sheets of the Trust as at December
      31, 2006 and 2005, and the related consolidated statements of operations and
      accumulated income and cash flows for the years then ended. These financial
      statements are the responsibility of the Trust’s management. Our responsibility
      is to express an opinion on these financial statements based on our audits.




We
      conducted our audit of the Trust’s financial statements as at December 31, 2006
      and for the year then ended in accordance with Canadian generally accepted
      auditing standards and the standards of the Public Company Accounting Oversight
      Board (United States). We conducted our audit of the Trust’s financial
      statements as at December 31, 2005 and for the year then ended in accordance
      with Canadian generally accepted auditing standards. Those standards require
      that we plan and perform an audit to obtain reasonable assurance about whether
      the financial statements are free of material misstatement. An audit of
      financial statements includes examining, on a test basis, evidence supporting
      the amounts and disclosures in the financial statements. A financial statement
      audit also includes assessing the accounting principles used and significant
      estimates made by management, and evaluating the overall financial statement
      presentation.




In
      our
      opinion, the consolidated financial statements referred to above present fairly,
      in all material respects, the financial position of the Trust as at December
      31,
      2006 and 2005 and the results of its operations and its cash flows for the
      year
      then ended in accordance with Canadian generally accepted accounting principles.











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







Internal
      control over financial reporting





We
      have
      also audited management's assessment, included in the Management’s Report on
      Internal Control Over Financial Reporting to the unitholders, that the Trust
      maintained effective internal control over financial reporting as of December
      31, 2006, based on criteria established in Internal Control - Integrated
      Framework issued by the Committee of Sponsoring Organizations of the Treadway
      Commission (COSO). The Trust’s management is responsible for maintaining
      effective internal control over financial reporting and for its assessment
      of
      the effectiveness of internal control over financial reporting. Our
      responsibility is to express opinions on management’s assessment and on the
      effectiveness of the Trust’s internal control over financial reporting based on
      our audit.




We
      conducted our audit of internal control over financial reporting in accordance
      with the standards of the Public Company Accounting Oversight Board (United
      States). Those standards require that we plan and perform the audit to obtain
      reasonable assurance about whether effective internal control over financial
      reporting was maintained in all material respects. An audit of internal control
      over financial reporting includes obtaining an understanding of internal control
      over financial reporting, evaluating management’s assessment, testing and
      evaluating the design and operating effectiveness of internal control, and
      performing such other procedures as we consider necessary in the circumstances.
      We believe that our audit provides a reasonable basis for our
      opinions.




A
      company’s internal control over financial reporting is a process designed to
      provide reasonable assurance regarding the reliability of financial reporting
      and the preparation of financial statements for external purposes in accordance
      with generally accepted accounting principles. A company’s internal control over
      financial reporting includes those policies and procedures that (i) pertain
      to
      the maintenance of records that, in reasonable detail, accurately and fairly
      reflect the transactions and dispositions of the assets of the company; (ii)
      provide reasonable assurance that transactions are recorded as necessary to
      permit preparation of financial statements in accordance with generally accepted
      accounting principles, and that receipts and expenditures of the company are
      being made only in accordance with authorizations of management and directors
      of
      the company; and (iii) provide reasonable assurance regarding prevention or
      timely detection of unauthorized acquisition, use, or disposition of the
      company’s assets that could have a material effect on the financial
      statements.




Because
      of its inherent limitations, internal control over financial reporting may
      not
      prevent or detect misstatements. Also, projections of any evaluation of
      effectiveness to future periods are subject to the risk that controls may become
      inadequate because of changes in conditions, or that the degree of compliance
      with the policies or procedures may deteriorate.


TABLE
          OF CONTENTS





In
      our
      opinion, management’s assessment that the Trust maintained effective internal
      control over financial reporting as at December 31, 2006 is fairly stated,
      in
      all material respects, based on criteria established in Internal Control —
Integrated Framework issued by the COSO. Furthermore, in our opinion, the Trust
      maintained, in all material respects, effective internal control over financial
      reporting as of December 31, 2006 based on criteria established in Internal
      Control — Integrated Framework issued by the COSO.







Chartered
        Accountants


Calgary,
        Alberta
 March
        7,
        2007







Comments
      by Auditor 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 18 to the
      Consolidated Financial Statements. Our report 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.


TABLE
          OF CONTENTS


**PROVIDENT
                ENERGY TRUST****CONSOLIDATED
                BALANCE SHEETS**Canadian
                dollars (000s)**As
                at**
            
            As
                at**December
                31,**
            
            December
                31,**2006**
            
            2005**Assets**Current
                assetsCash
                and cash equivalents
            
            **$**
            **10,302**
            
            $
            32,113Accounts
                receivable
            
            
            **270,135**
            
            
            267,246Petroleum
                product inventory
            
            
            **85,868**
            
            
            110,638Prepaid
                expenses
            
            
            **16,381**
            
            
            14,326Financial
                derivative instruments (note 14)
            
            
            **43,337**
            
            
            -**426,023**
            
            
            424,323Cash
                reserve for future site reclamation (note 15)
            
            
            **-**
            
            
            1,872Investments
            
            
            **4,320**
            
            
            3,758Deferred
                financing charges
            
            
            **12,351**
            
            
            14,710Property,
                plant and equipment (note 5)
            
            
            **2,333,537**
            
            
            1,702,689Intangible
                assets (note 6)
            
            
            **193,592**
            
            
            215,850Goodwill
                (note 3)
            
            
            **431,353**
            
            
            429,068Long-term
                financial derivative instruments (note 14)
            
            
            **34,663**
            
            
            -****
            **$**
            **3,435,839**
            
            $
            2,792,270**Liabilities**Current
                liabilitiesAccounts
                payable and accrued liabilities
            
            **$**
            **295,003**
            
            $
            309,704Cash
                distributions payable
            
            
            **21,506**
            
            
            20,644Distributions
                payable to non-controlling interests
            
            
            **677**
            
            
            452Financial
                derivative instruments (note 14)
            
            
            **53,068**
            
            
            14,149**370,254**
            
            
            344,949Long-term
                debt - revolving term credit facilities (note 7)
            
            
            **702,993**
            
            
            586,597Long-term
                debt - convertible debentures (note 7)
            
            
            **285,792**
            
            
            298,007Asset
                retirement obligation (note 9)
            
            
            **49,614**
            
            
            41,133Long-term
                financial derivative instruments (note 14)
            
            
            **77,790**
            
            
            -Other
                long-term liabilities (note 12)
            
            
            **16,305**
            
            
            5,019Future
                income taxes (note 13)
            
            
            **309,006**
            
            
            91,595Non-controlling
                interests (note 10)USOGP
                operations
            
            
            **81,111**
            
            
            11,885Exchangeable
                shares
            
            
            **-**
            
            
            8,259**Unitholders’
                equity**Unitholders’
                contributions (note 11)
            
            
            **2,254,048**
            
            
            1,971,707Convertible
                debentures equity component
            
            
            **18,522**
            
            
            19,301Contributed
                surplus (note 12)
            
            
            **1,315**
            
            
            1,675Cumulative
                translation adjustment
            
            
            **(42,294**
            **)**
            
            (41,785
            )Accumulated
                income
            
            
            **238,208**
            
            
            97,288Accumulated
                cash distributions
            
            
            **(926,825**
            **)**
            
            (643,360
            )**1,542,974**
            
            
            1,404,826**$**
            **3,435,839**
            
            $
            2,792,270





On
                behalf of the Board of Directors:M.H.
                (Mike) Shaikh, CA
            
            Thomas
                W. Buchanan, CADirector
            
            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,****2006**
            
            2005**Revenue**(note
                8)Revenue
            
            **$**
            **2,244,107**
            
            $
            1,419,450Realized
                loss on financial derivative instruments
            
            
            **(13,540**
            **)**
            
            (66,860
            )Unrealized
                (loss) gain on financial derivative instruments
            
            
            **(43,314**
            **)**
            
            7,684**2,187,253**
            
            
            1,360,274**Expenses**Cost
                of goods sold
            
            
            **1,471,171**
            
            
            786,564Production,
                operating and maintenance
            
            
            **172,253**
            
            
            171,193Transportation
            
            
            **19,786**
            
            
            6,932Depletion,
                depreciation and accretion
            
            
            **249,139**
            
            
            193,236General
                and administrative (note 12)
            
            
            **97,288**
            
            
            51,361Interest
                on bank debt
            
            
            **34,666**
            
            
            10,875Interest
                and accretion on convertible debentures
            
            
            **23,919**
            
            
            19,643Amortization
                of deferred financing charges
            
            
            **3,854**
            
            
            1,409Foreign
                exchange gain and other
            
            
            **(2,319**
            **)**
            
            (3,244
            )Gain
                on sale of assets (note 4)
            
            
            **-**
            
            
            (5,188
            )**2,069,757**
            
            
            1,232,781Income
                before taxes and non-controlling interests
            
            
            **117,496**
            
            
            127,493Capital
                tax expense
            
            
            **1,314**
            
            
            4,780Current
                and withholding taxes
            
            
            **5,829**
            
            
            5,628Future
                income tax (recovery) expense (note 13)
            
            
            **(34,316**
            **)**
            
            17,793**(27,173**
            **)**
            
            28,201**Net
                income before non-controlling interests**
            
            
            **144,669**
            
            
            99,292Non-controlling
                interests (note 10)USOGP
                operations
            
            
            **2,995**
            
            
            1,596Exchangeable
                shares
            
            
            **754**
            
            
            770**Net
                income**
            
            
            **140,920**
            
            
            96,926Accumulated
                income, beginning of year
            
            **$**
            **97,288**
            
            $
            362Accumulated
                income, end of year
            
            **$**
            **238,208**
            
            $
            97,288Net
                income per unit - basic
            
            **$**
            **0.72**
            
            $
            0.61Net
                income per unit - diluted
            
            **$**
            **0.72**
            
            $
            0.61





-2-
 TABLE
          OF CONTENTS


**PROVIDENT
                ENERGY TRUST****CONSOLIDATED
                STATEMENT OF CASH FLOWS**Canadian
                Dollars (000s)**Year
                ended****December
                31,****2006**
            
            2005**Cash
                provided by operating activities**Net
                income for the year
            
            **$**
            **140,920**
            
            $
            96,926Add
                (deduct) non-cash items:Depletion,
                depreciation and accretion
            
