**Exhibit
      99.1**










**ANNUAL
                  INFORMATION FORM**
                
                
                **For
                  the year ended December 31, 2005**
                
                
                
                
                
                
                
                
                
                
                
                **March 7,
                  2006**












**TABLE
      OF CONTENTS**




**Page**
            
            
            **Page**GLOSSARY
                OF TERMS
            iii
            
            Additional
                Operational Information
            45ABBREVIATIONS
                AND CONVERSIONS
            v
            
            INFORMATION
                RESPECTING ENERPLUS RESOURCES FUND
            45PRESENTATION
                OF ENERPLUS' OIL AND GAS RESERVES AND PRODUCTION
                INFORMATION
            vi
            
            Description
                of the Trust Units and the Trust Indenture
            45PRESENTATION
                OF ENERPLUS' FINANCIAL INFORMATION
            ix
            
            Description
                of the Royalty Agreements and Subordinated Notes
            52DESCRIPTION
                OF DISTRIBUTABLE INCOME
            ix
            
            Management
                and Corporate Governance
            53FORWARD-LOOKING
                STATEMENTS
            ix
            
            Unitholder
                Rights Plan
            53STRUCTURE
                OF ENERPLUS RESOURCES FUND
            1
            
            DEBT
                OF ENERPLUS
            54GENERAL
                DEVELOPMENT OF ENERPLUS RESOURCES FUND
            3
            
            Bank
                Credit Facility
            54Historical
                Overview
            3
            
            Senior
                Unsecured Notes
            55Developments
                in the Past Three Years
            3
            
            DISTRIBUTIONS
                TO UNITHOLDERS
            56OIL
                AND NATURAL GAS RESERVES
            6
            
            Distributable
                Income
            56Summary
                of Aggregate Enerplus Reserves
            7
            
            Distribution
                History
            56Summary
                of Conventional Oil and Natural Gas Reserves
            9
            
            U.S. Tax
                Reporting Matters
            57Summary
                of Joslyn Project Bitumen Reserves
            18
            
            INDUSTRY
                CONDITIONS
            58Reconciliation
                of Reserves
            21
            
            RISK
                FACTORS
            62Reconciliation
                of Changes in Net Present Value of Future Net Revenue
            25
            
            MARKET
                FOR SECURITIES
            74Undeveloped
                Reserves
            26
            
            DIRECTORS
                AND OFFICERS
            75Proved
                and Probable Reserves Not on Production
            27
            
            INTEREST
                OF MANAGEMENT AND OTHERS IN MATERIAL TRANSACTIONS
            78OPERATIONAL
                INFORMATION
            27
            
            MATERIAL
                CONTRACTS AND DOCUMENTS AFFECTING THE RIGHTS OF
                SECURITYHOLDERS
            78Overview
            27
            
            INTERESTS
                OF EXPERTS
            78Description
                of Principal Properties and Operations
            27
            
            REGISTRAR
                AND TRANSFER AGENT
            78Summary
                of Principal Production Locations
            37
            
            ADDITIONAL
                INFORMATION
            79Oil
                and Natural Gas Wells and Unproved Properties
            38
            
            APPENDIX
                "A"  - REPORT ON RESERVES DATA BY INDEPENDENT QUALIFIED RESERVES
                EVALUATOR OR AUDITOR
            A-1Exploration
                and Development Activities
            38
            
            APPENDIX
                "B"  - REPORT ON RESERVES DATA BY INDEPENDENT QUALIFIED RESERVES
                EVALUATOR OR AUDITOR
            B-1Quarterly
                Production History
            39
            
            APPENDIX
                "C"  - REPORT ON RESERVES DATA BY INDEPENDENT QUALIFIED RESERVES
                EVALUATOR OR AUDITOR
            C-1Quarterly
                Netback History
            40
            
            APPENDIX
                "D"  - REPORT OF MANAGEMENT AND DIRECTORS ON RESERVES DATA AND OTHER
                INFORMATION
            D-1Abandonment
                and Reclamation Costs
            42
            
            APPENDIX
                "E"  - AUDIT COMMITTEE DISCLOSURE
            E-1Tax
                Horizon
            42Costs
                Incurred
            42Marketing
                Arrangements and Forward Contracts
            42Environment,
                Health and Safety
            43Impact
                of Environmental Protection Requirements
            44













**GLOSSARY
      OF TERMS**




Unless
      the context otherwise requires, in this Annual Information Form, the following
      terms and abbreviations have the meanings set forth below. **Additional
      terms relating to oil and natural gas reserves and operations have the meanings
      set forth under "Presentation of Enerplus' Oil and Gas Reserves and Production
      Information."**




" **AECO** "
      means the physical storage and trading hub for natural gas on the TransCanada
      Alberta Transmission System (NOVA) which is the delivery point for the various
      benchmark Alberta index prices.




" **bitumen** "
      means a highly viscous crude oil which is too thick to flow in its native state
      and which cannot be produced without altering its viscosity. The density of
      bitumen is generally less than 10 o API;




" **D&M** "
      means DeGolyer and MacNaughton, independent petroleum consultants;




" **D&M
      Report** "
      means the independent engineering evaluation of Enerplus' U.S. conventional
      oil, NGLS and natural gas interests prepared by D&M dated January 23,
      2006 and effective December 31, 2005, utilizing commodity price forecasts
      of Sproule (for internal consistency in Enerplus' reserves reporting) dated
      December 31, 2005;




" **Deer
      Creek** "
      means Deer Creek Energy Limited, a wholly owned subsidiary of Total S.A.
      and the operator of the Joslyn Project;




" **ECT** "
      means Enerplus Commercial Trust, a trust organized under the laws of Alberta
      (the trustee of which is Enerplus ECT Resources Ltd., an Alberta
      corporation) and an indirect wholly owned subsidiary of the Fund;




" **EGEM** "
      means Enerplus Global Energy Management Company, an indirect wholly owned
      subsidiary of the Fund which, prior to its acquisition by Enerplus from a third
      party, provided management and administrative services to Enerplus;




" **EnerMark** "
      means EnerMark Inc., a corporation organized under the *Business
      Corporations Act* (Alberta) and a wholly owned subsidiary of the Fund;




" **Enerplus** "
      means Enerplus Resources Fund and its subsidiaries, taken as a
      whole;




" **Enerplus
      Oil & Gas** "
      means Enerplus Oil & Gas Ltd., a corporation organized under the *Business
      Corporations Act* (Alberta) and a wholly owned subsidiary of ERC;




" **Enerplus
      USA** "
      means Enerplus Resources (USA) Corporation, a corporation organized under the
      laws of Delaware and an indirect wholly-owned subsidiary of
      EnerMark;




" **ERC** "
      means Enerplus Resources Corporation, a corporation organized under the *Business
      Corporations Act* (Alberta) and a wholly owned subsidiary of EnerMark;




" **Fund** "
      means Enerplus Resources Fund;




" **GAAP** "
      means generally accepted accounting principles;




" **GLJ** "
      means GLJ Petroleum Consultants Ltd., independent petroleum
      consultants;




" **GLJ
      Report** "
      means the independent engineering evaluation of Enerplus' interest in the Joslyn
      Project prepared by GLJ dated February 28, 2006 and effective
      December 31, 2005, utilizing commodity price forecasts of Sproule
      (for internal consistency in Enerplus' reserves reporting) dated
      December 31, 2005;




" **Henry
      Hub** "
      means the physical storage and trading hub in Louisiana which is the delivery
      point for the NYMEX natural gas contract;




" **Joslyn
      Project** "
      or the " **Project** "
      means the development of Oil Sands Lease #24 located in the Athabasca oil
      sands fairway of northeastern Alberta;




" **Joslyn
      Lease** "
      means the sections of land contained within Alberta Oil Sands Lease
      No. 7280060T24 and Alberta Oil Sands Permit
      No. 7099110070;





iii







" **Lyco** "
      means Lyco Energy Corporation, a Delaware corporation which merged with Enerplus
      Newco LLC on February 9, 2006 and continued as Enerplus
      USA;




" **NI 51-101** "
      means National Instrument 51-101, *Standards
      of Disclosure for Oil and Gas Activities* ,
      adopted by the Canadian securities regulatory authorities;




" **NYMEX** "
      means the New York Mercantile Exchange;




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




" **Operating
      Subsidiaries** "
      means the direct and indirect subsidiaries of the Fund that own, acquire and
      operate oil and natural gas assets for the benefit of the Fund (with the
      material Operating Subsidiaries being EnerMark, ERC, Enerplus Oil &
Gas, ECT and Enerplus USA);




" **SAGD** "
      means Steam Assisted Gravity Drainage, an *in
      situ* production process used to recover bitumen from oil sands;




" **Sproule** "
      means Sproule Associates Limited, independent petroleum
      consultants;




" **Sproule
      Report** "
      means the independent engineering evaluation of Enerplus' Canadian conventional
      oil, NGLs and natural gas interests prepared by Sproule dated February 28,
      2006 and effective December 31, 2005, utilizing commodity price forecasts
      of Sproule dated December 31, 2005;




" **subsidiary** "
      has the meaning assigned thereto in the *Securities
      Act* (Alberta);




" **Tax Act** "
      means the *Income
      Tax Act* (Canada);




" **Trust
      Indenture** "
      means the Amended and Restated Trust Indenture dated January 1, 2004 among
      EnerMark, ERC and the Trustee, as may be amended, supplemented or restated
      from
      time to time;




" **Trust
      Units** "
      means the trust units of the Fund, each representing an equal undivided
      beneficial interest in the Fund;




" **Trustee** "
      means CIBC Mellon Trust Company, or its successor as trustee of the
      Fund;




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




" **WTI** "
      means West Texas Intermediate crude oil that serves as the benchmark crude
      oil
      for the NYMEX crude oil contract delivered in Cushing, Oklahoma.





iv







**ABBREVIATIONS
      AND CONVERSIONS**




In
      this Annual Information Form, the following abbreviations have the meanings
      set
      forth below.




**API**American
                  Petroleum Institute
                **bbls**barrels,
                  with each barrel representing 34.972 imperial gallons or
                  42 U.S. gallons
                **bbls/d**barrels
                  per day
                **Bcf**billion
                  cubic feet
                **Bcf/d**billion
                  cubic feet per day
                **BOE**barrels
                  of oil equivalent converting 6 Mcf of natural gas to one barrel of
                  oil equivalent and one barrel of natural gas liquids to one barrel
                  of oil
                  equivalent. The factor used to convert natural gas and natural
                  gas liquids
                  to oil equivalent is not based on either energy content or prices
                  but is a
                  commonly used industry benchmark.
              
              **BOE/d**barrels
                  of oil equivalent per day
                **Mbbls**one
                  thousand barrels
                **MBOE**         
                    one
                  thousand barrels of oil
                  equivalent
                **Mcf**one
                  thousand cubic feet
                **Mcf/d**one
                  thousand cubic feet per day
                **MMbbls**one
                  million barrels
                **MMBOE**one
                  million barrels of oil equivalent
                **MMBTU**one
                  million British Thermal Units
                **MMcf**one
                  million cubic feet
                MMcf/d     one
                  million cubic feet per day
                **NGLs**natural
                  gas liquids





In
      this Annual Information Form, unless otherwise indicated, all dollar amounts
      are
      in Canadian dollars and all references to " **$** "
      are to Canadian dollars.




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





**To
                Convert From**
            
            **To**
            
            **Multiply
                By**Mcf
            
            
            cubic
                metres
            
            
            28.174cubic
                metres
            
            
            cubic
                feet
            
            
            35.494bbls
            
            
            cubic
                metres
            
            
            0.159cubic
                metres
            
            
            bbls
            
            
            6.293feet
            
            
            metres
            
            
            0.305metres
            
            
            feet
            
            
            3.281miles
            
            
            kilometres
            
            
            1.609kilometres
            
            
            miles
            
            
            0.621acres
            
            
            hectares
            
            
            0.4047hectares
            
            
            acres
            
            
            2.471








v










**PRESENTATION
      OF ENERPLUS'**


**OIL
      AND GAS RESERVES AND PRODUCTION INFORMATION**




**Disclosure
      of Information**




**In
      this Annual Information Form, all estimates of oil and natural gas reserves
      and
      production are presented on a "company interest" basis (as defined below),
      unless expressly indicated that they have been presented on a "gross" or "net"
      basis. "Company interest" is not a term defined or recognized under
      NI 51-101 and does not have a standardized meaning under
      NI 51-101. Therefore, the "company interest" reserves of Enerplus may not
      be comparable to similar measures presented by other issuers, and investors
      are
      cautioned that "company interest" reserves should not be construed as an
      alternative to "gross" or "net" reserves calculated in accordance with
      NI 51-101.**




**Enerplus'
      actual oil and natural gas reserves and future production may be greater than
      or
      less than the estimates provided in this Annual Information Form. The estimated
      future net revenue from the production of Enerplus' oil and natural gas reserves
      does not represent the fair market value of Enerplus'
      reserves.**




The
      United States Securities and Exchange Commission (the " **SEC** ")
      generally permits oil and gas issuers, in their filings with the SEC, to
      disclose only proved reserves net of royalties and interests of others that
      an
      issuer has demonstrated by actual production or conclusive formation tests
      to be
      economically and legally producible under existing economic and operating
      conditions. Canadian securities laws permit oil and gas issuers, in their
      filings with Canadian securities regulators, to disclose not only Proved
      Reserves but also Probable Reserves (each as defined in NI 51-101 and
      described below), and to disclose reserves and production on a "gross" basis
      before deducting royalties. Probable Reserves are higher risk and are generally
      believed to be less likely to be accurately estimated or recovered than Proved
      Reserves. Enerplus has prepared this Annual Information Form in accordance
      with
      Canadian disclosure requirements, and as a result, Enerplus has disclosed
      reserves designated as "Probable Reserves" and "Proved plus Probable Reserves".
      The SEC's guidelines strictly prohibit reserves in these categories from being
      included in filings with the SEC that are required to be prepared in accordance
      with U.S. disclosure requirements. Moreover, Enerplus has determined and
      disclosed estimated future net revenue from its reserves using both constant
      and
      forecast prices and costs, whereas the SEC generally requires that prices and
      costs be held constant at levels in effect at the date of the reserve
      report.




Enerplus
      has adopted the standard of 6 Mcf:1 BOE when converting natural gas to
      BOEs. BOEs 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.




**Note
      to Reader Regarding Oil and Gas Information, Definitions and National
      Instrument 51-101**




The
      oil and gas operational and reserves information contained in this Annual
      Information Form contains the information required to be included in the
      Statement of Reserves Data and Other Oil and Gas Information pursuant to
      NI 51-101 adopted by the Canadian securities regulatory authorities
      and has been prepared and prescribed in accordance with Form 51-101F1.
      Readers should also refer to the Report on Reserves Data by Sproule attached
      hereto as Appendix "A", the Report on Reserves Data by GLJ attached hereto
      as Appendix "B", the Report on Reserves Data by D&M attached as
      Appendix "C" and the Report of Management and Directors on Oil and Gas
      Disclosure attached hereto as Appendix "D". The effective date for the
      Statement of Reserves Data and Other Oil and Gas Information contained in this
      Annual Information Form is December 31, 2005 and the information contained
      in the Annual Information Form has been prepared as of March 7,
      2006.




Certain
      of the following definitions and guidelines are contained in Section 5.4 of
      Volume 1 of the Canadian Oil and Gas Evaluation Handbook (First Edition,
      June 30, 2002) (the " **COGE
      Handbook** ")
      prepared jointly by The Society of Petroleum Evaluation Engineers (Calgary
      Chapter) and the Canadian Institute of Mining, Metallurgy & Petroleum
      (Petroleum Society) (the " **CIM
      (Petroleum Society)** ")
      and have been prepared by the Standing Committee on Reserves Definitions of
      the
      CIM (Petroleum Society). Readers should consult the COGE Handbook for additional
      explanation and guidance. Certain other terms used in this Annual Information





vi







Form
      have the meanings assigned to them in NI 51-101 and accompanying
      Companion Policy 51-101CP, adopted by the Canadian securities regulatory
      authorities.




**Interests
      in Reserves, Production, Wells and Properties**




" **company
      interest** "
      means, in relation to Enerplus' interest in production or reserves, its working
      interest (operating or non-operating) share before deduction of royalties and
      including any royalty interests of Enerplus.




" **gross** "
      means:




(i)
            in
                relation to Enerplus' interest in production or reserves, its working
                interest (operating or non-operating) share before deduction of royalties
                and without including any royalty interests of
                Enerplus;




(ii)
            in
                relation to wells, the total number of wells in which Enerplus has
                an
                interest; and




(iii)
            in
                relation to properties, the total area of properties in which Enerplus
                has
                an interest.




" **net** "
      means:




(i)
            in
                relation to Enerplus' interest in production or reserves, its working
                interest (operating or non-operating) share after deduction of royalty
                obligations, plus Enerplus' royalty interests in production or
                reserves;




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




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




" **working
      interest** "
      means the percentage of undivided interest held by Enerplus in the oil and/or
      natural gas or mineral lease granted by the mineral owner, Crown or freehold,
      which interest gives Enerplus the right to "work" the property (lease) to
      explore for, develop, produce and market the leased substances.




**Reserves
      Categories**




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




" **Probable
      Reserves** "
      are those additional reserves that are less certain to be recovered than Proved
      Reserves. It is equally likely that the actual remaining quantities recovered
      will be greater or less than the sum of the estimated Proved plus Probable
      Reserves.




" **Possible
      Reserves** "
      are those additional reserves that are less certain to be recovered than
      Probable Reserves. It is unlikely that the actual remaining quantities recovered
      will exceed the sum of the estimated Proved plus Probable plus Possible
      Reserves.




**Development
      and Production Status**




Each
      of the reserves categories (Proved, Probable and Possible) may be divided into
      developed and undeveloped categories:




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




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





vii







•
            "**Developed
                Non-Producing Reserves**"
                are those reserves that either have not been on production, or have
                previously been on production, but are shut-in, and the date of resumption
                of production is unknown.




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




**Levels
      of Certainty for Reported Reserves**




The
      qualitative certainty levels referred to in the definitions above are applicable
      to individual reserves entities (which refers to the lowest level at which
      reserves calculations are performed) and to reported reserves (which refers
      to
      the highest-level sum of individual entity estimates for which reserves
      estimates are presented). Reported reserves should target the following levels
      of certainty under a specific set of economic conditions:




•
            at
                least a 90 percent probability that the quantities actually recovered
                will equal or exceed the estimated Proved
                Reserves;




•
            at
                least a 50 percent probability that the quantities actually recovered
                will equal or exceed the sum of the estimated Proved plus Probable
                Reserves; and




•
            at
                least a 10 percent probability that the quantities actually recovered
                will equal the sum of the estimated Proved plus Probable plus Possible
                Reserves.




**Description
      of Price and Cost Assumptions**




" **Constant
      prices and costs** "
      means, unless expressly noted otherwise, prices and costs used in an estimate
      that are:




(i)
            Enerplus'
                prices and costs as at December 31, 2005, held constant throughout
                the estimated lives of the properties to which the estimate applies;
                and




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




" **Forecast
      prices and costs** "
      means future prices and costs that are:




(i)
            generally
                accepted as being a reasonable outlook of the future;
                and




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





viii







**PRESENTATION
      OF ENERPLUS' FINANCIAL INFORMATION**




**The
      financial information included and incorporated by reference in this Annual
      Information Form has been prepared in accordance with Canadian
      GAAP.** Canadian GAAP differs in some significant respects from U.S. GAAP and
      therefore this financial information may not be comparable to the financial
      information of U.S. companies. The principal differences as they apply to
      the Fund are summarized in Note 15 to the Fund's audited consolidated
      financial statements for the year ended December 31, 2005.




In
      this Annual Information Form, unless otherwise indicated, all dollar amounts
      are
      in Canadian dollars and all references to " **$** "
      are to Canadian dollars.




**DESCRIPTION
      OF DISTRIBUTABLE INCOME**




Throughout
      this Annual Information Form, Enerplus uses the term "distributable income"
      to
      refer to the amount of cash that has been or is to be available for distribution
      to the Fund's unitholders. "Distributable income" is not a measure recognized
      by
      Canadian GAAP and does not have a standardized meaning prescribed by GAAP,
      but
      is an amount calculated in accordance with the terms of the Fund's Trust
      Indenture. Therefore, distributable income of the Fund may not be comparable
      to
      similar measures presented by other issuers, and investors are cautioned that
      distributable income should not be construed as an alternative to net earnings,
      cash flow from operating activities or other measures of financial performance
      calculated in accordance with GAAP.




**FORWARD-LOOKING
      STATEMENTS**




This
      Annual Information Form contains certain forward-looking statements and
      forward-looking information which are based on Enerplus' current internal
      expectations, estimates, projections, assumptions and beliefs. The use of any
      of
      the words "anticipate", "continue", "estimate", "expect", "may", "will",
      "project", "plan", "should", "believe" and similar expressions are intended
      to
      identify forward-looking statements and forward-looking information. These
      statements are not guarantees of future performance and involve known and
      unknown risks, uncertainties and other factors that may cause actual results
      or
      events to differ materially from those anticipated in such forward-looking
      statements or information. Enerplus believes the expectations reflected in
      those
      forward-looking statements and information are reasonable but no assurance
      can
      be given that these expectations will prove to be correct, and such
      forward-looking statements and information included in this Annual Information
      Form should not be unduly relied upon. Such forward-looking statements and
      information speak only as of the date of this Annual Information Form and
      Enerplus does not undertake any obligation to publicly update or revise any
      forward-looking statements or information, except as required by applicable
      laws.




In
      particular, this Annual Information Form contains forward-looking statements
      and
      information pertaining to the following:




•
            the
                quantity of and future net revenues from Enerplus'
                reserves;




•
            oil,
                NGLs and natural gas production
                levels;




•
            commodity
                prices, foreign currency exchange rates and interest
                rates;




•
            capital
                expenditure programs and other
                expenditures;




•
            supply
                and demand for oil, NGLs and natural
                gas;




•
            expectations
                regarding Enerplus' ability to raise capital and to continually add
                to
                reserves through acquisitions and
                development;




•
            schedules
                and timing of certain projects and Enerplus' strategy for
                growth;




•
            Enerplus'
                future operating and financial results;
                and




•
            treatment
                under governmental and other regulatory regimes and tax, environmental
                and
                other laws.





ix







Enerplus'
      actual results could differ materially from those anticipated in these
      forward-looking statements and information as a result of both known and unknown
      risks, including the risk factors set forth under "Risk Factors" in this Annual
      Information Form and those set forth below:




•
            volatility
                in market prices for oil, NGLs and natural
                gas;




•
            changes
                or fluctuations in oil, NGLs and natural gas production
                levels;




•
            changes
                in foreign currency exchange rates and interest
                rates;




•
            changes
                in capital and other expenditure requirements and debt service
                requirements;




•
            liabilities
                and unexpected events inherent in oil and gas operations, including
                geological, technical, drilling and processing
                problems;




•
            uncertainties
                associated with estimating
                reserves;




•
            competition
                for, among other things, capital, acquisitions of reserves, undeveloped
                lands and skilled personnel;




•
            incorrect
                assessments of the value of
                acquisitions;




•
            Enerplus'
                success at acquisition, exploitation and development of
                reserves;




•
            changes
                in general economic, market and business conditions in Canada, North
                America and worldwide;




•
            actions
                by governmental or regulatory authorities including changes in income
                tax
                laws (including those relating to mutual fund trusts or investment
                eligibility) or changes in tax laws and incentive programs relating
                to the
                oil and gas industry and income trusts;
                and




•
            changes
                in environmental or other legislation applicable to Enerplus' operations,
                and Enerplus' ability to comply with current and future environmental
                and
                other laws.




Many
      of these risk factors and other specific risks and uncertainties are discussed
      in further detail throughout this Annual Information Form and in Enerplus'
      management's discussion and analysis for the year ended December 31, 2005,
      which is available through the internet on Enerplus' SEDAR profile at
      www.sedar.com. Readers are also referred to the risk factors described in this
      Annual Information Form under "Risk Factors" and in other documents Enerplus
      files from time to time with securities regulatory authorities. Copies of these
      documents are available without charge from Enerplus or electronically on the
      internet on Enerplus' SEDAR profile at www.sedar.com or Enerplus' website at
      www.enerplus.com.





x







**ENERPLUS
      RESOURCES FUND**




**Annual
      Information Form**


**For
      the year ended December 31, 2005**




**STRUCTURE
      OF ENERPLUS RESOURCES FUND**




**Enerplus
      Resources Fund**




Enerplus
      Resources Fund is an energy investment trust created in 1986 under the laws
      of
      the Province of Alberta pursuant to the Trust Indenture. The Fund's assets
      currently consist of the securities of several direct and indirect Operating
      Subsidiaries, unsecured debt issued by EnerMark to the Fund and 95%, 99% and
      99%
      royalties on the crude oil and natural gas property interests of EnerMark,
      ERC
      and Enerplus Oil & Gas, respectively. The head, principal and
      registered office of Enerplus is located at The Dome Tower, Suite 3000,
      333 - 7th Avenue S.W., Calgary, Alberta, T2P 2Z1. Enerplus also
      has a U.S. office located at Wells Fargo Center, Suite 1300,
      1700 Lincoln Street, Denver, Colorado, 80203. The Trustee of the Fund is
      CIBC Mellon Trust Company located at The Dome Tower, Suite 600,
      333 - 7th Avenue S.W., Calgary, Alberta T2P 2Z1. The board of
      directors of EnerMark is responsible for the governance of
      Enerplus.




The
      Fund's primary focus is to maintain and enhance monthly cash distributions
      to
      its unitholders from the net cash flow generated by the operation and
      development of its Operating Subsidiaries' existing crude oil and natural gas
      properties and the strategic acquisition and rationalization of properties
      and
      assets. See "Operational Information  - Overview".




**Operating
      Subsidiaries**




The
      Fund's direct and indirect Operating Subsidiaries acquire, exploit and operate
      crude oil and natural gas assets for the benefit of the Fund. See "Operational
      Information" and "Oil and Natural Gas Reserves" for information regarding the
      operations and oil and natural gas reserves of Enerplus. The Fund's material
      Operating Subsidiaries are EnerMark, ERC, Enerplus Oil & Gas, ECT and
      Enerplus USA.




Each
      of EnerMark, ERC and Enerplus Oil & Gas are corporations organized
      under the *Business
      Corporations Act* (Alberta). ECT is a trust organized under the laws of Alberta, and Enerplus
      USA
      is a corporation organized under the laws of Delaware. All of the issued and
      outstanding common shares of EnerMark are directly owned by the Fund and all
      of
      the trust units of ECT are indirectly owned by the Fund through its wholly
      owned
      subsidiary, Enerplus Limited Partnership II (an Alberta limited
      partnership). All of the issued and outstanding common shares of ERC are owned
      by EnerMark and all of the issued and outstanding common shares of Enerplus
      Oil & Gas are owned by ERC. All of the shares of Enerplus USA are
      indirectly owned by EnerMark.





1





**Organization
      Chart**




The
      simplified organizational structure of Enerplus, including the material
      Operating Subsidiaries of the Fund and the flow of funds from those Operating
      Subsidiaries to the Fund and from the Fund to its unitholders, is set forth
      below:










2





**GENERAL
      DEVELOPMENT OF ENERPLUS RESOURCES FUND**




**Historical
      Overview**




Enerplus
      Resources Fund was formed in 1986. The Fund's Trust Units are currently traded
      on the TSX under the symbol "ERF.UN" and on the NYSE under the symbol "ERF".
      The
      Fund was historically one of a group of royalty trusts, income funds and other
      entities managed by companies within the Enerplus organization.




**Developments
      in the Past Three Years**




*Acquisition
      of PCC Energy Inc. and PCC Energy Corp.*




On
      March 5, 2003, Enerplus acquired all of the outstanding shares of PCC
      Energy Inc. and PCC Energy Corp. (collectively, " **PCC** "),
      which were wholly owned Canadian subsidiaries of U.S. based PetroCorp
      Incorporated, for total cash consideration of $165.8 million. Enerplus also
      assumed a working capital deficiency of $1.1 million. A portion of the PCC
      properties acquired are subject to a royalty arrangement structured as a net
      profits interest (" **NPI** ")
      with a private U.S. company. The NPI is accounted for as a working interest
      of the U.S. company in these properties and as a result is not included in
      Enerplus' reserves, production, or financial information.




*Management
      Internalization Transaction*




On
      April 23, 2003, following receipt of unitholder approval, Enerplus acquired
      all of the outstanding shares of EGEM from an indirect wholly owned subsidiary
      of El Paso and incurred associated costs for a total cash consideration of
      $55.1 million. Prior to the acquisition, EGEM received management fees from
      Enerplus for providing administrative and management services to the Fund and
      its operating subsidiaries pursuant to a management agreement. As part of this
      transaction, EGEM agreed to fix the total fees payable under the management
      agreement from January 1, 2003 to April 23, 2003 at $3.0 million.
      Immediately following completion of the transaction, EGEM assigned and
      transferred all of its rights and obligations under the management agreement
      to
      EnerMark (a wholly owned subsidiary of the Fund), and the management
      agreement was effectively terminated.




*Acquisition
      of Ice Energy Limited*




On
      January 7, 2004, Enerplus completed the acquisition of all of the issued
      and outstanding shares of Ice Energy Limited. Enerplus previously owned
      approximately 12.7% of the shares of Ice Energy Limited which were acquired
      in a
      prior transaction. Total consideration for all of the Ice Energy Limited shares,
      including those previously owned by Enerplus, was $121.2 million. Enerplus
      also assumed a working capital deficiency of $9.3 million. As a result of
      this acquisition, Enerplus acquired an interest in the Shackleton area of
      western Saskatchewan. The acquired interests also include a 50% working interest
      in a joint venture to develop a commercial coal bed methane (also known as
      natural gas from coal) project in central Alberta.




*Participation
      in Joslyn Project and Other Oil Sands Projects*




In
      2002, Enerplus acquired a 16% working interest in the Joslyn Project. The
      remaining 84% working interest is owned by Deer Creek, which was acquired by
      Total S.A., a major international oil and gas company, in 2005. Deer Creek
      is the operator of the Joslyn Project. For a description of the status and
      operations of the Joslyn Project, see "Operational Information  -
      Description of Principal Properties and Operations  - Oil
      Sands".




In
      early 2006, Enerplus sold a 1% working interest in the Joslyn Project in
      exchange for equity in Laricina Energy Ltd., a new private oil sands
      focused company led by the former Chief Executive Officer of Deer Creek prior
      to
      its acquisition by Total S.A. Included in the sale is an area of mutual
      interest agreement which has been designed to jointly pursue additional in-situ
      oil sands ventures.





3







*Acquisition
      of Properties from ChevronTexaco Corporation*




On
      June 30, 2004, Enerplus completed the acquisition of conventional oil and
      natural gas interests located in western Canada from ChevronTexaco Corporation
      for total consideration of approximately $467.2 million. The acquired
      production was weighted approximately 46% to natural gas and 54% to crude oil
      and NGLs and the acquisition also provided Enerplus with approximately
      99,200 gross (45,400 net) acres of undeveloped land. The acquired
      properties were located in the Brooks area of southern Alberta, the Chinchaga
      area of northwestern Alberta, the Mitsue area of north central Alberta as well
      as in southeastern Saskatchewan and southwestern Manitoba.




*Unitholder
      Limited Liability Legislation*




Effective
      July 1, 2004 the *Income
      Trusts Liability Act* (Alberta) was proclaimed in force. The Act creates a statutory limitation on
      the
      liability of unitholders of income trusts organized under the laws of Alberta,
      such as the Fund. 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 comes into effect. The legislation does not
      affect the liability of unitholders with respect to any act, default, obligation
      or liability that arose before July 1, 2004. Additionally, in
      December 2004 Ontario adopted unitholder limited liability legislation
      similar to that implemented in Alberta. The Province of Québec historically had
      codified limited liability for trust unitholders. For additional information,
      see "Risk Factors  - Risks Related to Enerplus' Structure and the Ownership
      of the Trust Units  - The limited liability of the Fund's unitholders is
      uncertain".




*Acquisition
      of TriLoch Resources Inc.*




On
      July 1, 2005, Enerplus completed the acquisition of TriLoch
      Resources Inc. (" **TriLoch** ").
      Pursuant to a plan of arrangement, Enerplus issued 1,632,516 Trust Units in
      exchange for all of the shares of TriLoch. The Trust Unit value of $42.32 was
      based upon the weighted average price of the Fund's Trust Units on the TSX
      during the five day trading period surrounding the announcement of the
      transaction on May 17, 2005. Total consideration was approximately
      $77.4 million consisting of Trust Units, transaction costs and the
      retirement of TriLoch's bank indebtedness. Enerplus also assumed a working
      capital deficiency of $0.4 million. The TriLoch acquisition complemented
      Enerplus' existing asset base in the Enchant area of southern Alberta.
      Production from the area was weighted approximately 68% to natural gas and
      32%
      to crude oil and NGLs at the time of the acquisition.




*Acquisition
      of Lyco Energy Corporation and Sleeping Giant LLC*




On
      August 30, 2005, Enerplus acquired all of the outstanding shares, and
      retired the debt (including mandatory redeemable preferred shares) of Lyco
      Energy Corporation (" **Lyco** "),
      a private Delaware corporation operating in the states of Montana and North
      Dakota. The total consideration paid for Lyco was approximately
      $501.9 million and Enerplus also assumed a working capital deficiency of
      $4.4 million. In connection with the acquisition, the Fund issued
      10,637,500 Trust Units (issued upon the automatic conversion of
      subscription receipts upon the closing of the Lyco transaction) at a price
      of
      $46.25 for gross proceeds of $492.0 million (net proceeds of
      $466.9 million). Production from the Lyco properties was weighted
      approximately 92% light oil and 8% natural gas at the time of the acquisition.
      These properties predominantly produce high quality Middle Bakken light oil
      from
      the Sleeping Giant project area. The acquisition also provided Enerplus with
      approximately 120,000 net acres of undeveloped land in both Montana and
      North Dakota.




On
      October 4, 2005, Enerplus completed the acquisition of Sleeping
      Giant LLC, a private U.S. company. Total consideration paid for
      Sleeping Giant LLC was approximately $111.9 million and was financed
      through existing credit facilities. Enerplus also assumed positive working
      capital of $4.4 million. The assets of Sleeping Giant LLC consisted of
      additional working interests in the Sleeping Giant light crude oil project
      in
      Montana that formed part of the earlier Lyco acquisition. This acquisition
      increased Enerplus' working interest in certain producing wells in the
      Sleeping Giant project to an approximate 70% working interest.




Sleeping
      Giant LLC was subsequently merged with Lyco, and on February 9, 2006
      Lyco merged with Enerplus Newco LLC and continued as Enerplus Resources
      (USA) Corporation.





4







The
      Lyco and Sleeping Giant LLC acquisitions were Enerplus' first acquisitions
      of U.S. assets. On February 21, 2006 Enerplus opened an office in
      Denver, Colorado to support the ongoing operation of its assets in Montana
      and
      North Dakota and to facilitate future growth in the
      United States.




*Federal
      Government Pronouncements on Income Trusts and Mutual Fund Trust
      Status*




Throughout
      2004 and much of 2005, the Canadian federal government expressed concerns about
      a potential reduction in future tax revenues due to the increased presence
      of
      income trusts in the Canadian economy and the increased ownership of income
      trusts and other flow-through entities by non-residents of Canada. The former
      Canadian Minister of Finance indicated in the February 23, 2005 federal
      budget that further consultations would be pursued with stakeholders on taxation
      issues related to income trusts and other flow-through entities. On
      September 8, 2005, the Canadian Department of Finance released a discussion
      paper on these matters and invited interested parties to make submissions to
      the
      Department of Finance. On November 23, 2005, the former Canadian Minister
      of Finance issued a news release announcing that no change would be made to
      the
      tax treatment of income trusts in Canada and calling an end to the consultation
      process initiated in September 2005. In the January 2006 federal
      election, the Canadian federal Liberal government was replaced by a Conservative
      government. Both the Liberal and Conservative parties have stated they do not
      intend to change the current tax treatment of income trusts. In connection
      with
      the November 23, 2005 announcement, the former Liberal government also
      announced a reduction in the personal tax rate on corporate dividends received
      by Canadians in order to "level the playing field" between corporations and
      income trusts. The new Conservative government has not made any statement in
      respect of the proposed personal tax rate reduction.