            
            **249,139**
            
            
            193,236Debenture
                accretion and amortization of deferred charges
            
            
            **6,357**
            
            
            4,090Non-cash
                unit based compensation (notes 12 and 17)
            
            
            **23,083**
            
            
            9,753Unrealized
                loss (gain) on financial derivative instruments (note 8)
            
            
            **43,314**
            
            
            (7,684
            )Unrealized
                foreign exchange loss (gain) and other
            
            
            **418**
            
            
            (356
            )Future
                income tax (recovery) expense (note 13)
            
            
            **(34,316**
            **)**
            
            17,793Net
                income attributable to non-controlling interests
            
            
            **3,749**
            
            
            2,366Equity
                in loss of investee
            
            
            **-**
            
            
            252Gain
                on sale of assets (note 4)
            
            
            **-**
            
            
            (5,188
            )Cash
                flow from operations before changes in working capitaland
                site restoration expenditures
            
            
            **432,664**
            
            
            311,188Site
                restoration expenditures (note 15)
            
            
            **(4,622**
            **)**
            
            (2,481
            )Change
                in non-cash operating working capital
            
            
            **(13,693**
            **)**
            
            (51,344
            )**414,349**
            
            
            257,363**Cash
                provided by financing activities**Increase
                in long-term debt
            
            
            **117,385**
            
            
            325,771Declared
                distributions to unitholders
            
            
            **(283,465**
            **)**
            
            (230,714
            )Declared
                distributions to non-controlling interests
            
            
            **(6,523**
            **)**
            
            (3,360
            )Issue
                of trust units, net of issue costs
            
            
            **257,076**
            
            
            395,805Contributions
                by non-controlling interests (note 10)
            
            
            **135,829**
            
            
            -Issue
                of debentures, net of issue costs
            
            
            **-**
            
            
            239,822Redemption
                of debentures, net of costs
            
            
            **-**
            
            
            (2,997
            )Change
                in non-cash financing working capital
            
            
            **(154**
            **)**
            
            (50
            )**220,148**
            
            
            724,277**Cash
                used for investing activities**Capital
                expenditures
            
            
            **(190,433**
            **)**
            
            (156,499
            )Acquisition
                of Midstream NGL business (note 3)
            
            
            **(1,036**
            **)**
            
            (772,303
            )Acquisition
                of Nautilus
            
            
            **-**
            
            
            (91,420
            )Increase
                in investment
            
            
            **-**
            
            
            (1,010
            )Oil
                and gas property acquisitions (note 3)
            
            
            **(480,357**
            **)**
            
            (586
            )(Payments)
                proceeds from property dispositions
            
            
            **(1,268**
            **)**
            
            45,100Proceeds
                on sale of assets (notes 3 and 4)
            
            
            **11,517**
            
            
            29,295Reclamation
                fund contributions
            
            
            **(2,750**
            **)**
            
            (2,899
            )Reclamation
                fund withdrawals (note 15)
            
            
            **4,622**
            
            
            2,481Payment
                of financial derivative instruments
            
            
            **-**
            
            
            (7,192
            )Change
                in non-cash investing working capital
            
            
            **3,397**
            
            
            5,262**(656,308**
            **)**
            
            (949,771
            )**(Decrease)
                increase in cash and cash equivalents**
            
            
            **(21,811**
            **)**
            
            31,869**Cash
                and cash equivalents beginning of year**
            
            
            **32,113**
            
            
            244**Cash
                and cash equivalents end of year**
            
            **$**
            **10,302**
            
            $
            32,113Supplemental
                disclosure of cash flow informationCash
                interest paid including debenture interest
            
            **$**
            **56,036**
            
            $
            23,946Cash
                taxes paid
            
            **$**
            **9,601**
            
            $
            12,026


-3-
 TABLE
          OF CONTENTS


**NOTES
      TO THE CONSOLIDATED FINANCIAL STATEMENTS**





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





**December
      31, 2006**





**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
                of
                the Trust (“Provident”). Cash flow is paid from Provident to the Trust by
                way of royalty payments, interest payments and principal debt 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 consolidated accounts of all wholly and
                partially
                owned subsidiaries, 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)**
            **Cash
                and cash equivalents**




Cash
                and cash equivalents include short-term investments, such as money
                market
                deposits or similar type instruments, with an original maturity of
                three
                months or less when purchased.




**(iv)**
            **Property,
                plant & equipment and intangible
                assets**




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 for line-fill and cavern bottoms are presented as part of
                property, plant and equipment and are stated at the lower of historic
                cost
                and net realizable value 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




-4-
 TABLE
          OF CONTENTS


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.




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**




Oil
      and
      natural gas assets accounted for using the full cost method are subject to
      a
      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.





**(v)**
            **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.




**(vii)**
            **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.




**(viii)**
            **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.




**(ix)**
            **Unit
                based compensation**




The
                Trust uses the fair value method of valuing compensation expense
                associated with the Trust’s unit option plan. Provident has applied this
                method to options issued after January 1, 2003, the effective date
                for
                implementing stock based compensation. Under the 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.




-5-
 TABLE
            OF CONTENTS


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
                (included in general and administrative expenses) 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.




**(x)**
            **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 issue 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.




**(xi)**
            **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.




**(xii)**
            **Revenue
                recognition**




Revenue
                associated with the sales of Provident’s natural gas, natural gas liquids
                (“NGLs”) 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 when
                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 on a net basis when the services are provided. Revenues
                associated with the sale of natural gas liquids storage services
                are
                recognized when the services are
                provided.




**(xiii)**
            **Foreign
                currency translation**




The
                accounts of self-sustaining foreign operations are translated using
                the
                current rate method, whereby assets and liabilities are translated
                at
                period-end exchange rates, while revenue and expenses are translated
                using
                average rates for the period. Translation gains and losses related
                to
                self-sustaining operations are deferred and included as a separate
                component of unitholders’ equity.




The
                accounts of integrated foreign operations are translated using the
                temporal method, under which monetary assets and liabilities are
                translated at the period-end exchange rate, other assets and liabilities
                at the historical rates, and revenues and expenses at the rates for
                the
                period, except depreciation, depletion and accretion which is translated
                on the same basis as the related assets. Translation gains and losses
                are
                included in income in the period in which they
                arise.




-6-
 TABLE
          OF CONTENTS


**(xiv)**
            **Use
                of estimates**


The
                  preparation of financial statements requires management to make
                  estimates
                  based on currently available information. Actual results could
                  differ from
                  those estimated. 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 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.


**3.**
            **Acquisitions**




**i)**
            **Acquisition
                of Rainbow assets**




On
                August 31, 2006 Provident acquired a package of natural gas producing
                assets in the Rainbow and Peace River Arch areas of northwestern
                Alberta.
                The assets provide daily production of approximately 5,500 barrels
                of oil
                equivalent, over 90 percent of which is natural gas, and over 200
                identified drilling locations. The transaction was accounted for
                as an
                asset purchase with the allocation of the purchase price as
                follows:





Net
                assets acquired and liabilities assumedProperty,
                plant and equipment
            
            $
            660,427Asset
                retirement obligation
            
            
            (1,903
            )Future
                income taxes
            
            
            (185,726
            )$
            472,798ConsiderationAcquisition
                costs
            
            $
            500Cash
            
            
            472,298$
            472,798





The
      acquisition was financed by the issuance of 16,325,000 units at $13.85 per
      unit
      and Provident’s credit facilities.


**ii)**
            **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:




-7-
 TABLE
          OF CONTENTS


Net
                assets acquired and liabilities assumedProperty,
                plant and equipment
            $
            426,817Working
                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
            
            100,409Financial
                derivative instruments
            
            945Asset
                retirement obligation
            
            (7,604
            )Future
                income taxes
            
            (3,173
            )$
            773,339ConsiderationAcquisition
                costs
            $
            12,179Cash,
                net of cash acquired
            
            761,160$
            773,339





The
      Midstream NGL Acquisition was financed by the issue 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.




In
      February 2006, Provident sold its 49 percent interest in the Marysville
      Partnership, which owns the Marysville Underground Storage Terminal (MUST),
      for
      net cash proceeds of $11.5 million. The partnership interest was part of the
      assets acquired in the Midstream NGL acquisition. The purchase price allocation
      of the Midstream NGL acquisition was adjusted to reflect the revised fair value
      of the acquisition, resulting in an increase to goodwill amounting to $2.0
      million.




In
      June
      2006, Provident settled the final post-closing adjustments relating to the
      acquisition. The net cash payment resulted in an increase to goodwill amounting
      to $2.3 million.




In
      December 2006, Provident adjusted its estimate of acquisition costs relating
      to
      the acquisition. The purchase price allocation was adjusted to reflect the
      revised fair value of the acquisition, resulting in a decrease in goodwill
      of
      $2.0 million.


**4.**
            **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 of $5.2 million was recorded 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 are contingent proceeds, amounting
      to $2.7 million, which are held in escrow until this work is
      completed.





-8-
 TABLE
          OF CONTENTS
 **5.**
                **Property,
                      plant and equipment**


**Accumulated****depletion
                and**
            
            **Net
                Book****December
                31, 2006**
            
            **Cost**
            
            **depreciation**
            
            **value**Oil
                and natural gas properties
            
            $
            2,513,031
            
            $
            927,087
            
            $
            1,585,944Midstream
                assets
            
            
            781,092
            
            
            42,143
            
            
            738,949Office
                equipment
            
            
            17,070
            
            
            8,426
            
            
            8,644Total
            
            $
            3,311,193
            
            $
            977,656
            
            $
            2,333,537




Accumulateddepletion
                and
            
            
            Net
                BookDecember
                31, 2005
            
            
            Cost
            
            
            depreciation
            
            
            valueOil
                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
            
            $
            1,702,689





Costs
      associated with unproved properties excluded from costs subject to depletion
      as
      at December 31, 2006 totaled $17.8 million (December 31, 2005 - $23.8 million).
      Asset retirement costs of $49.9 million are included in property, plant and
      equipment (December 31, 2005 - $38.6 million). Midstream assets include $22.0
      million (2005 - $29.3 million) for products required for line-fill and cavern
      bottoms.




An
      impairment test calculation was performed on property, plant and equipment
      at
      December 31, 2006 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 for each cost
      centre.




The
      following table outlines prices used in the impairment test at December 31,
      2006:





**Oil**
            
            **Gas**
            
            **NGL****Year**
            
            **$****/bbl**
            
            **$****/mcf**
            
            **$****/bbl**2007
            
            $
            50.87
            
            $
            7.00
            
            $
            51.662008
            
            $
            50.97
            
            $
            7.57
            
            $
            52.142009
            
            $
            50.18
            
            $
            7.81
            
            $
            50.852010
            
            $
            51.23
            
            $
            7.79
            
            $
            50.262011
            
            $
            51.00
            
            $
            7.78
            
            $
            49.74Thereafter(1)
            
            
            2.00
            %
            
            2.00
            %
            
            2.00
            %(1)Percentage
                change represents the increase in each year after 2011 to the end
                of the
                reserve life.




-9-
 TABLE
          OF CONTENTS
   **6.**
              **Intangible
                    assets**


**Accumulated**
            
            
            **Net
                Book****December
                31, 2006**
            
            
            **Cost**
            
            
            **amortization**
            
            
            **value**Midstream
                and marketing contracts and customer relationships
            
            $
            183,100
            
            $
            12,842
            
            $
            170,258Fractionation
                spread support arrangement
            
            
            17,600
            
            
            9,258
            
            
            8,342Other
                intangible assets
            
            
            16,308
            
            
            1,316
            
            
            14,992Total
            
            $
            217,008
            
            $
            23,416
            
            $
            193,592






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




**7.**
              **Long-term
                      debt**


**December
                31,**
              **2006**
            
            
            December31,
              2005Revolving
                term credit facilities
            
            **$**
            **702,993**
            
            $
            586,597Convertible
                debentures
            
            
            **285,792**
            
            
            298,007**$**
            **988,785**
            
            $
            884,604





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




Provident
                has a $925 million term credit facility with a syndicate of Canadian
                chartered banks secured by midstream assets and by its Canadian oil
                and
                gas properties. 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, 2005 the facility
                totaled $750 million. In July 2006 the facility was increased to
                its
                current level of $925 million. At December 31, 2006, $691.9 million
                was
                drawn on this facility.




The
                terms of the credit facility have a revolving three year period expiring
                on May 30, 2009. Provident
                can extend the revolving period by an additional year, no earlier
                than 90
                days and no later than 30 days prior to the end of the first year
                of the
                applicable three year revolving period. If the lenders do not extend
                the
                revolving period, or Provident chooses not to extend, the credit
                facility
                will be terminated and the loan balance will become due and payable
                in
                full on the maturity date.




In
                addition, Provident’s U.S. subsidiaries have credit facilities with a
                borrowing base of U.S. $158 million with a syndicate of U.S. banks
                secured
                by oil and gas assets of the subsidiaries. Provident may draw upon
                the
                facility by way of U.S. base rate loans, LIBOR loans or letters of
                credit.
                The facilities have a termination date of October 10, 2010 and the
                current
                borrowing base is reviewed every six month period. At December 31,
                2006,
                $11.1 million was drawn on these
                facilities.




At
                December 31, 2006 the effective interest rate of the outstanding
                credit
                facilities was 5.2 percent (2005 - 4.6 percent). At December 31,
                2006
                Provident had $31.9 million in letters of credit outstanding (2005
                - $45.1
                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.


-10-
 TABLE
          OF CONTENTS


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 issue of the 10.5 percent convertible
      debentures, were reclassified to trust unit issue costs as a result of the
      issue
      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 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.







The
      Trust
      may elect to satisfy interest and principal obligations by the issue of trust
      units. For the twelve months ended December 31, 2006, $15.4 million of the
      face
      value of debentures were converted to trust units at the election of debenture
      holders (2005 - $109.3 million, including $45.7 million associated with the
      May
      31, 2005 redemption of the 10.5 percent convertible unsecured subordinated
      debentures). The following table details each outstanding convertible
      debenture.





**Convertible
                Debentures**
            
            **December
                31, 2006**
            
            December
                31, 2005ConversionCarrying
            
            Face
            
            Carrying
            
            Face
            
            
            
            Price
                per($
                000s except conversion pricing)
            
            Value(1)
            
            Value
            
            Value(1)
            
            Value
            
            Maturity
                Date
            
            unit(2)6.5%
                Convertible Debentures
            
            **$**
            **142,860**
            ****
            **$**
            **150,000**
            
            $
            141,522
            
            $
            150,000
            
            
            April
                30, 2011
            
            
            14.756.5%
                Convertible Debentures
            
            
            **93,134**
            
            
            **99,024**
            
            
            92,482
            
            
            99,179
            
            
            Aug.
                31, 2012
            
            
            13.758.0%
                Convertible Debentures
            
            
            **24,402**
            
            
            **25,114**
            
            
            32,382
            
            
            33,648
            
            
            July
                31, 2009
            
            
            12.008.75%
                Convertible Debentures
            
            
            **25,396**
            
            
            **25,972**
            
            
            31,621
            
            
            32,659
            
            
            Dec.
                31, 2008
            
            
            11.05**$**
            **285,792**
            ****
            **$**
            **300,110**
            
            $
            298,007
            
            $
            315,486





(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 price per
                unit.





**8**
            **.**
            **Revenue**


**Year
                  ended December 31,****2006**
              
              2005Gross
                  production revenue
              
              **$**
              **578,255**
              
              $
              621,761Product
                  sales and service revenue
              
              
              **1,764,392**
              
              
              908,111Royalties
              
              
              **(98,540**
              **)**
              
              (110,422
              )**Revenue**
              
              
              **2,244,107**
              
              
              1,419,450Realized
                  loss on financial derivative instruments
              
              
              **(13,540**
              **)**
              
              (66,860
              )Unrealized
                  (loss) gain on financial derivative instruments
              
              
              **(43,314**
              **)**
              
              7,684**$**
              **2,187,253**
              
              $
              1,360,274Change
                  in unrealized loss on financial derivative instruments
              
              **$**
              **(43,314**
              **)**
              $
              9,828Amortization
                  of loss on financial derivative instruments
              
              
              **-**
              
              
              (2,144
              )**Unrealized
                  (loss) gain on financial derivative instruments**
              
              **$**
              **(43,314**
              **)**
              $
              7,684


The
      realized loss on financial derivative instruments for the year ended December
      31, 2006 of $13.5 million (2005 - $66.9 million) relates to the cash settlement
      on derivative instruments.




-11-
 TABLE
          OF CONTENTS






**9.   
      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 has been
      estimated for future years.




The
      total
      undiscounted amount of future cash flows required to settle asset retirement
      obligations related to oil and gas operations is estimated to be $411.6 million
      (2005 - $293.0 million). Payments to settle oil and gas asset retirement
      obligations occur over the operating lives of the assets estimated to be from
      three to 49 years.




The
      total
      undiscounted amount of future cash flows required to settle the midstream
      services and marketing asset retirement obligations is estimated to be $166.1
      million (2005 - $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,****2006**
              
              2005Carrying
                  amount, beginning of year
              
              **$**
              **41,133**
              
              $
              40,506Acquisitions
              
              
              **1,903**
              
              
              9,161Change
                  in estimate
              
              
              **6,793**
              
              
              2,884Increase
                  in liabilities incurred during the period
              
              
              **1,443**
              
              
              1,784Settlement
                  of liabilities during the period
              
              
              **(4,622**
              **)**
              
              (2,614
              )Decrease
                  in liabilities due to disposition
              
              
              **(946**
              **)**
              
              (13,612
              )Accretion
                  of liability
              
              
              **3,910**
              
              
              3,024**Carrying
                  amount, end of year**
              
              **$**
              **49,614**
              
              $
              41,133






**10.    
                Non-controlling interests**


**(i)**
            **USOGP
                operations**


Year
                  ended December 31**,**
              
              **2006**
              
              2005Non-controlling
                  interest, beginning of year
              
              **$**
              **11,885**
              
              $
              13,649Net
                  income attributable to non-controlling interest
              
              
              **2,995**
              
              
              1,596Distributions
                  to non-controlling interest holders
              
              
              **(6,523**
              **)**
              
              (3,360
              )Investments
                  by non-controlling interest
              
              
              **72,754**
              
              
              -Non-controlling
                  interest, end of year
              
              **$**
              **81,111**
              
              $
              11,885Accumulated
                  income attributable to non-controlling interest
              
              **$**
              **5,514**
              
              $
              2,519


A
      non-controlling interest arose from Provident’s June 15, 2004 acquisition of 92
      percent of BreitBurn Energy Company L.P. (BreitBurn) of Los Angeles, California.
      Additional investments since June 2004 by Provident in BreitBurn have reduced
      the non-controlling interest percentage at December 31, 2006 to approximately
      4.4 percent (2005 - 4.4 percent). Contributions by this non-controlling interest
      total $0.5 million in 2006 (2005 - nil).




In
      the
      second quarter of 2006, a USOGP subsidiary began a land development project
      with
      a partner. The subsidiary has a 20 percent interest, with the partner holding
      80
      percent. Because the subsidiary stands to receive a majority share of the future
      proceeds, Provident is consolidating the results in its statements, with
      non-controlling interest. Contributions by the non-controlling interest total
      $3.7 million in 2006.




In
      the
      fourth quarter of 2006, Provident’s subsidiary, BreitBurn Energy Partners, L.P.
      (the “MLP”) completed its initial public offering. BreitBurn transferred oil and
      gas properties comprising approximately half of its proved reserves and two
      thirds of its daily production to the MLP. The


-12-
 TABLE
            OF CONTENTS


offering,
                including an underwriter’s option, of 6,900,000 common units at U.S.
                $18.50 per unit, resulted in approximately 34 percent of the MLP
                held by
                partners not controlled by Provident. Contributions by this
                non-controlling interest total $131.6 million in 2006. Non-controlling
                interest was increased by $68.5 million as a result of this transaction.
                The difference of $63.1 million has been recorded against property,
                plant
                and equipment in accordance with full cost accounting
                principles.




**(ii)**
            **Exchangeable
                shares**




The
                non-controlling interest on the consolidated balance sheet consists
                of the
                fair value of the exchangeable shares upon issue 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. In 2006, all outstanding exchangeable
                shares were converted into Provident trust
                units.