Enerplus
      believes the November 23, 2005 announcement should help to remove some
      of  the uncertainty surrounding the taxation of the income trust sector.
      However, the Fund continues to rely on an exception contained in the
      Tax Act in order to ensure that it maintains its "mutual fund trust" status
      under the Tax Act. Absent such exception, the high percentage of Trust Unit
      ownership by non-residents of Canada (approximately 73% in February 2006)
      may cause the Fund to be considered to be "established or maintained primarily
      for the benefit of non-residents of Canada", and as a result the Fund would
      lose
      its mutual fund trust status. See "Risk Factors  - Risks Related to
      Enerplus' Structure and the Ownership of the Trust Units".




*S&P/TSX
      Index Inclusion*




The
      increased presence and importance of the income trust sector in Canadian
      financial markets, together with the removal of the legislative uncertainty
      regarding unitholder limited liability in certain provinces described above
      under "--  Unitholder Limited Liability Legislation", led Standard and
      Poor's to include income trusts, including Enerplus, in the S&P/TSX
      Composite Index. Income trusts were given one-half of their respective
      weightings in the S&P/TSX Composite Index in December 2005 with the
      remaining one-half weighting to occur in mid-March 2006.





5




**OIL
      AND NATURAL GAS RESERVES**




**Overview**




All
      of Enerplus' reserves, including its U.S. reserves, have been evaluated in
      accordance with NI 51-101. Sproule Associates Limited, a firm of
      independent petroleum engineers based in Calgary, Alberta, has evaluated
      properties which comprise approximately 89% of the net present value (discounted
      at 10%, using forecast prices and costs) of Enerplus' Proved plus Probable
      Canadian conventional oil and natural gas reserves. Enerplus has evaluated
      the
      balance of the Canadian conventional properties using similar evaluation
      parameters, including the same forecast price, inflation and exchange rates
      assumptions utilized by Sproule. Sproule has reviewed Enerplus' evaluation
      of
      these properties.




DeGolyer
      and MacNaughton, independent petroleum consultants based in Dallas, Texas,
      has
      evaluated all of Enerplus' conventional oil and natural gas reserves located
      in
      the United States. For internal consistency in Enerplus' reserves
      reporting, D&M has used Sproule's forecast prices, inflation and exchange
      rates.




GLJ
      Petroleum Consultants Ltd., a private independent petroleum consulting firm
      based in Calgary, Alberta, has evaluated all of Enerplus' interests in the
      SAGD-recoverable bitumen reserves of the Joslyn Project, again using the same
      forecast price, inflation and exchange rates assumptions utilized by
      Sproule.




Enerplus
      follows the Canadian practice of reporting company interest and gross production
      and reserve volumes, which are presented prior to the deduction of royalties
      and
      similar payments, as well as net production and reserve volumes. In the
      United States, production and reserve volumes are reported on a net basis,
      after deducting these amounts. The Canadian practice of using forecast prices
      and costs when estimating the quantities of reserves is also followed by
      Enerplus. In the United States, reserve estimates are calculated using
      prices and costs held constant at amounts in effect at the date of the reserve
      report. Enerplus also follows the Canadian practice of reporting the aggregate
      of Proved plus Probable reserves portion. As a consequence, Enerplus' production
      volumes and reserve estimates may not be comparable to those made by companies
      utilizing United States disclosure standards.




The
      following tables summarize, as at December 31, 2005, Enerplus' oil, NGLs
      and natural gas reserves and the estimated net present values of future net
      cash
      revenues associated with such reserves, together with certain information,
      estimates and assumptions associated with such reserve estimates. The data
      contained in the tables is a summary of the evaluations, and as a result the
      tables may contain slightly different numbers than the evaluations themselves
      due to rounding. Additionally, the numbers in the tables may not add due to
      rounding.




All
      future net revenues are stated prior to provision for interest and general
      and
      administrative expenses and after deduction of royalties and estimated future
      capital expenditures, and both before and after income taxes. The future net
      revenues have been prepared on the basis that no cash income taxes will be
      paid
      by Enerplus in the future in Canada. Enerplus' U.S. operations are subject
      to cash income taxes, and as a result Enerplus' U.S. reserves are shown net
      of the taxes Enerplus estimates will be payable after taking into account
      inter-company debt within Enerplus' structure. See "Operational
      Information  - Tax Horizon". The estimated net present value of future net
      revenue does not include the Alberta Royalty Tax Credit. With respect to pricing
      information in the following reserves information, the wellhead oil prices
      were
      adjusted for quality and transportation based on historical actual prices.
      The
      natural gas prices were adjusted, where necessary, based on historical pricing
      based on heating values and the differing costs of service applied by various
      purchasers. The natural gas liquids prices were adjusted to reflect historical
      average prices received.




**It
      should not be assumed that the present worth of estimated future cash flows
      shown below is representative of the fair market value of the reserves. There
      is
      no assurance that such price and cost assumptions will be attained and variances
      could be material. The recovery and reserve estimates of Enerplus' crude oil,
      NGLs and natural gas reserves provided herein are estimates only. Actual
      reserves may be greater than or less than the estimates provided herein. Readers
      should review the definitions and information contained in "Presentation of
      Enerplus' Oil and Gas Reserves and Production Information" in conjunction with
      the following tables and notes.**





6





**Summary
      of Aggregate Enerplus Reserves**




The
      following tables summarize the aggregate company interest reserves volumes
      and
      net present value of future net revenue contained in the Sproule Report relating
      to Enerplus' Canadian conventional crude oil and natural gas reserves, the
      D&M Report relating to Enerplus' U.S. conventional crude oil and
      natural gas reserves and the GLJ Report relating to Enerplus' interest in the
      SAGD-recoverable bitumen reserves of the Joslyn Project, all based on Sproule's
      forecast price and cost assumptions. Detailed separate summaries of the Sproule
      Report, the D&M Report and the GLJ Report, including certain assumptions
      incorporated into those reports, and presentation of Enerplus' oil and gas
      reserves in accordance with NI 51-101 are contained in the tables
      following the summary report below.




**Summary
      of Aggregate Oil and Gas Reserves**


**As
      of December 31, 2005**




**Company
      Interest Reserves,**


**Forecast
      Prices and Costs**





**OIL
                AND NATURAL GAS RESERVES****RESERVES
                CATEGORY**
            
            **Light &**
              **Medium
                Oil**
            
            **Heavy**
              **Oil**
            
            **Bitumen**
            
            **Total
                Oil**
            
            **Natural
                Gas Liquids**
            
            **Natural
                Gas**
            
            **Total**(Mbbls)
            
            (Mbbls)
            
            (Mbbls)
            
            (Mbbls)
            
            (Mbbls)
            
            (Mmcf)
            
            (MBOE)Proved
                Developed ProducingCanada
            
            
            69,768
            
            
            30,583
            
            
            -
            
            
            100,351
            
            
            11,644
            
            
            771,428
            
            
            240,566United States
            
            
            15,773
            
            
            -
            
            
            -
            
            
            15,773
            
            
            -
            
            
            8,794
            
            
            17,239**Total**
            
            
            85,541
            
            
            30,583
            
            
            -
            
            
            116,124
            
            
            11,644
            
            
            780,222
            
            
            257,805Proved
                Developed Non-ProducingCanada
            
            
            163
            
            
            -
            
            
            -
            
            
            163
            
            
            475
            
            
            19,468
            
            
            3,884United States
            
            
            -
            
            
            -
            
            
            -
            
            
            -
            
            
            -
            
            
            -
            
            
            -**Total**
            
            
            163
            
            
            -
            
            
            -
            
            
            163
            
            
            475
            
            
            19,468
            
            
            3,884Proved
                UndevelopedCanada
            
            
            3,318
            
            
            2,318
            
            
            9,453
            
            
            15,089
            
            
            965
            
            
            161,728
            
            
            43,008United States
            
            
            7,822
            
            
            -
            
            
            -
            
            
            7,822
            
            
            -
            
            
            4,358
            
            
            8,548**Total**
            
            
            11,140
            
            
            2,318
            
            
            9,453
            
            
            22,911
            
            
            965
            
            
            166,086
            
            
            51,556Total
                ProvedCanada
            
            
            73,249
            
            
            32,901
            
            
            9,453
            
            
            115,603
            
            
            13,084
            
            
            952,624
            
            
            287,458United States
            
            
            23,595
            
            
            -
            
            
            -
            
            
            23,595
            
            
            -
            
            
            13,152
            
            
            25,787**Total**
            
            
            96,844
            
            
            32,901
            
            
            9,453
            
            
            139,198
            
            
            13,084
            
            
            965,776
            
            
            313,245ProbableCanada
            
            
            17,498
            
            
            8,495
            
            
            43,700
            
            
            69,693
            
            
            3,539
            
            
            309,572
            
            
            124,827United States
            
            
            5,574
            
            
            -
            
            
            -
            
            
            5,574
            
            
            -
            
            
            32,946
            
            
            11,065**Total**
            
            
            23,072
            
            
            8,495
            
            
            43,700
            
            
            75,267
            
            
            3,539
            
            
            342,518
            
            
            135,892Total
                Proved plus ProbableCanada
            
            
            90,747
            
            
            41,396
            
            
            53,153
            
            
            185,296
            
            
            16,623
            
            
            1,262,196
            
            
            412,285United States
            
            
            29,169
            
            
            -
            
            
            -
            
            
            29,169
            
            
            -
            
            
            46,098
            
            
            36,852**Total**
            
            
            119,916
            
            
            41,396
            
            
            53,153
            
            
            214,465
            
            
            16,623
            
            
            1,308,294
            
            
            449,137








7







**Summary
      of Aggregate Net Present Value**


**of
      Future Net Revenue Attributable to Oil and Gas Reserves**


**As
      of December 31, 2005**




**Company
      Interest Reserves,**


**Forecast
      Prices and Costs**





**NET
                PRESENT VALUE OF FUTURE NET REVENUE DISCOUNTED AT
                (%/YEAR)****Before
                Deducting Income Taxes**
            
            **After
                Deducting Income Taxes****RESERVES
                CATEGORY**
            
            **0%**
            
            **5%**
            
            **10%**
            
            **15%**
            
            **20%**
            
            **0%**
            
            **5%**
            
            **10%**
            
            **15%**
            
            **20%**(in $ millions)**CONVENTIONAL
                OIL AND GAS RESERVES**Proved
                Developed ProducingCanada
            
            
            6,991
            
            
            4,800
            
            
            3,789
            
            
            3,199
            
            
            2,807
            
            
            6,991
            
            
            4,800
            
            
            3,789
            
            
            3,199
            
            
            2,807United States
            
            
            745
            
            
            605
            
            
            510
            
            
            442
            
            
            391
            
            
            620
            
            
            500
            
            
            419
            
            
            360
            
            
            316**Total**
            
            
            7,736
            
            
            5,405
            
            
            4,299
            
            
            3,641
            
            
            3,198
            
            
            7,611
            
            
            5,300
            
            
            4,208
            
            
            3,559
            
            
            3,123Proved
                Developed Non-ProducingCanada
            
            
            107
            
            
            81
            
            
            65
            
            
            57
            
            
            48
            
            
            107
            
            
            81
            
            
            65
            
            
            57
            
            
            48United States
            
            
            -
            
            
            -
            
            
            -
            
            
            -
            
            
            -
            
            
            -
            
            
            -
            
            
            -
            
            
            -
            
            
            -**Total**
            
            
            107
            
            
            81
            
            
            65
            
            
            57
            
            
            48
            
            
            107
            
            
            81
            
            
            65
            
            
            57
            
            
            48Proved
                UndevelopedCanada
            
            
            687
            
            
            501
            
            
            380
            
            
            296
            
            
            236
            
            
            687
            
            
            501
            
            
            380
            
            
            296
            
            
            236United States
            
            
            299
            
            
            225
            
            
            175
            
            
            140
            
            
            114
            
            
            180
            
            
            133
            
            
            102
            
            
            82
            
            
            67**Total**
            
            
            986
            
            
            726
            
            
            555
            
            
            436
            
            
            350
            
            
            867
            
            
            634
            
            
            482
            
            
            378
            
            
            303Total
                ProvedCanada
            
            
            7,785
            
            
            5,382
            
            
            4,234
            
            
            3,552
            
            
            3,091
            
            
            7,785
            
            
            5,382
            
            
            4,234
            
            
            3,552
            
            
            3,091United States
            
            
            1,044
            
            
            830
            
            
            685
            
            
            582
            
            
            505
            
            
            800
            
            
            633
            
            
            521
            
            
            442
            
            
            383**Total
                Proved Conventional Reserves**
            
            
            8,829
            
            
            6,212
            
            
            4,919
            
            
            4,134
            
            
            3,596
            
            
            8,585
            
            
            6,015
            
            
            4,755
            
            
            3,994
            
            
            3,474ProbableCanada
            
            
            2,376
            
            
            1,121
            
            
            695
            
            
            495
            
            
            384
            
            
            2,376
            
            
            1,121
            
            
            695
            
            
            495
            
            
            384United States
            
            
            453
            
            
            257
            
            
            162
            
            
            111
            
            
            80
            
            
            308
            
            
            174
            
            
            108
            
            
            72
            
            
            51**Total
                Probable Conventional Reserves**
            
            
            2,829
            
            
            1,378
            
            
            857
            
            
            606
            
            
            464
            
            
            2,684
            
            
            1,295
            
            
            803
            
            
            567
            
            
            435**Total
                Proved Plus Probable Conventional Reserves**
            
            
            11,658
            
            
            7,590
            
            
            5,776
            
            
            4,740
            
            
            4,060
            
            
            11,269
            
            
            7,310
            
            
            5,558
            
            
            4,561
            
            
            3,909**BITUMEN
                RESERVES**Proved
                Undeveloped
            
            
            38
            
            
            19
            
            
            9
            
            
            3
            
            
            -
            
            
            38
            
            
            19
            
            
            9
            
            
            3
            
            
            -Probable
            
            
            299
            
            
            88
            
            
            27
            
            
            6
            
            
            (4
            )
            
            299
            
            
            88
            
            
            27
            
            
            6
            
            
            (4
            )**Total
                Proved Plus Probable Bitumen Reserves**
            
            
            337
            
            
            107
            
            
            36
            
            
            9
            
            
            (4
            )
            
            337
            
            
            107
            
            
            36
            
            
            9
            
            
            (4
            )**TOTAL
                CONVENTIONAL AND BITUMEN RESERVES**
            
            
            11,995
            
            
            7,697
            
            
            5,812
            
            
            4,749
            
            
            4,056
            
            
            11,606
            
            
            7,417
            
            
            5,594
            
            
            4,570
            
            
            3,905








8




**Summary
      of Conventional Oil and Natural Gas Reserves**




The
      following tables and notes summarize the reserves volumes and net present value
      of future net revenue attributable to Enerplus' conventional oil and gas
      reserves, including certain assumptions relating to the determination of those
      reserves and values. **All
      information relating to Canadian conventional reserves is contained in the
      Sproule Report and all information relating to United States conventional
      reserves is contained in the D&M Report.**




**Summary
      of Conventional Oil and Gas Reserves**


**As
      of December 31, 2005**




***Forecast
      Prices and Costs***





**OIL
                AND NATURAL GAS RESERVES****LIGHT
                AND MEDIUM OIL**
            
            **HEAVY
                OIL**
            
            **NATURAL
                GAS****RESERVES
                CATEGORY**
            
            **Company
                Interest**
            
            **Gross**
            
            **Net**
            
            **Company
                Interest**
            
            **Gross**
            
            **Net**
            
            **Company
                Interest**
            
            **Gross**
            
            **Net**(Mbbls)
            
            (Mbbls)
            
            (Mbbls)
            
            (Mbbls)
            
            (Mbbls)
            
            (Mbbls)
            
            (Mmcf)
            
            (Mmcf)
            
            (Mmcf)Proved
                Developed ProducingCanada
            
            
            69,768
            
            
            69,076
            
            
            63,384
            
            
            30,583
            
            
            30,556
            
            
            27,399
            
            
            771,428
            
            
            746,984
            
            
            618,640United States
            
            
            15,773
            
            
            15,773
            
            
            13,261
            
            
            -
            
            
            -
            
            
            -
            
            
            8,794
            
            
            8,794
            
            
            7,393**Total**
            
            
            85,541
            
            
            84,849
            
            
            76,645
            
            
            30,583
            
            
            30,556
            
            
            27,399
            
            
            780,222
            
            
            755,778
            
            
            626,033Proved
                Developed Non-ProducingCanada
            
            
            163
            
            
            164
            
            
            142
            
            
            -
            
            
            -
            
            
            -
            
            
            19,468
            
            
            19,258
            
            
            15,466United States
            
            
            -
            
            
            -
            
            
            -
            
            
            -
            
            
            -
            
            
            -
            
            
            -
            
            
            -
            
            
            -**Total**
            
            
            163
            
            
            164
            
            
            142
            
            
            
            
            
            
            
            
            
            
            
            19,468
            
            
            19,258
            
            
            15,466Proved
                UndevelopedCanada
            
            
            3,318
            
            
            3,281
            
            
            2,901
            
            
            2,318
            
            
            2,318
            
            
            1,966
            
            
            161,728
            
            
            156,197
            
            
            132,094United States
            
            
            7,822
            
            
            7,822
            
            
            6,554
            
            
            -
            
            
            -
            
            
            -
            
            
            4,358
            
            
            4,358
            
            
            3,651**Total**
            
            
            11,140
            
            
            11,103
            
            
            9,455
            
            
            2,318
            
            
            2,318
            
            
            1,966
            
            
            166,086
            
            
            160,555
            
            
            135,745Total
                Proved ReservesCanada
            
            
            73,249
            
            
            72,521
            
            
            66,427
            
            
            32,901
            
            
            32,874
            
            
            29,365
            
            
            952,624
            
            
            922,439
            
            
            766,200United States
            
            
            23,595
            
            
            23,595
            
            
            19,815
            
            
            -
            
            
            -
            
            
            -
            
            
            13,152
            
            
            13,152
            
            
            11,044**Total**
            
            
            96,844
            
            
            96,116
            
            
            86,242
            
            
            32,901
            
            
            32,874
            
            
            29,365
            
            
            965,776
            
            
            935,591
            
            
            777,244Probable
                ReservesCanada
            
            
            17,498
            
            
            17,272
            
            
            14,967
            
            
            8,495
            
            
            8,487
            
            
            6,131
            
            
            309,572
            
            
            301,586
            
            
            252,478United States
            
            
            5,574
            
            
            5,574
            
            
            4,673
            
            
            -
            
            
            -
            
            
            -
            
            
            32,946
            
            
            32,946
            
            
            27,655**Total**
            
            
            23,072
            
            
            22,846
            
            
            19,640
            
            
            8,495
            
            
            8,487
            
            
            6,131
            
            
            342,518
            
            
            334,532
            
            
            280,133Total
                Proved Plus Probable ReservesCanada
            
            
            90,747
            
            
            89,793
            
            
            81,394
            
            
            41,396
            
            
            41,361
            
            
            35,496
            
            
            1,262,196
            
            
            1,224,025
            
            
            1,018,678United States
            
            
            29,169
            
            
            29,169
            
            
            24,488
            
            
            -
            
            
            -
            
            
            -
            
            
            46,098
            
            
            46,098
            
            
            38,699**Total**
            
            
            119,916
            
            
            118,962
            
            
            105,882
            
            
            41,396
            
            
            41,361
            
            
            35,496
            
            
            1,308,294
            
            
            1,270,123
            
            
            1,057,377





*(continues
      on next page)*





9










*(continued)*





**OIL
                AND NATURAL GAS RESERVES****NATURAL
                GAS LIQUIDS**
            
            **TOTAL****RESERVES
                CATEGORY**
            
            **Company**
              **Interest**
            
            **Gross**
            
            **Net**
            
            **Company**
              **Interest**
            
            **Gross**
            
            **Net**(Mbbls)
            
            (Mbbls)
            
            (Mbbls)
            
            (MBOE)
            
            (MBOE)
            
            (MBOE)Proved
                Developed ProducingCanada
            
            
            11,644
            
            
            11,465
            
            
            8,095
            
            
            240,566
            
            
            235,595
            
            
            201,985United States
            
            
            -
            
            
            -
            
            
            -
            
            
            17,239
            
            
            17,239
            
            
            14,493**Total**
            
            
            11,644
            
            
            11,465
            
            
            8,095
            
            
            257,805
            
            
            252,834
            
            
            216,478Proved
                Developed Non-ProducingCanada
            
            
            475
            
            
            473
            
            
            331
            
            
            3,884
            
            
            3,846
            
            
            3,050United States
            
            
            -
            
            
            -
            
            
            -
            
            
            -
            
            
            -
            
            
            -**Total**
            
            
            475
            
            
            473
            
            
            331
            
            
            3,884
            
            
            3,846
            
            
            3,050Proved
                UndevelopedCanada
            
            
            965
            
            
            963
            
            
            681
            
            
            33,555
            
            
            32,595
            
            
            27,564United States
            
            
            -
            
            
            -
            
            
            -
            
            
            8,548
            
            
            8,548
            
            
            7,163**Total**
            
            
            965
            
            
            963
            
            
            681
            
            
            42,103
            
            
            41,143
            
            
            34,727Total
                Proved ReservesCanada
            
            
            13,084
            
            
            12,901
            
            
            9,107
            
            
            278,005
            
            
            272,036
            
            
            232,599United States
            
            
            -
            
            
            -
            
            
            -
            
            
            25,787
            
            
            25,787
            
            
            21,656**Total**
            
            
            13,084
            
            
            12,901
            
            
            9,107
            
            
            303,792
            
            
            297,823
            
            
            254,255Probable
                ReservesCanada
            
            
            3,539
            
            
            3,480
            
            
            2,470
            
            
            81,127
            
            
            79,503
            
            
            65,648United States
            
            
            -
            
            
            -
            
            
            -
            
            
            11,065
            
            
            11,065
            
            
            9,282**Total**
            
            
            3,539
            
            
            3,480
            
            
            2,470
            
            
            92,192
            
            
            90,568
            
            
            74,930Total
                Proved Plus Probable ReservesCanada
            
            
            16,623
            
            
            16,381
            
            
            11,577
            
            
            359,132
            
            
            351,539
            
            
            298,247United States
            
            
            -
            
            
            -
            
            
            -
            
            
            36,852
            
            
            36,852
            
            
            30,938**Total**
            
            
            16,623
            
            
            16,381
            
            
            11,577
            
            
            395,984
            
            
            388,391
            
            
            329,185








10




**Summary
      of Net Present Value of Future Net Revenue**


**Attributable
      to Conventional Oil and Gas Reserves**


**As
      of December 31, 2005**




***Forecast
      Prices and Costs***





**NET
                PRESENT VALUE OF FUTURE NET REVENUE DISCOUNTED AT
                (%/YEAR)****Before
                Deducting Income Taxes**
            
            **After
                Deducting Income Taxes****RESERVES
                CATEGORY**
            
            **0%**
            
            **5%**
            
            **10%**
            
            **15%**
            
            **20%**
            
            **0%**
            
            **5%**
            
            **10%**
            
            **15%**
            
            **20%**(in $ millions)Proved
                Developed ProducingCanada
            
            
            6,991
            
            
            4,800
            
            
            3,789
            
            
            3,199
            
            
            2,807
            
            
            6,991
            
            
            4,800
            
            
            3,789
            
            
            3,199
            
            
            2,807United States
            
            
            745
            
            
            605
            
            
            510
            
            
            442
            
            
            391
            
            
            620
            
            
            500
            
            
            419
            
            
            360
            
            
            316**Total**
            
            
            7,736
            
            
            5,405
            
            
            4,299
            
            
            3,641
            
            
            3,198
            
            
            7,611
            
            
            5,300
            
            
            4,208
            
            
            3,559
            
            
            3,123Proved
                Developed Non-ProducingCanada
            
            
            107
            
            
            81
            
            
            65
            
            
            57
            
            
            48
            
            
            107
            
            
            81
            
            
            65
            
            
            57
            
            
            48United States
            
            
            -
            
            
            -
            
            
            -
            
            
            -
            
            
            -
            
            
            -
            
            
            -
            
            
            -
            
            
            -
            
            
            -**Total**
            
            
            107
            
            
            81
            
            
            65
            
            
            57
            
            
            48
            
            
            107
            
            
            81
            
            
            65
            
            
            57
            
            
            48Proved
                UndevelopedCanada
            
            
            687
            
            
            501
            
            
            380
            
            
            296
            
            
            236
            
            
            687
            
            
            501
            
            
            380
            
            
            296
            
            
            236United States
            
            
            299
            
            
            225
            
            
            175
            
            
            140
            
            
            114
            
            
            180
            
            
            133
            
            
            102
            
            
            82
            
            
            67**Total**
            
            
            986
            
            
            726
            
            
            555
            
            
            436
            
            
            350
            
            
            867
            
            
            634
            
            
            482
            
            
            378
            
            
            303Total
                ProvedCanada
            
            
            7,785
            
            
            5,382
            
            
            4,234
            
            
            3,552
            
            
            3,091
            
            
            7,785
            
            
            5,382
            
            
            4,234
            
            
            3,552
            
            
            3,091United States
            
            
            1,044
            
            
            830
            
            
            685
            
            
            582
            
            
            505
            
            
            800
            
            
            633
            
            
            521
            
            
            442
            
            
            383**Total**
            
            
            8,829
            
            
            6,212
            
            
            4,919
            
            
            4,134
            
            
            3,596
            
            
            8,585
            
            
            6,015
            
            
            4,755
            
            
            3,994
            
            
            3,474ProbableCanada
            
            
            2,376
            
            
            1,121
            
            
            695
            
            
            495
            
            
            384
            
            
            2,376
            
            
            1,121
            
            
            695
            
            
            495
            
            
            384United States
            
            
            453
            
            
            257
            
            
            162
            
            
            111
            
            
            80
            
            
            308
            
            
            174
            
            
            108
            
            
            72
            
            
            51**Total**
            
            
            2,829
            
            
            1,378
            
            
            857
            
            
            606
            
            
            464
            
            
            2,684
            
            
            1,295
            
            
            803
            
            
            567
            
            
            435Total
                Proved plus ProbableCanada
            
            
            10,161
            
            
            6,503
            
            
            4,929
            
            
            4,047
            
            
            3,475
            
            
            10,161
            
            
            6,503
            
            
            4,929
            
            
            4,047
            
            
            3,475United States
            
            
            1,497
            
            
            1,087
            
            
            847
            
            
            693
            
            
            585
            
            
            1,108
            
            
            807
            
            
            629
            
            
            514
            
            
            434**Total**
            
            
            11,658
            
            
            7,590
            
            
            5,776
            
            
            4,740
            
            
            4,060
            
            
            11,269
            
            
            7,310
            
            
            5,558
            
            
            4,561
            
            
            3,909








11







**Summary
      of Conventional Oil and Gas Reserves**


**As
      of December 31, 2005**




***Constant
      Prices and Costs***





**OIL
                AND NATURAL GAS RESERVES****LIGHT
                AND MEDIUM OIL**
            
            **HEAVY
                OIL**
            
            **NATURAL
                GAS****RESERVES
                CATEGORY**
            
            **Company
                Interest**
            
            **Gross**
            
            **Net**
            
            **Company
                Interest**
            
            **Gross**
            
            **Net**
            
            **Company
                Interest**
            
            **Gross**
            
            **Net**(Mbbls)
            
            (Mbbls)
            
            (Mbbls)
            
            (Mbbls)
            
            (Mbbls)
            
            (Mbbls)
            
            (Mmcf)
            
            (Mmcf)
            
            (Mmcf)Proved
                Developed ProducingCanada
            
            
            71,318
            
            
            70,626
            
            
            64,862
            
            
            30,634
            
            
            30,608
            
            
            27,452
            
            
            794,051
            
            
            769,331
            
            
            637,078United States
            
            
            15,883
            
            
            15,883
            
            
            13,354
            
            
            -
            
            
            -
            
            
            -
            
            
            8,852
            
            
            8,852
            
            
            7,442**Total**
            
            
            87,201
            
            
            86,509
            
            
            78,216
            
            
            30,634
            
            
            30,608
            
            
            27,452
            
            
            802,903
            
            
            778,183
            
            
            644,520Proved
                Developed Non-ProducingCanada
            
            
            169
            
            
            168
            
            
            146
            
            
            -
            
            
            -
            
            
            -
            
            
            19,772
            
            
            19,562
            
            
            15,747United States
            
            
            -
            
            
            -
            
            
            -
            
            
            -
            
            
            -
            
            
            -
            
            
            -
            
            
            -
            
            
            -**Total**
            
            
            169
            
            
            168
            
            
            146
            
            
            -
            
            
            -
            
            
            -
            
            
            19,772
            
            
            19,562
            
            
            15,747Proved
                UndevelopedCanada
            
            
            3,355
            
            
            3,319
            
            
            2,935
            
            
            2,364
            
            
            2,363
            
            
            2,004
            
            
            164,320
            
            
            158,738
            
            
            133,899United States
            
            
            7,858
            
            
            7,858
            
            
            6,583
            
            
            -
            
            
            -
            
            
            -
            
            
            4,378
            
            
            4,378
            
            
            3,667**Total**
            
            
            11,213
            
            
            11,177
            
            
            9,518
            
            
            2,364
            
            
            2,363
            
            
            2,004
            
            
            168,698
            
            
            163,116
            
            
            137,566Total
                Proved ReservesCanada
            
            
            74,842
            
            
            74,113
            
            
            67,943
            
            
            32,998
            
            
            32,971
            
            
            29,456
            
            
            978,143
            
            
            947,631
            
            
            786,724United States
            
            
            23,741
            
            
            23,741
            
            
            19,937
            
            
            -
            
            
            -
            
            
            -
            
            
            13,230
            
            
            13,230
            
            
            11,109**Total**
            
            
            98,583
            
            
            97,854
            
            
            87,880
            
            
            32,998
            
            
            32,971
            
            
            29,456
            
            
            991,373
            
            
            960,861
            
            
            797,833Probable
                ReservesCanada
            
            
            17,649
            
            
            17,422
            
            
            15,111
            
            
            8,570
            
            
            8,562
            
            
            6,197
            
            
            316,239
            
            
            308,162
            
            
            257,853United States
            
            
            5,501
            
            
            5,501
            
            
            4,613
            
            
            -
            
            
            -
            
            
            -
            
            
            33,042
            
            
            33,042
            
            
            27,736**Total**
            
            
            23,150
            
            
            22,923
            
            
            19,724
            
            
            8,570
            
            
            8,562
            
            
            6,197
            
            
            349,281
            
            
            341,204
            
            
            285,589Total
                Proved Plus Probable ReservesCanada
            
            
            92,491
            
            
            91,535
            
            
            83,054
            
            
            41,568
            
            
            41,533
            
            
            35,653
            
            
            1,294,382
            
            
            1,255,793
            
            
            1,044,577United States
            
            
            29,242
            
            
            29,242
            
            
            24,550
            
            
            -
            
            
            -
            
            
            -
            
            
            46,272
            
            
            46,272
            
            
            38,845**Total**
            
            
            121,733
            
            
            120,777
            
            
            107,604
            
            
            41,568
            
            
            41,533
            
            
            35,653
            
            
            1,340,654
            
            
            1,302,065
            
            
            1,083,422





*(continues
      on next page)*





12





*(continued)*





**OIL
                AND NATURAL GAS RESERVES****NATURAL
                GAS LIQUIDS**
            
            **TOTAL****RESERVES
                CATEGORY**
            
            **Company**
              **Interest**
            
            **Gross**
            
            **Net**
            
            **Company**
              **Interest**
            
            **Gross**
            
            **Net**(Mbbls)
            
            (Mbbls)
            
            (Mbbls)
            
            (MBOE)
            
            (MBOE)
            
            (MBOE)Proved
                Developed ProducingCanada
            
            
            11,899
            
            
            11,718
            
            
            8,256
            
            
            246,193
            
            
            241,174
            
            
            206,750United States
            
            
            -
            
            
            -
            
            
            -
            
            
            17,358
            
            
            17,358
            
            
            14,594**Total**
            
            
            11,899
            
            
            11,718
            
            
            8,256
            
            
            263,551
            
            
            258,532
            
            
            221,344Proved
                Developed Non-ProducingCanada
            
            
            475
            
            
            474
            
            
            332
            
            
            3,939
            
            
            3,902
            
            
            3,102United States
            
            
            -
            
            
            -
            
            
            -
            
            
            -
            
            
            -
            
            
            -**Total**
            
            
            475
            
            
            474
            
            
            332
            
            
            3,939
            
            
            3,902
            
            
            3,102Proved
                UndevelopedCanada
            
            
            966
            
            
            965
            
            
            682
            
            
            34,072
            
            
            33,103
            
            
            27,938United States
            
            
            -
            
            
            -
            
            
            -
            
            
            8,588
            
            
            8,588
            
            
            7,194**Total**
            
            
            966
            
            
            965
            
            
            682
            
            
            42,659
            
            
            41,691
            
            
            35,132Total
                Proved ReservesCanada
            
            
            13,340
            
            
            13,157
            
            
            9,270
            
            
            284,204
            
            
            278,180
            
            
            237,790United States
            
            
            -
            
            
            -
            
            
            -
            
            
            25,946
            
            
            25,946
            
            
            21,789**Total**
            
            
            13,340
            
            
            13,157
            
            
            9,270
            
            
            310,150
            
            
            304,126
            
            
            259,578Probable
                ReservesCanada
            
            
            3,562
            
            
            3,504
            
            
            2,483
            
            
            82,488
            
            
            80,848
            
            
            66,767United States
            
            
            -
            
            
            -
            
            
            -
            
            
            11,008
            
            
            11,008
            
            
            9,236**Total**
            
            
            3,562
            
            
            3,504
            
            
            2,483
            
            
            93,496
            
            
            91,856
            
            
            76,002Total
                Proved Plus Probable ReservesCanada
            
            
            16,902
            
            
            16,661
            
            
            11,753
            
            
            366,691
            
            
            359,028
            
            
            304,556United States
            
            
            -
            
            
            -
            
            
            -
            
            
            36,954
            
            
            36,954
            
            
            31,024**Total**
            
            
            16,902
            
            
            16,661
            
            
            11,753
            
            
            403,645
            
            
            395,982
            
            
            335,580








13







**Summary
      of Net Present Value of Future Net Revenue**


**Attributable
      to Conventional Oil and Gas Reserves**


**As
      of December 31, 2005**




***Constant
      Prices and Costs***







**NET
                PRESENT VALUE OF FUTURE NET REVENUE DISCOUNTED AT
                (%/YEAR)****Before
                Deducting Income Taxes**
            
            **After
                Deducting Income Taxes****RESERVES
                CATEGORY**
            
            **0%**
            
            **5%**
            
            **10%**
            
            **15%**
            
            **20%**
            
            **0%**
            
            **5%**
            
            **10%**
            
            **15%**
            
            **20%**(in $ millions)Proved
                Developed ProducingCanada
            
            
            8,206
            
            
            5,500
            
            
            4,224
            
            
            3,480
            
            
            2,987
            
            
            8,206
            
            
            5,500
            
            
            4,224
            
            
            3,480
            
            
            2,987United States
            
            
            861
            
            
            685
            
            
            568
            
            
            485
            
            
            424
            
            
            685
            
            
            544
            
            
            450
            
            
            384
            
            
            334**Total**
            
            
            9,067
            
            
            6,185
            
            
            4,792
            
            
            3,965
            
            
            3,411
            
            
            8,891
            
            
            6,044
            
            
            4,674
            
            
            3,864
            
            
            3,321Proved
                Developed Non-ProducingCanada
            
            
            130
            
            
            97
            
            
            77
            
            
            64
            
            
            55
            
            
            130
            
            
            97
            
            
            77
            
            
            64
            
            
            55United States
            
            
            -
            
            
            -
            
            
            -
            
            
            -
            
            
            -
            
            
            -
            
            
            -
            
            
            -
            
            
            -
            
            
            -**Total**
            
            
            130
            
            
            97
            
            
            77
            
            
            64
            
            
            55
            
            
            130
            
            
            97
            
            
            77
            
            
            64
            
            
            55Proved
                UndevelopedCanada
            
            
            980
            
            
            711
            
            
            530
            
            
            406
            
            
            319
            
            
            980
            
            
            711
            
            
            530
            
            
            406
            
            
            319United States
            
            
            358
            
            
            267
            
            
            206
            
            
            164
            
            
            132
            
            
            223
            
            
            167
            
            
            129
            
            
            102
            
            
            83**Total**
            
            
            1,338
            
            
            978
            
            
            736
            
            
            570
            
            
            451
            
            
            1,203
            
            
            878
            
            
            659
            
            
            508
            
            
            402Total
                ProvedCanada
            
            
            9,316
            
            
            6,308
            
            
            4,831
            
            
            3,950
            
            
            3,361
            
            
            9,316
            
            
            6,308
            
            
            4,831
            
            
            3,950
            
            
            3,361United States
            
            
            1,219
            
            
            952
            
            
            774
            
            
            649
            
            
            556
            
            
            908
            
            
            711
            
            
            579
            
            
            486
            
            
            417**Total**
            
            
            10,535
            
            
            7,260
            
            
            5,605
            
            
            4,599
            
            
            3,917
            
            
            10,224
            
            
            7,019
            
            
            5,410
            
            
            4,436
            
            
            3,778ProbableCanada
            
            
            2,724
            
            
            1,320
            
            
            821
            
            
            581
            
            
            442
            
            
            2,724
            
            
            1,320
            
            
            821
            
            
            581
            
            
            442United States
            
            
            539
            
            
            309
            
            
            196
            
            
            134
            
            
            97
            
            
            356
            
            
            199
            
            
            122
            
            
            81
            
            
            57**Total**
            
            
            3,263
            
            
            1,629
            
            
            1,017
            
            
            715
            
            
            539
            
            
            3,080
            
            
            1,519
            
            
            943
            
            
            662
            
            
            499Total
                Proved plus ProbableCanada
            
            
            12,040
            
            
            7,628
            
            
            5,652
            
            
            4,531
            
            
            3,803
            
            
            12,040
            
            
            7,628
            
            
            5,652
            
            
            4,531
            
            
            3,803United States
            
            
            1,758
            
            
            1,261
            
            
            970
            
            
            783
            
            
            653
            
            
            1,264
            
            
            910
            
            
            701
            
            
            567
            
            
            474**Total**
            
            
            13,798
            
            
            8,889
            
            
            6,622
            
            
            5,314
            
            
            4,456
            
            
            13,304
            
            
            8,538
            
            
            6,353
            
            
            5,098
            
            
            4,277








14




*Forecast
      Prices and Costs*




The
      forecast price and cost case assumes no legislative or regulatory amendments,
      and includes the effects of inflation. The estimated future net revenue to
      be
      derived from the production of the reserves includes an inflation rate of 2.5%
      per year until 2008 and 1.5% per year thereafter, an exchange rate of
      Cdn$1.00=US$0.85 and the following price forecasts supplied by
      Sproule.





**CRUDE
                OIL**
            
            **NATURAL
                GAS**
            
            **NATURAL
                GAS LIQUIDS****Edmonton
                Par Price****Year**
            
            **WTI**
              **Cushing
                Oklahoma**
            
            **Edmonton**
              **Par
                Price**
              **40o API**
            
            **Hardisty**
              **Heavy**
              **12o API**
            
            **Cromer**
              **Medium**
              **29.3o API**
            
            **30 day
                spot**
              **@ AECO**
            
            **Henry
                Hub**
              **Price**
            
            **Propanes**
            
            **Butanes**
            
            **Pentanes**
              **Plus**
            
            **Inflation**
              **Rate**
            
            **Exchange**
              **Rate**($US/bbl)
            
            ($Cdn/bbl)
            
            ($Cdn/bbl)
            
            ($Cdn/bbl)
            
            ($Cdn/mmbtu)
            
            ($US/mmbtu)
            
            ($Cdn/bbl)
            
            ($Cdn/bbl)
            
            ($Cdn/bbl)
            
            (%/year)
            
            ($US/$Cdn)2006
            
            
            60.81
            
            
            70.07
            
            
            37.07
            
            
            59.62
            
            
            11.58
            
            
            11.59
            
            
            39.25
            
            
            47.01
            
            
            71.77
            
            
            2.5
            
            
            0.852007
            
            
            61.61
            
            
            70.99
            
            
            37.29
            
            
            60.39
            
            
            10.84
            
            
            10.11
            
            
            39.76
            
            
            47.62
            
            
            72.71
            
            
            2.5
            
            
            0.852008
            
            
            54.60
            
            
            62.73
            
            
            34.23
            
            
            53.48
            
            
            8.95
            
            
            8.50
            
            
            35.14
            
            
            42.08
            
            
            64.25
            
            
            2.5
            
            
            0.852009
            
            
            50.19
            
            
            57.53
            
            
            32.27
            
            
            49.18
            
            
            7.87
            
            
            7.58
            
            
            32.22
            
            
            38.59
            
            
            58.92
            
            
            1.5
            
            
            0.852010
            
            
            47.76
            
            
            54.65
            
            
            31.15
            
            
            46.75
            
            
            7.57
            
            
            7.32
            
            
            30.61
            
            
            36.66
            
            
            55.97
            
            
            1.5
            
            
            0.85Thereafter
            
            
            1.5
            %
            
            1.5
            %
            
            (1)
            
            
            (1)
            
            
            (1)
            
            
            1.5
            %
            
            1.5
            %
            
            1.5
            %
            
            1.5
            %
            
            1.5
            
            
            0.85


___________


Note:


(1)
            Escalation
                varies after 2010




In
      2005, Enerplus received a weighted average price (net of transportation
      costs but before hedging) of $41.99/bbl for heavy crude oil, $61.96/bbl for
      light and medium crude oil, $47.33/bbl for NGLs and $8.41/Mcf for natural
      gas.




*Constant
      Prices and Costs*




The
      constant price and cost case assumes the continuance of product prices at
      December 31, 2005 and operating costs projected for 2006, and the
      continuance of current laws and regulations. Product prices have not been
      escalated beyond this date nor have operating and capital costs been increased
      on an inflationary basis. The future net revenue to be received from the
      production of the reserves was based on an exchange rate of Cdn$1.00=US$0.85
      and
      the following prices in effect as at December 31, 2005:





**CRUDE
                OIL**
            
            **NATURAL
                GAS**
            
            **NATURAL
                GAS LIQUIDS****Edmonton
                Par Price****Year**
            
            **WTI**
              **Cushing
                Oklahoma**
            
            **Edmonton**
              **Par
                Price**
              **40o API**
            
            **Hardisty**
              **Heavy**
              **12o API**
            
            **Cromer**
              **Medium**
              **29.3o API**
            
            **30 day
                spot**
              **@ AECO**
            
            **Henry
                Hub**
              **Price**
            
            **Propanes**
            
            **Butanes**
            
            **Pentanes**
              **Plus**
            
            **Inflation**
              **Rate**
            
            **Exchange**
              **Rate**($US/bbl)
            
            ($Cdn/bbl)
            
            ($Cdn/bbl)
            
            ($Cdn/bbl)
            
            ($Cdn/mmbtu)
            
            ($US/mmbtu)
            
            ($Cdn/bbl)
            
            ($Cdn/bbl)
            
            ($Cdn/bbl)
            
            (%/year)
            
            ($US/$Cdn)2006
            
            
            61.04
            
            
            68.12
            
            
            30.86
            
            
            52.28
            
            
            9.99
            
            
            10.08
            
            
            51.90
            
            
            59.32
            
            
            71.35
            
            
            -
            
            
            0.85








15







*Undiscounted
      Future Net Revenue by Reserves Category*




The
      undiscounted total future net revenue by reserves category as of
      December 31, 2005, using both constant and forecast prices and costs, is
      set forth below:





**RESERVES
                CATEGORY**
            
            **Revenue**
            
            **Royalties**
            
            **Operating
                Costs**
            
            **Development**
              **Costs**
            
            **Abandonment**
              **and**
              **Reclamation**
              **Costs**
            
            **Future
                Net Revenue**
              **Before**
              **Income**
              **Taxes**
            
            **Income**
              **Taxes**
            
            **Future
                Net Revenue**
              **After**
              **Income**
              **Taxes**(in $ millions)**Constant
                Prices and Costs**Proved
                ReservesCanada
            
            
            16,230
            
            
            2,870
            
            
            3,573
            
            
            364
            
            
            107
            
            
            9,316
            
            
            -
            
            
            9,316United States
            
            
            1,808
            
            
            411
            
            
            88
            
            
            84
            
            
            6
            
            
            1,219
            
            
            311
            
            
            908Total
            
            
            18,038
            
            
            3,281
            
            
            3,661
            
            
            448
            
            
            113
            
            
            10,535
            
            
            311
            
            
            10,224Proved
                Plus Probable ReservesCanada
            
            
            20,872
            
            
            3,786
            
            
            4,520
            
            
            416
            
            
            110
            
            
            12,040
            
            
            -
            
            
            12,040United States
            
            
            2,571
            
            
            590
            
            
            117
            
            
            100
            
            
            6
            
            
            1,758
            
            
            494
            
            
            1,264Total
            
            
            23,443
            
            
            4,376
            
            
            4,637
            
            
            516
            
            
            116
            
            
            13,798
            
            
            494
            
            
            13,304**Forecast
                Prices and Costs**Proved
                ReservesCanada
            
            
            14,856
            
            
            2,399
            
            
            4,139
            
            
            378
            
            
            155
            
            
            7,785
            
            
            -
            
            
            7,785United States
            
            
            1,601
            
            
            363
            
            
            100
            
            
            86
            
            
            8
            
            
            1,044
            
            
            244
            
            
            800Total
            
            
            16,457
            
            
            2,762
            
            
            4,239
            
            
            464
            
            
            163
            
            
            8,829
            
            
            244
            
            
            8,585Proved
                Plus Probable ReservesCanada
            
            
            19,474
            
            
            3,232
            
            
            5,475
            
            
            432
            
            
            174
            
            
            10,161
            
            
            -
            
            
            10,161United States
            
            
            2,277
            
            
            520
            
            
            147
            
            
            103
            
            
            10
            
            
            1,497
            
            
            389
            
            
            1,108Total
            
            
            21,751
            
            
            3,752
            
            
            5,622
            
            
            535
            
            
            184
            
            
            11,658
            
            
            389
            
            
            11,269





*Net
      Present Value of Future Net Revenue by Reserves Category*




The
      net present value of future net revenue before income taxes by reserves category
      and production group as of December 31, 2005, using both constant and
      forecast prices and costs and discounted at 10% per year, is set forth
      below:





**Future
                Net Revenue Before Income Taxes**
              **(Discounted
                at 10%/year)****RESERVES
                CATEGORY**
            
            **Production
                Group**
            
            **Constant
                Prices and Costs**
            
            **Forecast
                Prices and Costs**(in $ millions)**Canada**Proved
                Reserves
            
            Light
              and Medium Crude Oil (a)
            
            
            1,157
            
            
            1,023Heavy
                Oil
            
            
            301
            
            
            352Natural
                Gas(b)
            
            
            3,373
            
            
            2,859Proved
                Plus Probable Reserves
            
            Light
              and Medium Crude Oil(a)
            
            
            1,309
            
            
            1,158Heavy
                Oil
            
            
            328
            
            
            383Natural
                Gas(b)
            
            
            4,015
            
            
            3,388**United States**Proved
                Reserves
            
            Light
              and Medium Crude Oil(a)
            
            
            698
            
            
            612Heavy
                Oil
            
            
            -
            
            
            -Natural
                Gas(b)
            
            
            76
            
            
            73Proved
                Plus Probable Reserves
            
            Light
              and Medium Crude Oil(a)
            
            
            736
            
            
            633Heavy
                Oil
            
            
            -
            
            
            -Natural
                Gas(b)
            
            
            234
            
            
            214


___________


Notes:


(a)
            Excludes
                solution gas and other by-products.




(b)
            Includes
                by-products and solution gas from oil
                wells.





16







*Estimated
      Production for Estimates of Future Net Revenue*




The
      volume of gross production from Proved plus Probable Reserves estimated for
      2006
      in preparing the estimated net present values of future net revenue is set
      forth
      below. Canadian production has been estimated by Sproule and
      U.S. production has been estimated by D&M.





**Canada**
            
            **United States****Product
                Type**
            
            **Aggregate
                Estimated**
              **2006
                Production**
            
            **Daily
                Estimated**
              **2006
                Production**
            
            **Aggregate
                Estimated**
              **2006
                Production**
            
            **Daily
                Estimated**
              **2006
                Production**Crude
                oilLight
                and medium crude oil
            
            
            5,904
            
            Mbbls
            
            
            16,174
            
            bbl/d
            
            
            3,876
            
            Mbbls
            
            
            10,619
            
            bbl/dHeavy
                oil
            
            
            3,661
            
            Mbbls
            
            
            10,031
            
            bbl/d
            
            -
            -Total
                crude oil
            
            
            9,565
            
            Mbbls
            
            
            26,205
            
            bbl/d
            
            
            3,876
            
            Mbbls
            
            
            10,619
            
            bbl/dNatural
                gas liquids
            
            
            1,504
            
            Mbbls
            
            
            4,122
            
            bbl/d
            
            -
            -Total
                liquids
            
            
            11,069
            
            Mbbls
            
            
            30,327
            
            bbl/d
            
            
            3,876
            
            Mbbls
            
            
            10,619
            
            bbl/dNatural
                gas
            
            
            105,816
            
            MMcf
            
            
            289,907
            
            Mcf/d
            
            
            2,555
            
            MMcf
            
            
            7,001
            
            Mcf/dTotal
            
            
            28,705
            
            MBOE
            
            
            78,645
            
            BOE/d
            
            
            4,302
            
            MBOE
            
            
            11,786
            
            BOE/d




*Future
      Development Costs*




The
      amount of development costs deducted in the estimation of net present value
      of
      future net revenue is as follows (see also "Operational Information  -
      Exploration and Development Activities"):





**Constant
                Prices and Costs**
            
            **Forecast
                Prices and Costs****Proved
                Reserves**
            
            **Proved
                Plus**
              **Probable Reserves**
            
            **Proved
                Reserves**
            
            **Proved
                Plus**
              **Probable Reserves****Year**
            
            **Undiscounted**
            
            **Discounted**
              **at
                10%/year**
            
            **Undiscounted**
            
            **Discounted**
              **at
                10%/year**
            
            **Undiscounted**
            
            **Discounted**
              **at
                10%/year**
            
            **Undiscounted**
            
            **Discounted**
              **at
                10%/year**(in $ millions)**CANADA**2006
            
            
            161
            
            
            154
            
            
            184
            
            
            175
            
            
            161
            
            
            154
            
            
            184
            
            
            1752007
            
            
            72
            
            
            62
            
            
            82
            
            
            71
            
            
            74
            
            
            64
            
            
            84
            
            
            732008
            
            
            46
            
            
            36
            
            
            54
            
            
            43
            
            
            49
            
            
            38
            
            
            57
            
            
            452009
            
            
            31
            
            
            22
            
            
            36
            
            
            26
            
            
            33
            
            
            24
            
            
            39
            
            
            282010
            
            
            16
            
            
            10
            
            
            19
            
            
            13
            
            
            18
            
            
            11
            
            
            21
            
            
            14Remainder
            
            
            38
            
            
            19
            
            
            41
            
            
            19
            
            
            43
            
            
            21
            
            
            47
            
            
            22**Total**
            
            
            364
            
            
            303
            
            
            416
            
            
            347
            
            
            378
            
            
            312
            
            
            432
            
            
            357**UNITED
                STATES**2006
            
            
            71
            
            
            67
            
            
            79
            
            
            76
            
            
            72
            
            
            69
            
            
            81
            
            
            782007
            
            
            13
            
            
            12
            
            
            21
            
            
            18
            
            
            14
            
            
            11
            
            
            22
            
            
            192008
            
            
            -
            
            
            -
            
            
            -
            
            
            -
            
            
            -
            
            
            -
            
            
            -
            
            
            -2009
            
            
            -
            
            
            -
            
            
            -
            
            
            -
            
            
            -
            
            
            -
            
            
            -
            
            
            -2010
            
            
            -
            
            
            -
            
            
            -
            
            
            -
            
            
            -
            
            
            -
            
            
            -
            
            
            -Remainder
            
            
            -
            
            
            -
            
            
            -
            
            
            -
            
            
            -
            
            
            -
            
            
            -
            
            
            -**Total**
            
            
            84
            
            
            79
            
            
            100
            
            
            94
            
            
            86
            
            
            80
            
            
            103
            
            
            97








17




**Summary
      of Joslyn Project Bitumen Reserves**




The
      following tables summarize the reserves volumes and net present value of future
      net revenue attributable to Enerplus' 16% working interest in the
      SAGD-recoverable bitumen reserves of the Joslyn Project as of December 31,
      2005, including certain assumptions relating to the determination of those
      reserves and values, as contained in the GLJ Report. Subsequent to
      December 31, 2005, Enerplus reduced its economic interest in the Joslyn
      Project to 15%, as described in "General Development of Enerplus Resources
      Fund  - Developments in the Past Three Years  - Participation in
      Joslyn Project and Other Oil Sands Projects."




**Summary
      of Enerplus' Interest in the SAGD Bitumen Reserves of the**


**Joslyn Lease
      and Net Present Values of Future Net Revenue**


**As
      of December 31, 2005**




**Forecast
      Prices and Costs**




**BITUMEN**
              **RESERVES**
            
            **NET
                PRESENT VALUE OF FUTURE NET REVENUE,**
              **BEFORE
                AND AFTER INCOME TAXES DISCOUNTED AT**
              **(%/YEAR)****RESERVES
                CATEGORY**
            
            **Gross**
            
            **Net**
            
            **0%**
            
            **5%**
            
            **10%**
            
            **15%**
            
            **20%**(Mbbls)
            
            (Mbbls)
            
            (in $ millions)Proved
                Undeveloped Reserves
            
            
            9,453
            
            
            9,358
            
            
            38
            
            
            19
            
            
            9
            
            
            3
            
            
            0Probable
                Reserves
            
            
            43,700
            
            
            41,150
            
            
            299
            
            
            88
            
            
            27
            
            
            6
            
            
            (4
            )Total
                Proved Plus Probable
            
            
            53,153
            
            
            50,508
            
            
            337
            
            
            107
            
            
            36
            
            
            9
            
            
            (4
            )




**Constant
      Prices and Costs**





**BITUMEN**
              **RESERVES**
            
            **NET
                PRESENT VALUE OF FUTURE NET REVENUE,**
              **BEFORE
                AND AFTER INCOME TAXES DISCOUNTED AT**
              **(%/YEAR)****RESERVES
                CATEGORY**
            
            **Gross**
            
            **Net**
            
            **0%**
            
            **5%**
            
            **10%**
            
            **15%**
            
            **20%**(Mbbls)
            
            (Mbbls)
            
            (in $ millions)Proved
                Undeveloped Reserves
            
            
            9,308
            
            
            9,215
            
            
            7
            
            
            (1
            )
            
            (4
            )
            
            (6
            )
            
            (7
            )Probable
                Reserves
            
            
            43,845
            
            
            43,407
            
            
            117
            
            
            27
            
            
            0
            
            
            (9
            )
            
            (13
            )Total
                Proved Plus Probable Reserves
            
            
            53,153
            
            
            52,622
            
            
            124
            
            
            26
            
            
            (4
            )
            
            (15
            )
            
            (20
            )




*Forecast
      Prices and Costs*




The
      forecast price and cost case assumes no legislative or regulatory amendments,
      and includes the effects of inflation. The estimated future net revenue to
      be
      derived from the production of the reserves was based on an inflation rate
      of
      2.5% per year until 2008 and 1.5% per year thereafter, an exchange rate of
      Cdn$1.00=US$0.85 and the price forecasts set forth below supplied by Sproule
      as
      at December 31, 2005 (but utilized by GLJ for internal consistency in
      Enerplus' reserves reporting). The forecast net prices for bitumen produced
      from
      the Joslyn Project (" **Joslyn
      Bitumen** ")
      are calculated by subtracting blending costs, transportation and quality
      differentials from the forecast prices for Bow River Medium crude oil for the
      relevant periods.





18








**CRUDE
                OIL**
            
            **NATURAL
                GAS****Year**
            
            **WTI**
              **Cushing**
              **Oklahoma**
            
            **Edmonton**
              **Par
                Price**
              **40o API**
            
            **Bow**
              **River**
              **Medium**
            
            **Joslyn**
              **Bitumen**
            
            **AECO**
              **30 Day**
              **Spot
                Price**($US/bbl)
            
            ($Cdn/bbl)
            
            ($Cdn/bbl)
            
            ($Cdn/bbl)
            
            ($Cdn/MMBTU)2006
            
            
            60.81
            
            
            70.07
            
            
            47.27
            
            
            27.78
            
            
            11.582007
            
            
            61.61
            
            
            70.99
            
            
            47.79
            
            
            28.08
            
            
            10.842008
            
            
            54.60
            
            
            62.73
            
            
            43.23
            
            
            23.49
            
            
            8.952009
            
            
            50.19
            
            
            57.53
            
            
            40.28
            
            
            20.77
            
            
            7.872010
            
            
            47.76
            
            
            54.65
            
            
            38.65
            
            
            20.40
            
            
            7.57Thereafter
            
            
            1.5
            %
            
            1.5
            %
            
            (1
            )
            
            (1
            )
            
            (1
            )


___________


Note:


(1)
            Escalation
                varies after 2010.




*Constant
      Prices and Costs*




The
      constant price and cost case assumes the continuance of product prices at
      December 31, 2005 and operating costs projected for 2006, and the
      continuance of current laws and regulations. In accordance with Canadian
      Securities Administrators Staff Notice 51-315, the constant price of bitumen
      produced from the Joslyn Project (" **Joslyn
      Bitumen** ")
      was calculated by deducting the 2005 average price differential of a barrel
      of
      WTI crude oil and a barrel of Joslyn Bitumen from the December 31, 2005
      price for a barrel of WTI crude oil of US$61.04/bbl. Product prices have not
      been escalated beyond this date nor have operating and capital costs been
      increased on an inflationary basis. The future net revenue to be received from
      the production of the reserves was based on an exchange rate of Cdn$1.00=US$0.85
      and the following prices in effect as at December 31, 2005:





**CRUDE
                OIL**
            
            **NATURAL
                GAS****WTI**
              **Cushing
                Oklahoma**
            
            **Edmonton**
              **Par
                Price**
              **40o API**
            
            **Bow
                River**
              **Medium**
            
            **Joslyn**
              **Bitumen**
            
            **AECO
                30 Day**
              **Spot
                Price**($US/bbl)
            
            ($Cdn/bbl)
            
            ($Cdn/bbl)
            
            ($Cdn/bbl)
            
            ($Cdn/MMBTU)61.04
            
            
            68.12
            
            
            44.28
            
            
            21.24
            
            
            9.99




*Undiscounted
      Future Net Revenue by Reserves Category*




The
      undiscounted total future net revenue by reserves category as of
      December 31, 2005, using both constant and forecast prices and costs, is
      set forth below:





**RESERVES
                CATEGORY**
            
            **Revenue**
            
            **Royalties**
            
            **Operating
                Costs**
            
            **Development**
              **Costs**
            
            **Abandonment**
              **and**
              **Reclamation**
              **Costs**
            
            **Future
                Net Revenue**
              **Before**
              **Income**
              **Taxes**
            
            **Income**
              **Taxes**
            
            **Future
                Net Revenue**
              **After**
              **Income**
              **Taxes**(in $ millions)**Constant
                Prices and Costs**Proved
                Undeveloped Reserves
            
            
            198
            
            
            2
            
            
            147
            
            
            41
            
            
            1
            
            
            7
            
            
            0
            
            
            7Probable
                Reserves
            
            
            931
            
            
            9
            
            
            607
            
            
            195
            
            
            3
            
            
            117
            
            
            0
            
            
            117Total
                Proved Plus Probable Reserves
            
            
            1,129
            
            
            11
            
            
            754
            
            
            236
            
            
            4
            
            
            124
            
            
            0
            
            
            124**Forecast
                Prices and Costs**Proved
                Undeveloped Reserves
            
            
            229
            
            
            2
            
            
            143
            
            
            45
            
            
            1
            
            
            38
            
            
            0
            
            
            38Probable
                Reserves
            
            
            1,321
            
            
            85
            
            
            678
            
            
            254
            
            
            5
            
            
            299
            
            
            0
            
            
            299Total
                Proved Plus Probable Reserves
            
            
            1,550
            
            
            87
            
            
            821
            
            
            299
            
            
            6
            
            
            337
            
            
            0
            
            
            337








19


*Net
      Present Value of Future Net Revenue by Reserves Category*




The
      net present value of future net revenue by reserves category and production
      group as of December 31, 2005, using both constant and forecast prices and
      costs and discounted at 10% per year, is set forth below:





**Future
                Net Revenue Before Income Taxes**
              **(Discounted
                at 10%/year)****RESERVES
                CATEGORY**
            
            **Production
                Group**
            
            **Constant
                Prices**
              **and
                Costs**
            
            **Forecast
                Prices**
              **and
                Costs**(in $ millions)Proved
                Undeveloped Reserves
            
            Bitumen
            
            
            (4
            )
            
            9Probable
                Reserves
            
            Bitumen
            
            
            0
            
            
            27Total
                Proved Plus Probable Reserves
            
            Bitumen
            
            
            (4
            )
            
            36




*Estimated
      Production for Estimates of Future Net Revenue*




The
      volume of gross production from the Proved plus Probable Reserves in 2006
      estimated by GLJ in preparing the estimated net present values of future net
      revenue is as follows:





**Product
                Type**
            
            **Aggregate
                Estimated**
              **2006
                Production**
            
            **Daily
                Estimated**
              **2006
                Production**Bitumen
            
            
            270
                Mbbls
            
            
            739
                bbl/d




*Future
      Development Costs*




The
      amount of development costs deducted in the estimation of net present value
      of
      future net revenue is as follows (see also "Operational Information  -
      Exploration and Development Activities"):





**Constant
                Prices and Costs****Proved
                Reserves**
            
            **Proved
                Plus**
              **Probable Reserves****Year**
            
            **Undiscounted**
            
            **Discounted**
              **at
                10%/year**
            
            **Undiscounted**
            
            **Discounted**
              **at
                10%/year**(in $ millions)2006
            
            
            5
            
            
            5
            
            
            11
            
            
            112007
            
            
            11
            
            
            11
            
            
            32
            
            
            112008
            
            
            -
            
            
            -
            
            
            8
            
            
            62009
            
            
            -
            
            
            -
            
            
            -
            
            
            -2010
            
            
            -
            
            
            -
            
            
            5
            
            
            3Remainder
            
            
            25
            
            
            10
            
            
            180
            
            
            57**Total**
            
            
            41
            
            
            26
            
            
            236
            
            
            88





**Forecast
                Prices and Costs****Proved
                Reserves**
            
            **Proved
                Plus**
              **Probable Reserves****Year**
            
            **Undiscounted**
            
            **Discounted**
              **at
                10%/year**
            
            **Undiscounted**
            
            **Discounted**
              **at
                10%/year**(in $ millions)2006
            
            
            5
            
            
            5
            
            
            11
            
            
            112007
            
            
            11
            
            
            11
            
            
            33
            
            
            112008
            
            
            -
            
            
            -
            
            
            9
            
            
            72009
            
            
            -
            
            
            -
            
            
            -
            
            
            -2010
            
            
            -
            
            
            -
            
            
            6
            
            
            4Remainder
            
            
            29
            
            
            12
            
            
            240
            
            
            66**Total**
            
            
            45
            
            
            28
            
            
            299
            
            
            99








20










**Reconciliation
      of Reserves**




The
      following tables reconcile Enerplus' oil and natural gas reserves (on both
      a company interest and net reserves basis) from December 31, 2004 to
      December 31, 2005, using forecast prices and costs.




*Reconciliation
      of Company Interest Reserves*







**CANADA**
            
            **Light
                and Medium Crude Oil**
            
            **Heavy
                Oil**
            
            **Bitumen****Factors**
            
            **Proved**
            
            **Probable**
            
            **Proved**
              **Plus**
              **Probable**
            
            **Proved**
            
            **Probable**
            
            **Proved**
              **Plus**
              **Probable**
            
            **Proved**
            
            **Probable**
            
            **Proved**
              **Plus**
              **Probable**(Mbbls)
            
            (Mbbls)
            
            (Mbbls)
            
            (Mbbls)
            
            (Mbbls)
            
            (Mbbls)
            
            (Mbbls)
            
            (Mbbls)
            
            (Mbbls)**December 31,
                2004**
            
            
            73,039
            
            
            17,180
            
            
            90,219
            
            
            31,369
            
            
            9,603
            
            
            40,972
            
            
            -
            
            
            47,747
            
            
            47,747Acquisitions
            
            
            1,899
            
            
            1,075
            
            
            2,974
            
            
            -
            
            
            -
            
            
            -
            
            
            -
            
            
            -
            
            
            -Divestments
            
            
            (1,297
            )
            
            (780
            )
            
            (2,077
            )
            
            (1,343
            )
            
            (808
            )
            
            (2,151
            )
            
            -
            
            
            -
            
            
            -Discoveries
            
            
            103
            
            
            34
            
            
            137
            
            
            -
            
            
            -
            
            
            -
            
            
            -
            
            
            -
            
            
            -Extensions
            
            
            238
            
            
            (25
            )
            
            213
            
            
            38
            
            
            20
            
            
            58
            
            
            -
            
            
            -
            
            
            -Technical
                Revisions
            
            
            (1,966
            )
            
            (1,808
            )
            
            (3,774
            )
            
            1,400
            
            
            (610
            )
            
            790
            
            
            9,453
            
            
            (4,047
            )
            
            5,406Economic
                Factors
            
            
            4,368
            
            
            1,441
            
            
            5,809
            
            
            1,694
            
            
            468
            
            
            2,162
            
            
            -
            
            
            -
            
            
            -Improved
                Recovery
            
            
            3,280
            
            
            381
            
            
            3,661
            
            
            2,976
            
            
            (178
            )
            
            2,798
            
            
            -
            
            
            -
            
            
            -Production
            
            
            (6,415
            )
            
            -
            
            
            (6,415
            )
            
            (3,233
            )
            
            -
            
            
            (3,233
            )
            
            -
            
            
            -
            
            
            -**December 31,
                2005**
            
            
            **73,249**
            
            
            **17,498**
            
            
            **90,747**
            
            
            **32,901**
            
            
            **8,495**
            
            
            **41,396**
            
            
            **9,453**
            
            
            **43,700**
            
            
            **53,153**





**CANADA
                (continued)**
            
            **Natural
                Gas Liquids**
            
            **Associated
                and Non-Associated**
              **Gas
                (Natural Gas)**
            
            **Total****Factors**
            
            **Proved**
            
            **Probable**
            
            **Proved**
              **Plus**
              **Probable**
            
            **Proved**
            
            **Probable**
            
            **Proved**
              **Plus**
              **Probable**
            
            **Proved**
            
            **Probable**
            
            **Proved**
              **Plus**
              **Probable**(Mbbls)
            
            (Mbbls)
            
            (Mbbls)
            
            (MMcf)
            
            (MMcf)
            
            (MMcf)
            
            (MBOE)
            
            (MBOE)
            
            (MBOE)**December 31,
                2004**
            
            
            12,776
            
            
            3,292
            
            
            16,068
            
            
            971,598
            
            
            295,698
            
            
            1,267,296
            
            
            279,117
            
            
            127,105
            
            
            406,222Acquisitions
            
            
            49
            
            
            14
            
            
            63
            
            
            13,609
            
            
            5,951
            
            
            19,560
            
            
            4,216
            
            
            2,081
            
            
            6,297Divestments
            
            
            (59
            )
            
            (40
            )
            
            (99
            )
            
            (15,614
            )
            
            (7,911
            )
            
            (23,525
            )
            
            (5,301
            )
            
            (2,947
            )
            
            (8,248
            )Discoveries
            
            
            7
            
            
            (1
            )
            
            6
            
            
            2,887
            
            
            568
            
            
            3,455
            
            
            591
            
            
            127
            
            
            718Extensions
            
            
            724
            
            
            143
            
            
            867
            
            
            36,671
            
            
            14,322
            
            
            50,993
            
            
            7,112
            
            
            2,525
            
            
            9,637Technical
                Revisions
            
            
            874
            
            
            (54
            )
            
            820
            
            
            (16,995
            )
            
            (16,860
            )
            
            (33,855
            )
            
            6,930
            
            
            (9,329
            )
            
            (2,399
            )Economic
                Factors
            
            
            353
            
            
            159
            
            
            512
            
            
            20,889
            
            
            7,541
            
            
            28,430
            
            
            9,896
            
            
            3,325
            
            
            13,221Improved
                Recovery
            
            
            71
            
            
            26
            
            
            97
            
            
            39,134
            
            
            10,263
            
            
            49,397
            
            
            12,849
            
            
            1,940
            
            
            14,789Production
            
            
            (1,711
            )
            
            -
            
            
            (1,711
            )
            
            (99,555
            )
            
            -
            
            
            (99,555
            )
            
            (27,952
            )
            
            -
            
            
            (27,952
            )**December 31,
                2005**
            
            
            **13,084**
            
            
            **3,539**
            
            
            **16,623**
            
            
            **952,624**
            
            
            **309,572**
            
            
            **1,262,196**
            
            
            **287,458**
            
            
            **124,827**
            
            
            **412,285**





**UNITED
                STATES**
            
            **Light
                and Medium Crude Oil**
            
            **Heavy
                Oil**
            
            **Bitumen****Factors**
            
            **Proved**
            
            **Probable**
            
            **Proved**
              **Plus**
              **Probable**
            
            **Proved**
            
            **Probable**
            
            **Proved**
              **Plus**
              **Probable**
            
            **Proved**
            
            **Probable**
            
            **Proved**
              **Plus**
              **Probable**(Mbbls)
            
            (Mbbls)
            
            (Mbbls)
            
            (Mbbls)
            
            (Mbbls)
            
            (Mbbls)
            
            (Mbbls)
            
            (Mbbls)
            
            (Mbbls)**December 31,
                2004**
            
            
            -
            
            
            -
            
            
            -
            
            
            -
            
            
            -
            
            
            -
            
            
            -
            
            
            -
            
            
            -Acquisitions
            
            
            23,900
            
            
            5,041
            
            
            28,941
            
            
            -
            
            
            -
            
            
            -
            
            
            -
            
            
            -
            
            
            -Divestments
            
            
            -
            
            
            -
            
            
            -
            
            
            -
            
            
            -
            
            
            -
            
            
            -
            
            
            -
            
            
            -Discoveries
            
            
            -
            
            
            -
            
            
            -
            
            
            -
            
            
            -
            
            
            -
            
            
            -
            
            
            -
            
            
            -Extensions
            
            
            -
            
            
            -
            
            
            -
            
            
            -
            
            
            -
            
            
            -
            
            
            -
            
            
            -
            
            
            -Technical
                Revisions
            
            
            747
            
            
            533
            
            
            1,280
            
            
            -
            
            
            -
            
            
            -
            
            
            -
            
            
            -
            
            
            -Economic
                Factors
            
            
            -
            
            
            -
            
            
            -
            
            
            -
            
            
            -
            
            
            -
            
            
            -
            
            
            -
            
            
            -Improved
                Recovery
            
            
            -
            
            
            -
            
            
            -
            
            
            -
            
            
            -
            
            
            -
            
            
            -
            
            
            -
            
            
            -Production
            
            
            (1,052
            )
            