Following
                is a summary of the non-controlling interest - exchangeable shares
                for
                years ended December 31, 2006 and
                2005:







Year
                ended December 31**,**
            
            **2006**
            
            2005Non-controlling
                interest, beginning of year
            
            **$**
            **8,259**
            
            $
            35,921Reduction
                of book value for conversion to trust units
            
            
            **(9,013**
            **)**
            
            (28,432
            )Net
                income attributable to non-controlling interest
            
            
            **754**
            
            
            770Non-controlling
                interest, end of year
            
            **$**
            **-**
            
            $
            8,259Accumulated
                income attributable to non-controlling interest
            
            **$**
            **-**
            
            $
            2,252





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





**Year
                ended December 31,****2006**
            
            2005**Exchangeable
                shares****Provident
                Acquisitions Inc.**
            **Number
                of units**
            
            
            **Amount**
            
            
            Number
                of units
            
            
            AmountBalance
                at beginning of year
            
            
            **-**
            
            **$**
            **-**
            
            
            336,876
            
            $
            3,675Converted
                to trust units
            
            
            **-**
            
            
            **-**
            
            
            (336,876
            )
            
            (3,675
            )Balance,
                end of year
            
            
            **-**
            
            
            **-**
            
            
            -
            
            
            -Exchange
                ratio, end of year
            
            
            **-**
            
            
            
            
            
            -**Trust
                units issuable upon conversion, end of year**
            
            
            **-**
            
            **$**
            **-**
            
            
            -
            
            $
            -**Exchangeable
                shares****Provident
                Energy Ltd.**Balance
                at beginning of year
            
            
            **463,545**
            
            **$**
            **4,961**
            
            
            638,474
            
            $
            6,833Converted
                to trust units
            
            
            **(463,545**
            **)**
            ****
            **(4,961**
            **)**
            
            (174,929
            )
            
            (1,872
            )Balance,
                end of year
            
            
            **-**
            
            
            **-**
            
            
            463,545
            
            
            4,961Exchange
                ratio, end of year
            
            
            **-**
            
            
            
            
            
            1.50962**Trust
                units issuable upon conversion, end of year**
            
            
            **-**
            
            **$**
            **-**
            
            
            699,777
            
            $
            4,961**Exchangeable
                shares (Series B)****Provident
                Energy Ltd.**Balance
                at beginning of year
            
            
            **91,320**
            
            **$**
            **1,046**
            
            
            2,095,271
            
            $
            23,931Converted
                to trust units
            
            
            **(91,320**
            **)**
            ****
            **(1,046**
            **)**
            
            (2,003,951
            )
            
            (22,885
            )Balance,
                end of year
            
            
            **-**
            
            
            **-**
            
            
            91,320
            
            
            1,046Exchange
                ratio, end of year
            
            
            **-**
            
            
            
            
            
            1.19311**Trust
                units issuable upon conversion, end of year**
            
            
            **-**
            
            **$**
            **-**
            
            
            108,955
            
            $
            1,046**Total
                Trust units issuable upon conversion****of
                all exchangeable shares, end of year**
            
            
            **-**
            
            **$**
            **-**
            
            
            808,732
            
            $
            6,007




-13-
 TABLE
          OF CONTENTS


**11.**
            **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.




**(i)**
            **2006
                activity**




On
                July 31, 2006 the Trust issued 16,325,000 Subscription Receipts at
                a price
                of $13.85 per Subscription Receipt for total proceeds of $226.1 million
                ($214.2 million net of issue costs). Each Subscription Receipt entitled
                the holder to receive one trust unit upon completion of the Rainbow
                asset
                acquisition. The acquisition closed on August 31, 2006 at which time
                all
                the outstanding Subscription Receipts were converted into 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 August distribution
                paid in September. This payment was treated as a reduction to the
                proceeds
                received for the units issued through the Subscription Receipts to
                $13.73
                per trust unit, reducing the amount attributed to Unitholders’
                contributions by $2.0 million. Proceeds from the issue were used
                to fund
                the Rainbow asset acquisition.




In
                2006 the Trust issued 6.1 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 $70.1
                million.




**(ii)**
            **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.




-14-
 TABLE
          OF CONTENTS


**Year
                ended December 31,****2006**
            2005**Trust
                Units**
            
            **Number
                of units**
            
            **Amount
                (000s)**
            
            Number
                of units
            
            Amount
                (000s)Balance
                at beginning of year
            
            
            **188,772,788**
            
            **$**
            **1,971,707**
            
            
            142,226,248
            
            $
            1,438,393Issued
                for cash
            
            
            **16,325,000**
            
            
            **224,142**
            
            
            30,230,000
            
            
            373,238Exchangeable
                share conversions
            
            
            **881,083**
            
            
            **9,012**
            
            
            2,971,217
            
            
            28,432Issued
                pursuant to unit option plan
            
            
            **907,201**
            
            
            **8,589**
            
            
            2,265,179
            
            
            23,435Issued
                pursuant to the distribution reinvestment plan
            
            
            **2,714,636**
            
            
            **33,045**
            
            
            1,330,156
            
            
            16,438To
                be issued pursuant to the distribution reinvestment plan
            **300,134**
            
            
            **3,806**
            
            
            107,000
            
            
            2,005Debenture
                conversions
            
            
            **1,327,565**
            
            
            **15,689**
            
            
            6,135,418
            
            
            64,808Redemption
                of the 10.5% debentures (note 7)
            
            
            **-**
            
            
            **-**
            
            
            3,507,570
            
            
            46,707Unit
                issue costs
            
            
            **-**
            
            
            **(11,942**
            **)**
            
            -
            
            
            (21,749
            )**Balance
                at end of year**
            
            
            **211,228,407**
            
            **$**
            **2,254,048**
            
            
            188,772,788
            
            $
            1,971,707




The
          basic
          per trust unit amounts for 2006 were calculated based on the weighted average
          number of units outstanding of 196,627,060 (2005 - 159,315,847). The diluted
          per
          trust unit amounts for 2006 are calculated including an additional 286,957
          trust
          units (2005 - 369,566) for the effect of the unit option plan. Provident’s
          convertible debentures are not included in the computation of diluted earnings
          per unit as their effect is anti- dilutive.




**12.**
            **Unit
                based compensation**




**(i)**
            **Restricted/Performance
                units**




Certain
                employees of the Trust’s Canadian subsidiaries are granted restricted
                trust units (RTUs) and/or performance trust units (PTUs), both of
                which
                entitle the employee to receive cash compensation in relation to
                the value
                of a specific 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. RTUs vest evenly over a period of three
                years commencing at the grant date. 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.
                PTUs
                vest three years from the date of grant and can be increased to a
                maximum
                of double the PTUs granted or a minimum of nil PTUs depending on
                the
                Trust’s performance vis-à-vis other trusts’ performance based on certain
                benchmarks.




As
                of December 31, 2006 there were 571,423 RTUs and 1,704,234 PTUs
                outstanding (2005 - 226,055 RTUs and 464,291 PTUs). The fair value
                estimate associated with the RTUs and PTUs is expensed in the statement
                of
                operations over the vesting period. At December 31, 2006, $2.3 million
                (2005 - $1.0 million) is included in accounts payable and accrued
                liabilities for this plan and $13.3 million (2005 - $2.5 million)
                is
                included in other long-term liabilities. The following table reconciles
                the expense recorded for RTUs and
                PTUs.







**Year
                ended December 31,**
            
            **2006**
            
            2005Cash
                general and administrative
            
            **$**
            **1,021**
            
            $
            -Non-cash
                unit based compensation (included in general and
                administrative)
            
            **11,156**
            
            
            2,600Operating
                expense
            
            
            **939**
            
            
            -**$**
            **13,116**
            
            $
            2,600





**(ii)**
            **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 were eligible to participate in the Plan. There are 8,000,000
                trust units reserved for the Trust option plan. Options were 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 (i)) was approved.
                This
                program replaces the unit option plan. Unit options in existence
                will
                continue to be outstanding.


-15-
 TABLE
            OF CONTENTS


**Year
                ended December 31,**
            
            **2006**
            
            
            
            2005**Weighted**
            
            
            
            Weighted**Number
                of**
            
            **Average**
            
            Number
                of
            
            Average**Options**
            
            **Exercise
                Price**
            
            Options
            
            Exercise
                PriceOutstanding,
                beginning of year
            
            
            **3,205,625**
            
            **$**
            **11.11**
            
            
            5,200,331
            
            $
            11.01Granted
            
            
            **-**
            
            
            **-**
            
            
            296,200
            
            
            11.73Exercised
            
            
            **(907,201**
            **)**
            
            **11.13**
            
            
            (2,265,179
            )
            
            10.97Forfeited
            
            
            **(183,616**
            **)**
            
            **11.08**
            
            
            (25,727
            )
            
            10.97Outstanding,
                end of year
            
            
            **2,114,808**
            
            **$**
            **11.09**
            
            
            3,205,625
            
            $
            11.11**Exercisable,
                end of year**
            
            
            **1,947,989**
            
            **$**
            **11.08**
            
            
            2,206,801
            
            $
            11.12





At
      December 31, 2006, the Trust had 2,114,808 options outstanding with strike
      prices ranging between $10.49 and $12.14 per unit. The weighted average
      remaining contractual life of the options is 1.96 years and the weighted average
      exercise price is $11.09 per unit excluding average potential reductions to
      the
      strike prices of $1.50 per unit.




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




In
      2006
      the Trust recorded non-cash unit based compensation expense of $0.2 million,
      for
      the 5.6 million options granted on or after January 1, 2003 (2005 - $1.1
      million).




As
      at
      December 31, 2006, 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:




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 $0.1 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,**
            
            **2006**
            
            2005Contributed
                surplus, beginning of the year
            
            **$**
            **1,675**
            
            $
            2,002Non-cash
                unit based compensation (included in general and
                administrative)
            
            
            **203**
            
            
            1,055Benefit
                on options exercised charged to unitholders’ equity
            
            
            **(563**
            **)**
            
            (1,382
            )**Contributed
                surplus, end of year**
            
            **$**
            **1,315**
            
            $
            1,675





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




Certain
                employees of the Trust’s U.S. subsidiaries are granted unit appreciation
                rights (UARs) which entitle the employee to receive cash compensation
                in
                relation to the value of a specific number of underlying notional
                trust
                units. UARs vest evenly over a period of three years commencing one
                year
                after grant and expire after four
                years.