            -
            
            
            (1,052
            )
            
            -
            
            
            -
            
            
            -
            
            
            -
            
            
            -
            
            
            -**December 31,
                2005**
            
            
            **23,595**
            
            
            **5,574**
            
            
            **29,169**
            
            
            **-**
            
            
            **-**
            
            
            **-**
            
            
            **-**
            
            
            **-**
            
            
            **-**





*(continues
      on next page)*





21








**UNITED
                STATES (continued)**
            
            **Natural
                Gas Liquids**
            
            **Associated
                and Non-Associated**
              **Gas
                (Natural Gas)**
            
            **Total****Factors**
            
            **Proved**
            
            **Probable**
            
            **Proved**
              **Plus**
              **Probable**
            
            **Proved**
            
            **Probable**
            
            **Proved**
              **Plus**
              **Probable**
            
            **Proved**
            
            **Probable**
            
            **Proved**
              **Plus**
              **Probable**(Mbbls)
            
            (Mbbls)
            
            (Mbbls)
            
            (MMcf)
            
            (MMcf)
            
            (MMcf)
            
            (MBOE)
            
            (MBOE)
            
            (MBOE)**December 31,
                2004**
            
            
            -
            
            
            -
            
            
            -
            
            
            -
            
            
            -
            
            
            -
            
            
            -
            
            
            -
            
            
            -Acquisitions
            
            
            -
            
            
            -
            
            
            -
            
            
            12,784
            
            
            32,779
            
            
            45,563
            
            
            26,031
            
            
            10,504
            
            
            36,535Divestments
            
            
            -
            
            
            -
            
            
            -
            
            
            -
            
            
            -
            
            
            -
            
            
            -
            
            
            -
            
            
            -Discoveries
            
            
            -
            
            
            -
            
            
            -
            
            
            -
            
            
            -
            
            
            -
            
            
            -
            
            
            -
            
            
            -Extensions
            
            
            -
            
            
            -
            
            
            -
            
            
            -
            
            
            -
            
            
            -
            
            
            -
            
            
            -
            
            
            -Technical
                Revisions
            
            
            -
            
            
            -
            
            
            -
            
            
            946
            
            
            167
            
            
            1,113
            
            
            904
            
            
            561
            
            
            1,465Economic
                Factors
            
            
            -
            
            
            -
            
            
            -
            
            
            -
            
            
            -
            
            
            -
            
            
            -
            
            
            -
            
            
            -Improved
                Recovery
            
            
            -
            
            
            -
            
            
            -
            
            
            -
            
            
            -
            
            
            -
            
            
            -
            
            
            -
            
            
            -Production
            
            
            -
            
            
            -
            
            
            -
            
            
            (578
            )
            
            -
            
            
            (578
            )
            
            (1,148
            )
            
            -
            
            
            (1,148
            )**December 31,
                2005**
            
            
            **-**
            
            
            **-**
            
            
            **-**
            
            
            **13,152**
            
            
            **32,946**
            
            
            **46,098**
            
            
            **25,787**
            
            
            **11,065**
            
            
            **36,852**





**TOTAL
                ENERPLUS**
            
            **Light
                and Medium Crude Oil**
            
            **Heavy
                Oil**
            
            **Bitumen****Factors**
            
            **Proved**
            
            **Probable**
            
            **Proved**
              **Plus**
              **Probable**
            
            **Proved**
            
            **Probable**
            
            **Proved**
              **Plus**
              **Probable**
            
            **Proved**
            
            **Probable**
            
            **Proved**
              **Plus**
              **Probable**(Mbbls)
            
            (Mbbls)
            
            (Mbbls)
            
            (Mbbls)
            
            (Mbbls)
            
            (Mbbls)
            
            (Mbbls)
            
            (Mbbls)
            
            (Mbbls)**December 31,
                2004**
            
            
            73,039
            
            
            17,180
            
            
            90,219
            
            
            31,369
            
            
            9,603
            
            
            40,972
            
            
            -
            
            
            47,747
            
            
            47,747Acquisitions
            
            
            25,799
            
            
            6,116
            
            
            31,915
            
            
            -
            
            
            -
            
            
            -
            
            
            -
            
            
            -
            
            
            -Divestments
            
            
            (1,297
            )
            
            (780
            )
            
            (2,077
            )
            
            (1,343
            )
            
            (808
            )
            
            (2,151
            )
            
            -
            
            
            -
            
            
            -Discoveries
            
            
            103
            
            
            34
            
            
            137
            
            
            -
            
            
            -
            
            
            -
            
            
            -
            
            
            -
            
            
            -Extensions
            
            
            238
            
            
            (25
            )
            
            213
            
            
            38
            
            
            20
            
            
            58
            
            
            -
            
            
            -
            
            
            -Technical
                Revisions
            
            
            (1,219
            )
            
            (1,275
            )
            
            (2,494
            )
            
            1,400
            
            
            (610
            )
            
            790
            
            
            9,453
            
            
            (4,047
            )
            
            5,406Economic
                Factors
            
            
            4,368
            
            
            1,441
            
            
            5,809
            
            
            1,694
            
            
            468
            
            
            2,162
            
            
            -
            
            
            -
            
            
            -Improved
                Recovery
            
            
            3,280
            
            
            381
            
            
            3,661
            
            
            2,976
            
            
            (178
            )
            
            2,798
            
            
            -
            
            
            -
            
            
            -Production
            
            
            (7,467
            )
            
            -
            
            
            (7,467
            )
            
            (3,233
            )
            
            -
            
            
            (3,233
            )
            
            -
            
            
            -
            
            
            -**December 31,
                2005**
            
            
            **96,844**
            
            
            **23,072**
            
            
            **119,916**
            
            
            **32,901**
            
            
            **8,495**
            
            
            **41,396**
            
            
            **9,453**
            
            
            **43,700**
            
            
            **53,153**





**TOTAL
                ENERPLUS (continued)**
            
            **Natural
                Gas Liquids**
            
            **Associated
                and Non-Associated**
              **Gas
                (Natural Gas)**
            
            **Total****Factors**
            
            **Proved**
            
            **Probable**
            
            **Proved**
              **Plus**
              **Probable**
            
            **Proved**
            
            **Probable**
            
            **Proved**
              **Plus**
              **Probable**
            
            **Proved**
            
            **Probable**
            
            **Proved**
              **Plus**
              **Probable**(Mbbls)
            
            (Mbbls)
            
            (Mbbls)
            
            (MMcf)
            
            (MMcf)
            
            (MMcf)
            
            (MBOE)
            
            (MBOE)
            
            (MBOE)**December 31,
                2004**
            
            
            12,776
            
            
            3,292
            
            
            16,068
            
            
            971,598
            
            
            295,698
            
            
            1,267,296
            
            
            279,117
            
            
            127,105
            
            
            406,222Acquisitions
            
            
            49
            
            
            14
            
            
            63
            
            
            26,393
            
            
            38,730
            
            
            65,123
            
            
            30,247
            
            
            12,585
            
            
            42,832Divestments
            
            
            (59
            )
            
            (40
            )
            
            (99
            )
            
            (15,614
            )
            
            (7,911
            )
            
            (23,525
            )
            
            (5,301
            )
            
            (2,947
            )
            
            (8,248
            )Discoveries
            
            
            7
            
            
            (1
            )
            
            6
            
            
            2,887
            
            
            568
            
            
            3,455
            
            
            591
            
            
            127
            
            
            718Extensions
            
            
            724
            
            
            143
            
            
            867
            
            
            36,671
            
            
            14,322
            
            
            50,993
            
            
            7,112
            
            
            2,525
            
            
            9,637Technical
                Revisions
            
            
            874
            
            
            (54
            )
            
            820
            
            
            (16,049
            )
            
            (16,693
            )
            
            (32,742
            )
            
            7,834
            
            
            (8,768
            )
            
            (934
            )Economic
                Factors
            
            
            353
            
            
            159
            
            
            512
            
            
            20,889
            
            
            7,541
            
            
            28,430
            
            
            9,896
            
            
            3,325
            
            
            13,221Improved
                Recovery
            
            
            71
            
            
            26
            
            
            97
            
            
            39,134
            
            
            10,263
            
            
            49,397
            
            
            12,849
            
            
            1,940
            
            
            14,789Production
            
            
            (1,711
            )
            
            -
            
            
            (1,711
            )
            
            (100,133
            )
            
            -
            
            
            (100,133
            )
            
            (29,100
            )
            
            -
            
            
            (29,100
            )**December 31,
                2005**
            
            
            **13,084**
            
            
            **3,539**
            
            
            **16,623**
            
            
            **965,776**
            
            
            **342,518**
            
            
            **1,308,294**
            
            
            **313,245**
            
            
            **135,892**
            
            
            **449,137**








22


*Reconciliation
      of Net Reserves*





**CANADA**
            
            **Light
                and Medium Crude Oil**
            
            **Heavy
                Oil**
            
            **Bitumen****Factors**
            
            **Proved**
            
            **Probable**
            
            **Proved**
              **Plus**
              **Probable**
            
            **Proved**
            
            **Probable**
            
            **Proved**
              **Plus**
              **Probable**
            
            **Proved**
            
            **Probable**
            
            **Proved**
              **Plus**
              **Probable**(Mbbls)
            
            (Mbbls)
            
            (Mbbls)
            
            (Mbbls)
            
            (Mbbls)
            
            (Mbbls)
            
            (Mbbls)
            
            (Mbbls)
            
            (Mbbls)**December 31,
                2004**
            
            
            66,272
            
            
            14,892
            
            
            81,164
            
            
            26,971
            
            
            8,264
            
            
            35,235
            
            
            -
            
            
            43,640
            
            
            43,640Acquisitions
            
            
            1,349
            
            
            897
            
            
            2,246
            
            
            -
            
            
            -
            
            
            -
            
            
            -
            
            
            -
            
            
            -Divestments
            
            
            (1,099
            )
            
            (778
            )
            
            (1,877
            )
            
            (1,205
            )
            
            (702
            )
            
            (1,907
            )
            
            -
            
            
            -
            
            
            -Discoveries
            
            
            84
            
            
            27
            
            
            111
            
            
            -
            
            
            -
            
            
            -
            
            
            -
            
            
            -
            
            
            -Extensions
            
            
            202
            
            
            (21
            )
            
            181
            
            
            33
            
            
            20
            
            
            53
            
            
            -
            
            
            -
            
            
            -Technical
                Revisions
            
            
            (1,789
            )
            
            (1,556
            )
            
            (3,345
            )
            
            1,136
            
            
            (441
            )
            
            695
            
            
            9,358
            
            
            (2,490
            )
            
            6,868Economic
                Factors
            
            
            3,814
            
            
            1,190
            
            
            5,004
            
            
            1,312
            
            
            349
            
            
            1,661
            
            
            -
            
            
            -
            
            
            -Improved
                Recovery
            
            
            2,939
            
            
            316
            
            
            3,255
            
            
            3,759
            
            
            (1,359
            )
            
            2,400
            
            
            -
            
            
            -
            
            
            -Production
            
            
            (5,345
            )
            
            -
            
            
            (5,345
            )
            
            (2,641
            )
            
            -
            
            
            (2,641
            )
            
            -
            
            
            -
            
            
            -**December 31,
                2005**
            
            
            **66,427**
            
            
            **14,967**
            
            
            **81,394**
            
            
            **29,365**
            
            
            **6,131**
            
            
            **35,496**
            
            
            **9,358**
            
            
            **41,150**
            
            
            **50,508**





**CANADA
                (continued)**
            
            **Natural
                Gas Liquids**
            
            **Associated
                and Non-Associated**
              **Gas
                (Natural Gas)**
            
            **Total****Factors**
            
            **Proved**
            
            **Probable**
            
            **Proved**
              **Plus**
              **Probable**
            
            **Proved**
            
            **Probable**
            
            **Proved**
              **Plus**
              **Probable**
            
            **Proved**
            
            **Probable**
            
            **Proved**
              **Plus**
              **Probable**(Mbbls)
            
            (Mbbls)
            
            (Mbbls)
            
            (MMcf)
            
            (MMcf)
            
            (MMcf)
            
            (MBOE)
            
            (MBOE)
            
            (MBOE)**December 31,
                2004**
            
            
            8,942
            
            
            2,318
            
            
            11,260
            
            
            778,610
            
            
            243,208
            
            
            1,021,818
            
            
            231,953
            
            
            109,649
            
            
            341,602Acquisitions
            
            
            31
            
            
            10
            
            
            41
            
            
            9,731
            
            
            4,493
            
            
            14,224
            
            
            3,002
            
            
            1,656
            
            
            4,658Divestments
            
            
            (49
            )
            
            (29
            )
            
            (78
            )
            
            (10,546
            )
            
            (5,603
            )
            
            (16,149
            )
            
            (4,111
            )
            
            (2,443
            )
            
            (6,554
            )Discoveries
            
            
            3
            
            
            1
            
            
            4
            
            
            2,291
            
            
            450
            
            
            2,741
            
            
            469
            
            
            103
            
            
            572Extensions
            
            
            512
            
            
            100
            
            
            612
            
            
            30,032
            
            
            11,976
            
            
            42,008
            
            
            5,752
            
            
            2,095
            
            
            7,847Technical
                Revisions
            
            
            700
            
            
            (53
            )
            
            647
            
            
            (15,560
            )
            
            (15,893
            )
            
            (31,453
            )
            
            6,812
            
            
            (7,189
            )
            
            (377
            )Economic
                Factors
            
            
            216
            
            
            106
            
            
            322
            
            
            17,405
            
            
            7,049
            
            
            24,454
            
            
            8,243
            
            
            2,820
            
            
            11,063Improved
                Recovery
            
            
            49
            
            
            17
            
            
            66
            
            
            32,974
            
            
            6,798
            
            
            39,772
            
            
            12,243
            
            
            107
            
            
            12,350Production
            
            
            (1,297
            )
            
            -
            
            
            (1,297
            )
            
            (78,737
            )
            
            -
            
            
            (78,737
            )
            
            (22,406
            )
            
            -
            
            
            (22,406
            )**December 31,
                2005**
            
            
            **9,107**
            
            
            **2,470**
            
            
            **11,577**
            
            
            **766,200**
            
            
            **252,478**
            
            
            **1,018,678**
            
            
            **241,957**
            
            
            **106,798**
            
            
            **348,755**





**UNITED
                STATES**
            
            **Light
                and Medium Crude Oil**
            
            **Heavy
                Oil**
            
            **Bitumen****Factors**
            
            **Proved**
            
            **Probable**
            
            **Proved**
              **Plus**
              **Probable**
            
            **Proved**
            
            **Probable**
            
            **Proved**
              **Plus**
              **Probable**
            
            **Proved**
            
            **Probable**
            
            **Proved**
              **Plus**
              **Probable**(Mbbls)
            
            (Mbbls)
            
            (Mbbls)
            
            (Mbbls)
            
            (Mbbls)
            
            (Mbbls)
            
            (Mbbls)
            
            (Mbbls)
            
            (Mbbls)**December 31,
                2004**
            
            
            -
            
            
            -
            
            
            -
            
            
            -
            
            
            -
            
            
            -
            
            
            -
            
            
            -
            
            
            -Acquisitions
            
            
            20,076
            
            
            4,235
            
            
            24,311
            
            
            -
            
            
            -
            
            
            -
            
            
            -
            
            
            -
            
            
            -Divestments
            
            
            -
            
            
            -
            
            
            -
            
            
            -
            
            
            -
            
            
            -
            
            
            -
            
            
            -
            
            
            -Discoveries
            
            
            -
            
            
            -
            
            
            -
            
            
            -
            
            
            -
            
            
            -
            
            
            -
            
            
            -
            
            
            -Extensions
            
            
            -
            
            
            -
            
            
            -
            
            
            -
            
            
            -
            
            
            -
            
            
            -
            
            
            -
            
            
            -Technical
                Revisions
            
            
            624
            
            
            438
            
            
            1,062
            
            
            -
            
            
            -
            
            
            -
            
            
            -
            
            
            -
            
            
            -Economic
                Factors
            
            
            -
            
            
            -
            
            
            -
            
            
            -
            
            
            -
            
            
            -
            
            
            -
            
            
            -
            
            
            -Improved
                Recovery
            
            
            -
            
            
            -
            
            
            -
            
            
            -
            
            
            -
            
            
            -
            
            
            -
            
            
            -
            
            
            -Production
            
            
            (885
            )
            
            -
            
            
            (885
            )
            
            -
            
            
            -
            
            
            -
            
            
            -
            
            
            -
            
            
            -**December 31,
                2005**
            
            
            **19,815**
            
            
            **4,673**
            
            
            **24,488**
            
            
            **-**
            
            
            **-**
            
            
            **-**
            
            
            **-**
            
            
            **-**
            
            
            **-**





*(continues
      on next page)*





23








**UNITED
                STATES (continued)**
            
            **Natural
                Gas Liquids**
            
            **Associated
                and Non-Associated**
              **Gas
                (Natural Gas)**
            
            **Total****Factors**
            
            **Proved**
            
            **Probable**
            
            **Proved**
              **Plus**
              **Probable**
            
            **Proved**
            
            **Probable**
            
            **Proved**
              **Plus**
              **Probable**
            
            **Proved**
            
            **Probable**
            
            **Proved**
              **Plus**
              **Probable**(Mbbls)
            
            (Mbbls)
            
            (Mbbls)
            
            (MMcf)
            
            (MMcf)
            
            (MMcf)
            
            (MBOE)
            
            (MBOE)
            
            (MBOE)**December 31,
                2004**
            
            
            -
            
            
            -
            
            
            -
            
            
            -
            
            
            -
            
            
            -
            
            
            -
            
            
            -
            
            
            -Acquisitions
            
            
            -
            
            
            -
            
            
            -
            
            
            10,738
            
            
            27,535
            
            
            38,273
            
            
            21,866
            
            
            8,824
            
            
            30,690Divestments
            
            
            -
            
            
            -
            
            
            -
            
            
            -
            
            
            -
            
            
            -
            
            
            -
            
            
            -
            
            
            -Discoveries
            
            
            -
            
            
            -
            
            
            -
            
            
            -
            
            
            -
            
            
            -
            
            
            -
            
            
            -
            
            
            -Extension
            
            
            -
            
            
            -
            
            
            -
            
            
            -
            
            
            -
            
            
            -
            
            
            -
            
            
            -
            
            
            -Technical
                Revisions
            
            
            -
            
            
            -
            
            
            -
            
            
            792
            
            
            120
            
            
            912
            
            
            756
            
            
            458
            
            
            1,214Economic
                Factors
            
            
            -
            
            
            -
            
            
            -
            
            
            -
            
            
            -
            
            
            -
            
            
            -
            
            
            -
            
            
            -Improved
                Recovery
            
            
            -
            
            
            -
            
            
            -
            
            
            -
            
            
            -
            
            
            -
            
            
            -
            
            
            -
            
            
            -Production
            
            
            -
            
            
            -
            
            
            -
            
            
            (486
            )
            
            -
            
            
            (486
            )
            
            (966
            )
            
            -
            
            
            (966
            )**December 31,
                2005**
            
            
            **-**
            
            
            **-**
            
            
            **-**
            
            
            **11,044**
            
            
            **27,655**
            
            
            **38,699**
            
            
            **21,656**
            
            
            **9,282**
            
            
            **30,938**





**TOTAL
                ENERPLUS**
            
            **Light
                and Medium Crude Oil**
            
            **Heavy
                Oil**
            
            **Bitumen****Factors**
            
            **Proved**
            
            **Probable**
            
            **Proved**
              **Plus**
              **Probable**
            
            **Proved**
            
            **Probable**
            
            **Proved**
              **Plus**
              **Probable**
            
            **Proved**
            
            **Probable**
            
            **Proved**
              **Plus**
              **Probable**(Mbbls)
            
            (Mbbls)
            
            (Mbbls)
            
            (Mbbls)
            
            (Mbbls)
            
            (Mbbls)
            
            (Mbbls)
            
            (Mbbls)
            
            (Mbbls)**December 31,
                2004**
            
            
            66,272
            
            
            14,892
            
            
            81,164
            
            
            26,971
            
            
            8,264
            
            
            35,235
            
            
            -
            
            
            43,640
            
            
            43,640Acquisitions
            
            
            21,425
            
            
            5,132
            
            
            26,557
            
            
            -
            
            
            -
            
            
            -
            
            
            -
            
            
            -
            
            
            -Divestments
            
            
            (1,099
            )
            
            (778
            )
            
            (1,877
            )
            
            (1,205
            )
            
            (702
            )
            
            (1,907
            )
            
            -
            
            
            -
            
            
            -Discoveries
            
            
            84
            
            
            27
            
            
            111
            
            
            -
            
            
            -
            
            
            -
            
            
            -
            
            
            -
            
            
            -Extensions
            
            
            202
            
            
            (21
            )
            
            181
            
            
            33
            
            
            20
            
            
            53
            
            
            -
            
            
            -
            
            
            -Technical
                Revisions
            
            
            (1,165
            )
            
            (1,118
            )
            
            (2,283
            )
            
            1,136
            
            
            (441
            )
            
            695
            
            
            9,358
            
            
            (2,490
            )
            
            6,868Economic
                Factors
            
            
            3,814
            
            
            1,190
            
            
            5,004
            
            
            1,312
            
            
            349
            
            
            1,661
            
            
            -
            
            
            -
            
            
            -Improved
                Recovery
            
            
            2,939
            
            
            316
            
            
            3,255
            
            
            3,759
            
            
            (1,359
            )
            
            2,400
            
            
            -
            
            
            -
            
            
            -Production
            
            
            (6,230
            )
            
            -
            
            
            (6,230
            )
            
            (2,641
            )
            
            -
            
            
            (2,641
            )
            
            -
            
            
            -
            
            
            -**December 31,
                2005**
            
            
            **86,242**
            
            
            **19,640**
            
            
            **105,882**
            
            
            **29,365**
            
            
            **6,131**
            
            
            **35,496**
            
            
            **9,358**
            
            
            **41,150**
            
            
            **50,508**


**TOTAL
                ENERPLUS (continued)**
            
            **Natural
                Gas Liquids**
            
            **Associated
                and Non-Associated**
              **Gas
                (Natural Gas)**
            
            **Total****Factors**
            
            **Proved**
            
            **Probable**
            
            **Proved**
              **Plus**
              **Probable**
            
            **Proved**
            
            **Probable**
            
            **Proved**
              **Plus**
              **Probable**
            
            **Proved**
            
            **Probable**
            
            **Proved**
              **Plus**
              **Probable**(Mbbls)
            
            (Mbbls)
            
            (Mbbls)
            
            (MMcf)
            
            (MMcf)
            
            (MMcf)
            
            (MBOE)
            
            (MBOE)
            
            (MBOE)**December 31,
                2004**
            
            
            8,942
            
            
            2,318
            
            
            11,260
            
            
            778,610
            
            
            243,208
            
            
            1,021,818
            
            
            231,953
            
            
            109,649
            
            
            341,602Acquisitions
            
            
            31
            
            
            10
            
            
            41
            
            
            20,469
            
            
            32,028
            
            
            52,497
            
            
            24,868
            
            
            10,480
            
            
            35,348Divestments
            
            
            (49
            )
            
            (29
            )
            
            (78
            )
            
            (10,546
            )
            
            (5,603
            )
            
            (16,149
            )
            
            (4,111
            )
            
            (2,443
            )
            
            (6,554
            )Discoveries
            
            
            3
            
            
            1
            
            
            4
            
            
            2,291
            
            
            450
            
            
            2,741
            
            
            469
            
            
            103
            
            
            572Extensions
            
            
            512
            
            
            100
            
            
            612
            
            
            30,032
            
            
            11,976
            
            
            42,008
            
            
            5,752
            
            
            2,095
            
            
            7,847Technical
                Revisions
            
            
            700
            
            
            (53
            )
            
            647
            
            
            (14,768
            )
            
            (15,773
            )
            
            (30,541
            )
            
            7,568
            
            
            (6,731
            )
            
            837Economic
                Factors
            
            
            216
            
            
            106
            
            
            322
            
            
            17,405
            
            
            7,049
            
            
            24,454
            
            
            8,243
            
            
            2,820
            
            
            11,063Improved
                Recovery
            
            
            49
            
            
            17
            
            
            66
            
            
            32,974
            
            
            6,798
            
            
            39,772
            
            
            12,243
            
            
            107
            
            
            12,350Production
            
            
            (1,297
            )
            
            -
            
            
            (1,297
            )
            
            (79,223
            )
            
            -
            
            
            (79,223
            )
            
            (23,372
            )
            
            -
            
            
            (23,372
            )**December 31,
                2005**
            
            
            **9,107**
            
            
            **2,470**
            
            
            **11,577**
            
            
            **777,244**
            
            
            **280,133**
            
            
            **1,057,377**
            
            
            **263,613**
            
            
            **116,080**
            
            
            **379,693**








24





**Reconciliation
      of Changes in Net Present Value of Future Net Revenue**




The
      following table sets forth a reconciliation of changes in the net present value
      of future net revenues associated with Enerplus' net Proved Reserves, by country
      and in total, from December 31, 2004 to December 31, 2005 using
      constant prices and costs and discounted at 10% per year.




*Canada*





(in $ millions)**Period
                and Factor**Estimated
                Future Net Revenue at December 31, 2004
            
            
            2,933.8Sales
                and Transfers of Oil, Natural Gas and NGLs Produced, Net of Production
                Costs and Royalties
            
            
            (950.0
            )Net
                Change in Prices, Production Costs and Royalties Related to Future
                Production
            
            
            2,169.8Changes
                in Previously Estimated Development Costs Incurred During the
                Period
            
            
            113.3Changes
                in Estimated Future Development Costs
            
            
            (229.0
            )Net
                Change Resulting from Extensions and Improved Recovery
            
            
            412.7Net
                Change Resulting from Discoveries
            
            
            10.7Changes
                from Acquisitions of Reserves
            
            
            39.8Changes
                from Dispositions of Reserves
            
            
            (29.5
            )Net
                Change Resulting from Revisions in Quantity Estimates
            
            
            126.1Accretion
                of
                Discount
            
            
            229.5Net
                Change in Income Taxes
            
            
            0.0Estimated
                Future Net Revenue at December 31, 2005
            
            
            4,827.2




*United
      States*





(in $ millions)**Period
                and Factor**Estimated
                Future Net Revenue at December 31, 2004
            
            
            0.0Sales
                and Transfers of Oil, Natural Gas and NGLs Produced, Net of Production
                Costs and Royalties
            
            
            (59.1
            )Net
                Change in Prices, Production Costs and Royalties Related to Future
                Production
            
            
            0.0Changes
                in Previously Estimated Development Costs Incurred During the
                Period
            
            
            0.0Changes
                in Estimated Future Development Costs
            
            
            (78.8
            )Net
                Change Resulting from Extensions and Improved Recovery
            
            
            0.0Net
                Change Resulting from Discoveries
            
            
            0.0Changes
                from Acquisitions of Reserves
            
            
            912.2Changes
                from Dispositions of Reserves
            
            
            0.0Net
                Change Resulting from Revisions in Quantity Estimates
            
            
            0.0Accretion
                of
                Discount
            
            
            0.0Net
                Change in Income Taxes
            
            
            (195.7
            )Estimated
                Future Net Revenue at December 31, 2005
            
            
            578.6





*(continues
      on next page)*





25





*Total
      Enerplus*





(in $ millions)**Period
                and Factor**Estimated
                Future Net Revenue at December 31, 2004
            
            
            2,933.8Sales
                and Transfers of Oil, Natural Gas and NGLs Produced, Net of Production
                Costs and Royalties
            
            
            (1,009.1
            )Net
                Change in Prices, Production Costs and Royalties Related to Future
                Production
            
            
            2,169.8Changes
                in Previously Estimated Development Costs Incurred During the
                Period
            
            
            113.3Changes
                in Estimated Future Development Costs
            
            
            (307.8
            )Net
                Change Resulting from Extensions and Improved Recovery
            
            
            412.7Net
                Change Resulting from Discoveries
            
            
            10.7Changes
                from Acquisitions of Reserves
            
            
            952.0Changes
                from Dispositions of Reserves
            
            
            (29.5
            )Net
                Change Resulting from Revisions in Quantity Estimates
            
            
            126.1Accretion
                of
                Discount
            
            
            229.5Net
                Change in Income Taxes
            
            
            (195.7
            )Estimated
                Future Net Revenue at December 31, 2005
            
            
            5,405.8




**Undeveloped
      Reserves**




The
      following table discloses the volumes of Undeveloped Reserves of Enerplus that
      were first attributed in the years indicated.




*Proved
      Undeveloped Reserves*





**Crude
                Oil****Year**
            
            **Heavy**
            
            **Light and
                Medium**
            
            **Bitumen**
            
            **NGLs**
            
            **Natural**
              **Gas**
            
            **Total**(Mbbls)
            
            (Mbbls)
            
            (Mbbls)
            
            (Mbbls)
            
            (Bcf)
            
            (MBOE)2003
            
            
            950
            
            
            320
            
            
            -
            
            
            35
            
            
            27.5
            
            
            5,8882004
            
            
            189
            
            
            1,182
            
            
            -
            
            
            55
            
            
            63.0
            
            
            11,9202005
            
            
            768
            
            
            2,524
            
            
            -
            
            
            414
            
            
            55.0
            
            
            12,873





*Probable
      Undeveloped Reserves*




**Crude
                Oil****Year**
            
            **Heavy**
            
            **Light and
                Medium**
            
            **Bitumen**
            
            **NGLs**
            
            **Natural**
              **Gas**
            
            **Total**(Mbbls)
            
            (Mbbls)
            
            (Mbbls)
            
            (Mbbls)
            
            (Bcf)
            
            (MBOE)2003
            
            
            74
            
            
            263
            
            
            -
            
            
            80
            
            
            33.9
            
            
            6,0672004
            
            
            950
            
            
            1,808
            
            
            47,747
            
            
            40
            
            
            25.0
            
            
            54,7112005
            
            
            126
            
            
            902
            
            
            -
            
            
            104
            
            
            22.0
            
            
            4,799





Enerplus
      attributes Proved and Probable Undeveloped Reserves based on accepted
      engineering and geological practices as defined under NI 51-101. These
      practices include the determination of reserves based on the presence of
      commercial test rates from either production tests or drill stem tests,
      extensions of known accumulations based upon either geological or geophysical
      information and the optimization of existing fields. Enerplus has been very
      active for the last several years in drilling and developing these Undeveloped
      Reserves volumes, and based on the estimates of future capital expenditures,
      Enerplus expects this to continue.





26




**Proved
      and Probable Reserves Not on Production**




Enerplus
      has approximately 5,912.8 MBOE of Proved plus Probable Reserves which are
      capable of production but which, as of December 31, 2005, were not on
      production. These reserves do not include the Probable Reserves attributable
      to
      Enerplus' interest in the SAGD-recoverable bitumen reserves in the Joslyn
      Project. These reserves have generally been non-producing for periods ranging
      from a few months to more than five years. In general, these reserves are
      related to commercially producible volumes that are not producing due to
      production requirements of other reserve formations or zones in the same well
      bore, or are related to reserves volumes which require the completion of
      infrastructure before production can begin.




**OPERATIONAL
      INFORMATION**




**Overview**




Enerplus'
      operational strategies and activities are directed towards maximizing value
      and
      distributable income over the long-term. Enerplus utilizes its technical and
      operating experience  to increase value through acquisitions and through
      development and optimization activities on new and existing oil and natural
      gas
      properties. Enerplus achieves this value creation through a focused and
      disciplined acquisition strategy, an active capital development program directed
      towards lower risk development and  optimization of its existing
      assets.




Enerplus'
      acquisition strategy is generally directed towards longer-life assets with
      lower
      risk development potential which fit within core strategic areas and complement
      the existing asset base. Enerplus typically funds its acquisitions by drawing
      from its existing credit facility, the issuance of Trust Units or a combination
      of both.




Enerplus
      develops its properties through lower risk development projects which include
      infill drilling, step-out drilling, joint venture arrangements, farmouts,
      waterflood implementation and other activities. Enerplus' development
      investments currently focus on waterfloods, shallow natural gas, coalbed methane
      and bitumen in Western Canada and Bakken oil development in Montana and North
      Dakota. Enerplus also invests in development of other conventional oil and
      gas
      properties in Canada. On higher risk opportunities, Enerplus generally enters
      into farmout arrangements under which an exploration-oriented company would
      pursue the opportunities on Enerplus' behalf, generally at no cost to Enerplus,
      in exchange for a portion of Enerplus' interests. Enerplus may pursue some
      higher risk opportunities on its own if the risk/return ratio justifies the
      risk. Enerplus typically looks for projects of sufficient size which, if proven,
      could materially add to the value of the Fund going forward.




Optimization
      of Enerplus' existing assets takes the form of downhole recompletions and
      stimulations, enhancement of artificial lift, water injection and facility
      optimization and other activities. These activities are typically smaller
      projects with attractive rates of return given the limited capital investment
      required and rapid payback.




Risk
      management is a key strategy for Enerplus. This is achieved through an
      acquisition focus which is generally concentrated on longer-life properties
      which typically have more predictable production and reserves, lower risk
      development activities and partnering on higher risk activities through joint
      venture or farmout arrangements, and other risk mitigation actions.
      Enerplus has historically experienced an approximate 99% drilling
      success rate by avoiding a large component of exploration type drilling which
      is
      typically higher risk.




**Description
      of Principal Properties and Operations**




Outlined
      below is a description of Enerplus' oil and natural gas operations and each
      of
      Enerplus' main types of operational activities, or "play types". All production
      information represents Enerplus' "company interest" in production from these
      properties, which includes overriding royalty interests of Enerplus but is
      calculated before deduction of royalty interests owned by others. All references
      to reserve volumes represent Enerplus' estimated "company interest" reserves
      (before deduction of royalties) contained in the Sproule Report, GLJ Report
      or
      D&M Report, as applicable, using forecast prices and costs. See
      "Presentation of Enerplus' Oil and Gas Reserves and Production
      Information".





27







Enerplus'
      oil and natural gas property interests are located in western Canada in the
      provinces of British Columbia, Alberta, Saskatchewan and Manitoba and in
      the United States in the states of Montana and North Dakota. All of
      Enerplus' major properties have related field production facilities and
      infrastructure to accommodate Enerplus' production. Production volumes for
      the
      year ended December 31, 2005 from Enerplus' properties consisted of
      approximately 43% crude oil and NGLs and 57% natural gas on a BOE basis.
      Enerplus' 2005 production was comprised of average daily production of
      29,315 bbls/d of crude oil, 4,689 bbls/d of NGLs and 274.3 MMcf/d
      of natural gas for a total of 79,727 BOE/d, an increase of 6% when compared
      to the previous year. As of the date of this Annual Information Form,
      approximately 65% of this production is operated by Enerplus and the remaining
      35% is operated by industry partners. As at December 31, 2005, the oil and
      natural gas property interests held by Enerplus were estimated to contain Proved
      plus Probable Reserves of 177.9 MMbbls of crude oil and NGLs,
      53.2 MMbbls of Bitumen and 1,308.3 Bcf of natural gas for a total of
      449.1 MMBOE. See "Oil and Natural Gas Reserves".




Enerplus'
      acquisition and development activities are focused on resource plays that are
      typically large and extensive accumulations of discovered oil and natural gas
      with limited geological risk. Resource plays typically cover large geographic
      areas and require many wells to develop the play over time. With a large number
      of wells generating a relatively predictable "average" or "type well", the
      timing, cost, production rates and reserve additions associated with the play
      can be more accurately predicted. Production from Enerplus' resource plays
      generally exhibit low declines over the long term, with long reserve life.
      Enerplus' resource plays include shallow natural gas in southeast Alberta and
      southwest Saskatchewan, coalbed methane in central Alberta, oil sands in
      northeast Alberta and Bakken oil in Montana. In addition, Enerplus owns
      interests in 12 major and 15 minor waterflood properties throughout
      western Canada. Waterfloods are similar to resource plays in that the oil in
      place is a relatively known quantity, production declines are relatively low
      and
      the goal is to maximize recovery of a known resource. Other conventional oil
      and
      gas properties make up the balance of the Enerplus portfolio. Outlined below
      is
      a more detailed description of each of Enerplus' play type.





28







*Shallow
      Natural Gas*









Shallow
      natural gas has been a core development area for Enerplus since the late 1990s.
      The shallow natural gas formations in southeast Alberta and southwest
      Saskatchewan cover an area of over 10,000 square kilometres. These zones
      are typically less than 800 metres in depth with most production coming
      from the Milk River, Medicine Hat, and Second White Specks producing zones.
      Shallow natural gas is Enerplus' second largest resource play by production
      as
      it represented approximately 17% of Enerplus' 2005 average daily production
      and
      approximately 20% of its Proved plus Probable reserves (representing
      approximately 90 MMBOE). Enerplus participated in drilling 336 gross
      (200.5 net) shallow natural gas wells in 2005. Total capital expenditures
      for shallow natural gas operations were $58.7 million in 2005.




Production
      from Enerplus' shallow natural gas operations for the year ended
      December 31, 2005 averaged approximately 82.6 MMcf/d of natural gas.
      The largest shallow natural gas producing properties are Bantry, Hanna Garden
      Plains, Verger, Countess, and Medicine Hat South in Alberta and Shackleton
      in
      Saskatchewan, all of which have associated pipeline infrastructure and
      compression facilities. Enerplus is the operator of most of the production
      from
      these areas, except for Shackleton which is operated by a third
      party.




Enerplus
      plans to invest approximately $74 million on shallow natural gas
      development in 2006, including drilling approximately 570 gross
      (300 net) wells, including 121 gross (108 net) high density wells
      within existing producing areas. The largest parts of the 2006 development
      program will be at Shackleton, Atlee Buffalo, Bantry, Medicine Hat North, Hanna
      Garden, and Verger.





29







*Waterfloods*









Waterflood
      development is Enerplus' largest play type. In a waterflood play, water is
      injected into the producing reserves formation to supplement the original
      reservoir pressure and provide a drive mechanism to move additional oil to
      the
      producing well. Pressure maintenance and the production of oil from water
      injection can result in a production profile with decreasing and stable declines
      and higher recovery of reserves. Infill drilling and well/injector optimization
      are effective methods of enhancing reserve recovery even further. Enerplus'
      waterflood plays produced approximately 18,100 BOE/d in 2005, or
      approximately 23% of Enerplus' production during the year. At year-end 2005,
      Enerplus had waterflood oil and natural gas reserves of approximately
      108 MMBOE, which represented approximately 24% of Enerplus' Proved plus
      Probable reserves. Enerplus invested approximately $62.2 million on
      waterflood development in 2005 including participation in drilling on
      52 gross (36.7 net) development wells.




Enerplus'
      waterflood assets are found in Alberta, Saskatchewan, and Manitoba, the largest
      of which are Pembina 5 Way, Giltedge, Joarcam, the Medicine Hat Glauconitic
      "C" Unit, the Mitsue Unit, Virden, Silver Heights and Gleneath. Enerplus is
      the operator of these major areas, with the exception of Mitsue, which is
      non-operated. All of Enerplus' major waterflood areas have associated crude
      oil
      production installations for emulsion treating and injection or water disposal.
      In addition, Joarcam also has facilities for natural gas compression,
      dehydration and processing.




In
      2005, Enerplus drilled 18 gross (17.5 net) Viking oil wells at the
      Joarcam property and completed construction of a crude oil battery to handle
      additional production. At Pembina 5 Way, Enerplus drilled 10 gross
      (10 net) Cardium oil wells and upgraded its battery and water injection
      capabilities. Development at the Medicine Hat Glauconitic "C" Unit included
      the
      drilling of 2 gross (1.6 net) horizontal infill oil wells along with
      facility and pump upgrades.




Enerplus
      plans to invest approximately $78 million on waterflood development
      activities in 2006, including participation in the drilling of approximately
      80 gross (60 net) wells. Most of this drilling will occur at the
      Joarcam and Pembina areas.





30







*Bakken
      Oil*









Enerplus
      owns an approximate 70% average working interest in certain producing
      wells in the Sleeping Giant Bakken oil field in Richland County,
      Montana, which was acquired through the acquisitions of Lyco and
      Sleeping Giant LLC in 2005. Production from this area is from the
      Middle Bakken dolomite formation at a depth of approximately 10,000 feet
      and consists of sweet light oil and some natural gas. Since early 2000, the
      pool
      has been exploited with the drilling of horizontal wells coupled with hydraulic
      fracturing. Initial peak monthly average oil production rates on wells with
      4,000 to 9,000 foot horizontal lateral wells has ranged between
      300 and 400 bbls/d of crude oil and Enerplus expects to recover
      between 400 and 750 MBOE of oil and natural gas reserves over the life
      of each well. These wells cost approximately $3 million to $4 million
      each to drill, complete and tie-in. With a 2005 exit production rate of
      approximately 10,000 BOE/day, the Bakken play area accounted for
      approximately 12% of Enerplus' production at year-end of 2005. As of
      December 31, 2005, Enerplus had estimated Proved and Probable reserves of
      approximately 37 MMBOE in this play area.




Since
      the acquisitions of its property interests in 2005, Enerplus invested
      $29.1 million dollars in the Bakken play to drill 15 gross
      (9.4 net) wells. In 2006, Enerplus plans to further develop Sleeping Giant
      and expand the play on 120,000 net acres of undeveloped land in Montana and
      North Dakota. Enerplus plans to drill 43 gross (27 net) oil wells with
      the Bakken formation as the main target.





31







*Oil
      Sands*









The
      Joslyn Lease is located approximately 60 kilometres north of Fort McMurray
      in northern Alberta and contains oil sands rights in the McMurray formation.
      Enerplus became involved in the oil sands in 2002 through acquisition of a
      16%
      working interest in the Joslyn Lease from Deer Creek Energy Ltd. Deer Creek
      is the operator of the Joslyn Project and intends to recover the bitumen located
      on the Joslyn Lease through a combination of multi-phased SAGD and mining
      development. In 2005, Deer Creek was acquired by Total S.A., a major
      international oil and gas company with experience in the extraction and refining
      of heavy oil.




In
      2005, Enerplus invested approximately $33.2 million in the Joslyn Project,
      with $30.6 million directed to SAGD and $2.6 million directed to
      advancing the mine development. This capital was spent on, among other things,
      drilling 271 gross delineation wells, beginning construction of a
      62 kilometre, 40,000 bbls/d sales pipeline, and the purchase of
      4.5 gross sections of land adjacent to the existing Joslyn Lease acreage.
      Enerplus and Deer Creek, in cooperation with industry participants, also
      initiated a pilot project to explore the potential of burning emulsified bitumen
      as an alternative fuel to natural gas, and continued to develop the
      10,000 bbls/d SAGD Phase II project on schedule. The SAGD Phase I
      facility and well pair are currently producing 200 bbls/d, and are
      providing useful information for the operation of SAGD
      Phase II.




In
      a transaction subsequent to the year end, Enerplus sold a 1% working interest
      in
      the Joslyn Project in exchange for equity in Laricina Energy Ltd.
      (" **Laricina** "),
      a new private oil sands focused company led by the former Chief Executive
      Officer of Deer Creek. Included in the sale is an area of mutual interest
      agreement which has been designed to jointly pursue additional in-situ oil
      sand
      ventures. Following the sale to Laricina, Enerplus now has a 15% working
      interest in the Joslyn Project.





32







Enerplus
      will continue to develop the Joslyn Project with Deer Creek in 2006 and expects
      to invest $31 million in the Joslyn Project in 2006, including
      $6 million to further pursue the mine development by drilling
      additional core holes, receiving regulatory approvals, and engineering and
      design work. SAGD Phase II drilling and the construction of the water
      treatment and central facilities is also anticipated to be completed in 2006.
      Enerplus also expects that the 2006 investment will lead to receiving regulatory
      approval for both the 15,000 bbls/d SAGD Phase III A and the first
      stage of the mine. The reserves attributed to Enerplus' interest in the
      Joslyn Project as described under "Oil and Natural Gas Reserves -- Summary
      of Joslyn Project Bitumen Reserves" only include reserves attributable to SAGD
      Phases I, II, and III A of the Joslyn Project and do not include any reserves
      attributable to SAGD Phase III B or the mine portion of the Joslyn Project.




The
      current plans of Deer Creek, as provided to Enerplus, for the Joslyn Project
      are
      as follows:





**Sanctioned
                Projects**
            
            **Joslyn**
              **Project**
              **Production/**
              **Throughput**
            
            **Net**
              **Production/**
              **Throughput****(1)**
            
            **Net
                Future Development**
              **Capital****(1)**
            
            **Start
                Up****(2)**
            
            **Full**
              **Production/**
              **Throughput**(bbls/d)
            
            (bbls/d)
            
            ($millions)SAGD
                Phase I (Pilot)
            
            
            200
            
            
            30
            
            
            
            
            
            Q2
                2004
            
            
            2005SAGD
                Phase II
            
            
            10,000
            
            
            1,500
            
            
            34
            
            
            Q1
                2006
            
            
            2009**Future
                Development Projects**SAGD
                Phase IIIA and Phase IIIB
            
            
            30,000
            
            
            4,500
            
            
            167
            
            
            2008
            
            
            2011Mine
                Phase I
            
            
            100,000
            
            
            15,000
            
            
            466
            
            
            2010
            
            
            2014Mine
                Phase II
            
            
            100,000
            
            
            15,000
            
            
            466
            
            
            2016
            
            
            2020Upgrader
            
            
            n/a
            
            
            n/a
            
            
            n/a
            
            
            2013
            
            
            2014


___________


Notes:


(1)
            The
                net information presented in this table reflects Enerplus' 15% working
                interest after the sale of a 1% interest to Laricina in early 2006.
                GLJ's
                estimates of SAGD production may vary from Deer Creek's estimates
                of
                production described above.




(2)
            Start-up
                for SAGD refers to initial steaming. Start up for mining refers to
                initial
                extraction.




Additionally,
      Enerplus has commissioned an interim engineering report by GLJ (the "**GLJ
      Mine Report**") to evaluate the reserves located in the northern portion
      of  the Joslyn Lease (the "**North Mine Project**"). Enerplus
      anticipates the GLJ Mine Report will be completed in April 2006. Based
      on an application filed by Deer Creek with the Alberta Energy and Utilities
      Board and Alberta Environment in February 2006, Enerplus expects that the
      reserves associated with the North Mine Project may be reclassified from a
      resource to a probable reserve category, which would result in Enerplus
      including additional probable reserves (and the corresponding future
      development capital) associated with the Joslyn Project in its reserves
      reporting. The application filed by Deer Creek estimates 890  MMBOE of
      recoverable bitumen (133.5 MMBOE net to Enerplus) are contained in the
      proposed North Mine Project, and provides for two 50,000 BOE/d producing
      mine phases and approximately $2 billion of initial capital, plus
      additional future maintenance capital requirements. A determination of reserves
      and the value associated with those reserves, as determined in the GLJ Mine
      Report, cannot be made at this time.  Deer Creek has also identified
      potential future mining bitumen resources associated with a southern mine which
      are not reflected in Enerplus' existing reserves and are not dealt with in
      the GLJ Mine Report or in Deer Creek's regulatory application. No
      assurance can be made as to the ultimate outcome of the Deer Creek application,
      the GLJ Mine Report or the future development of the North Mine
      Project or the southern mine.





33




*Coal
      Bed Methane*









Enerplus'
      coal bed methane (" **CBM** ")
      commercial development has been focused on the Horseshoe Canyon formation in
      three areas in the central Alberta fairway. Horseshoe Canyon coals are typically
      dry and do not have the water handling issues often associated with CBM
      production. Production from CBM for the year ended December 31, 2005
      averaged approximately 4.7 MMcf/d of natural gas. Enerplus' major CBM
      producing properties are Trochu, Bashaw, and Joffre, each of which is in central
      Alberta. All of Enerplus' major CBM producing areas have associated pipeline
      infrastructure and gas compression facilities. At December 31, 2005,
      Enerplus had estimated Proved plus Probable CBM reserves of approximately
      32 Bcf (5.3 MMBOE).




Enerplus
      invested approximately $42 million on CBM development in 2005, including
      participation in the drilling of 130 gross (83.2 net) wells and
      associated pipeline infrastructure and natural gas compression facilities at
      Bashaw.




In
      2006, Enerplus plans to invest approximately $49 million on CBM
      development, including participation in drilling of 150 gross (87 net)
      wells. The majority of this development will take place in the Horseshoe Canyon
      formation coals of Bashaw, Joffre, Trochu, and Gadsby. Enerplus also plans
      to
      invest in pilot projects for Mannville and other formation coals in
      2006.





34





*Other
      Conventional*









In
      addition to the play types outlined above, Enerplus also owns other conventional
      oil and natural gas assets across western Canada. These assets include operated
      and non-operated properties and various reservoir and commodity types. Major
      conventional assets include the Deep Basin/Foothills natural gas properties
      in
      western Alberta and northeast British Columbia, the Bantry North oil property
      in
      southern Alberta and the oil properties located in southeast Saskatchewan.
      Average 2005 daily production from these other conventional properties was
      approximately 43,900 BOE/d or approximately 55% of Enerplus' production.
      These other conventional reserves accounted for approximately 34% of Enerplus'
      estimated total Proved plus Probable reserves as of December 31, 2005.
      Enerplus invested approximately $143.4 million on development activities in
      other conventional properties in 2005.




Major
      producing properties in the Deep Basin/Foothills category include (i) the
      sweet, liquids-rich natural gas plays in the Deep Basin region which encompasses
      the Elmworth, Karr, Wapiti, and South Wapiti producing fields, primarily
      operated by Burlington Resources Canada Ltd., Devon Canada Corporation and
      BP Canada Energy Company, (ii) interests in the deep sour natural
      gas play in the Hanlan, Alberta region operated by Petro-Canada, and
      (iii) interests in the Mount Benjamin natural gas property also operated by
      Petro-Canada. Major production facilities within this area include (i) a 3%
      interest in the Wapiti gas plant, (ii) an 8.5% interest in the Hanlan-Robb
      sour gas plant, (iii) a 2% interest in the Ram River sour gas plant,
      (iv) a 3% interest in the Burnt Timber sour gas plant, and (v) a 6%
      interest in the Elmworth gas plant. Enerplus invested approximately
      $28 million in Deep Basin/Foothills development in 2005 including
      participation in the drilling of 87 gross (6.2 net) wells. In
      December 2005, Enerplus' production from the Deep Basin/Foothills region
      was approximately 8,500 BOE/day.





35







Enerplus
      acquired a 100% working interest in the Bantry North oil property as part of
      the
      ChevronTexaco acquisition in mid-2004. Oil and natural gas production from
      this
      field is from the Sunburst formation and the reservoir is supported by natural
      water drive. In 2005, Enerplus invested approximately $25 million to drill
      8 wells and installed facilities to handle existing and future incremental
      production. At the end of 2005, production was approximately 1,250 BOE/day.
      Enerplus expects additional production of approximately 1,400 BOE/day to
      come on stream during the first quarter of 2006 following the completion and
      start-up of a non-operated sour gas facility and meter station.




Operated
      conventional properties in southeast Saskatchewan include Tatagwa, Colgate,
      Heward and Neptune, as well as Routledge, Manitoba. Medium density oil
      production is generally pressure supported by natural water drive. In 2005,
      Enerplus invested $9.6 million to drill 8 gross (6.5 net)
      wells.




Other
      major facilities included in Enerplus' conventional oil and natural gas
      properties include (i) a 22% interest in the oil emulsion treating and
      water disposal facility at Hayter, Alberta; (ii) a 100% interest in the
      Pine Creek gas compression facility, (iii) an 11% interest in the Progress
      sour gas plant, (iv) a 14.7% interest in the Sylvan Lake gas plant, and
      (v) an 8% interest in the Minnehik Buck Lake sour
      gas plant.




Enerplus
      plans to invest approximately $164 million on development activities at
      other conventional properties in 2006. Major activities include drilling
      80 gross (10 net) natural gas wells in the Deep Basin/Foothills areas
      at a cost of approximately $38 million, drilling 19 gross
      (13 net) oil wells in southeast Saskatchewan at a cost of approximately
      $22 million, and drilling 6 horizontal wells and upgrading existing
      pumps at Bantry North at a cost of approximately $10 million. Enerplus also
      plans to invest approximately $5 million to tie-in 2 gross
      (1 net) natural gas wells in the Shekelie area along with a
      3-D seismic program to be conducted on Enerplus' lands.





36


**Summary
      of Principal Production Locations**




During
      the year ended December 31, 2005, on a BOE basis, 83% of Enerplus'
      production was derived from Alberta, 8% from Saskatchewan, 4% from Montana,
      3%
      from British Columbia and 2% from Manitoba. The following table describes
      Enerplus' principal producing properties and the average daily production from
      those properties during the year ended December 31, 2005. All properties
      listed in the table (other than "Other") are located in Alberta unless otherwise
      noted.




**2005
      Average Daily Production**





**Product****Crude
                Oil****Property**
            
            **Heavy**
              **(bbls/d)**
            
            **Light**
              **and
                Medium**
              **(bbls/d)**
            
            **NGLs**
              **(bbls/d)**
            
            **Natural Gas**
              **(Mcf/d)**
            
            **Total**
              **(BOE/d)**Sleeping
                Giant, Montana, U.S.A.(1)
            
            
            -
            
            
            2,883
            
            
            -
            
            
            1,582
            
            
            3,147Bantry
            
            
            2,556
            
            
            -
            
            
            52
            
            
            26,500
            
            
            7,025Joarcam
            
            
            -
            
            
            2,073
            
            
            109
            
            
            6,108
            
            
            3,200Pembina
                5 Way
            
            
            -
            
            
            2,251
            
            
            145
            
            
            2,119
            
            
            2,749Chinchaga
            
            
            -
            
            
            -
            
            
            -
            
            
            15,439
            
            
            2,573Hanna
                Garden
            
            
            -
            
            
            3
            
            
            6
            
            
            13,470
            
            
            2,254Pine
                Creek
            
            
            -
            
            
            7
            
            
            546
            
            
            10,034
            
            
            2,225Verger
            
            
            -
            
            
            2
            
            
            -
            
            
            13,038
            
            
            2,175Giltedge
            
            
            2,047
            
            
            -
            
            
            -
            
            
            148
            
            
            2,072Medicine
                Hat
            
            
            1,609
            
            
            -
            
            
            -
            
            
            950
            
            
            1,767Elmworth
            
            
            -
            
            
            -
            
            
            513
            
            
            7,370
            
            
            1,741Benjamin
            
            
            -
            
            
            -
            
            
            11
            
            
            9,657
            
            
            1,621Valhalla
            
            
            -
            
            
            342
            
            
            100
            
            
            6,729
            
            
            1,564Progress
            
            
            -
            
            
            575
            
            
            81
            
            
            5,039
            
            
            1,496Shackleton,
                Saskatchewan
            
            
            -
            
            
            -
            
            
            -
            
            
            8,809
            
            
            1,468Medicine
                Hat South
            
            
            -
            
            
            -
            
            
            -
            
            
            7,762
            
            
            1,294Mitsue
            
            
            -
            
            
            880
            
            
            130
            
            
            1,138
            
            
            1,200Shorncliff
            
            
            1,074
            
            
            -
            
            
            11
            
            
            284
            
            
            1,132Virden,
                Manitoba
            
            
            -
            
            
            1,129
            
            
            -
            
            
            -
            
            
            1,129Enchant(2)
            
            
            -
            
            
            317
            
            
            24
            
            
            2,360
            
            
            734Ferrier
            
            
            -
            
            
            54
            
            
            251
            
            
            4,747
            
            
            1,096Countess
            
            
            -
            
            
            -
            
            
            1
            
            
            6,412
            
            
            1,070Sylvan
                Lake
            
            
            -
            
            
            242
            
            
            182
            
            
            3,863
            
            
            1,068Hanlan
            
            
            -
            
            
            -
            
            
            5
            
            
            6,190
            
            
            1,037Hayter
            
            
            991
            
            
            -
            
            
            1
            
            
            54
            
            
            1,001Other
            
            
            581
            
            
            9,699
            
            
            2,521
            
            
            114,534
            
            
            31,889**TOTAL**
            
            
            **8,858**
            
            
            **20,457**
            
            
            **4,689**
            
            
            **274,336**
            
            
            **79,727**


___________


Notes:


(1)
            This
                property was acquired by Enerplus on August 30, 2005 and further
                interests were acquired on October 4, 2005. Production from this
                property is only included in Enerplus' operational results from such
                dates, and accordingly the annualized average daily production presented
                is not indicative of a full year of production results from this
                property.




(2)
            Additional
                interests in this area were acquired by Enerplus on July 1, 2005.
                Production from this property is only included in Enerplus' operational
                results from such date, and accordingly the annualized average daily
                production presented is not indicative of a full year of production
                results from this property.





37


**Oil
      and Natural Gas Wells and Unproved Properties**




The
      following table summarizes, as at December 31, 2005, Enerplus' interests in
      producing wells and in non-producing wells which were not producing but which
      may be capable of production, along with Enerplus' interests in Unproved
      properties. Although many wells produce both oil and natural gas, a well is
      categorized as an oil well or a natural gas well based upon the proportion
      of
      oil or natural gas production that constitutes the majority of production from
      that well.





**Producing
                Wells**
            
            **Non-Producing
                Wells**
            
            **Unproved
                Properties****Oil**
            
            **Natural
                Gas**
            
            **Oil**
            
            **Natural
                Gas**
            
            **(thousand
                of acres)****Gross**
            
            **Net**
            
            **Gross**
            
            **Net**
            
            **Gross**
            
            **Net**
            
            **Gross**
            
            **Net**
            
            **Gross**
            
            **Net**Alberta
            
            
            3,342
            
            
            1,281.8
            
            
            5,532
            
            
            2,819.0
            
            
            776
            
            
            301.0
            
            
            532
            
            
            219.1
            
            
            695.5
            
            
            300.9Saskatchewan
            
            
            1,596
            
            
            403.7
            
            
            685
            
            
            392.0
            
            
            173
            
            
            30.9
            
            
            30
            
            
            10.7
            
            
            154.2
            
            
            72.3British
                Columbia
            
            
            201
            
            
            23.4
            
            
            117
            
            
            24.1
            
            
            42
            
            
            5.0
            
            
            69
            
            
            17.2
            
            
            122.5
            
            
            54.5Manitoba
            
            
            557
            
            
            309.6
            
            
            -
            
            
            -
            
            
            16
            
            
            9.9
            
            
            -
            
            
            -
            
            
            13.8
            
            
            10.2Montana
            
            
            107
            
            
            64.4
            
            
            -
            
            
            -
            
            
            2
            
            
            1.0
            
            
            -
            
            
            -
            
            
            73.9
            
            
            47.5North
                Dakota
            
            
            1
            
            
            1.0
            
            
            -
            
            
            -
            
            
            -
            
            
            -
            
            
            -
            
            
            -
            
            
            118.1
            
            
            70.8Joslyn
                Project
            
            
            15
            
            
            2.4
            
            
            -
            
            
            -
            
            
            -
            
            
            -
            
            
            -
            
            
            -
            
            
            29.7
            
            
            4.8Total
            
            
            5,819
            
            
            2,086.3
            
            
            6,334
            
            
            3,235.1
            
            
            1,009
            
            
            347.8
            
            
            631
            
            
            247.0
            
            
            1,207.7
            
            
            561.0





Enerplus
      expects its rights to explore, develop and exploit on approximately
      112,000 net acres of Unproved Properties to ordinarily expire prior to
      December 31, 2006. Enerplus has no material work commitments on such
      properties and, where Enerplus determines appropriate, it can extend expiring
      leases by either making the necessary applications to extend or performing
      the
      necessary work.




**Exploration
      and Development Activities**




The
      primary operational focus of Enerplus is to pursue attractive risk/return growth
      opportunities through the development of existing properties and the acquisition
      of new properties. Enerplus will also continue its ongoing property
      rationalization program on a selective basis and any sale proceeds may be used
      to acquire interests in existing core areas or new properties with attractive
      exploitation opportunities.




During
      2005, Enerplus participated in the drilling of 859 gross wells
      (393.3 net wells) with virtually a 100% net well success rate. The majority
      of Enerplus' drilling activity was in the shallow natural gas areas around
      Hanna
      Garden, Medicine Hat, Verger, Countess and Bantry. The Fund also had active
      operated drilling and facility programs in oil dominated areas such as Pembina,
      Joarcam, Giltedge and Medicine Hat Glauconitic "C". The Shackleton and Hatton
      shallow natural gas areas in southwestern Saskatchewan, the Deep Basin area
      of
      northwestern Alberta and the Foothills region of western Alberta were the focus
      areas of non-operated drilling activity in 2005. The following table summarizes
      the number and type of wells that Enerplus drilled or participated in the
      drilling of for the year ended December 31, 2005, in each of Canada and the
      United States. Wells have been classified in accordance with the
      definitions of such terms in NI 51-101.





**Canada**
            
            **United States****Development**
              **Wells**
            
            **Exploratory**
              **Wells**
            
            **Development**
              **Wells**
            
            **Exploratory**
              **Wells****Category
                of Well**
            
            **Gross**
            
            **Net**
            
            **Gross**
            
            **Net**
            
            **Gross**
            
            **Net**
            
            **Gross**
            
            **Net**Crude
                oil wells
            
            
            140
            
            
            56.9
            
            
            4
            
            
            4.0
            
            
            14
            
            
            8.9
            
            
            1
            
            
            0.5Natural
                gas wells
            
            
            634
            
            
            308.8
            
            
            38
            
            
            8.6
            
            
            -
            
            
            -
            
            
            -
            
            
            -Bitumen
                recovery wells
            
            
            14
            
            
            2.2
            
            
            -
            
            
            -
            
            
            -
            
            
            -
            
            
            -
            
            
            -Service
                wells
            
            
            13
            
            
            3.4
            
            
            -
            
            
            -
            
            
            -
            
            
            -
            
            
            -
            
            
            -Dry
                and abandoned wells
            
            
            1
            
            
            0.0
            
            
            -
            
            
            -
            
            
            -
            
            
            -
            
            
            -
            
            
            -Total
            
            
            802
            
            
            371.3
            
            
            42
            
            
            12.6
            
            
            14
            
            
            8.9
            
            
            1
            
            
            0.5








38








Enerplus
      currently intends to focus its development activities in the Western Canadian
      Sedimentary Basin and on the Sleeping Giant property in Montana and North
      Dakota, although Enerplus also considers acquisitions outside of these areas.
      Enerplus' development activities are typically funded through debt which may
      be
      subsequently repaid through internally generated cash flow withheld by the
      Fund's Operating Subsidiaries, as well as through the issuance of Trust Units.
      Enerplus does not anticipate that the cost of funding these development
      activities will have a material effect on Enerplus' disclosed oil and gas
      reserves or future net revenue attributable to those reserves.




**Quarterly
      Production History**




The
      following table sets forth Enerplus' average daily production volumes, on a
      company interest basis, for each fiscal quarter in 2005 and for the entire
      year,
      separately for production in Canada and the United States and in total.
      Enerplus had no heavy crude oil or NGLs production in the United States in
      2005.





**Year
                Ended December 31, 2005****First**
              **Quarter**
            
            **Second**
              **Quarter**
            
            **Third**
              **Quarter**
            
            **Fourth**
              **Quarter**
            
            **Total for**
              **Year****Canada**Crude
                oilLight
                and medium oil (bbls/d)
            
            
            18,288
            
            
            17,352
            
            
            17,196
            
            
            17,469
            
            
            **17,574**Heavy
                oil (bbls/d)
            
            
            9,160
            
            
            8,741
            
            
            8,958
            
            
            8,580
            
            
            **8,858**Total
                crude oil (bbls/d)
            
            
            27,448
            
            
            26,093
            
            
            26,154
            
            
            26,049
            
            
            **26,432**Natural
                gas liquids (bbls/d)
            
            
            4,621
            
            
            4,549
            
            
            4,538
            
            
            5,045
            
            
            **4,689**Total
                liquids (bbls/d)
            
            
            32,069
            
            
            30,642
            
            
            30,692
            
            
            31,094
            
            
            **31,121**Natural
                gas (Mcf/d)
            
            
            280,463
            
            
            269,159
            
            
            277,180
            
            
            264,342
            
            
            **272,754**Total
                Canada (BOE/d)
            
            
            78,813
            
            
            75,502
            
            
            76,889
            
            
            75,151
            
            
            **76,580****United States**Light
                and medium crude oil (bbls/d)
            
            
            N/A
            
            
            N/A
            
            
            2,321
            
            
            9,118
            
            
            **2,883**Natural
                gas (Mcf/d)
            
            
            N/A
            
            
            N/A
            
            
            1,176
            
            
            5,102
            
            
            **1,582**Total
                United States (BOE/d)
            
            
            N/A
            
            
            N/A
            
            
            2,517
            
            
            9,968
            
            
            **3,147****Total
                Enerplus**Crude
                oilLight
                and medium oil (bbls/d)
            
            
            18,288
            
            
            17,352
            
            
            19,517
            
            
            26,587
            
            
            **20,457**Heavy
                oil (bbls/d)
            
            
            9,160
            
            
            8,741
            
            
            8,958
            
            
            8,580
            
            
            **8,858**Total
                crude oil (bbls/d)
            
            
            27,448
            
            
            26,093
            
            
            28,475
            
            
            35,167
            
            
            **29,315**Natural
                gas liquids (bbls/d)
            
            
            4,621
            
            
            4,549
            
            
            4,538
            
            
            5,045
            
            
            **4,689**Total
                liquids (bbls/d)
            
            
            32,069
            
            
            30,642
            
            
            33,013
            
            
            40,212
            
            
            **34,004**Natural
                gas (Mcf/d)
            
            
            280,463
            
            
            269,159
            
            
            278,356
            
            
            269,443
            
            
            **274,336**Total
                Enerplus (BOE/d)
            
            
            78,813
            
            
            75,502
            
            
            79,406
            
            
            85,119
            
            
            **79,727**








39


**Quarterly
      Netback History**




The
      following tables set forth Enerplus' average netbacks received for each fiscal
      quarter in 2005 and for the entire year (excluding the effects of commodity
      derivative instruments), separately for production in Canada and the
      United States. Enerplus had no heavy crude oil or NGLs production in the
      United States in 2005. Netbacks are calculated on the basis of prices
      received before the effects of commodity derivative instruments on sales
      volumes, less related royalties and related production costs. For multiple
      product well types, production costs are entirely attributed to that well's
      principal product type. As a result, no production costs are attributed to
      Enerplus' NGLs production or United States natural gas production as those
      costs have been attributed to the applicable wells' principal product
      type.





**Year
                Ended December 31, 2005***Light
                and Medium Crude Oil ($ per bbl)*
            
            **First**
              **Quarter**
            
            **Second**
              **Quarter**
            
            **Third**
              **Quarter**
            
            **Fourth**
              **Quarter**
            
            **Total
                for**
              **Year****Canada**Sales
                price(1)
            
            $
            53.89
            
            $
            57.00
            
            $
            70.48
            
            $
            62.60
            
            **$**
            **60.93**Royalties
            
            
            (8.80
            )
            
            (9.18
            )
            
            (11.35
            )
            
            (9.83
            )
            
            **(9.78**
            **)**Production
                costs(2)
            
            
            (12.03
            )
            
            (12.87
            )
            
            (14.12
            )
            
            (12.54
            )
            
            **(12.88**
            **)**Netback
            
            $
            33.06
            
            $
            34.95
            
            $
            45.01
            
            $
            40.23
            
            **$**
            **38.27****United States**Sales
                price(1)
            
            
            N/A
            
            
            N/A
            
            $
            74.96
            
            $
            66.55
            
            **$**
            **68.25**Royalties(3)
            
            
            N/A
            
            
            N/A
            
            
            (13.99
            )
            
            (13.01
            )
            
            **(13.21**
            **)**Production
                costs(2)
            
            
            N/A
            
            
            N/A
            
            
            (1.96
            )
            
            (1.96
            )
            
            **(1.96**
            **)**Netback
            
            
            N/A
            
            
            N/A
            
            $
            59.01
            
            $
            51.58
            
            **$**
            **53.08****Total
                Enerplus**Sales
                price(1)
            
            $
            53.89
            
            $
            57.00
            
            $
            71.01
            
            $
            63.95
            
            **$**
            **61.96**Royalties(3)
            
            
            (8.80
            )
            
            (9.18
            )
            
            (11.66
            )
            
            (10.92
            )
            
            **(10.26**
            **)**Production
                costs(2)
            
            
            (12.03
            )
            
            (12.87
            )
            
            (12.67
            )
            
            (8.91
            )
            
            **(11.34**
            **)**Netback
            
            $
            33.06
            
            $
            34.95
            
            $
            46.68
            
            $
            44.12
            
            **$**
            **40.36**





**Year
                Ended December 31, 2005***Heavy
                Oil ($ per bbl)*
            
            **First**
              **Quarter**
            
            **Second**
              **Quarter**
            
            **Third**
              **Quarter**
            
            **Fourth**
              **Quarter**
            
            **Total
                for**
              **Year****Canada/Total
                Enerplus**Sales
                price(1)
            
            $
            35.06
            
            $
            38.49
            
            $
            53.04
            
            $
            41.24
            
            **$**
            **41.99**Royalties
            
            
            (6.41
            )
            
            (7.02
            )
            
            (9.72
            )
            
            (7.59
            )
            
            **(7.69**
            **)**Production
                costs(2)
            
            
            (8.30
            )
            
            (9.50
            )
            
            (9.48
            )
            
            (11.75
            )
            
            **(9.73**
            **)**Netback
            
            $
            20.35
            
            $
            21.97
            
            $
            33.84
            
            $
            21.90
            
            **$**
            **24.57**





**Year
                Ended December 31, 2005***Natural
                Gas Liquids ($ per bbl)*
            
            **First**
              **Quarter**
            
            **Second**
              **Quarter**
            
            **Third**
              **Quarter**
            
            **Fourth**
              **Quarter**
            
            **Total
                for**
              **Year****Canada/Total
                Enerplus**Sales
                price(1)
            
            $
            43.80
            
            $
            45.98
            
            $
            48.60
            
            $
            50.55
            
            **$**
            **47.33**Royalties
            
            
            (10.95
            )
            
            (11.03
            )
            
            (11.66
            )
            
            (12.14
            )
            
            **(11.47**
            **)**Production
                costs(2)
            
            
            -
            
            
            -
            
            
            -
            
            
            -
            
            
            **-**Netback
            
            $
            32.85
            
            $
            34.95
            
            $
            36.94
            
            $
            38.41
            
            **$**
            **35.86**








40





**Year
                Ended December 31, 2005****First**
              **Quarter**
            
            **Second**
              **Quarter**
            
            **Third**
              **Quarter**
            
            **Fourth**
              **Quarter**
            
            **Total
                for**
              **Year***Natural
                Gas ($ per Mcf)***Canada**Sales
                price(1)
            
            $
            6.58
            
            $
            7.36
            
            $
            8.09
            
            $
            11.61
            
            **$**
            **8.39**Royalties
            
            
            (1.51
            )
            
            (1.63
            )
            
            (1.75
            )
            
            (2.14
            )
            
            **(1.76**
            **)**Production
                costs(2)
            
            
            (0.90
            )
            
            (1.07
            )
            
            (1.00
            )
            
            (1.07
            )
            
            **(1.01**
            **)**Netback
            
            $
            4.17
            
            $
            4.66
            
            $
            5.34
            
            $
            8.40
            
            **$**
            **5.62****United States**Sales
                price(1)
            
            
            N/A
            
            
            N/A
            
            $
            8.24
            
            $
            13.58
            
            **$**
            **12.58**Royalties(3)
            
            
            N/A
            
            
            N/A
            
            
            (1.32
            )
            
            (2.17
            )
            
            **(2.01**
            **)**Production
                costs(2)
            
            
            N/A
            
            
            N/A
            
            
            -
            
            
            -
            
            
            **-**Netback
            
            
            N/A
            
            
            N/A
            
            $
            6.92
            
            $
            11.41
            
            **$**
            **10.57****Total
                Enerplus**Sales
                price(1)
            
            $
            6.58
            
            $
            7.36
            
            $
            8.09
            
            $
            11.65
            
            **$**
            **8.41**Royalties(3)
            
            
            (1.51
            )
            
            (1.63
            )
            
            (1.75
            )
            
            (2.15
            )
            
            **(1.75**
            **)**Production
                costs(2)
            
            
            (0.90
            )
            
            (1.07
            )
            
            (1.00
            )
            
            (1.05
            )
            
            **(1.01**
            **)**Netback
            
            $
            4.17
            
            $
            4.66
            
            $
            5.34
            
            $
            8.45
            
            **$**
            **5.65**





**Year
                Ended December 31, 2005****First**
              **Quarter**
            
            **Second**
              **Quarter**
            
            **Third**
              **Quarter**
            
            **Fourth**
              **Quarter**
            
            **Total
                for**
              **Year***Total
                ($ per BOE)***Canada**Sales
                price(1)
            
            $
            42.55
            
            $
            46.57
            
            $
            53.97
            
            $
            63.78
            
            **$**
            **51.68**Royalties
            
            
            (8.78
            )
            
            (9.39
            )
            
            (10.68
            )
            
            (11.51
            )
            
            **(10.09**
            **)**Production
                costs(2)
            
            
            (6.98
            )
            
            (7.86
            )
            
            (7.88
            )
            
            (8.02
            )
            
            **(7.68**
            **)**Netback
            
            $
            26.79
            
            $
            29.32
            
            $
            35.41
            
            $
            44.25
            
            **$**
            **33.91****United States**Sales
                price(1)
            
            
            N/A
            
            
            N/A
            
            $
            72.98
            
            $
            67.82
            
            **$**
            **68.86**Royalties(3)
            
            
            N/A
            
            
            N/A
            
            
            (13.53
            )
            
            (13.01
            )
            
            **(13.11**
            **)**Production
                costs(2)
            
            
            N/A
            
            
            N/A
            
            
            (1.80
            )
            
            (1.80
            )
            
            **(1.80**
            **)**Netback
            
            
            N/A
            
            
            N/A
            
            $
            57.65
            
            $
            53.01
            
            **$**
            **53.95****Total
                Enerplus**Sales
                price(1)
            
            $
            42.55
            
            $
            46.57
            
            $
            54.57
            
            $
            64.26
            
            **$**
            **52.36**Royalties(3)
            
            
            (8.78
            )
            
            (9.39
            )
            
            (10.77
            )
            
            (11.68
            )
            
            **(10.21**
            **)**Production
                costs(2)
            
            
            (6.98
            )
            
            (7.86
            )
            
            (7.69
            )
            
            (7.29
            )
            
            **(7.45**
            **)**Netback
            
            $
            26.79
            
            $
            29.32
            
            $
            36.11
            
            $
            45.29
            
            **$**
            **34.70**


___________


Notes:


(1)
            Net
                of transportation costs but before the effects of commodity derivative
                instruments.