The
                UARs 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
                U.S.
                dollars and are based on quoted U.S. distributions and market
                prices.




-16-
 TABLE
            OF CONTENTS


The
      fair
      value associated with the UARs is expensed in the statement of operations over
      the vesting period. At December 31, 2006, $2.5 million (2005 - $0.7 million)
      is
      included in accounts payable and accrued liabilities for this plan and $0.1
      million (2005 - $0.7 million) is included in other long-term liabilities. The
      following table reconciles the expense recorded for UARs.




**Year
                  ended December 31,**
              
              **2006**
              
              2005Cash
                  general and administrative
              
              **$**
              **798**
              
              $
              1,034Non-cash
                  unit based compensation (included in general and
                  administrative)
              
              
              **1,246**
              
              
              1,137**$**
              **2,044**
              
              $
              2,171


**2006**
              
              **2005****Number
                  of Unit Appreciation**
                **Rights**
              
              **Weighted**
                **Average****Exercise**
                **Price
                  (U.S.$)**
              
              Number
                  of Unit
                Appreciation
                Rights
              
              Weighted
                Average
                  Exercise
                Price
                (U.S.$)**Year
                  ended December 31,**Outstanding,
                  beginning of year
              
              
              **768,693**
              
              **$**
              **8.34**
              
              
              976,000
              
              $
              7.98Granted
              
              
              **-**
              
              
              **-**
              
              
              147,000
              
              
              10.01Exercised
              
              
              **(282,840**
              **)**
              
              **8.20**
              
              
              (296,641
              )
              
              7.91Forfeited
              
              
              **(13,332**
              **)**
              
              **8.85**
              
              
              (57,666
              )
              
              8.79Outstanding,
                  end of year
              
              
              **472,521**
              
              **$**
              **8.41**
              
              
              768,693
              
              $
              8.34Exerciseable,
                  end of year
              
              
              **81,852**
              
              **$**
              **8.46**
              
              
              22,704
              
              $
              8.92Weighted
                  average remaining contract life (years)
              
              
              **1.58**
              
              
              
              
              
              2.58Average
                  potential reductions to exercise price
              
              **$**
              **1.30**
              
              
              
              
              $
              0.71




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




Pursuant
                to employment agreements between the Trust’s U.S. subsidiaries 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 the U.S. subsidiaries as at the end of the fiscal period. At December
                31, 2006 there were 2,755,566 notional units outstanding under the
                key
                employee plan (2005 - 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. In 2006, 555,566 units were granted with the remaining
                2,200,000 being granted in 2004. There were 12,984,001 notional units
                outstanding under the phantom unit plan (2005 - 4,155,290) of which
                all
                notional units vest immediately and are payable 90 days from the
                fiscal
                year-end. At December 31, 2006, $13.4 million (2005 - $3.5 million)
                is
                included in accounts payable and accrued liabilities for these plans,
                and
                $2.9 million (2005 - $1.8 million) is included in other long-term
                liabilities.




The
                following table reconciles the expense recorded for the other unit
                based
                compensation plans.







**Year
                ended December 31,**
            
            **2006**
            
            2005Cash
                general and administrative
            
            **$**
            **3,807**
            
            $
            1,255Non-cash
                unit based compensation (included in general and
                administrative)
            
            
            **10,478**
            
            
            4,961**$**
            **14,285**
            
            $
            6,216





**13.  
      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:


-17-
 TABLE
            OF CONTENTS


**Year
                ended December 31,****2006**
            
            2005Petroleum
                and natural gas properties, production facilities and
                other
            
            **$**
            **266,156**
            
            $
            89,607Midstream
                facilities
            
            
            **42,850**
            
            
            1,988**$**
            **309,006**
            
            $
            91,595





The
      income tax provision differs from the expected amount calculated by applying
      the
      Canadian combined federal and provincial income tax rate of 34.67 percent (2005
      - 37.82 percent) as follows:





**Year
                ended December 31,****2006**
            
            2005Expected
                income tax expense
            
            **$**
            **40,736**
            
            $
            48,218Increase
                (decrease) resulting from:Non-deductible
                Crown charges and other payments
            
            
            **8,135**
            
            
            14,285Federal
                resource allowance
            
            
            **(5,742**
            **)**
            
            (11,489
            )Alberta
                Royalty Tax Credit
            
            
            **(173**
            **)**
            
            (188
            )Income
                of the Trust and other
            
            
            **(70,999**
            **)**
            
            (32,567
            )Capital
                Taxes
            
            
            **1,314**
            
            
            4,780Witholding
                tax and other
            
            
            **3,308**
            
            
            5,628Income
                tax rate changes
            
            
            **(3,752**
            **)**
            
            (466
            )Income
                tax (recovery) expense
            
            **$**
            **(27,173**
            **)**
            $
            28,201





On
      December 21, 2006, the Minister of Finance released for comment draft
      legislation concerning the taxation of certain publicly traded trusts and
      partnerships. The legislation reflects proposals originally announced by the
      Minister on October 31, 2006. Under the proposed legislation, certain
      distributions will not be deductible to publicly traded income trusts and
      partnerships with the exception of real estate investments trusts and, as a
      result, these entities will in effect be taxed as corporations on the amount
      of
      the non-deductible distributions. For entities in existence on October 31,
      2006
      the proposed rules, if passed into law, would not apply until 2011. As the
      tax
      proposals had not been substantially enacted as of December 31, 2006, the
      consolidated financial statements do not reflect the impact of the proposed
      taxation.





**14.  
      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, asset retirement obligations, commodity and
      foreign currency contracts and long-term debt. Except as noted below, as at
      December 31, 2006 and 2005, 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.




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.





-18-
 TABLE
          OF CONTENTS


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




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




In
                2006, Provident paid $5.7 million to settle various oil market based
                contracts on an aggregate volume of 2.1 million barrels. For 2005,
                Provident paid $59.0 million to settle various oil market based contracts
                on an aggregate volume of 2.6 million barrels. The estimated value
                of
                contracts in place if settled at market prices at December 31, 2006
                would
                have resulted in an opportunity gain of $7.2 million (2005 - an
                opportunity cost of $7.1 million).




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




In
                2006, Provident received $7.6 million to settle various natural gas
                market
                based contracts on an aggregate of 9.5 million gigajoules (“GJ”). For
                2005, Provident paid $5.6 million to settle various natural gas market
                based contracts on an aggregate of 5.2 million gigajoules (“GJ”). The
                estimated value of contracts in place if settled at market prices
                at
                December 31, 2006 would have resulted in an opportunity gain of $8.6
                million (2005 - an opportunity cost of $6.5
                million).




**c)**
            **Midstream**




In
                2006, Provident paid $15.4 million (2005 - $2.3 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, 2006 would have resulted in an opportunity
                cost of
                $68.8 million (2005 - $0.4
                million).




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




The
                estimated value of contracts in place if settled at foreign exchange
                rates
                at December 31, 2006 would have resulted in an opportunity gain of
                $0.1
                million (2005 - opportunity cost of $0.1 million). The foreign exchange
                gains have been included in note 17 as a component of foreign exchange
                gain and other and allocated to their respective business
                segments.




The
      contracts in place at December 31, 2006 are summarized in the following
      tables:





**COGP****Volume****Year                               
                Product**
            
            
            **Terms**
            **Effective
                Period****(Buy)**
            **Sell****2007                           
                Crude Oil**
            750
            Bpd
            
            Participating
                Swap US $60.00 per bbl (62% above the floor price)
            January
                1 - December 31750
            Bpd
            
            Puts
                US $60.00 per bbl
            January
                1 - December 31**Natural Gas**
            2,500
            Gjpd
            
            Participating
                Swap Cdn $6.50 per gj (65% above the floor price)
            January
                1 - August 312,000
            Gjpd
            
            Participating
                Swap Cdn $6.50 per gj (max to 100% above the floor price)
            January
                1 - August 315,000
            Gjpd
            
            Participating
                Swap Cdn $7.00 per gj (max to 82% above the floor price)
            January
                1 - March 311,500
            Gjpd
            
            Participating
                Swap Cdn $7.00 per gj (max to 80% above the floor price)
            January
                1 - March 31,November
                1 - December 314,000
            Gjpd
            
            Participating
                Swap Cdn $6.44 per gj (max to 100% above the floor price)
            April
                1 - August 311,500
            Gjpd
            
            Participating
                Swap Cdn $6.50 per gj (max to 61% above the floor price)
            April
                1 - August 313,000
            Gjpd
            
            Participating
                Swap Cdn $6.33 per gj (max to 100% above the floor price)
            April
                1 - October 313,000
            Gjpd
            
            Participating
                Swap Cdn $6.33 per gj (max to 90% above the floor price)
            April
                1 - October 316,000
            Gjpd
            
            Participating
                Swap Cdn $6.30 per gj (max to 95% above the floor price)
            April
                1 - October 312,000
            Gjpd
            
            Participating
                Swap Cdn $6.13 per gj (max to 68% above the floor price)
            April
                1 - October 311,000
            Gjpd
            
            Participating
                Swap Cdn $6.00 per gj (max to 66% above the floor price)
            April
                1 - October 316,500
            Gjpd
            
            Costless
                Collar Cdn $6.31 floor, Cdn $12.93 ceiling
            January
                1 - March 317,500
            Gjpd
            
            Costless
                Collar Cdn $6.42 floor, Cdn $9.63 ceiling
            January
                1 - August 314,000
            Gjpd
            
            Costless
                Collar Cdn $6.75 floor, Cdn $8.56 ceiling
            April
                1 - August 315,000
            Gjpd
            
            Puts
                Cdn $6.85 per gj
            January
                1 - December 312,000
            Gjpd
            
            Puts
                Cdn $6.75 per gj
            January
                1 - March 319,500
            Gjpd
            
            Puts
                Cdn $6.89 per gj
            January
                1 - March 31,November
                1 - December 314,000
            Gjpd
            
            Puts
                Cdn $6.75 per gj
            November
                1 - December 31