(2)
            Production
                costs are costs incurred to operate and maintain wells and related
                equipment and facilities, including operating costs of support equipment
                used in oil and gas activities and other costs of operating and
                maintaining those wells and related equipment and facilities. Examples
                of
                production costs include items such as field staff labour costs,
                costs of
                materials, supplies and fuel consumed and supplies utilized in operating
                the wells and related equipment (such as power, chemicals and lease
                rentals), repairs and maintenance costs, property taxes, insurance
                costs,
                costs of workovers, net processing and treating fees, overhead fees,
                taxes
                (other than income, capital, withholding or U.S. state production
                taxes) and other costs.




(3)
            Includes
                U.S. state production taxes.





41


**Abandonment
      and Reclamation Costs**




In
      connection with its operations, Enerplus will incur abandonment and reclamation
      costs for surface leases, wells, facilities and pipelines. Enerplus estimates
      such costs through a model that incorporates data from Enerplus' operating
      history, industry information sources and a cost formula used by the Alberta
      Energy Utilities Board, together with other operating assumptions. Enerplus
      expects all of its net wells to incur these costs. Enerplus anticipates the
      total amount of such costs, net of estimated salvage value for such equipment,
      to be approximately $422 million on an undiscounted basis and
      $54 million discounted at 10%. The calculations of future net revenue under
      "Oil and Natural Gas Reserves" above have excluded approximately
      $232 million on an undiscounted basis and $27 million discounted at
      10% as these calculations do not reflect any costs for abandonment and
      reclamation for facilities and wells for which no reserves have been attributed.
      In the next three financial years, Enerplus anticipates that a total of
      approximately $22.5 million on an undiscounted basis and $19.1 million
      discounted at 10% will be incurred in respect of abandonment and reclamation
      costs.




**Tax
      Horizon**




*Canadian*




No
      cash Canadian income taxes have been paid by the Fund or its Canadian Operating
      Subsidiaries for the year ended December 31, 2005. Under Enerplus' current
      structure, taxable income of the Canadian Operating Subsidiaries is transferred
      through interest, royalty and other distribution payments to the Fund, which
      in
      turn, allocates all of its taxable income to the unitholders. Therefore, no
      Canadian income taxes are currently expected to be incurred by the Fund or
      its
      Canadian Operating Subsidiaries in the future.




*United States*




A
      total of $2.8 million of U.S. income related cash taxes were incurred
      with respect to U.S. operations in the year ended December 31, 2005.
      Enerplus' U.S. operations are subject to income taxes payable on the
      taxable income determined under U.S. income tax rules and regulations. As
      funds are repatriated back to Canada, withholding taxes as required by
      U.S. tax law would become payable. As a result, Enerplus'
      U.S. operations are expected to continue to incur U.S. income related
      cash taxes in the future.




For
      additional information, see Notes 1(h) and 11 to the Fund's
      audited financial statements for the year ended December 31,
      2005.




**Costs
      Incurred**




In
      the financial year ended December 31, 2005, Enerplus made the following
      expenditures:





**Property**
              **Acquisition Costs****Proved**
            
            **Unproved**
            
            **Exploration
                Costs**
            
            **Development
                Costs**($ in
                millions)Canada
            
            $
            91.5
            
            $
            10.6
            
            $
            9.9
            
            $
            319.1United States
            
            
            589.6
            
            
            22.9
            
            
            1.8
            
            
            27.3**Total**
            
            $
            681.1
            
            $
            33.5
            
            $
            11.7
            
            $
            346.4





**Marketing
      Arrangements and Forward Contracts**




*Crude
      Oil and NGLs*




Enerplus'
      crude oil and NGLs production is marketed to a diverse portfolio of
      intermediaries and end users on 30 day continuously renewing contracts
      whose terms fluctuate with monthly spot market prices. Enerplus received an
      average price (net of transportation costs but before the effects of
      commodity derivative instruments) of $61.96/bbl for its light and medium crude
      oil, $41.99/bbl for its heavy crude oil and $47.33/bbl for its NGLs for the
      year
      ended December 31, 2005, compared to $47.87/bbl for its light and medium
      crude oil, $34.98/bbl for its heavy crude oil and $38.14/bbl for its NGLs for
      the year ended December 31, 2004. Enerplus





42





has
      a long term transportation commitment to deliver 2,480 bbls/d of Canadian
      production on the Plains Marketing Canada Joarcam Pipeline. Enerplus also has
      a
      long term gathering agreement for approximately 9,000 bbls/d of
      U.S. production on the Plains All American Trenton Pipeline System. Neither
      of these transportation agreements impact Enerplus' ability to market to a
      variety of purchasers under a variety of market-based terms.




*Natural
      Gas*




In
      marketing its natural gas production, Enerplus' efforts are directed to achieve
      a mix of contracts, customers, and geographic markets. Enerplus sells
      approximately one-third of its natural gas production under aggregator contracts
      wherein a large pool of reserve based natural gas production is aggregated,
      managed and sold downstream under long term transportation and sales contracts
      to a variety of end users. These entire sales proceeds and transportation costs
      are pooled and paid equitably to all supply producers. In 2005, these
      aggregators contracts returned a price just slightly lower than the monthly
      Alberta spot market price. As well, Enerplus has its own firm transportation
      commitments to deliver natural gas into the U.S. midwest (Chicago) area.
      These contracts consist of a total of 10 MMcf/d on each of the Foothills
      and Northern Border pipelines until October 31, 2008; 5 MMcf/d on the
      Alliance Pipeline until October 31, 2015; and 5 MMcf/d on each of the
      TransCanada and Viking Pipelines to Marshfield, Illinois until
      October 2008. The remainder of Enerplus' natural gas production is sold
      primarily in the provinces of Alberta, Saskatchewan and British Columbia at
      prevailing spot market prices.




Enerplus'
      percentage of 2005 revenues attributable to natural gas (net of
      transportation costs but before the effects of commodity derivative instruments)
      was 55% compared to 58% in 2004. The average price received by Enerplus
      (net of transportation costs but before the effects of commodity derivative
      instruments) for its natural gas in 2005 was $8.41/Mcf compared to $6.56/Mcf
      in
      the year ended December 31, 2004. Within its sales portfolio of aggregator,
      downstream and spot natural gas, Enerplus sold approximately 40% of its natural
      gas based on the AECO month index, 40% based on the AECO day index and 20%
      at
      NYMEX monthly index prices.




*Future
      Commitments and Forward Contracts*




Enerplus
      may use various types of financial instruments and fixed price physical sales
      contracts to manage the risk related to fluctuating commodity prices. Absent
      such hedging activities, all of the crude oil and NGLs and the majority of
      natural gas production of Enerplus is sold into the open market at prevailing
      spot prices, which exposes Enerplus to the risks associated with commodity
      price
      fluctuations and foreign exchange rates. See "Risk Factors". Information
      regarding Enerplus' financial and physical instruments is contained in
      Note 12 to the Fund's audited annual consolidated financial statements
      for the year ended December 31, 2005 and under the headings "Pricing" and
      "Price Risk Management" in the Fund's management's discussion and analysis
      for
      the year ended December 31, 2005, each of which is available through the
      Internet on Enerplus' SEDAR profile at www.sedar.com.




**Environment,
      Health and Safety**




Enerplus
      is committed to the ongoing health and safety of its employees, contractors
      and
      the general public as evidenced by its participation in industry recognized
      programs that drive and measure its Environment, Health and Safety
      (" **EHS** ")
      performance. Enerplus believes its efforts in EHS are essential to its continued
      corporate success and are important to all of its stakeholders. As a measure
      of
      its commitment to safety, Enerplus received industry recognition from Work
      Safe
      Alberta with a "Best Safety Performer" award presented in 2005. Of Alberta's
      128,000 employers, less than one percent received this award which is based
      upon stringent criteria of low lost time claims while maintaining strong
      compliance to regulatory requirements.




Enerplus
      has maintained its Certificate of Recognition (" **COR** ")
      which is a framework developed by Alberta's Workplace Health and Safety to
      promote and utilize health and safety programs in the Province of Alberta.
      Enerplus first received this certificate in 2000 and has maintained its COR
      through annual reviews and a rigorous audit every three years, with the next
      audit due in 2006. Enerplus also continues to be an active Platinum Level
      participant (the highest level attainable) in the Environment, Health and
      Safety Stewardship





43





Program
      initiated by the Canadian Association of Petroleum Producers (" **CAPP** ").
      This stewardship program provides comparison on key benchmarks including
      recordable and lost time injuries for employees and contractors. Enerplus'
      employees outperformed industry peers as measured against CAPP's historical
      benchmark injury data with zero lost time incidents and only two minor medical
      aid incidents in 2005.




Continued
      focus on contractor safety through 2005 resulted in Enerplus outperforming
      CAPP's historical benchmark total recordable injury data in 2004 and maintained
      its four-year trend on total recordable injury frequency rate down to
      1.53 per 200,000 man hours for 2005 in Canada. Contractor lost time
      frequency rates also trended downward from 0.73 per 200,000 man hours
      in 2004 to 0.46 per 200,000 man hours in 2005 in Canada. Contractor
      safety in the United States was not at as high a level as in Canada and
      will be a focus area for Enerplus in 2006. Contractor statistics for
      U.S. operations, which Enerplus added in August 2005 with the
      acquisition of Lyco, were 0.69 per 200,000 man hours and 1.66 per
      200,000 man hours for lost time and total recordable injuries,
      respectively.




Enerplus
      remains committed to meeting its responsibilities to protect the environment
      wherever it operates through a variety of programs and actively monitor its
      compliance with all regulators. Key efforts include:




(i)
            utilizing
                employee awareness training and facility inspections to improve its
                overall environmental awareness, reduce flared and vented volumes
                and
                mitigate the impact from environmental incidents at its operated
                facilities;




(ii)
            monitoring
                and tracking emissions at its facilities is part of its on-going
                commitment to meet various reporting initiatives including the National
                Pollutant Release Inventory and the CAPP Benzene Emissions and Green
                House
                Gas Emissions benchmarks;




(iii)
            maintaining
                an active well abandonment and site restoration program. Enerplus
                continued to assess and remediate sites impacted by historic operations,
                with a primary focus on spill sites, flare pit and drill sump removal.
                Enerplus also maintained comprehensive inspection programs and initiated
                facility upgrades in 2005 targeted at improving the integrity of
                surface
                pipe, storage tanks and underground pipelines;
                and




(iv)
            initiating
                a review of all of its pipelines that cross bodies of water in order
                to
                identify high risk crossings and implement appropriate emergency
                response
                plans. In 2005, an area study was reviewed with the findings of this
                study
                being used to define the longer term, company wide program that will
                be
                implemented in 2006. Enerplus' emergency response plans are continuously
                reviewed to ensure protection of the environment from accidental
                spills or
                releases. Operators are trained in emergency response for both safety
                and
                environmental incidents to mitigate the impacts of unexpected
                releases.




Increased
      emphasis on non-saline water use, particularly in sensitive water shed areas,
      is
      a focus in 2006. To that end, Enerplus has implemented a study to review and
      minimize this water use and ensure protection of non-saline water sites while
      at
      the same time ensuring that it has sufficient water to maintain its
      operations.




Overall,
      Enerplus spent $7.8 million on EHS related activities, which is higher than
      its historical spending in this area. In 2006, Enerplus plans to spend
      $10.4 million toward EHS initiatives as part of its ongoing
      commitment.




**Impact
      of Environmental Protection Requirements**




Enerplus
      carries out its activities and operations in compliance with all relevant and
      applicable environmental regulations and good industry practice. See
      "Information Respecting Enerplus Resources Fund  - Operations of
      Enerplus  - Environmental Obligations". At present, Enerplus believes that
      it meets all applicable environmental standards and regulations and has included
      appropriate amounts in its capital expenditure budget to continue to meet its
      ongoing environmental obligations. The costs incurred by Enerplus in respect
      of
      continued environmental compliance and site restoration costs amounted to
      approximately 2% of the total development expenditures incurred by Enerplus
      in
      2005. See "Industry Conditions  - Environmental Regulation" and "Risk
      Factors".





44





**Additional
      Operational Information**




*Insurance*




Enerplus
      carries insurance coverage to protect its assets at or above the standards
      typical within the oil and natural gas industry. Insurance levels are determined
      and acquired by Enerplus after considering the perceived risk of loss, coverage
      determined appropriate and the overall cost. Coverages currently in place
      include protection against third party liability, property damage or loss,
      and,
      for certain properties, business interruption. In addition, director and officer
      liability coverage is also carried for directors and
      officers of Enerplus.




*Personnel*




As
      at December 31, 2005, Enerplus employed a total of
      566 persons.




**INFORMATION
      RESPECTING ENERPLUS RESOURCES FUND**




**Description
      of the Trust Units and the Trust Indenture**




The
      following is a summary of certain provisions of the Trust Indenture and the
      Trust Units. For a complete description, reference should be made to the Trust
      Indenture, a copy of which may be viewed at the offices of, or obtained from,
      the Trustee, and a copy of which was filed on the Fund's SEDAR profile at
      www.sedar.com on January 5, 2004 (as may be subsequently amended and
      superseded).




*General*




The
      Fund was created, and the Trust Units are issued, pursuant to the Trust
      Indenture. The Trust Indenture, among other things, provides for the
      administration of the Fund, the investment of the Fund's assets, the calculation
      and payment of distributions to unitholders, the calling of and conduct of
      business at meetings of unitholders, the appointment and removal of the Trustee,
      redemptions of Trust Units and the payment of distributions by the Fund to
      its
      unitholders. Among other things, material amendments to the Trust Indenture,
      the
      early termination of the Fund and the sale or transfer of all or substantially
      all of the property of the Fund require the approval by extraordinary resolution
      (i.e., 66 2 / 3 %
      of the votes cast) of the unitholders. See "--  Meetings of Unitholders and
      Voting" and "--  Amendments to the Trust Indenture" below.




*Trust
      Units and Other Securities of the Fund*




The
      Fund is authorized to issue an unlimited number of Trust Units and each Trust
      Unit represents an equal undivided beneficial interest in the Fund. All Trust
      Units share equally in all distributions from the Fund and in the net assets
      of
      the Fund upon the termination or winding-up of the Fund. Each Trust Unit
      entitles the holder thereof to one vote at meetings of unitholders. No
      unitholder will be liable to pay any further amounts or assessments in respect
      of the Trust Units. No conversion or pre-emptive rights attach to the Trust
      Units.




The
      Trust Indenture provides that the directors of EnerMark may from time to time
      authorize the creation and issuance of options, rights, warrants or similar
      rights to acquire Trust Units or other securities convertible or exchangeable
      into Trust Units, on the terms and conditions as the directors of EnerMark
      may
      determine. A right, warrant, option or other similar security is not considered
      to be a Trust Unit and a holder of such securities is not considered to be
      a
      unitholder of Enerplus. Additionally, the directors of EnerMark may authorize
      the creation and issuance of debentures, notes and other indebtedness of the
      Fund on such terms and conditions as the directors of EnerMark may
      determine.




*The
      Trustee*




CIBC Mellon
      Trust Company is the trustee of the Fund and also acts as transfer agent and
      registrar for the Trust Units. The Trust Indenture provides that, subject to
      the
      specific limitations and the grant of powers to EnerMark contained in the Trust
      Indenture, the Trustee has full, absolute and exclusive power, control and
      authority over the property of the Fund and over the affairs of the Fund to
      the
      same extent as if the Trustee were the sole owner of such property in its own
      right, and may do all such acts and things as it, in its sole judgment





45





and
      discretion, deems necessary or incidental to, or desirable for, the carrying
      out
      of the duties of the Trustee as established pursuant to the Trust Indenture.
      In
      particular, among other things, the Trustee is responsible for making the
      payment of distributions or other property to unitholders, maintaining certain
      records of the Fund and providing certain reports to unitholders.




However,
      certain powers, authorities and obligations have been granted to EnerMark in
      the
      Trust Indenture, including the responsibility for the general administration
      and
      management of the day to day affairs and operations of the Fund. Other powers
      and responsibilities may be delegated to such other persons as the Fund Trustee
      may deem necessary or desirable. See "--  Responsibilities of and
      Delegation to EnerMark" below.




The
      Trustee shall be removed by notice in writing delivered by EnerMark to the
      Trustee if the Trustee fails to meet certain criteria stated within the Trust
      Indenture or with the approval of at least 66 2 / 3 %
      of the votes cast at a meeting of unitholders called for that purpose. The
      Trustee or any successor may resign upon 60 days notice to EnerMark. Such
      resignation or removal shall become effective upon the acceptance of appointment
      by a successor trustee. If the Trustee is removed by EnerMark, EnerMark may
      appoint a successor trustee. If the Trustee resigns or is removed by
      unitholders, its successor must be either appointed by EnerMark or the
      unitholders. If a successor trustee does not accept its appointment as trustee,
      a court may appoint the successor trustee.




The
      Trust Indenture provides that the Trustee shall exercise the powers and
      discharge the duties of its office honestly, in good faith and in the best
      interests of the Fund and its unitholders and shall exercise the degree of
      care,
      diligence and skill that a reasonably prudent person would exercise in
      comparable circumstances. To the extent the performance of certain duties and
      activities has been granted, allocated or delegated to EnerMark in the Trust
      Indenture, or to the extent that the Trustee has relied on EnerMark in carrying
      out the Trustee's duties, the Trustee is deemed to have satisfied its standard
      of care.




The
      Trustee will not be liable for: (i) any action taken in good faith in
      reliance on prima facie properly executed documents or for the disposition
      of
      monies or securities; (ii) any depreciation or loss incurred by reason of
      the sale of any security or assets; (iii) any inaccuracy in any evaluation
      or advice of EnerMark or any retained expert or other advisor, or any reliance
      on any such evaluation or advice; (iv) the disposition of monies or
      securities; or (v) any action or failure to act of EnerMark or any other
      person to whom the Trustee has properly delegated its duties. These provisions,
      however, will not protect the Trustee in cases of wilful misfeasance, bad faith,
      negligence or disregard of its obligations and duties nor shall it protect
      the
      Trustee in any case where the Trustee fails to act in accordance with the
      standard of care described above. The Trustee may retain an expert or advisor
      in
      connection with the performance of its duties under the Trust Indenture and
      may
      act or refuse to act on the advice of any such expert or advisor without
      liability.




The
      Trustee, where it has met its standard of care, shall be indemnified by the
      Fund, EnerMark and ERC for any costs or liabilities imposed upon the Trustee
      in
      consequence of its performance of its duties, but shall have no additional
      recourse against the Fund's unitholders. In addition, the Trust Indenture
      contains other customary provisions limiting the liability of the Trustee.
      The
      Trustee is entitled to receive from the Fund the fees that may be agreed upon
      in
      writing by EnerMark, on behalf of the Fund, and the Trustee, and is entitled
      to
      be reimbursed by the Fund for its expenses incurred in acting as
      trustee.




*Responsibilities
      of and Delegation to EnerMark*




Under
      the Trust Indenture, in addition to the duties of EnerMark described elsewhere
      in this Annual Information Form, EnerMark has been allocated the responsibility
      for the general administration and management of the affairs and day-to-day
      operations of the Fund. The Trustee is also authorized to delegate any of the
      powers and duties granted to it (to the extent not prohibited by law) to
      any person as the Trustee may deem necessary or desirable. All significant
      operational and strategic matters relating to the Fund have been either granted
      or delegated to EnerMark in the Trust Indenture including, among other things,
      the responsibility to: (i) determine the timing and terms of future
      offerings or repurchases of Trust Units and other securities of the Fund;
      (ii) undertake all matters relating to borrowings by the Fund, including
      the granting of security and subordination agreements by the Fund;
      (iii) vote all securities held by the Fund (subject to restrictions in the
      Trust Indenture); (iv) approve the Fund's public disclosure documents;
      (v) undertake all matters pertaining to any take-over bid, merger,
      amalgamation, arrangement, substantial asset acquisition or similar transaction





46





involving
      the Fund; (vi) ensure compliance by the Fund with its continuous disclosure
      obligations under applicable securities laws; (vii) provide investor
      relations services; (viii) prepare and cause to be provided to unitholders
      all information to which unitholders are entitled under the Trust Indenture
      and
      under applicable laws; (ix) call and hold meetings of unitholders and
      prepare, approve and arrange for the distribution of required materials,
      including notices of meetings and information circulars, in respect of all
      such
      meetings; (x) compute, determine, approve and direct the Trustee to make
      distributions to unitholders; and (xi) use its best efforts to ensure the
      Fund maintains its status as a mutual fund trust under the Tax Act. The
      Trust Indenture permits EnerMark to delegate its responsibilities, but no such
      delegation will relieve EnerMark of its obligations under the Trust Indenture.
      If, however, EnerMark delegates its responsibilities to a third party and in
      so
      doing does not breach its standard of care, EnerMark will not be liable for
      the
      acts or omissions of such delegate.




In
      exercising its powers and discharging its duties under the Trust Indenture,
      EnerMark is required to act honestly, in good faith and with a view to the
      best
      interests of the Fund and the unitholders, and shall exercise the same degree
      of
      care, diligence and skill that a reasonably prudent person, having
      responsibilities of a similar nature to those set forth in the Trust Indenture,
      would exercise in comparable circumstances. The Trust Indenture also sets forth
      certain rights, restrictions and limitations which pertain to the performance
      by
      EnerMark of the duties granted to it under the Trust Indenture or delegated
      to
      it by the Trustee. The Trust Indenture provides that the Trustee shall have
      no
      liability to any unitholder or other person as a result of the granting and
      allocation of certain powers and responsibilities to EnerMark pursuant to the
      Trust Indenture or the delegation by the Trustee of any of its powers and duties
      to EnerMark.




*Certain
      Restrictions on Powers of the Trustee and EnerMark*




The
      Trust Indenture provides that neither the Trustee nor EnerMark may, without
      approval of the Fund's unitholders by ordinary resolution (meaning approval
      by a
      majority of the votes cast), vote shares of EnerMark to appoint, remove or
      replace the directors of EnerMark or appoint or change the auditors of the
      Fund,
      except to fill a vacancy in the office of auditors. Additionally, the Trust
      Indenture provides that neither the Trustee nor EnerMark may, without approval
      of the unitholders by extraordinary resolution (meaning approval by at least
      66 2 / 3 %
      of the votes):




(i)
            amend
                the Trust Indenture (except in certain circumstances described under
                "Amendments to the Trust Indenture"
                below);




(ii)
            sell,
                assign, lease, exchange or otherwise dispose of, or agree to do so,
                all or
                substantially all of the property and assets of the Fund, other than
                (A) in conjunction with an internal reorganization of the direct or
                indirect assets of the Fund as a result of which the Fund has the
                same
                direct or indirect interest in such property and assets that it had
                prior
                to the reorganization, or (B) pursuant to a pledge relating to
                indebtedness of the Fund or its
                subsidiaries;




(iii)
            authorize
                the termination, liquidation or winding-up of the Fund;
                or




(iv)
            authorize
                the combination, merger or similar transaction between the Fund and
                any
                other person that is not an affiliate or associate of the Fund, except
                in
                connection with an internal reorganization of the Fund and its affiliates
                (but for greater certainty, a take-over bid by or on behalf of the
                Fund, an acquisition by or on behalf of the Fund by way of plan of
                arrangement or the acquisition by the Fund of all or substantially
                all of
                the assets of another person shall not be subject to the approval
                of
                the unitholders).




Additionally,
      neither the Trustee nor EnerMark shall take, or fail to take, any actions which
      would result in the Fund not qualifying as a "mutual fund trust" under the
      Tax Act.




The
      Trustee has delegated the voting of securities held by the Fund (primarily
      being
      the common shares of EnerMark) to EnerMark, subject to restrictions on voting
      those securities contained in the Trust Indenture. In certain circumstances,
      including those described above, before the Fund (through EnerMark) may vote
      these securities, a vote of the unitholders of the Fund on the matter must
      first
      be held in accordance with the provisions of the Trust Indenture. EnerMark
      shall
      then be required to vote the applicable securities held by the Fund in favour
      of, or in opposition to, the matter in equal proportion to the votes cast by
      the
      unitholders of the Fund in favour of, or in opposition to, the matter, as
      applicable.





47







*Non-Resident
      Ownership Provisions*




As
      long as the fund is able to meet the "TCP Exception" described under "Risk
      Factors  - Risks Related to Enerplus' Structure and Ownership of the Trust
      Units  - Changes in tax and other laws may adversely affect unitholders",
      there is no specified limitation in the Tax Act as to the level of
      non-Canadian resident ownership of the Trust Units. However, absent the TCP
      Exception, in order for the Fund to maintain its status as a mutual fund trust
      under the Tax Act, it may be necessary for the Fund to ensure that it has
      not been established or maintained primarily for the benefit of non-residents
      of
      Canada (" **non-residents** ")
      within the meaning of the Tax Act or to otherwise restrict the number of
      Trust Units held by non-residents. Accordingly, the Trust Indenture provides
      that, from time to time, EnerMark may restrict the number of Trust Units owned
      by non-residents and take all necessary steps to monitor the ownership of the
      Trust Units such that the Fund maintains the status of a unit trust and mutual
      fund trust for the purposes of the Tax Act. The Trust Indenture also
      provides that, if at any time EnerMark becomes aware that the number of Trust
      Units owned by non-residents exceeds the restricted number of Trust Units as
      determined by EnerMark, or that such a situation is imminent, EnerMark, on
      behalf of the Fund, will make a public announcement of the situation and will
      take steps to ensure no additional Trust Units are issued or transferred to
      non-residents, and may require non-residents (generally chosen in the inverse
      order of acquisition or registration of the Trust Units) to sell their Trust
      Units, or a portion thereof, in order to reduce the level of non-resident
      ownership below the determined threshold. The Fund's transfer agent may require
      declarations as to residency to effect these provisions.




As
      a result of the uncertainty involved in the methodology used to determine the
      proportion of non-resident ownership, any reasonable and bona fide exercise
      by
      EnerMark of its discretion in making a determination as to the proportion of
      non-resident ownership shall be binding and shall not subject the Trustee,
      EnerMark or the Fund's transfer agent to any liability for any violation of
      non-resident ownership restrictions under the Tax Act. Notwithstanding any
      other provision of the Trust Indenture, non-residents are not entitled to vote
      on any resolutions to amend the non-resident ownership provisions contained
      in
      the Trust Indenture.




For
      additional information regarding non-resident ownership restrictions and
      developments, see "Risk Factors  - Risks Related to Enerplus' Structure and
      Ownership of the Trust Units".




*Investments
      of the Fund*




The
      Fund is a limited purpose trust which is restricted to investing in investments
      or properties described in Section 132(6)(b) of the Tax Act
      including, without limitation, any investments or property acquired directly
      or
      indirectly from the issue of Trust Units. However, the Fund cannot hold property
      or investments which would result in the Fund not being either a "unit trust"
      or
      a "mutual fund trust", or which would cause the Trust Units to be foreign
      property, for the purposes of the Tax Act. At present, the directly held
      assets of the Fund are securities of certain of its wholly owned Operating
      Subsidiaries, unsecured indebtedness issued to the Fund by EnerMark and the
      royalty interests issued to the Fund by EnerMark, ERC and Enerplus
      Oil & Gas. The Fund may also dispose of any of its investments or
      properties, and also may invest cash which is not being used immediately for
      the
      purposes required in the Trust Indenture in short term financial instruments
      guaranteed by a Canadian chartered bank or the federal or a provincial
      government of Canada.




*Distributions
      of Distributable Income*




The
      Fund makes distributions from its net income and net realized capital gains.
      It
      receives income from EnerMark, ERC and Enerplus Oil & Gas pursuant to
      the royalty agreements, as well as from other sources such as principal and
      interest payments and dividend and distribution payments received from its
      Operating Subsidiaries. These Operating Subsidiaries may retain a portion of
      their operating cash flow to repay debt or fund capital expenditure and working
      capital requirements. In determining what amount of its income is distributable,
      the Fund deducts all taxes (including withholding tax) and all expenses and
      liabilities of the Fund which are due or accrued and which are chargeable to
      income. The Trust Indenture provides that the amount of distributable income
      and
      net realized capital gains to be paid in any period, and the timing of those
      distributions, is within EnerMark's discretion.





48







Under
      the Trust Indenture, EnerMark has the authority to determine the timing and
      the
      number of distribution record dates within the year. Currently, the Fund has
      established a monthly distribution, with the 10th day of each calendar month
      as
      a distribution record date and the 20th day of such month as the corresponding
      distribution payment date. The January 20 payment date is an exception as
      its corresponding record date is December 31 of the immediately preceding
      year. Under certain circumstances, including where the Fund does not have
      sufficient cash to pay the full distribution to be made on a distribution
      payment date, the distribution payable to unitholders may, at the option of
      EnerMark, include a distribution of Trust Units having a value equal to the
      cash
      shortfall.




Once
      a distribution record date has been set, the Fund must declare the amount of
      distributable income and net realized capital gains, if any, that will be
      distributed on or before that date and may pay out the distribution on the
      corresponding distribution payment date. The Trust Indenture provides that
      EnerMark, on behalf of the Fund and the Trustee, may declare payable to the
      unitholders on a pro rata basis all or any part of the distributable income
      and net realized capital gains of the Fund for that period ending on the
      distribution record date to the extent that cash flow was not previously
      declared payable. The authority to determine the amount of distributable income
      and net realized capital gains, if any, that will be paid on a given
      distribution date, and to administer these payments, has been granted to
      EnerMark. On December 31 of each fiscal year, an amount equal to the net
      income of the Fund for such fiscal year determined in accordance with the
      Tax Act plus any net realized capital gains of the Fund, to the extent that
      either is not previously declared payable by the Fund to its unitholders in
      such
      fiscal year, will be payable to unitholders immediately prior to the end of
      that
      fiscal year. Notwithstanding the foregoing, the Fund may retain that amount
      of
      distributable income and net realized capital gains that is determined to be
      necessary to pay any tax liability of the Fund, and those amounts will not
      be
      payable by the Fund to unitholders. See "Distributions to Unitholders" for
      additional information regarding the cash distributions paid by the Fund to
      its
      unitholders.




*Meetings
      of Unitholders and Voting*




The
      Trust Indenture provides that there shall be an annual meeting of the Fund's
      unitholders (which may include any holders of voting rights then outstanding)
      at
      a time and place determined by EnerMark for the purpose of: (i) the
      presentation of the audited financial statements of the Fund for the prior
      fiscal year; (ii) directing and instructing the Fund as to the manner in
      which it (through EnerMark) shall vote the shares of EnerMark held by the Fund
      in respect of the election of the directors of EnerMark; (iii) appointing
      the auditors of the Fund for the ensuing year; and (iv) transacting such
      other business as EnerMark or the Trustee may determine or as may be properly
      brought before the meeting.




The
      Trust Indenture provides that special meetings of unitholders may be convened
      at
      any time and for any purpose by the Trustee or EnerMark and must be convened
      if
      requisitioned in writing by unitholders representing not less than 20% of the
      Trust Units then outstanding. A requisition will be required to state in
      reasonable detail the business proposed to be transacted at the
      meeting.




At
      all meetings of the Fund's unitholders, each holder is entitled to one vote
      in
      respect of each Trust Unit held. Unitholders may attend and vote at all meetings
      of the unitholders either in person or by proxy, and a proxy holder does not
      have to be a unitholder. Two persons present in person or represented by proxy
      and representing no less than 5% of the votes attached to all outstanding Trust
      Units will constitute a quorum for the transaction of business at such meetings.
      If a quorum is not present at any such meeting, the meeting will stand adjourned
      until at least one day later and to such place and time as the chairman of
      the
      meeting determines, and the unitholders present in person or by proxy at such
      adjourned meeting will constitute a quorum for the transaction of any business
      which might have been dealt with at the original meeting in accordance with
      the
      notice calling the original meeting. Provided due and proper notice to
      unitholders is given in accordance with the Trust Indenture, a resolution
      executed by unitholders holding the requisite number of the outstanding Trust
      Units entitled to vote shall have the same effect as if it had been passed
      by
      that percentage of votes cast at a meeting of unitholders.




The
      Trust Indenture contains provisions as to the notice required and other
      procedures with respect to the calling and holding of meetings of unitholders
      and the holders of other securities of the Fund. All activities necessary to
      organize any such meeting will be undertaken by EnerMark.