-19-
 TABLE
          OF CONTENTS


**USOGP**


**Volume****Year**
              **Product**
              **(Buy)**
              **Sell**
              **Terms**
              **Effective
                  Period****2007**
              **Crude
                  Oil**
              250
              Bpd
              US
                  $60.00 per bbl
              January
                  1 - December 31250
              Bpd
              Participating
                  Swap US $55.00 per bbl (max to 84% above the floor price)
              January
                  1 - December 313,500
              Bpd
              US
                  $67.84 per bbl
              January
                  1 - June 302,650
              Bpd
              US
                  $68.44 per bbl
              July
                  1 - December 31250
              Bpd
              Costless
                  Collar US $66.00 floor, US $69.25 ceiling
              July
                  1 - December 31250
              Bpd
              Costless
                  Collar US $66.00 floor, US $71.50 ceiling
              July
                  1 - December 31**2008**
              **Crude
                  Oil**
              2,650
              Bpd
              US
                  $68.44 per bbl
              January
                  1 - June 30250
              Bpd
              Costless
                  Collar US $66.00 floor, US $69.25 ceiling
              January
                  1 - June 30250
              Bpd
              Costless
                  Collar US $66.00 floor, US $71.50 ceiling
              January
                  1 - June 302,500
              Bpd
              Participating
                  Swap US $60.00 per bbl (max to 53.3% above the floor
                  price)
              July
                  1 - September 314,500
              Bpd
              Participating
                  Swap US $60.00 per bbl (avg to 56% above the floor price)
              October
                  1 - December 31**2009**
              **Crude
                  Oil**
              500
              Bpd
              Participating
                  Swap US $60.00 per bbl (max to 55.5% above the floor
                  price)
              January
                  1 - September 302,000
              Bpd
              Participating
                  Swap US $60.00 per bbl (max to 59% above the floor price)
              January
                  1 - September 30
  
 **Midstream****Volume****Year**
              **Product**
              **(Buy)**
              **Sell**
              **Terms**
              **Effective
                  Period****2007**
              **Crude
                  Oil**
              250
              Bpd
              Costless
                  Collar US $64.50 floor, US $69.20 ceiling
              January
                  1 - December 312,000
              Bpd
              Costless
                  Collar US $72.43 floor, US $80.29 ceiling
              April
                  1 - December 3110,077
              Bpd
              Cdn
                  $77.02 per bbl
              January
                  1 - December 31(7,643)
              Bpd
              Cdn
                  $64.35 per bbl(4)
              January
                  1 - March 31(1,122)
              Bpd
              US
                  $80.81 per bbl(4)
              January
                  1 - March 31**Natural
                  Gas**
              3,000
              Gjpd
              Cdn
                  $8.28 per gj
              January
                  1 - January 31(1,350)
              Gjpd
              Costless
                  Collar Cdn $8.62 floor, Cdn $9.10 ceiling
              January
                  1 - December 31(3,201)
              Gjpd
              Cdn
                  $7.70 per gj
              January
                  1 - March 31(22,196)
              Gjpd
              Cdn
                  $8.17 per gj
              April
                  1 - December 31(48,493)
              Gjpd
              Cdn
                  $8.20 per gj
              January
                  1 - December 31**Propane**
              9,328
              Bpd
              US
                  $0.9841 per gallon(4)
                  (6)
              January
                  1 - March 31806
              Bpd
              US
                  $0.965 per gallon(6) (8)
              January
                  1 - February 281,666
              Bpd
              US
                  $0.9668 per gallon(6) (8)
              January
                  1 - March 31948
              Bpd
              Cdn
                  $1.2081 per gallon(4) (6)
              January
                  1 - March 31**Normal
                  Butane**
              1,808
              Bpd
              US
                  $1.1135 per gallon(4)
                  (7)
              January
                  1 - March 31306
              Bpd
              Cdn
                  $1.3788 per gallon(4) (7)
              January
                  1 - March 31**Foreign
                  Exchange**
              
              
              Sell
                  US $817,163 per month @ 1.1434(5)
              January
                  1 - December 31Sell
                  US $968,486 per month @ 1.1013(5)
              April
                  1 - December 31**2008**
              **Crude
                  Oil**
              2,250
              Bpd
              Costless
                  Collar US $68.50 floor, US $73.72 ceiling
              January
                  1 - December 31500
              Bpd
              Costless
                  Collar US $73.00 floor, US $80.00 ceiling
              January
                  1 - June 30500
              Bpd
              Costless
                  Collar US $64.00 floor, US $74.50 ceiling
              January
                  1 - September 30250
              Bpd
              US
                  $65.60 per bbl
              January
                  1 - December 318,521
              Bpd
              Cdn
                  $76.65 per bbl
              January
                  1 - December 31**Natural
                  Gas**
              (56,824)
              Gjpd
              Cdn
                  $8.34 per gj
              January
                  1 - December 31(13,123)
              Gjpd
              Cdn
                  $8.60 per gj
              January
                  1 - June 30(2,965)
              Gjpd
              Cdn
                  $7.94 per gj
              January
                  1 - September 30(8,760)
              Gjpd
              Cdn
                  $7.94 per gj
              July
                  1 - December 31**Foreign
                  Exchange**
              
              
              Sell
                  US $599,652 per month @ 1.1172(5)
              January
                  1 - December 31Sell
                  US $1,107,166 per month @ 1.1035(5)
              January
                  1 - June 30Sell
                  US $974,222 per month @ 1.1255(5)
              January
                  1 - September 30**2009**
              **Crude
                  Oil**
              2,500
              Bpd
              Costless
                  Collar US $65.00 floor, US $69.23 ceiling
              January
                  1 - December 31500
              Bpd
              Costless
                  Collar US $70.00 floor, US $79.00 ceiling
              January
                  1 - June 301,500
              Bpd
              Cdn
                  $81.44 per bbl
              January
                  1 - June 30250
              Bpd
              Cdn
                  $77.37 per bbl
              January
                  1 - March 31500
              Bpd
              Cdn
                  $75.10 per bbl
              July
                  1 - December 31250
              Bpd
              Cdn
                  $76.70 per bbl
              July
                  1 - September 30250
              Bpd
              US
                  $64.60 per bbl
              January
                  1 - December 313,374
              Bpd
              Cdn
                  $74.26 per bbl
              January
                  1 - December 31**Natural
                  Gas**
              (35,261)
              Gjpd
              Cdn
                  $8.28 per gj
              January
                  1 - December 31(1,481)
              Gjpd
              Cdn
                  $8.74 per gj
              January
                  1 - March 31(14,714)
              Gjpd
              Cdn
                  $8.32 per gj
              January
                  1 - June 30(1,481)
              Gjpd
              Cdn
                  $7.59 per gj
              July
                  1 - September 30(2,776)
              Gjpd
              Cdn
                  $7.75 per gj
              July
                  1 - December 31**Foreign
                  Exchange**
              
              
              Sell
                  US $522,154 per month @ 1.1093(5)
              January
                  1 - December 31Sell
                  US $1,055,833 per month @ 1.099(5)
              January
                  1 - June 30**2010**
              **Crude
                  Oil**
              1,500
              Bpd
              Costless
                  Collar US $62.90 floor, US $67.48 ceiling
              January
                  1 - December 314,688
              Bpd
              Cdn
                  $72.98 per bbl
              January
                  1 - December 31**Natural
                  Gas**
              (35,273)
              Gjpd
              Cdn
                  $8.03 per gj
              January
                  1 - December 31(1,485)
              Gjpd
              Cdn
                  $7.09 per gj
              April
                  1 - December 31**Foreign
                  Exchange**
              
              
              Sell
                  US $472,828 per month @ 1.1078(5)
              January
                  1 - December 31





-20-
 TABLE
          OF CONTENTS


**Midstream,
                continued**




**Effective
                Period****Volume**
            **Terms****Year**
            **Product**
            **(Buy)**
            **Sell****2011**
            **Crude
                Oil**
            500
            Bpd
            Costless
                Collar US $65.00 floor, US $75.00 ceiling
            January
                1 - June 30250
            Bpd
            Costless
                Collar US $60.00 floor, US $68.10 ceiling
            July
                1 - September 30250
            Bpd
            Costless
                Collar US $60.00 floor, US $67.30 ceiling
            July
                1 - September 30500
            Bpd
            Costless
                Collar US $56.00 floor, US $75.25 ceiling
            July
                1 - September 30500
            Bpd
            Costless
                Collar US $58.00 floor, US $76.20 ceiling
            July
                1 - September 30500
            Bpd
            Costless
                Collar US $60.00 floor, US $71.60 ceiling
            July
                1 - September 303,250
            Bpd
            Cdn
                $74.26 per bbl
            January
                1 - June 30750
            Bpd
            Cdn
                $69.94 per bbl
            January
                1 - March 31885
            Bpd
            Cdn
                $70.99 per bbl
            January
                1 - September 30250
            Bpd
            Cdn
                $73.35 per bbl
            January
                1 - October 31250
            Bpd
            Cdn
                $72.75 per bbl
            January
                1 - November 30500
            Bpd
            Cdn
                $73.15 per bbl
            April
                1 - June 30**Natural
                Gas**
            (2,700)
            Gjpd
            Cdn
                $8.53 per gj
            January
                1 - March 31(23,726)
            Gjpd
            Cdn
                $7.46 per gj
            January
                1 - June 30(4,955)
            Gjpd
            Cdn
                $7.02 per gj
            January
                1 - September 30(1,481)
            Gjpd
            Cdn
                $7.25 per gj
            January
                1 - October 31(1,481)
            Gjpd
            Cdn
                $7.24 per gj
            January
                1 - November 30(11,859)
            Gjpd
            Cdn
                $6.72 per gj
            July
                1 - September 30(2,820)
            Gjpd
            Cdn
                $6.21 per gj
            April
                1 - June 30**Foreign
                Exchange**
            
            
            Sell
                US $980,417 per month @ 1.0805 (5)
            January
                1 - June 30Sell
                US $717,600 per month @ 1.0931 (5)
            July
                1 - September 30


(1)
        The
        above table represents a number of transactions entered into over an extended
        period of time.
 (2)
        Natural gas contracts are settle against AECO monthly index
 (3)
        Crude
        Oil contracts are settled against NYMEX WTI calendar average
 (4)
        Conversion of crude oil BTU hedges to propane
 (5)
        U.S.
        Dollar hedge contracts settled against Bank of Canada noon rate average
 (6)
        Propane contracts are settled against Belvieu C3 TET


(7)
        Normal
        butane contracts are settled against Belvieu NC4 NON-TET


(8)
        Midstream inventory hedges




**15.**
            **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. The cash reserve was $1.9 million at the
                beginning of 2006. For the year ended December 31, 2006, $2.7 million
                was
                contributed to the reserve and actual expenditures totaled $4.6 million.
                During 2006, Provident retired a number of wells that included non-
                routine costs. As a result, the cash reserve was depleted in the
                year. It
                is expected that the reserve will rebuild in 2007. For the year ended
                December 31, 2005, $2.9 million was added to the cash reserve and
                actual
                expenditures totaled $2.5 million.