49





*Redemption
      Right*




Each
      unitholder is entitled to require the Fund to redeem at any time or from time
      to
      time, at the demand of the unitholder and upon receipt by the Fund of a duly
      completed and properly executed notice requesting such redemption, all or any
      part of the Trust Units registered in the name of the unitholder at a price
      per
      Trust Unit equal to the lesser of:




(i)
            85%
                of the market price (as defined in the Trust Indenture) of the Trust
                Units on the principal market on which the Trust Units are quoted
                for
                trading during the 10 day trading period commencing immediately after
                the date on which the Trust Units were tendered to the Fund 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 were so tendered
                for
                redemption.




The
      price that unitholders receive for Trust Units surrendered for redemption during
      any calendar month will be paid to the unitholder on the last day of the
      following month. There is however a limitation on the amount of cash that the
      Fund can pay for redemptions. The maximum amount of cash that the Fund can
      pay
      for all Trust Units surrendered for redemption in any calendar month and the
      preceding calendar month cannot exceed $500,000, although EnerMark has the
      ability to waive this limitation at its discretion. If a unitholder is not
      entitled to receive a cash payment for Trust Units surrendered for redemption
      as
      a result of such limitations, a unitholder will receive notes or other
      investments of the Fund, subject to receipt of any applicable regulatory
      approvals. If at the time that a unitholder surrenders his or her Trust Units
      for redemption, the Trust Units are not listed for trading on the Toronto Stock
      Exchange or another market which EnerMark considers, in its sole discretion,
      provides representative fair market value prices for the Trust Units, or if
      the
      normal trading of the Trust Units has been suspended or halted, the unitholder
      will receive a price per Trust Unit equal to 85% of the fair market value as
      determined by EnerMark as at the redemption date. Once a Trust Unit is presented
      for redemption, the holder is no longer entitled to receive distributions from
      the Fund.




It
      is anticipated that the redemption right will not be the primary mechanism
      for
      unitholders to dispose of their Trust Units. Notes and other assets of the
      Fund
      which may be distributed in specie to unitholders in connection with a
      redemption will not be listed on any stock exchange and no market is expected
      to
      develop in such notes or in the other assets of the Fund. Notes and other Fund
      assets so distributed are expected to be subject to resale restrictions under
      applicable securities laws and are not expected to be qualified investments
      for
      registered retirement savings plans, registered education savings plans,
      registered retirement income funds or deferred profit savings plans, each as
      defined in the Tax Act.




*Repurchase
      of Trust Units*




The
      Fund is entitled, from time to time, to purchase Trust Units for cancellation
      or
      otherwise at a price per Trust Unit and on a basis which is determined by
      EnerMark. Such purchases will be made in compliance with applicable securities
      legislation and the rules prescribed under applicable stock exchange or
      regulatory policies. Any such purchases will constitute an "issuer bid" under
      Canadian provincial securities legislation and, if such a purchase is not
      exempt, must be conducted in accordance with the applicable requirements
      thereof.




*Term
      and Termination of the Fund*




The
      Trustee shall commence to wind up the affairs of the Fund when there are no
      longer any Trust Units outstanding. However, the Fund may be terminated earlier
      if the unitholders vote by extraordinary resolution (meaning 66 2 / 3 %
      of the votes cast) to terminate the Fund at any meeting of unitholders duly
      called for that purpose, following which the Trustee shall commence to wind
      up
      the affairs of the Fund. However, such a vote may be held only if requested
      in
      writing by the holders of at least 25% of the Trust Units or if called by the
      Trustee following the refusal of the Trustee or EnerMark to redeem Trust Units.
      The quorum requirement for such a meeting is at least 20% of the issued and
      outstanding Trust Units represented in person or by proxy.




Upon
      being required to commence to wind up the affairs of the Fund, the Trustee
      will
      give notice to the unitholders designating the time at which unitholders may
      surrender their Trust Units for cancellation and the date at which the register
      of the Fund shall be closed.





50







After
      the date on which the Trustee is required to commence to wind up the affairs
      of
      the Fund, the Trustee will generally carry on no activities except for the
      purpose of winding up the affairs of the Fund and, for this purpose, the Trustee
      will continue to be vested with and may exercise all or any of the powers
      conferred upon the Trustee under the Trust Indenture.




*Reporting
      to Unitholders*




The
      accounts of the Fund are audited at least annually by an independent recognized
      firm of chartered accountants selected by the unitholders, and the financial
      statements of the Fund, together with the report of the auditors, are mailed
      by
      the Fund to unitholders within appropriate regulatory time periods in each
      calendar year. The fiscal year-end of the Fund is December 31.




The
      Trust Indenture provides that a unitholder has the right, upon payment of
      reasonable production costs, to obtain a copy of the Trust Indenture and the
      right to inspect and, on payment of the reasonable charges of the registrar
      therefor, to obtain a list of the registered holders of the Trust Units for
      purposes connected with the Fund.




*Auditors*




The
      Trust Indenture generally mirrors the provisions of the *Business
      Corporations Act* (Alberta) regarding the appointment, removal and resignation of auditors. The
      Trust Indenture states that the appointment or removal of the Fund's auditors
      (as well as the appointment of a new auditor upon such removal) must be
      approved by the Fund's unitholders. However, if the Fund's auditors resign
      or
      are removed by the unitholders without a successor properly appointed, the
      board
      of directors of EnerMark has the power to appoint new auditors to fill the
      vacancy created by the resignation or removal. The new auditors will hold office
      until the next annual meeting of the Fund's unitholders.




*Amendments
      to the Trust Indenture*




The
      Trust Indenture may be amended from time to time by the Trustee, EnerMark and
      ERC. Material amendments to the Trust Indenture require approval by at least
      66 2 / 3 %
      of the votes cast at a meeting of the unitholders called for that purpose.
      However, the Trustee, EnerMark and ERC may, without the approval of the
      unitholders, make amendments to the Trust Indenture for the purposes
      of:




(i)
            ensuring
                that the Fund will comply with any applicable laws or requirements
                of any
                governmental agency or authority of Canada or of any
                province;




(ii)
            ensuring
                that the Fund will maintain its status as a "unit trust" or "mutual
                fund
                trust", and not become foreign property, pursuant to the
                Tax Act;




(iii)
            ensuring
                that such additional protection is provided for the interests of
                unitholders as the Trustee or EnerMark may consider
                expedient;




(iv)
            removing
                any conflicts or inconsistencies between the provisions of the Trust
                Indenture or any supplemental indenture and any prospectus filed
                with any
                regulatory or governmental body with respect to the Fund, or any
                applicable law or regulation of any jurisdiction, if, in the opinion
                of
                the Trustee, such an amendment will not be detrimental to the interests
                of
                the unitholders;




(v)
            adding
                to the provisions of the Trust Indenture such additional covenants
                and
                enforcement provisions as, in the opinion of counsel, are necessary
                or
                advisable, or making such provisions not inconsistent with the Trust
                Indenture as may be necessary or desirable with respect to matters
                or
                questions arising under the Trust Indenture, provided that the same
                are
                not, in the opinion of the Trustee, prejudicial to the interests
                of the
                unitholders;




(vi)
            modifying
                any of the provisions of the Trust Indenture, including relieving
                EnerMark
                from any of its obligations, conditions or restrictions, provided
                that
                such modification or relief shall be or become operative or effective
                only
                if, in the opinion of the Trustee, such modification or relief is
                not
                prejudicial to the interests of the unitholders;
                and





51







(vii)
            for
                any other purpose not inconsistent with the terms of the Trust Indenture,
                including the correction or rectification of any ambiguities, defective
                or
                inconsistent provisions, errors, mistakes or omissions therein, provided
                that, in the opinion of the Trustee, the rights of the unitholders
                are not
                prejudiced thereby.




The
      determinations to be made by the Trustee and the discretion to be exercised
      by
      the Trustee in the foregoing provisions has been delegated to EnerMark, provided
      that such an amendment would not prejudice the rights of the
      Trustee.




**Description
      of the Royalty Agreements and Subordinated Notes**




The
      Fund's primary sources of net cash flow are: (i) payments received from
      95%, 99% and 99% net royalty interests issued to the Fund by EnerMark, ERC
      and
      Enerplus Oil & Gas, respectively, on the production from their oil and
      natural gas properties; (ii) interest and principal payments on unsecured,
      subordinated debt issued to the Fund by EnerMark; and (iii) dividend and
      distribution payments received by the Fund from EnerMark and ECT, respectively.
      Outlined below is a description of the royalties granted by EnerMark, ERC and
      Enerplus Oil & Gas to the Fund and the subordinated debt issued by
      EnerMark to the Fund.




*Royalty
      Agreements*




Pursuant
      to separate royalty agreements with the Fund, each of EnerMark, ERC and Enerplus
      Oil & Gas have granted to the Fund a 95%, 99% and 99% royalty,
      respectively, on the net income from their respective oil and natural gas
      properties and operations. The Fund pays these royalties on or about the 20th
      day of the second month following the month to which such income relates. The
      net cash flow received by the Fund from EnerMark, ERC and Enerplus
      Oil & Gas pursuant to the royalty agreements is equal to the gross
      production revenue from their oil and natural gas operations, less certain
      permitted deductions (generally being operating costs, other third party
      royalties, general and administrative expenses, debt service charges, taxes
      on
      the properties and site restoration and abandonment costs). Unitholders may
      also
      receive distributions of the net proceeds received from the sale of properties,
      although it is anticipated that these proceeds will generally be used to repay
      debt or purchase additional properties and assets.




Under
      the royalty agreements, the properties in respect of which the Fund has been
      granted a royalty interest may be encumbered by security interests given by
      EnerMark, ERC and Enerplus Oil & Gas to secure loans provided to
      EnerMark, including pursuant to EnerMark's credit facilities and outstanding
      senior notes. Such security interests may rank ahead of the royalty interests
      of
      the Fund. Further, each of EnerMark, ERC and Enerplus Oil & Gas have
      the option at any time to apply any amount of gross production revenues to
      the
      repayment of debt. The Fund has entered into a subordination agreement pursuant
      to which the royalty payments to the Fund by EnerMark, ERC and Enerplus
      Oil & Gas are subordinated and will rank junior to the indebtedness of
      EnerMark to its lenders and the holders of its senior unsecured
      notes.




Pursuant
      to the respective royalty agreements, EnerMark, ERC and Enerplus Oil &
Gas have the right to dispose of properties and the associated royalties. The
      royalty agreements continue in force for as long as the applicable operating
      company has an interest in the properties covered by its respective royalty
      agreement. The royalty agreements and the royalty indenture (described below)
      may be amended in writing from time to time. All decisions in respect of such
      amendments are made by the board of directors of EnerMark on behalf of all
      parties to those agreements.




The
      royalty from ERC is paid to the Fund as payments on royalty units issued by
      ERC
      to the Fund pursuant to an amended and restated royalty indenture dated
      June 21, 2001 between ERC and the Trustee. All of the royalty units are
      held by the Trustee on behalf of the Fund.




*Unsecured,
      Subordinated Promissory Notes of EnerMark*




EnerMark
      has issued unsecured, subordinated promissory notes to the Fund. The
      subordinated notes bear interest at various annual rates, expire at various
      dates and the principal amounts of the notes vary as additional funds (generally
      from the issuance of Trust Units) are loaned from the Fund to EnerMark and
      principal repayments are made on the notes. The payment of principal and
      interest on the notes is subordinated to the





52





prior
      payment in full of all other debt of EnerMark, other than debt which, by its
      terms or by operation of law, ranks equal with the subordinated notes. The
      Fund
      has entered into a subordination agreement pursuant to which the payment to
      the
      Fund by EnerMark of obligations under the subordinated notes issued to the
      Fund
      is subordinated and will rank junior to the indebtedness of EnerMark to its
      lenders and the holders of its senior unsecured notes.




*Subordination
      of Royalty, Interest, Distribution and Dividend Payments from Operating
      Subsidiaries of the Fund*




As
      stated above, the terms of the existing royalty agreements and the subordinated
      debt issued by EnerMark to the Fund, together with the subordination agreements
      entered into by the Fund and the terms of EnerMark's credit facilities and
      senior notes, result in the royalty, interest, distribution and dividend
      payments from the Fund's Operating Subsidiaries to the Fund being subordinate
      to
      payments made, or required to be made, on indebtedness to third parties. As
      a
      result, royalty, interest, distribution and dividend payments from EnerMark,
      ERC, Enerplus Oil & Gas, ECT and Enerplus USA to the Fund, and the
      related cash distributions from the Fund to unitholders, may be adversely
      affected if EnerMark is in default of such indebtedness or if there are
      variations in the terms of EnerMark's indebtedness to third parties, including
      interest rates or the timing or principal repayments. See "Risk
      Factors".




**Management
      and Corporate Governance**




Under
      the terms of the Trust Indenture, subject to certain powers remaining with
      the
      Trustee, EnerMark has been allocated the responsibility for the general
      administration and management of the affairs and day-to-day operations of the
      Fund. See "Information Respecting Enerplus Resources Fund  - Description of
      the Trust Units and the Trust Indenture  - Responsibilities of and
      Delegation to EnerMark" and see "Directors and Officers".




Information
      regarding the Fund's corporate governance and the duties and procedures of
      the
      EnerMark board of directors and its committees is contained under the heading
      "Corporate Governance" in the Fund's 2005 Annual Report and under the heading
      "Statement of Corporate Governance Practices" in the Fund's information circular
      and proxy statement dated February 28, 2006. Enerplus fully complies with
      the provisions of National Instrument 58-101  - *Disclosure
      of Corporate Governance Practices,* Multilateral Instrument 52-109  - *Certification
      of Disclosure in Issuer's Annual and Interim Filings* and Multilateral Instrument 52-110  - *Audit
      Committees* adopted by the Canadian Securities Administrators and intends to fully comply
      with all other securities regulatory or stock exchange requirements relating
      to
      corporate governance. As mentioned above, all governance and management
      functions for Enerplus are contained within the Fund's wholly-owned Operating
      Subsidiary, EnerMark.




**Unitholder
      Rights Plan**




On
      March 5, 1999, the Fund entered into a Unitholder Rights Plan Agreement
      (the " **Rights
      Plan** ")
      with CIBC Mellon Trust Company, as rights agent, which was approved by
      Enerplus' unitholders on April 23, 1999 and was renewed for an additional
      three years by the Enerplus unitholders at each of the 2002 and 2005 annual
      general and special meetings of unitholders. The Rights Plan generally provides
      that, following the acquisition by any person or entity of 20% or more of the
      issued and outstanding Trust Units (except pursuant to certain permitted or
      excepted transactions) and upon the occurrence of certain other events, each
      holder of Trust Units, other than such acquiring person or entity, shall be
      entitled to acquire Trust Units at a discounted price. The Rights Plan is
      similar to other shareholder or unitholder rights plans adopted in the energy
      sector. A copy of the Rights Plan is available through the Internet on Enerplus'
      SEDAR profile at www.sedar.com, filed as a "Security holders document" on
      April 12, 2005.





53












**DEBT
      OF ENERPLUS**




The
      Fund may, with the approval of the board of directors of EnerMark, borrow,
      incur
      indebtedness, give any guarantee or enter into any subordination agreement
      on
      behalf of the Fund, or pledge or provide any security interest or encumbrance
      on
      any property of the Fund. At present, all indebtedness of Enerplus is incurred
      directly by its primary Operating Subsidiary, EnerMark. As at December 31,
      2005, EnerMark had senior debt facilities comprised of an $850 million bank
      credit facility (the " **Bank
      Credit Facility** ")
      and US$229 million of senior unsecured notes (the " **Senior
      Unsecured Notes** ")
      (collectively, the " **Credit
      Facilities** ").
      The Credit Facilities are the legal obligation of EnerMark and are guaranteed
      by
      the Fund's other material subsidiaries. Payments on the Credit Facilities have
      priority over payments to the Fund and over claims of and future distributions
      to unitholders. In the event of a breach or a default, or a failure to
      refinance, distributions from the Fund to unitholders may be reduced or
      suspended. However, unitholders have no direct liability with respect to the
      Credit Facilities.




**Bank
      Credit Facility**




The
      $850 million Bank Credit Facility is an unsecured, covenant-based three
      year committed credit agreement with nine North American banks. As at
      December 31, 2005, $329 million was outstanding under this facility.
      This bank debt carries floating interest rates that Enerplus expects to range
      between 60.0 and 115.0 basis points over bankers' acceptance rates,
      depending on Enerplus' ratio of Consolidated Senior Debt to Consolidated EBITDA
      (each as defined below).




In
      addition to the standard representations, warranties and covenants commonly
      contained in a credit facility of this nature, there are the following financial
      covenants:




•
            the
                ratio of Consolidated Senior Debt to Consolidated EBITDA at the end
                of any
                fiscal quarter shall not exceed 3:1, except that upon the completion
                of a
                Material Acquisition (as defined below), and for a period extending
                to the end of the second full quarter thereafter, this limit increases
                to
                3.5:1;




•
            the
                ratio of Consolidated Total Debt (as defined below) to Consolidated
                EBITDA at the end of any fiscal quarter shall not exceed 4:1;
                and




•
            the
                ratio of Consolidated Senior Debt to Total Capitalization (as defined
                below) shall not exceed 50%, except that upon the completion of a
                Material
                Acquisition, and for a period extending to the end of the second
                full
                quarter thereafter, this limit increases to
                55%.




With
      respect to these financial covenants, the following definitions apply to the
      Fund and its subsidiaries on a consolidated basis:





Consolidated
                EBITDA:
            The
                aggregate of the last four quarters' net income plus the sum
                of:•    interest
                expense;•    all
                provisions for federal, provincial or other income and capital
                taxes;•    depletion,
                depreciation, amortization and accretion; and•    other
                non-cash amounts.Consolidated
                Senior Debt:
            All
                indebtedness and obligations in respect of amounts borrowed excluding
                Subordinated Debt.Consolidated
                Total Debt:
            The
                aggregate of Consolidated Senior Debt and Subordinated
                Debt.Material
                Acquisition:
            An
                acquisition or series of acquisitions which increases the tangible
                assets
                of Enerplus by more than 5%.Subordinated
                Debt:
            Debt
                which, by its terms, is subordinated to the Bank Credit facility
                (but excludes convertible debentures which allow the Fund to issue
                Trust Units or other securities of the Fund in satisfaction of interest
                or
                principal).Total
                Capitalization:
            The
                aggregate of Consolidated Senior Debt and the Fund's unitholders'
                equity
                (calculated in accordance with GAAP as shown on the Fund's consolidated
                balance sheet).








54




**Senior
      Unsecured Notes**




Enerplus
      has issued twelve year (with a ten-year average life) Senior Unsecured Notes
      which total US$229 million through issuances of US$175 million on
      June 19, 2002 and US$54 million on October 1, 2003, as summarized
      below:





**Terms
                of Notes**
            **US$175 million**
            **US$54 million**Issued:
            June 19,
                2002
            October 1,
                2003Maturity:
            June 19,
                2014
            October 1,
                2015Coupon
                rate:
            6.62%
            5.46%Semi-annual
                interest paid yearly on:
            June 19
                and
              December 19
            April 1
                and
              October 1Principal
                payments in five annual equal instalments beginning:
            June 19,
                2010
            October 1,
                2011





In
      addition to standard representations, warranties and covenants, the Senior
      Unsecured Notes also contain the following key financial covenants:




•
            the
                ratio of Consolidated EBITDA (as defined below) for the four
                immediately preceding fiscal quarters to consolidated interest expense
                shall be not less than 4.0 to
                1.0;




•
            Consolidated
                Debt (as defined below) is limited to 60% of the present value of
                Enerplus' Proved Reserves (discounted at 10% and based on forecast
                prices
                and costs); and




•
            the
                ratio of Consolidated Debt to Consolidated EBITDA for each period
                of four
                consecutive fiscal quarters shall not exceed 3.0 to 1.0, but is
                permitted to be up to 3.5 to 1.0 for a maximum of six
                months.




For
      purposes of the above covenants, "Consolidated Debt" has the same meaning as
      "Consolidated Senior Debt" in the definitions relating to the Bank Credit
      Facility. "Consolidated EBITDA" is defined (with respect to the Fund and its
      subsidiaries on a consolidated basis) as the sum of: (i) net income
      determined in accordance to GAAP; (ii) all provisions for federal,
      provincial or other income and capital taxes; (iii) all provisions for
      depletion, depreciation, and amortization; and (iv) interest
      expense.




Concurrent
      with the issuance of the US$175,000,000 notes on June 19, 2002, Enerplus
      entered into a cross currency swap whereby the amount of the notes was fixed
      for
      purposes of interest and principal repayments at a notional CDN$268,328,000.
      Interest payments are made on a floating rate basis, set at the rate for three
      month Canadian bankers' acceptances, plus 1.18%.




Additional
      information regarding EnerMark's debt arrangements is contained in Note 8
      to the Fund's audited annual consolidated financial statements for the year
      ended December 31, 2005 and under the heading "Liquidity and Capital
      Resources" in Enerplus' management's discussion and analysis for the year ended
      December 31, 2005. Notwithstanding that it is unsecured, the indebtedness
      of Enerplus to its lenders and senior noteholders ranks senior to and is in
      priority to the royalty, interest, distribution and dividend payments that
      are
      made to the Fund by its Operating Subsidiaries, and therefore ahead of
      distributions from the Fund to its unitholders. See "Information Respecting
      Enerplus Resources Fund  - Description of the Royalty Agreements and
      Subordinated Notes" and "Risk Factors".





55







**DISTRIBUTIONS
      TO UNITHOLDERS**




Unitholders
      of record on a distribution record date are entitled to receive distributions
      which are paid by Enerplus to its unitholders on the corresponding distribution
      payment date. Enerplus has established the 10th day of each calendar month
      as a
      distribution record date with the 20th day of such month being the corresponding
      distribution payment date, with the exception of the January 20th payment
      date which is preceded by a distribution record date of December 31 of the
      prior year. Distributions to unitholders that are not resident in Canada may
      be
      subject to Canadian withholding tax.




**Distributable
      Income**




Although
      the Fund intends to make distributions of its available cash to unitholders,
      these cash distributions are not assured. The amount available to the Fund
      to
      pay distributions depends on the level of net cash flow received by the Fund
      from its Operating Subsidiaries pursuant to the royalty agreements and as
      interest, principal, dividend and distribution payments. Distributions for
      a
      period generally represent net cash flow of the Operating Subsidiaries from
      the
      period approximately two months prior to the period in which the distribution
      is made.




The
      amount of cash flow paid to the Fund from its Operating Subsidiaries, and the
      amount of cash distributions subsequently paid by the Fund to unitholders,
      depends on numerous factors including the Operating Subsidiaries' financial
      performance, debt covenants and obligations, working capital requirements and
      future capital requirements. Such amounts are, in part, subject to the
      discretion of the board of directors of EnerMark, which regularly evaluates
      the
      Fund's distribution payout with respect to anticipated cash flows, debt levels,
      capital expenditures plans and amounts to be retained to fund acquisitions
      and
      expenditures. In the past, the level of cash retained has typically varied
      between 10% and 40% of Enerplus' total annual cash flow. For the year ended
      December 31, 2005, approximately 36% of the cash available for distribution
      was retained.




The
      after-tax return from an investment in the Fund's Trust Units to unitholders
      subject to Canadian income tax can be made up of both a return on and a return
      of capital. That composition may change over time, thus affecting an investor's
      after-tax return. Returns on capital are generally taxed as ordinary income
      in
      the hands of a unitholder. Returns of capital are generally tax-deferred
      (and reduce the holder's cost base in the Trust Units for tax
      purposes).




An
      investment in the Trust Units is subject to a number of risks that should be
      considered by an investor. The market value of the Trust Units may deteriorate
      if the Fund is unable to meet its cash distribution targets in the future,
      and
      that deterioration may be material. See "Risk Factors".




**Distribution
      History**




The
      Fund may, on or before any distribution record date, declare payable to the
      unitholders all or any part of the distributable income of the Fund. See
      "Description of the Trust Units  - Distributions of
      Distributable Income."




The
      cash flow available for distribution can vary significantly from period to
      period for a number of reasons, including fluctuations in: (i) the sales
      price that Enerplus realizes for its oil and natural gas production (after
      hedging contract receipts and payments), (ii) the quantity of oil and
      natural gas that Enerplus produces, (iii) the cost to produce oil and
      natural gas and administer the Fund and its subsidiaries, (iv) the amount
      of cash retained for debt service or repayment or to fund capital expenditures,
      and (v) foreign currency exchange rates and interest rates. In addition,
      the level of distributions per Trust Unit will be affected by the number of
      outstanding Trust Units.





56




The
      following cash distributions have been paid or declared payable by Enerplus
      to
      its unitholders since the beginning of 2003:





**Month
                of Record and Payment Date**
            
            **2006**
            
            **2005**
            
            **2004**
            
            **2003**January(1)
            
            $
            0.42
            
            $
            0.35
            
            $
            0.35
            
            $
            0.30February
            
            
            0.42
            
            
            0.35
            
            
            0.35
            
            
            0.32March
            
            
            0.42
            
            
            0.35
            
            
            0.35
            
            
            0.35April
            
            
            N/A
            
            
            0.35
            
            
            0.35
            
            
            0.35May
            
            
            N/A
            
            
            0.35
            
            
            0.35
            
            
            0.37June
            
            
            N/A
            
            
            0.35
            
            
            0.35
            
            
            0.37July
            
            
            N/A
            
            
            0.35
            
            
            0.35
            
            
            0.37August
            
            
            N/A
            
            
            0.37
            
            
            0.35
            
            
            0.37September
            
            
            N/A
            
            
            0.37
            
            
            0.35
            
            
            0.37October
            
            
            N/A
            
            
            0.37
            
            
            0.35
            
            
            0.37November
            
            
            N/A
            
            
            0.42
            
            
            0.35
            
            
            0.35December
            
            
            N/A
            
            
            0.42
            
            
            0.35
            
            
            0.35


___________


Note:


(1)
            The
                record date for the distribution was December 31 of the prior
                year.




**The
      historical distribution payments described above may not be reflective of future
      distribution payments, which will be subject to review by the board of directors
      of EnerMark taking into account the prevailing circumstances at the relevant
      time. See "Risk Factors".**




**U.S. Tax
      Reporting Matters**




For
      U.S. tax reporting purposes, Enerplus believes that the Fund should be
      considered to be a corporation (but not a "passive foreign investment
      corporation") and that its Trust Units should be equity as determined under
      U.S. federal income tax principles.




Based
      upon the computation of current and accumulated earnings and profit in
      accordance with U.S. federal income tax principles, 93% of the
      distributions paid by the Fund during 2005 should be considered to be dividends.
      Under the Jobs and Growth Tax Relief Reconciliation Act of 2003 (P.L. 108-27,
      117 Stat. 752), the dividend portion of Enerplus' 2005 distributions should
      be considered "Qualified Dividends" eligible for the reduced rate of tax
      applicable to long term capital gains.




U.S. unitholders
      who received cash distributions were subject to at least a 15% Canadian
      withholding tax. The withholding tax is applied to both the taxable portion
      of
      the distribution as computed under Canadian tax law, and the non-taxable portion
      of the distribution. U.S. taxpayers may be eligible for a foreign tax
      credit with respect to Canadian withholding taxes paid.





57







**INDUSTRY
      CONDITIONS**




**Overview**




The
      oil and natural gas industry is subject to extensive controls and regulation
      governing its operations (including land tenure, exploration, development,
      production, refining, transportation and marketing) imposed by legislation
      enacted by various levels of government. The oil and natural gas industry is
      also subject to various agreements among the various federal, provincial and
      state governments with respect to pricing and taxation of oil and natural gas.
      Although it is not expected that any of these controls, regulations or
      agreements will affect Enerplus' operations in a manner materially different
      than they would affect other Canadian oil and gas issuers of similar size,
      the
      controls, regulations and agreements should be considered carefully by investors
      in the oil and gas industry. All current legislation is a matter of public
      record and Enerplus is unable to predict what additional legislation or
      amendments may be enacted. Outlined below are some of the principal aspects
      of
      legislation, regulations and agreements governing the oil and gas
      industry.




The
      discussion below focuses on the Canadian oil and natural gas industry
      (and particularly Alberta, where 83% of Enerplus' 2005 daily production
      occurred). In 2005, Enerplus acquired oil and natural gas properties and related
      assets in Montana and North Dakota in the United States. Enerplus'
      U.S. oil and natural gas operations are regulated by administrative
      agencies under statutory provisions of the states where such operations are
      conducted and by certain agencies of the federal government for operations
      on
      federal leases. These statutory provisions regulate matters such as the
      exploration for and production of crude oil and natural gas, including
      provisions related to permits for the drilling of wells, bonding requirements
      in
      order to drill or operate wells, the location of wells, the method of drilling
      and casing wells, the surface use and restoration of properties upon which
      wells
      are drilled, and the abandonment of wells. Enerplus' U.S. operations are
      also subject to various conservation laws and regulations which regulate matters
      such as the size of drilling and spacing units or proration units, the number
      of
      wells which may be drilled in an area, and the unitization or pooling of crude
      oil and natural gas properties. In addition, state conservation laws sometimes
      establish maximum rates of production from crude oil and natural gas wells,
      generally prohibit the venting or flaring of natural gas, and impose certain
      requirements regarding the ratability or fair apportionment of production from
      fields and individual wells.




Additionally,
      the regulatory scheme as it relates to oil sands is somewhat different from
      that
      related to oil and gas generally. In Alberta, the regulation of oil sands
      operations, pipelines, upgraders and cogeneration facilities is undertaken
      jointly by the Alberta Energy and Utilities Board (the " **EUB** ")
      pursuant to various statutes, including the *Oil
      Sands Conservation Act* (Alberta), and by Alberta Environment pursuant to Alberta's *Environmental
      Protection and Enhancement Act* .
      In addition to requiring certain approvals prior to the construction and
      operation of oil sands recovery projects, pipelines, upgraders and cogeneration
      facilities, the legislation allows the EUB to inspect and investigate and,
      where
      a practice employed or a facility used is hazardous to human health or the
      environment, to make remedial orders. Similar powers are available to the
      Alberta Environment. Certain changes to oil sands recovery operations,
      pipelines, upgraders and cogeneration facilities also require the approval
      of
      the EUB, the Alberta Environment, or both. The construction, operation,
      decommissioning and reclamation of facilities as part of a scheme to recover
      bitumen from oil sands, extract and upgrade products therefrom, and transport
      those products to market, may invoke regulation by the federal government under
      various federal statutes and regulations, including the *Canadian
      Environmental Assessment Act* ,
      the *Canadian
      Environmental Protection Act* (Canada), the *Fisheries
      Act* (Canada) and the *Navigable
      Waters Protection Act* (Canada). Certain approvals or authorizations may be needed prior to
      construction, operation or modification of facilities or operational practices.
      Inspections and investigations may result in remedial orders.




**Pricing
      and Marketing  - Oil**




Producers
      of oil negotiate sales contracts directly with oil purchasers, with the result
      that the market determines the price of oil. The price depends, in part, on
      oil
      type and quality, prices of competing fuels, distance to market, the value
      of
      refined products and the supply/demand balance and other contractual terms,
      as
      well as on the world price of oil. In Canada, oil exports may be made pursuant
      to export contracts with terms not exceeding one year in the case of light
      crude
      oil, and not exceeding two years in the case of heavy crude oil, provided that
      an order approving any such export has been obtained from the National Energy
      Board (the " **NEB** ").
      Any oil export to be made pursuant to a contract of longer duration (to a
      maximum of 25 years) requires an exporter to obtain an export licence from
      the NEB and the issue of such a licence requires the approval of the Governor
      in
      Council.





58







**Pricing
      and Marketing  - Natural Gas**




The
      price of natural gas sold in intraprovincial, interprovincial and international
      trade is determined by negotiation between buyers and sellers. The price
      depends, in part, on natural gas quality, prices of competing natural gas and
      other fuels, distance to market, access to downstream transportation, length
      of
      contract term, weather conditions, the value of refined products and the
      supply/demand balance and other contractual terms. Natural gas exported from
      Canada is subject to regulation by the NEB and the Government of Canada.
      Exporters are free to negotiate prices and other terms with purchasers, provided
      that the export contracts must continue to meet certain criteria prescribed
      by
      the NEB and the Government of Canada. Natural gas exports for a term of less
      than two years or for a term of two to 20 years (in quantities of not
      more than 30,000 cubic metres per day), must be made pursuant to an NEB
      order. Any natural gas export to be made pursuant to a contract of longer
      duration (to a maximum of 25 years) or a larger quantity requires an
      exporter to obtain an export licence from the NEB and the issue of such a
      licence requires the approval of the Governor in Council.




The
      governments of Alberta, British Columbia and Saskatchewan also regulate the
      volume of natural gas which may be removed from those provinces for consumption
      elsewhere, based on such factors as reserve availability, transportation
      arrangements and market considerations.




**The
      North American Free Trade Agreement ("NAFTA")**




On
      January 1, 1994, NAFTA became effective among the governments of Canada,
      the United States of America and Mexico. In the context of energy
      resources, Canada continues to remain free to determine whether exports to
      the
      United States or Mexico will be allowed, provided that any export
      restrictions do not: (i) reduce the proportion of energy resource exported
      relative to domestic use (based upon the proportion prevailing in the most
      recent 36 month period); (ii) impose an export price higher than the
      domestic price; and (iii) disrupt normal channels of supply. All three
      countries are generally prohibited from imposing minimum export or import price
      requirements and, except as permitted in the enforcement of countervailing
      and
      anti-dumping orders and undertakings, minimum or maximum import price
      requirements.




NAFTA
      contemplates the reduction of Mexican restrictive trade practices in the energy
      sector and prohibits discriminatory border restrictions and export taxes. NAFTA
      also contemplates clearer disciplines on regulators to ensure fair
      implementation of any regulatory changes and to minimize disruption of
      contractual arrangements, which is important for Canadian natural gas
      exports.




**Royalties
      and Incentives**




*General*




In
      addition to federal regulations, each province in Canada has legislation and
      regulations which govern land tenure, royalties, production rates, environmental
      protection and other matters. In all Canadian jurisdictions, producers of oil
      and natural gas are required to pay annual rental payments in respect of Crown
      leases, and royalties and freehold production taxes in respect of oil and
      natural gas produced from Crown and freehold lands, respectively. 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-owned
      lands are determined by negotiations between the freehold mineral owner and
      the
      lessee. Crown royalties are determined by government regulation and are
      generally calculated as a percentage of the value of the gross production.
      The
      rate of royalties payable generally depends in part on prescribed reference
      prices, well productivity, geographical location, field discovery date and
      the
      type or quality of the petroleum product produced. Other royalties and
      royalty-like interests are from time to time carved out of the working interest
      owner's interest through non-public transactions. These are often referred
      to as
      overriding royalties, gross overriding royalties or net profits or net carried
      interests.





59







From
      time to time, the federal and provincial governments in Canada have established
      incentive programs which have included royalty rate reductions (including for
      specific wells), royalty holidays and tax credits for the purpose of encouraging
      oil and natural gas exploration or enhanced planning projects, although the
      trend is toward eliminating these types of programs in favour of long term
      programs which enhance predictability for producers. If applicable, oil and
      natural gas royalty holidays and reductions would reduce the amount of Crown
      royalties paid by oil and gas producers to the provincial
      governments.




The
      Province of Alberta imposes royalties of varying rates on the production of
      crude oil from lands in which it owns the mineral rights. In Alberta, the amount
      payable to the Alberta government as a royalty in respect of oil depends on
      the
      type of oil, the vintage of the oil, the quantity of oil produced in a month
      and
      the value of the oil. The vintage of oil is determined based on various criteria
      set out in the regulations, but is generally broken down into three categories
      being old oil, new oil (applicable to oil pools discovered after March 31,
      1974 and prior to October 1, 1992) and third tier oil (which is oil
      produced from pools discovered after September 30, 1992). The royalty rate
      on old oil is between 10% and 35%, for new oil it is between 10% and 30%, and
      for third tier oil it is between 10% and 25%.