**16.**
            **Commitments**




Provident
                has office lease commitments that extend through April 2013. Future
                minimum lease payments for the following five years are: 2007 - $4.6
                million; 2008 - $8.0 million; 2009 - $7.8 million; 2010 - $6.9 million;
                and 2011 - $6.9 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: 2007 - U.S. $5.8 million;
                2008 -
                U.S. $5.6 million; 2009 - U.S. $4.2 million; 2010 - U.S. $2.7 million;
                and
                2011 - U.S. $1.5 million. dditionally,
                under an arrangement to use a third party interest in the Younger
                plant,
                Provident has a commitment to make payments calculated with reference
                to a
                number of variables including return on capital.Payments
                for the next five years are estimated as follows: 2007 - $4.5 million;
                2008 - $4.3 million; 2009 - $4.0 million; 2010 - $3.8 million; and
                2011 -
                4.1 million. In
                relation to the United States oil and natural gas production segment,
                Provident has surety bonds to provide U.S. $4.9 million of coverage
                to
                Occidental Petroleum Corporation related to a purchase of oil and
                gasproducing
                properties.


-21-
 TABLE
          OF CONTENTS


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: 2007 - U.S. $0.7
      million; 2008 - U.S. $0.6 million; 2009 - U.S. $0.6 million; 2010 - U.S. $0.6
      million; and 2011 - U.S. $0.6 million.





**17.    
      Segmented information**





The
      Trust’s business activities are conducted through three business segments:
      Canadian oil and natural gas production (COGP), 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-
  **Year
                    ended December 31,
                    2006****Canada
                    Oil**
                  **and
                    Natural**
                  **Gas**
                  **Production**
                
                **United
                    States**
                  **Oil
                    and**
                  **Natural
                    Gas Production**
                
                **Total
                    Oil****and**
                  **Natural****Gas****Production**
                
                **Midstream**
                  **Services
                    and Marketing****(1)**
                
                **Total****Revenue**Gross
                    production revenue
                
                
                
                
                $
                402,095
                
                $
                176,160
                
                $
                578,255
                
                $
                -
                
                $
                578,255Royalties
                
                
                
                
                
                (81,225
                )
                
                (17,315
                )
                
                (98,540
                )
                
                -
                
                
                (98,540
                )Product
                    sales and service revenue
                
                
                
                
                
                -
                
                
                -
                
                
                -
                
                
                1,764,392
                
                
                1,764,392Realized
                    gain (loss) on financial derivative
                  instruments
                
                4,371
                
                
                (2,505
                )
                
                1,866
                
                
                (15,406
                )
                
                (13,540
                )325,241
                
                
                156,340
                
                
                481,581
                
                
                1,748,986
                
                
                2,230,567**Expenses**Cost
                    of goods sold
                
                
                
                
                
                -
                
                
                -
                
                
                -
                
                
                1,471,171
                
                
                1,471,171Production,
                    operating and maintenance
                
                
                
                
                
                97,626
                
                
                52,008
                
                
                149,634
                
                
                22,619
                
                
                172,253Transportation
                
                
                
                
                
                5,114
                
                
                -
                
                
                5,114
                
                
                14,672
                
                
                19,786Foreign
                    exchange gain and other
                
                
                
                
                
                (9
                )
                
                -
                
                
                (9
                )
                
                (2,728
                )
                
                (2,737
                )Cash
                    general and administrative
                
                
                
                
                
                24,065
                
                
                26,519
                
                
                50,584
                
                
                23,621
                
                
                74,205126,796
                
                
                78,527
                
                
                205,323
                
                
                1,529,355
                
                
                1,734,678Earnings
                    before interest, taxes, depletion, depreciation,
                  accretion
                    and other non-cash items
                
                198,445
                
                
                77,813
                
                
                276,258
                
                
                219,631
                
                
                495,889**Non-cash
                    revenue**Unrealized
                    gain (loss) on financial derivative
                  instruments
                
                17,299
                
                
                7,735
                
                
                25,034
                
                
                (68,348
                )
                
                (43,314
                )Amortization
                    of loss on financial derivative
                  instruments
                
                -
                
                
                -
                
                
                -
                
                
                -
                
                
                -17,299
                
                
                7,735
                
                
                25,034
                
                
                (68,348
                )
                
                (43,314
                )**Other
                    expenses**Depletion,
                    depreciation and accretion
                
                
                
                
                
                168,953
                
                
                31,058
                
                
                200,011
                
                
                49,128
                
                
                249,139Interest
                    on bank debt
                
                
                
                
                
                10,082
                
                
                4,861
                
                
                14,943
                
                
                19,723
                
                
                34,666Interest
                    and accretion on convertible debentures
                
                5,746
                
                
                5,828
                
                
                11,574
                
                
                12,345
                
                
                23,919Amortization
                    of deferred financing charges
                
                956
                
                
                786
                
                
                1,742
                
                
                2,112
                
                
                3,854Unrealized
                    foreign exchange loss and other
                
                -
                
                
                -
                
                
                -
                
                
                418
                
                
                418Non-cash
                    unit based compensation
                
                
                
                
                
                4,320
                
                
                12,476
                
                
                16,796
                
                
                6,287
                
                
                23,083Internal
                    management charge
                
                
                
                
                
                (1,280
                )
                
                1,280
                
                
                -
                
                
                -
                
                
                -Gain
                    on sale of assets
                
                
                
                
                
                -
                
                
                -
                
                
                -
                
                
                -
                
                
                -Capital
                    taxes
                
                
                
                
                
                1,314
                
                
                -
                
                
                1,314
                
                
                -
                
                
                1,314Current
                    and withholding taxes
                
                
                
                
                
                (2,124
                )
                
                3,332
                
                
                1,208
                
                
                4,621
                
                
                5,829Future
                    income tax (recovery) expense
                
                (56,161
                )
                
                20,297
                
                
                (35,864
                )
                
                1,548
                
                
                (34,316
                )131,806
                
                
                79,918
                
                
                211,724
                
                
                96,182
                
                
                307,906Non-controlling
                    interest - USOGP
                
                
                
                
                
                -
                
                
                2,995
                
                
                2,995
                
                
                -
                
                
                2,995Non-controlling
                    interest - Exchangeables
                
                
                
                
                
                485
                
                
                37
                
                
                522
                
                
                232
                
                
                754**Net
                    income for the year**
                
                
                
                
                $
                83,453
                
                **$**
                **2,598**
                
                **$**
                **86,051**
                
                **$**
                **54,869**
                
                **$**
                **140,920**(1)Included in the Midstream Services and Marketing segment is product
                    sales
                    and service revenue of $332.9 million associated with U.S.
                    operations.






-23-
 TABLE
          OF CONTENTS


**December
                  31, 2006****Canada
                  Oil**
                **and
                  Natural**
                **Gas**
                **Production**
              
              **United
                  States**
                **Oil
                  and**
                **Natural
                  Gas Production**
              
              **Total
                  Oil and**
                **Natural
                  Gas Production**
              
              **Midstream**
                **Services
                  and Marketing**
              
              **Total****Selected
                  balance sheet items****Capital
                  Assets**Property,
                  plant and equipment net
              
              
              
              
              $
              1,211,112
              
              $
              380,451
              
              $
              1,591,563
              
              $
              741,974
              
              $
              2,333,537Intangible
                  assets
              
              
              
              
              
              -
              
              
              -
              
              
              -
              
              
              193,592
              
              
              193,592Goodwill
              
              
              
              
              
              330,944
              
              
              -
              
              
              330,944
              
              
              100,409
              
              
              431,353**Capital
                  Expenditures**Capital
                  expenditures
              
              
              
              
              
              70,088
              
              
              54,337
              
              
              124,425
              
              
              66,008
              
              
              190,433Corporate
                  acquisitions
              
              
              
              
              
              -
              
              
              -
              
              
              -
              
              
              1,036
              
              
              1,036Oil
                  and gas property acquisitions
              
              
              
              
              
              482,369
              
              
              (2,012
              )
              
              480,357
              
              
              -
              
              
              480,357Proceeds
                  from property dispositions
              
              
              
              
              
              (1,264
              )
              
              (4
              )
              
              (1,268
              )
              
              -
              
              
              (1,268
              )**Goodwill
                  additions**
              
              
              
              
              
              -
              
              
              -
              
              
              -
              
              
              2,285
              
              
              2,285**Working
                  capital**Accounts
                  receivable
              
              
              
              
              
              58,250
              
              
              24,744
              
              
              82,994
              
              
              187,141
              
              
              270,135Petroleum
                  product inventory
              
              
              
              
              
              -
              
              
              -
              
              
              -
              
              
              85,868
              
              
              85,868Accounts
                  payable and accrued liabilities
              
              
              
              
              
              86,305
              
              
              52,626
              
              
              138,931
              
              
              156,072
              
              
              295,003Long-term
                  debt
              
              
              
              
              $
              217,533
              
              $
              128,542
              
              $
              346,075
              
              $
              642,710
              
              $
              988,785




-24-
 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)**
              
              **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
              
              
              -
              
              
              -
              
              
              -
              
              
              908,111
              
              
              908,111Realized
                  loss on financial derivative instruments
              
              
              (48,308
              )
              
              (16,323
              )
              
              (64,631
              )
              
              (2,229
              )
              
              (66,860
              )323,234
              
              
              123,474
              
              
              446,708
              
              
              905,882
              
              
              1,352,590**Expenses**Cost
                  of goods sold
              
              
              -
              
              
              -
              
              
              -
              
              
              786,564
              
              
              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
              )Cash
                  general and administrative
              
              
              18,552
              
              
              11,490
              
              
              30,042
              
              
              11,566
              
              
              41,608117,717
              
              
              50,499
              
              
              168,216
              
              
              835,193
              
              
              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 non-hedging derivative instruments
              
              
              13,302
              
              
              (1,910
              )
              
              11,392
              
              
              (1,564
              )
              
              9,828Amortization
                  of loss on non-hedging 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
              
              
              193,236Interest
                  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 and other
              
              
              31
              
              
              10
              
              
              41
              
              
              (397
              )
              
              (356
              )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.


-25-
 TABLE
          OF CONTENTS


**December
                31, 2005****United****Canada
                Oil**
            
            **States
                Oil**
            
            **Total
                Oil****and**
            
            **and**
            
            **and**
            
            **Midstream****Natural**
            
            **Natural**
            
            **Natural**
            
            **Services****Gas**
            
            **Gas**
            
            **Gas**
            
            **and****Production**
            
            **Production**
            
            **Production**
            
            **Marketing**
            
            **Total****Selected
                balance sheet items****Capital
                Assets**Property,
                plant and equipment net
            
            $
            634,732
            
            $
            351,073
            
            $
            985,805
            
            $
            716,844
            
            $
            1,702,649Intangible
                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
            
            
            156,499Corporate
                acquisitions
            
            
            -
            
            
            91,420
            
            
            91,420
            
            
            772,303
            
            
            863,723Oil
                and gas property acquisitions
            
            
            586
            
            
            -
            
            
            586
            
            
            -
            
            
            586Proceeds
                from property dispositions
            
            
            45,100
            
            
            -
            
            
            45,100
            
            
            -
            
            
            45,100**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
            
            
            176,628
            
            
            43,243
            
            
            219,871
            
            
            89,833
            
            
            309,704Long-term
                debt
            
            $
            238,843
            
            $
            168,075
            
            $
            406,918
            
            $
            477,686
            
            $
            884,604




-26-
 TABLE
          OF CONTENTS


**18.   
      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,
            
            
            
            
            
            **2006**
            
            2005(Cdn$000s)Net
                income as reported
            
            
            
            
            
            
            
            **$**
            **140,920**
            
            $
            96,926AdjustmentsDepletion,
                depreciation and accretion (a)
            
            
            
            
            
            
            
            
            **12,146**
            
            
            13,697Depletion,
                depreciation and accretion other (a)
            
            
            
            
            
            
            
            
            **(382,230**
            **)**
            
            **-**FAS
                133 adjustment (b)
            
            
            
            
            
            
            
            
            **-**
            
            
            2,144General
                and administrative (e)
            
            
            
            
            
            
            
            
            **(483**
            **)**
            
            (1
            )Future
                income recovery (taxes) (a) (b) (c)
            
            
            
            
            
            
            
            
            **110,898**
            
            
            (5,357
            )Accretion
                on convertible debentures (g)
            
            
            
            
            
            
            
            
            **2,694**
            
            
            2,849Non-controlling
                interest - Exchangeable shares (i)
            
            
            
            
            
            
            
            
            **754**
            
            
            770Net
                (loss) income - U.S. GAAP
            
            
            
            
            
            
            
            **$**
            **(115,301**
            **)**
            $
            111,028Net
                (loss) income per unit - basic and diluted
            
            
            
            
            
            
            
            **$**
            **(0.59**
            **)**
            $
            0.70**Condensed
                Consolidated Balance Sheet**As
                at December 31 (Cdn$ 000s)
            
            
            **2006**
            
            
            
            2005**Canadian**
            
            
            **U.S.
                GAAP**
            
            
            Canadian
                GAAP
            
            
            U.S.
                GAAP**Assets**Property,
                plant and equipment (a)
            
            **$**
            **2,333,537**
            
            **$**
            **1,906,964**
            
            $
            1,702,689
            
            $
            1,646,200**Liabilities
                and unitholders’ equity**Long-term
                debt - convertible debentures (g)
            
            
            **285,792**
            
            
            **300,110**
            
            
            298,007
            
            
            315,486Other
                long-term liabilities (e)
            
            
            **16,305**
            
            
            **16,788**
            
            
            5,019
            
            
            5,019Future
                income taxes (a) (b) (c)
            
            
            **309,006**
            
            
            **180,122**
            
            
            91,595
            
            
            73,609Non-controlling
                interest - Exchangeable shares (i)
            
            
            **-**
            
            
            **-**
            
            
            8,259
            
            
            -Units
                subject to redemption (h) (i)
            
            
            **-**
            
            
            **2,317,196**
            
            
            -
            
            
            2,236,360Convertible
                debentures equity component (g)
            
            
            **18,522**
            
            
            **-**
            
            
            19,301
            
            
            -Unitholders’
                contributions (h)
            
            
            **2,254,048**
            
            
            **-**
            
            
            1,971,707
            
            
            -Cumulative
                translation adjustment (f)
            
            
            **(42,294**
            **)**
            
            **-**
            
            
            (41,785
            )
            
            -Accumulated
                income (loss)
            
            
            **238,208**
            
            
            **(1,044,840**
            **)**
            
            97,288
            
            
            (838,253
            )Accumulated
                cash distributions (h)
            
            
            **(926,825**
            **)**
            
            **-**
            
            
            (643,360
            )
            
            -Accumulated
                other comprehensive loss (f)
            
            **$**
            -
            
            $
            **(43,187**
            **)**
            $
            -
            
            $
            (42,679
            )





(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 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.




-27-
 TABLE
          OF CONTENTS


In
                computing its consolidated net earnings for U.S. GAAP purposes, the
                Trust
                recorded additional depletion in 2006 of $382.2 million (2005 - nil)
                and a
                related future income tax recovery of $114.7 million as a result
                of the
                application of the ceiling test. These charges were not required
                under the
                Canadian GAAP ceiling tests.




(b)
            At
                January 1, 2004, the Trust recorded an unrealized loss of $25.1 million
                in
                deferred charges on the consolidated balance sheet that was recognized
                in
                income over the term of the previously designated hedged items. For
                the
                period ending December 31, 2006, no expenses were recorded (2005
                - $2.1
                million). Under U.S. GAAP the amortization of the deferred charge
                has
                already been captured in prior period accumulated
                losses.




(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 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)
            Under
                Canadian GAAP, Provident follows CICA handbook section 3870 “Stock-based
                compensation and other stock-based payments” which provides for the
                presentation and measurement of cash-settled unit-based compensation
                as
                liabilities based on the intrinsic value each period. Under U.S.
                GAAP


FAS
                123R “Share-based payments”, public entities are required to measure
                liability awards based on the award’s fair value remeasured at each
                reporting date until the date of settlement. Under
                U.S.


GAAP,
                Provident measures the fair value of such liability awards using
                a
                binomial option pricing model at each reporting date until the date
                of
                settlement. Compensation cost for each period is based on the change
                in
                the fair value of the units for each reporting period and is recognized
                over the vesting period.




(f)
            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.




(g)
            Under
                Canadian GAAP Provident applies CICA Handbook Section 3861 ("HB 3861")
                "Financial Instruments - Presentation and Disclosure" for financial
                instruments that may be settled at the issuer's option in cash or
                its own
                equity. 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
                assigned within equity to the conversion feature component of the
                convertible debentures.




(h)
            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 temporary equity
                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.




-28-
 TABLE
          OF CONTENTS


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


GAAP
                purposes. In 2006, all of the outstanding exchangeable shares were
                converted into Provident Trust
                units





**Recent
      U.S. Accounting Pronouncements**




**Accounting
      for certain hybrid financial instruments**





In
      March
      2006 the FASB issued FAS 155, “Accounting for Certain Hybrid Financial
      Instruments”. FAS 155 permits fair value re-measurement for any hybrid financial
      instrument that contains an embedded derivative that otherwise would require
      bifurcation, clarifies which interest-only and principal-only strips are not
      subject to FAS 133, establishes a requirement to evaluate interests in
      securitized financial assets to identify freestanding derivatives or instruments
      that are considered hybrid financial instruments, clarifies that concentrations
      of credit risk in the form of subordination are not embedded derivatives and
      eliminates the prohibition on qualifying special-purpose entities holding a
      derivative financial instrument that pertains to a beneficial interest other
      than another derivative financial instrument. This statement is effective for
      all financial derivative instruments acquired after September 13, 2006. The
      adoption of this statement has not had a material impact on the Trust’s
      consolidated financial statements.





**Accounting
      for servicing of financial assets**





In
      March
      2006, FAS 156, “Accounting for Services of Financial Assets” was issued as an
      amendment to FAS 140. The revisions clarify when a servicer should separately
      recognize servicing assets and servicing liabilities, indicates that separately
      recognized servicing assets and liabilities should initially be measured at
      fair
      value and allows for subsequent measurement of the assets and liabilities to
      be
      conducted under the amortization method or the fair value measurement method.
      FAS 156 is effective for fiscal years beginning after September 15, 2006. The
      Trust does not expect the adoption of this statement to have a material impact
      on its financial statements.





**Accounting
      for uncertainty in income taxes**





In
      July
      2006, the FASB issued FIN 48, “Accounting for Uncertainty in Income Taxes”. The
      interpretation creates a single model to address uncertainty in tax positions
      and clarifies the accounting for income taxes by prescribing the minimum
      recognition threshold a tax position is required to meet before being recognized
      in the financial statements. The statement also provides guidance on
      de-recognition, measurement, classification, interest and penalties, accounting
      in interim periods, disclosures and transitions as well as specifically scopes
      out accounting for contingencies. FIN 48 is effective for fiscal years beginning
      after December 15, 2006. The Trust is currently evaluating the effect that
      this
      interpretation might have on the Trust’s financial statements.




**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.





-29-
 TABLE
          OF CONTENTS


**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 adoption
      of
      this statement has not had a material impact on the Trust’s 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 adoption of this statement has not had a material impact on the Trust’s
      financial statements.




TABLE
          OF CONTENTS


**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 29, 2007.




**PROVIDENT ENERGY TRUST**
              **By:
                Provident Energy Ltd.**Date:
              March 28, 2007
            By:
            /s/ Thomas
              W.
              BuchananName:
              Thomas W. BuchananTitle:
              President
              and Chief Executive Officer




TABLE
          OF CONTENTS


**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
                LLP99.6
            Consent
                of McDaniel & Associates Consultants
                Ltd.99.7
            Consent
                of Netherland Sewell & Associates
                Inc.99.8
            Consent
                of AJM Petroleum Consultants