The
      royalty payable to the Alberta government in respect of natural gas is
      determined by a sliding scale based on a reference price (which is the greater
      of the amount obtained by the producer and a prescribed minimum price), the
      type
      of natural gas, the quantity produced in a given month and the vintage of the
      natural gas. The vintage of natural gas is based on various criteria set out
      in
      the regulations, but is generally determined based on when the natural gas
      pools
      were discovered and natural gas from such pools was recovered. As an incentive
      for the production and marketing of natural gas which may have been flared,
      the
      royalty rate on natural gas produced in association with oil is less than
      non-associated natural gas. The royalty payable on natural gas varies between
      15% and 30%, in the case of new natural gas, and between 15% and 35%, in the
      case of old natural gas. Natural gas produced from qualifying exploratory
      natural gas wells spudded or deepened after July 31, 1985 and before
      June 1, 1988 is eligible for a royalty exemption for a period of
      12 months, up to a prescribed maximum amount. Natural gas produced from
      qualifying intervals in eligible natural gas wells spudded or deepened to a
      depth below 2,500 meters is also subject to a royalty exemption, the amount
      of which depends on the depth of the well.




Alberta's
      current royalty system for oil sands, introduced in 1997 and expiring
      June 30, 2007, is designed to support the development of the oil sands
      industry. An initial royalty of 1% of the quantity of oil sands product that
      is
      recovered and delivered to the royalty calculation point is payable until the
      owners have recovered specified allowed costs, including certain exploration
      and
      development costs, operating costs, a return allowance (based on the monthly
      federal long-term bond rate) and royalties paid to the Crown. Subsequent to
      such
      recovery, the royalty payable is the greater of the aforesaid 1% royalty and
      25%
      of net revenue from an oil sands project. The foregoing royalty will approximate
      a 1% royalty on gross revenue before payout and a 25% royalty on net revenue
      after payout.




**Land
      Tenure**




Crude
      oil and natural gas located in the western Canadian provinces is owned
      predominantly by the respective provincial governments. Provincial governments
      grant rights to explore for and produce oil and natural gas pursuant to leases,
      licences and permits for varying periods and on conditions set forth in
      provincial legislation including requirements to perform specific work or make
      payments. Oil and natural gas located in such provinces can also be privately
      owned and rights to explore for and produce such oil and natural gas are granted
      by lease on such terms and conditions as may be negotiated.




Oil
      produced from oil sands owned by the Province of Alberta is produced under
      provincial Crown oil sands leases. While such leases may historically have
      had
      initial terms which varied in length, continuations beyond the initial terms
      are
      now subject to standardized criteria as provided for in the *Oil
      Sands Tenure Regulation* (Alberta). A lease may generally be continued after the initial term provided
      certain minimum levels of exploration or production have been achieved and
      all
      lease rentals (including escalating rentals) have been timely paid, subject
      to
      certain exceptions. The surface rights required for pipelines, upgraders and
      co-generation facilities are generally governed by leases, easements,
      rights-of-way, permits or licenses granted by landowners or governmental
      authorities.





60







**Environmental
      Regulation**




The
      oil and natural gas industry is currently subject to environmental regulation
      pursuant to provincial and federal legislation. Environmental legislation
      provides for restrictions and prohibitions on releases or emissions of various
      substances produced or utilized in association with certain oil and gas industry
      operations. In addition, legislation requires that well, pipeline and facility
      sites be abandoned and reclaimed to the satisfaction of provincial authorities.
      As well, applicable environmental laws may impose remediation obligations with
      respect to a property designated as a contaminated site upon certain responsible
      persons, which include persons responsible for the substance causing the
      contamination, persons who caused release of the substance and any past or
      present owner, tenant or other person in possession of the site. Compliance
      with
      such legislation can require significant expenditures. A breach of such
      legislation may result in the imposition of material fines and penalties, the
      suspension or revocation of necessary licenses and authorizations, civil
      liability for pollution damage or the issuance of clean-up orders.




In
      Alberta, environmental compliance is governed by the *Environmental
      Protection and Enhancement Act* (Alberta) (the " **EPEA** ")
      and the *Oil
      and Gas Conservation Act* (Alberta), both of which impose certain environmental responsibilities on oil
      and natural gas operators and working interest holders in Alberta and impose
      penalties for violations. The EPEA also imposes certain environmental
      responsibilities on the operators of oil sands in-situ extraction projects,
      pipelines, upgraders and cogeneration plants. In certain instances EPEA imposes
      significant penalties for violations. In Saskatchewan, environmental compliance
      is governed by the *Environmental
      Management and Protection Act* (Saskatchewan) and the *Oil
      and Gas Conservation Act* (Saskatchewan). In British Columbia, energy projects may be subject to review
      pursuant to the provisions of the *Environmental
      Assessment Act* (British Columbia), which rolls the previous processes for the review of major
      energy projects into a single environmental assessment process that contemplates
      public participation in the environmental review.




In
      1994, the United Nations' Framework Convention on Climate Change came into
      force
      and three years later led to the Kyoto Protocol which requires participating
      countries, upon ratification, to reduce their emissions of carbon dioxide and
      other greenhouse gases. Canada ratified the Kyoto Protocol in late 2002. The
      upstream Canadian oil and gas sector is in discussions with various federal
      and
      provincial levels of government regarding the development of green house gas
      regulations for the industry. Although the Canadian federal government has
      not
      released details of any implementation plan, it has stated that it intends
      to
      limit the emission reduction targets for the industry and regulate the cost
      of
      emission credits, which could result in increased capital expenditures and
      operating costs. However, until an implementation plan is developed, it is
      impossible to assess the impact on specific industries and any individual
      businesses within an industry. See "Risk Factors  - Risks Related to
      Enerplus' Business and Operations  - Enerplus' operation of oil and natural
      gas wells could subject it to environmental claims and liability".




Enerplus
      believes that it is, and intends to continue to be, in material compliance
      with
      applicable environmental laws and regulations and is committed to meeting its
      responsibilities to protect the environment wherever it operates or holds
      working interests. Enerplus anticipates that this compliance may result in
      increased expenditures of both a capital and expense nature as a result of
      increasingly stringent laws relating to the protection of the environment.
      Enerplus believes that it is reasonably likely that the trend in environmental
      legislation and regulation will continue toward stricter standards.




**Worker
      Safety**




Oilfield
      operations must be carried out in accordance with safe work procedures, rules
      and policies contained in provincial safety legislation. Such legislation
      requires that every employer ensures the health and safety of all persons at
      any
      of its work sites and all workers engaged in the work of that employer, and
      that
      every employer ensure that all of its employees are aware of their duties and
      responsibilities under the applicable legislation. Such legislation also
      provides for accident reporting procedures.





61







**RISK
      FACTORS**




Trust
      Units are inherently different from capital stock of a corporation, although
      many of the business risks to which Enerplus is subject are similar to those
      that would be faced by a corporation engaged in the oil and gas business.
      Prospective investors should carefully consider the following risk factors,
      together with other information contained in this Annual Information Form and
      the information incorporated by reference, before investing in the Trust Units.
      The following risk factors have been organized into separate sections dealing
      with risks related to Enerplus' business and operations, risks relating to
      ownership of the Trust Units and Enerplus' structure and risks specifically
      applicable to Unitholders who are not residents of Canada.




**Risks
      Related to Enerplus' Business and Operations**




***Volatility
      in oil and natural gas prices could have a material adverse effect on Enerplus'
      results of operations and financial condition which, in turn, could affect
      the
      market price of Trust Units and the amount of distributions to
      unitholders.***




Enerplus'
      results of operations and financial condition are dependent on the prices it
      receives for the oil and natural gas it sells. Oil and natural gas prices have
      fluctuated widely during recent years and are likely to continue to be volatile
      in the future. Oil and natural gas prices may fluctuate in response to a variety
      of factors beyond Enerplus' control, including:




•
            global
                energy policy, including the ability of OPEC to set and maintain
                production levels and
                prices for oil;




•
            political
                conditions, including the risk of hostilities in the Middle East
                and
                global terrorism;




•
            currency
                fluctuations;




•
            global
                and domestic economic conditions;




•
            weather
                conditions;




•
            the
                supply and price of imported oil and liquefied natural
                gas;




•
            the
                production and storage levels of North American natural
                gas;




•
            the
                level of consumer demand;




•
            the
                price and availability of alternative
                fuels;




•
            the
                proximity of reserves to, and capacity of, transportation
                facilities;




•
            the
                effect of world-wide energy conservation measures;
                and




•
            government
                regulations.




Any
      decline in crude oil or natural gas prices may have a material adverse effect
      on
      Enerplus' operations, financial condition, borrowing ability, reserves and
      the
      level of expenditures for the development of Enerplus' oil and natural gas
      reserves. Any resulting decline in Enerplus' cash flow could reduce
      distributions paid to the Fund's unitholders.




Enerplus
      may use financial derivative instruments and other hedging mechanisms to try
      to
      limit a portion of the adverse effects resulting from volatility in natural
      gas
      and oil commodity prices. To the extent Enerplus hedges its commodity price
      exposure, it may forego the benefits it would otherwise experience if commodity
      prices were to increase. In addition, Enerplus' commodity hedging activities
      could expose it to losses. These losses could occur under various circumstances,
      including if the other party to Enerplus' hedge does not perform its obligations
      under the hedge agreement.





62







***An
      increase in operating costs or a decline in Enerplus' production level could
      have a material adverse effect on results of operations and financial condition
      and, therefore, could reduce distributions to
      unitholders.***




Higher
      operating costs for the underlying properties of Enerplus will directly decrease
      the amount of cash flow received by the Fund and, therefore, may reduce
      distributions to Enerplus' unitholders. Electricity, chemicals, supplies,
      reclamation and abandonment and labour costs are a few of Enerplus' operating
      costs that are susceptible to material fluctuation.




The
      level of production from Enerplus' existing properties may decline at rates
      greater than anticipated due to unforeseen circumstances, many of which are
      beyond Enerplus' control. A significant decline in production could result
      in
      materially lower revenues and cash flow and, therefore, could reduce the amount
      available for distributions to unitholders.




***Enerplus'
      distributions may be reduced during periods in which it makes capital
      expenditures or debt repayments using cash flow.***




To
      the extent that Enerplus uses cash flow from its Operating Subsidiaries to
      finance acquisitions, development costs and other significant capital
      expenditures, the net cash flow that the Fund receives will be reduced. Hence,
      the timing and amount of capital expenditures may affect the amount of net
      cash
      flow received by the Fund and, as a consequence, the amount of cash available
      to
      distribute to Enerplus' unitholders. To the extent that external sources of
      capital, including the issuance of additional Trust Units, becomes limited
      or
      unavailable, Enerplus' ability to make the necessary capital investments to
      maintain or expand its oil and gas reserves and to invest in assets, as the
      case
      may be, will be impaired. To the extent that Enerplus is required to use cash
      flow to finance capital expenditures, property acquisitions or asset
      acquisitions, as the case may be, the level of its distributable income will
      be
      reduced or even eliminated.




The
      board of directors of EnerMark has the discretion to determine the extent to
      which cash flow from the Fund's Operating Subsidiaries will be allocated to
      the
      payment of debt service charges as well as the repayment of outstanding debt.
      Funds used for such purposes will not be payable to the Fund. As a consequence,
      the amount of funds retained by the Fund's Operating Subsidiaries to pay debt
      service charges or reduce debt will reduce the amount of cash distributed to
      the
      Fund's unitholders during those periods in which funds are so retained. In
      addition, variations in interest rates and scheduled principal repayments,
      if
      required under the terms of banking agreements, could result in significant
      changes in the amount required to be applied to debt service before payment
      of
      any amounts by the Operating Subsidiaries to the Fund. Certain covenants in
      agreements with lenders may also limit payments by these subsidiaries to the
      Fund. Although lines of credit are believed to be sufficient, there can be
      no
      assurance that the amount will be adequate for the financial obligations of
      Enerplus or that additional funds can be obtained. Furthermore, if the Fund's
      Operating Subsidiaries are unable to pay their debt service charges or otherwise
      commit an event of default such as bankruptcy, lenders may rank senior to
      securities or royalties of the operating companies which are held by the Fund,
      which will result in a decrease of the amount of cash paid to the Fund and
      subsequently distributed from the Fund to its unitholders.




The
      retention of cash flow in the Operating Subsidiaries of the Fund to finance
      capital expenditures or debt repayments may result in current income taxes
      being
      incurred by the Canadian Operating Subsidiaries and/or increased incomes taxes
      payable by the U.S. Operating Subsidiary. Payment of cash income taxes may
      in turn reduce the cash distribution made by the Fund to
      unitholders.




A
      return on an investment in the Fund is not comparable to the return on an
      investment in a fixed-income security. The recovery of an initial investment
      in
      the Fund is at risk, and the anticipated return on such investment is based
      on
      many performance assumptions. Although the Fund intends to make distributions
      of
      its available cash to unitholders of the Fund, these cash distributions may
      be
      reduced or suspended. Cash distributions are not guaranteed. The actual amount
      distributed will depend on numerous factors including: the financial performance
      of the Operating Subsidiaries of the Fund, debt obligations, commodity prices,
      production levels, working capital requirements, future capital requirements,
      applicable law and other factors beyond the control of the Fund. In addition,
      the market value of the Fund's Trust Units may decline if the Fund's cash
      distributions decline in the future, and that decline may be
      material.





63







***Fluctuations
      in foreign currency exchange rates could adversely affect Enerplus'
      business.***




The
      price that Enerplus receives for a majority of its oil and natural gas is based
      on United States dollar denominated benchmarks, and therefore the price
      that Enerplus receives in Canadian dollars is affected by the exchange rate
      between the two currencies. A material increase in the value of the Canadian
      dollar relative to the United States dollar may negatively impact Enerplus'
      net production revenue by decreasing the Canadian dollars Enerplus receives
      for
      a given sale in United States dollars. Currently, Enerplus does not engage
      in significant risk management activities related to foreign exchange rates,
      with the exception of the cross-currency swap associated with the
      US$175 million of senior unsecured notes issued by EnerMark in
      June 2002, as described in Note 8(b) to the Fund's audited
      consolidated financial statements for the year ended
      December 31, 2005.




***If
      Enerplus is unable to add additional reserves, the value of the Trust Units
      and
      the Fund's distributions to unitholders would be expected to
      decline.***




Enerplus
      adds to its oil and natural gas reserves primarily through acquisitions and
      ongoing development, together with certain exploration activities. As a result,
      Enerplus' future oil and natural gas reserves are highly dependent on its
      success in exploiting its reserve base and acquiring additional reserves.
      Exploitation and development risks arise for Enerplus and, as a result, may
      affect the value of the Trust Units and distributions to unitholders due to
      the
      uncertain results of searching for and producing oil and natural gas using
      imperfect scientific methods. Enerplus also has historically distributed the
      majority of its net cash flow to unitholders rather than reinvest it in reserve
      additions. Therefore, if capital from external sources is not available on
      commercially reasonable terms, Enerplus' ability to make the necessary capital
      investments to maintain or expand its oil and natural gas reserves will be
      impaired. Even if the necessary capital is available, Enerplus cannot assure
      prospective investors that it will be successful in acquiring additional
      reserves on terms that meet its investment objectives. Without these reserve
      additions, Enerplus' reserves will deplete and, as a consequence, either its
      production or the average life of its reserves will decline. Either decline
      may
      result in a reduction in the value of the Trust Units and in a reduction in
      cash
      available for distribution to the Fund's unitholders.




***Enerplus'
      actual reserves will vary from its reserve estimates, and those variations
      could
      be material.***




The
      value of the Trust Units depends upon, among other things, the reserves
      attributable to Enerplus' properties. Estimating reserves is inherently
      uncertain. Ultimately, actual reserves attributable to Enerplus' properties
      will
      vary from estimates, and those variations may be material. The reserve
      information contained in this Annual Information Form is only an estimate.
      A
      number of factors are considered and a number of assumptions are made when
      estimating reserves. These factors and assumptions include, among
      others:




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




•
            future
                commodity prices, production and development costs, royalties and
                capital
                expenditures;




•
            initial
                production rates;




•
            production
                decline rates;




•
            ultimate
                recovery of reserves;




•
            success
                of future exploitation activities;




•
            marketability
                of production;




•
            effects
                of government regulation; and




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




Reserve
      estimates are based on the relevant factors, assumptions and prices on the
      date
      the evaluations were prepared. Many of these factors are subject to change
      and
      are beyond Enerplus' control. If these factors, assumptions and prices prove
      to
      be inaccurate, Enerplus' actual reserves could vary materially from its reserve
      estimates. Additionally, all such estimates are, to some degree, uncertain
      and
      classifications of reserves are only attempts to define the degree of
      uncertainty involved. For these reasons, estimates of the economically
      recoverable quantities of oil and natural gas, the classification of such
      reserves based on risk of recovery and estimates of future net revenues expected
      therefrom, prepared by different engineers or by the same engineers at different
      times, may vary substantially.





64







Estimates
      with respect to reserves that may be developed and produced in the future
      (particularly oil sands reserves) are often based upon volumetric calculations
      and upon analogy to similar types of reserves, rather than upon actual
      production history. Estimates based on these methods generally are less reliable
      than those based on actual production history. Subsequent evaluation of the
      same
      reserves based upon production history may result in variations in the estimated
      reserves.




Reserve
      estimates may require revision based on actual production experience. Such
      figures have been determined based upon assumed oil, natural gas and NGLs prices
      and operating costs. Market price fluctuations of commodity prices may render
      uneconomic the recovery of certain categories of petroleum or natural gas or
      grades of bitumen. Moreover, short term factors relating to oil sands resources
      may impair the profitability of the Joslyn Project in any particular period.
      No
      assurance can be provided as to the gravity or quality of bitumen produced
      from
      the Joslyn Project.




***The
      recovery of bitumen and heavy oil using the SAGD process is subject to
      uncertainty.***




The
      SAGD process has had limited production history in commercial projects. Although
      Deer Creek and Enerplus are conducting a SAGD pilot test on the Joslyn Lease,
      there can be no assurance that the Joslyn Project will achieve the same or
      similar results as the pilot project or produce bitumen and heavy oil at the
      expected levels or costs, on schedule or at all.




***When
      making acquisitions, Enerplus forms estimates of future performance of the
      assets to be acquired that may prove to be
      inaccurate.***




When
      acquiring assets, Enerplus is subject to inherent risks associated with
      predicting the future performance of those assets. Enerplus makes certain
      estimates and assumptions respecting the prospectivity and characteristics
      of
      the assets it acquires which may not be realized over time. As such, assets
      acquired may not possess the value Enerplus attributed to them, which could
      adversely impact Enerplus' cash flows and distributions to its
      unitholders.




An
      initial assessment of an acquisition may be based on a report by engineers
      or
      firms of engineers that have different evaluation methods, approaches and
      assumptions than those of Enerplus' engineers, and these initial assessments
      may
      differ significantly from Enerplus' subsequent assessments.




***Since
      many of Enerplus' properties are not operated by Enerplus, results of operations
      may be adversely affected by the failure of third-party
      operators.***




The
      continuing production from a property, and to some extent the marketing of
      that
      production, is dependent upon the ability of the operators of Enerplus'
      properties. As of the date of this Annual Information Form, approximately 35%
      of
      Enerplus' daily production is from properties operated by third parties. To
      the
      extent a third-party operator fails to perform these duties properly or becomes
      insolvent, Enerplus' cash flow may be reduced. Third party operators also make
      estimates of future capital expenditures more difficult.




Further,
      the operating agreements governing the properties not operated by Enerplus
      typically require the operator to conduct operations in a good and "workmanlike"
      manner. These operating agreements generally provide, however, that the operator
      has no liability to the other non-operating working interest owners for losses
      sustained or liabilities incurred, except for liabilities that may result from
      gross negligence or wilful misconduct.




The
      Joslyn Project is operated by Deer Creek, and accordingly the future success
      of
      that Project is highly dependent on the strategies, operations and management
      of
      Deer Creek. The Joslyn Project is also subject to the risk that Deer Creek
      may
      change its business strategies and determine not to proceed with future phases
      of the Joslyn Project or may not generate sufficient financing to proceed with
      the Project. Enerplus will be subject to the risk of default by Deer Creek
      in
      meeting its obligations to pay its proportionate share of expenditures of the
      Joslyn Project. Such default by Deer Creek may adversely affect the continuation
      of the Project, the construction or operations of the Project or other facets
      of
      the Project, any of which may adversely affect Enerplus.





65







***Enerplus'
      indebtedness may limit the timing or amount of the distributions that the Fund
      pays to unitholders.***




The
      payments of interest and principal with respect to Enerplus' indebtedness ranks
      ahead of payments of cash from Enerplus' Operating Subsidiaries to the Fund
      and
      therefore reduces amounts available for distribution from the Fund to
      unitholders. Enerplus has an unsecured credit facility available to it at
      variable interest rates. In addition, Enerplus has swapped US$175 million
      of its U.S. dollar denominated senior unsecured notes with fixed interest
      rates into Canadian dollar denominated floating rate debt. Variations in
      interest rates and scheduled principal repayments could result in significant
      changes to the amount of the cash flows required to be applied by the Operating
      Subsidiaries to their debt before payment of any amounts by them to the Fund.
      The agreements governing this credit facility and the senior unsecured notes
      each stipulate that if Enerplus is in default or fails to comply with certain
      covenants, the Fund's ability to make distributions to unitholders may be
      restricted. In addition, the Fund's right to receive payments from its Operating
      Subsidiaries is expressly subordinated to the rights of the lenders under the
      credit facility and the holders of the senior unsecured notes. See "Debt of
      Enerplus".




***Enerplus'
      credit facility and any replacement credit facility may not provide sufficient
      liquidity.***




The
      amounts available under Enerplus' credit facility may not be sufficient for
      future operations, or Enerplus may not be able to obtain additional financing
      on
      attractive economic terms, if at all. Enerplus' credit facility is available
      on
      a three year term, extendable each year with a bullet payment required at the
      end of three years if the facility is not renewed. If this occurs, Enerplus
      may
      need to obtain alternate financing. Additionally, Enerplus must repay principal
      in five equal annual instalments on approximately $268.3 million of senior
      notes commencing June 19, 2010 and on US$54.0 million of senior notes
      commencing October 1, 2011. See "Debt of Enerplus". Any failure to obtain
      replacement financing, or financing on favourable terms, may have a material
      adverse effect on Enerplus' business, and distributions to unitholders may
      be
      materially reduced or eliminated, as repayment of such debt has priority over
      the payment of cash from the Operating Subsidiaries to the Fund, and as a
      result, from the Fund to unitholders.




***The
      Joslyn Project is in the early development stage and is subject to numerous
      risks.***




The
      Joslyn Project is currently in the development stage. There is a risk that
      the
      Joslyn Project will not be completed on time or on budget or at all.
      Additionally, there is a risk that the Joslyn Project may have delays,
      interruption of operations or increased costs due to many factors, including,
      without limitation:




•
            breakdown
                or failure of equipment or
                processes;




•
            construction
                performance falling below expected levels of output or
                efficiency;




•
            design
                errors;




•
            contractor
                or operator errors;




•
            non-performance
                by third-party designers, contractors and suppliers or failure of
                third
                parties to construct the infrastructure required for the Joslyn Project
                to
                successfully proceed;




•
            labour
                disputes, disruptions or declines in
                productivity;




•
            increases
                in materials or labour costs;




•
            inability
                to attract sufficient numbers of qualified
                workers;




•
            delays
                in obtaining, or conditions imposed by, regulatory
                approvals;




•
            changes
                in Project scope;




•
            violation
                of permit requirements;




•
            disruption
                in the supply of energy;





66







•
            availability
                of drilling rigs and services;




•
            catastrophic
                events such as fires, earthquakes, storms or explosions;
                and




•
            challenges
                to the proprietary technology of Deer Creek and/or its
                affiliates.




Given
      the stage of development of the Joslyn Project, various changes to the Project
      may be made by Deer Creek during implementation of or prior to completing the
      Project. The information contained in this Annual Information Form regarding
      the
      Joslyn Project, including, without limitation, reserve and economic evaluations
      is conditional upon receipt of all regulatory approvals, no material changes
      being made to the Joslyn Project or its scope and the overall continuation
      of
      the Project as currently planned.




The
      current construction and operations schedules may not proceed as planned, there
      may be delays and the Joslyn Project may not be completed on budget. Any such
      delays will likely increase the costs of the Joslyn Project and may require
      additional financing, which may not be available or may only be available on
      unfavourable terms.




***Enerplus
      may be unable to compete successfully with other organizations in the oil and
      natural gas industry.***




The
      oil and natural gas industry is highly competitive. Enerplus competes for
      capital, acquisitions of reserves, undeveloped lands, skilled personnel, access
      to drilling rigs, service rigs and other equipment, access to processing
      facilities, pipeline and refining capacity and in many other respects with
      a
      substantial number of other organizations, many of which may have greater
      technical and financial resources than Enerplus. Some of these organizations
      not
      only explore for, develop and produce oil and natural gas but also conduct
      refining operations and market oil and other products on a world-wide basis.
      As
      a result of these complementary activities, some of Enerplus' competitors may
      have greater and more diverse competitive resources to draw upon.




***Enerplus'
      operation of oil and natural gas wells could subject it to environmental claims
      and liability.***




The
      oil and natural gas industry is subject to extensive environmental regulation
      pursuant to local, provincial and federal legislation. A breach of that
      legislation may result in the imposition of fines or the issuance of "clean
      up"
      orders. Legislation regulating Enerplus' industry may be changed to impose
      higher standards and potentially more costly obligations. For example, the
      1997
      Kyoto Protocol to the United Nations Framework Convention on Climate Change,
      known as the Kyoto Protocol, which would require (among other things)
      significant reductions in greenhouse gas emissions, was ratified by Canada
      in
      late 2002. Although the implications are unknown at this time as specified
      measures for meeting Canada's commitments have not yet been developed, the
      Kyoto
      Protocol may result in additional costs for oil and natural gas producers such
      as Enerplus. See "Industry Conditions  - Environmental
      Regulation".




Enerplus
      is not fully insured against certain environmental risks, either because such
      insurance is not available or because of high premium costs. In particular,
      insurance against risks from environmental pollution occurring over time
      (as opposed to sudden and catastrophic damages) is not available on
      economically reasonable terms. Accordingly, Enerplus' properties may be subject
      to liability due to hazards that cannot be insured against, or that have not
      been insured against due to prohibitive premium costs or for other
      reasons.




Enerplus
      does not establish a separate reclamation fund for the purpose of funding its
      estimated future environmental and reclamation obligations. Enerplus cannot
      assure prospective investors that it will be able to satisfy its future
      environmental and reclamation obligations. Any site reclamation or abandonment
      costs incurred in the ordinary course, in a specific period, will be funded
      out
      of cash flows and, therefore, will reduce the amounts available for distribution
      to unitholders. Should Enerplus be unable to fully fund the cost of remedying
      an
      environmental claim, Enerplus might be required to suspend operations or enter
      into interim compliance measures pending completion of the required
      remedy.





67







***Enerplus'
      operations are subject to changes in government regulations and obtaining
      required regulatory approvals.***




The
      oil and gas industry operates under federal, provincial, state and municipal
      legislation and regulation governing such matters as land tenure, prices,
      royalties, production rates, environmental protection controls, income, the
      exportation of crude oil, natural gas and other products, as well as other
      matters. The industry is also subject to regulation by governments in such
      matters as the awarding or acquisition of exploration and production rights,
      oil
      sands or other interests (including the terms and conditions relating to the
      Joslyn Lease and Joslyn Project), the imposition of specific drilling
      obligations, environmental protection controls, control over the development
      and
      abandonment of fields and mine sites (including restrictions on production),
      and
      possibly expropriation or cancellation of contract rights. See "Industry
      Conditions".




Government
      regulations may be changed from time to time in response to economic or
      political conditions. The exercise of discretion by governmental authorities
      under existing regulations, the implementation of new regulations or the
      modification of existing regulations affecting the crude oil and natural gas
      industry could reduce demand for crude oil and natural gas, increase Enerplus'
      costs and have a material adverse impact on Enerplus.




***A
      decline in Enerplus' ability to market oil and natural gas production could
      have
      a material adverse effect on its production levels or on the price that Enerplus
      receives for production which, in turn, could reduce distributions to its
      unitholders.***




Enerplus'
      business depends in part upon the availability, proximity and capacity of
      natural gas gathering systems, pipelines and processing facilities. Canadian
      federal and provincial, as well as United States federal and state,
      regulation of oil and gas production, processing and transportation, tax and
      energy policies, general economic conditions, and changes in supply and demand
      could adversely affect Enerplus' ability to produce and market oil and natural
      gas. If market factors change and inhibit the marketing of Enerplus' production,
      overall production or realized prices may decline, which could reduce
      distributions to unitholders.




***If
      Enerplus expands beyond its current areas of operations or expands the scope
      of
      operations beyond oil and natural gas production, Enerplus may face new
      challenges and risks. If Enerplus is unsuccessful in managing these challenges
      and risks, its results of operations and financial condition could be adversely
      affected.***




Enerplus'
      operations and expertise are currently focused on conventional oil and natural
      gas and coalbed methane production and development in the Western Canadian
      Sedimentary Basin and the northern United States, together with its
      participation in the development of oil sands reserves in the Joslyn Project.
      In
      the future, Enerplus may acquire oil and natural gas properties and assets
      outside this geographic area. In addition, the Trust Indenture does not limit
      Enerplus' activities to oil and natural gas production and development, and
      Enerplus could acquire other energy related assets, such as oil and natural
      gas
      processing plants or pipelines. Expansion of Enerplus' activities into new
      areas
      may present challenges and risks that it has not faced in the past, including
      dealing with additional regulatory matters. If Enerplus does not manage these
      challenges and risks successfully, its results of operations and financial
      condition could be adversely affected.





68





***Delays
      in business operations could adversely affect the Fund's distributions to
      unitholders.***




In
      addition to the usual delays in payment by purchasers of oil and natural gas
      to
      the operators of Enerplus' properties, and the delays of those operators in
      remitting payment to Enerplus, payments between any of these parties may also
      be
      delayed by:




•
            restrictions
                imposed by lenders;




•
            accounting
                delays;




•
            delays
                in the sale or delivery of
                products;




•
            delays
                in the connection wells to a gathering
                system;




•
            blowouts
                or other accidents;




•
            adjustments
                for prior periods;




•
            recovery
                by the operator of expenses incurred in the operation of the properties;
                or




•
            the
                establishment by the operator of reserves for these
                expenses.




Any
      of these delays could reduce the amount of cash available for distribution
      to
      Enerplus' unitholders in a given period and expose Enerplus to additional third
      party credit risks.




***The
      industry in which Enerplus operates exposes Enerplus to potential liabilities
      that may not be covered by insurance.***




Enerplus'
      operations are subject to all of the risks normally associated with the
      operation and development of oil and natural gas properties, including the
      drilling of oil and natural gas wells and the production and transportation
      of
      oil and natural gas. These risks and hazards include encountering unexpected
      formations or pressures, blow-outs, craterings and fires, all of which could
      result in personal injury, loss of life or environmental and other damage to
      Enerplus' property and the property of others. Enerplus cannot fully protect
      against all of these risks, nor are all of these risks insurable. Enerplus
      may
      become liable for damages arising from these events against which it cannot
      insure or against which it may elect not to insure because of high premium
      costs
      or other reasons. While Enerplus has both safety and environmental policies
      in
      place to protect its operators and employees and to meet regulatory requirements
      in areas where they operate, any costs incurred to repair damages or pay
      liabilities would reduce funds available for distribution to the Fund's
      unitholders.




***The
      loss of Enerplus' key management and other personnel could impact its
      business.***




Unitholders
      are entirely dependent on the management of Enerplus with respect to the
      acquisition of oil and natural gas properties and assets, the development and
      acquisition of additional reserves, the management and administration of all
      matters relating to Enerplus' properties and the administration of the Fund.
      Current high commodity prices coupled with a lack of qualified personnel in
      certain disciplines has created challenges for Enerplus in terms of recruiting
      and retaining key personnel. The loss of the services of key individuals could
      have a detrimental effect on the Fund. Investors should carefully consider
      whether they are willing to rely on the management of Enerplus before investing
      in the Trust Units.




***Conflicts
      of interest may arise between Enerplus and its directors and
      officers.***




Circumstances
      may arise where directors and officers of Enerplus are directors or officers
      of
      corporations or other entities involved in the oil and gas industry which are
      in
      competition to the interests of Enerplus. No assurances can be given that
      opportunities identified by such persons will be provided to
      Enerplus.




***Lower
      oil and gas prices increase the risk of write-downs of Enerplus' oil and gas
      property investments.***




Under
      Canadian accounting rules, the net capitalized cost of oil and gas properties
      may not exceed a "ceiling limit" that is based, in part, upon estimated future
      net cash flows from reserves. If the net capitalized costs exceed this limit,
      Enerplus must charge the amount of the excess against earnings. If oil and
      natural gas prices decline, Enerplus' net capitalized cost may exceed this
      ceiling, ultimately resulting in a charge against its earnings. While these
      write-downs would not affect cash flow, the charge to earnings could be viewed
      unfavourably in the market.





69





***Unforeseen
      title defects may result in a loss of entitlement to production and
      reserves.***




From
      time to time, Enerplus conducts title reviews in accordance with industry
      practice prior to purchases of resource assets. However, if conducted, these
      reviews do not guarantee that an unforeseen defect in the chain of title will
      not arise and defeat Enerplus' title to the purchased assets. If this type
      of
      defect were to occur, Enerplus' entitlement to the production and reserves
      from
      the purchased assets could be jeopardized and, as a result, distributions to
      unitholders may be reduced.




**Risks
      Related to Enerplus' Structure and the Ownership of the Trust
      Units**




***Changes
      in tax and other laws may adversely affect
      unitholders.***




Income
      tax laws, or other laws or government incentive programs relating to the oil
      and
      gas industry, such as the treatment of mutual fund trusts and resource
      allowance, may in the future be changed or interpreted in a manner that
      adversely affects the Fund and its unitholders. Additionally, tax laws and
      tax
      treaties in foreign countries in which Enerplus operates or has financing
      structures may be changed or interpreted in a manner which is detrimental to
      Enerplus' operations and financial structure, and therefore the
      unitholders.




In
      particular, generally speaking, the Tax Act provides that a trust will
      permanently lose its "mutual fund trust" status (which is essential to the
      income trust structure) if it is established or maintained primarily for the
      benefit of non-residents of Canada (which is generally interpreted to mean
      that
      the majority of unitholders must not be non-residents of Canada), unless at
      all
      times after February 21, 1990, "all or substantially all" of the trust's
      property consisted of property other than taxable Canadian property
      (the " **TCP
      Exception** ").
      Based on the most recent information obtained by Enerplus through its transfer
      agent and financial intermediaries, in February 2006 an estimated 73% of
      the Fund's issued and outstanding Trust Units were held by non-residents of
      Canada (as defined in the Tax Act) at that time. The Fund is currently
      able to take advantage of the TCP Exception, and as a result, the Fund's Trust
      Indenture does not currently have a specific limit on the percentage of Trust
      Units that may be owned by non-residents.




On
      March 23, 2004 the Canadian federal government announced proposed changes
      to the Tax Act which would have effectively eliminated, over a period of
      time, the TCP Exception currently relied on by Enerplus to maintain its mutual
      fund trust status, and would have required the Fund to comply with the
      requirement that it "not be maintained primarily for the benefit of
      non-residents" before January 1, 2007. In response to submissions from and
      discussions with stakeholders, the Canadian federal government suspended the
      implementation of those proposed amendments. The Canadian Minister of Finance
      indicated in the February 23, 2005 federal budget that further
      consultations would be pursued with stakeholders on taxation issues related
      to
      income trusts and other flow-through entities. On September 8, 2005, the
      Canadian Department of Finance released a discussion paper on these matters
      and
      invited interested parties to make submissions to the Department of Finance.
      On
      November 23, 2005, the former Canadian Minister of Finance issued a news
      release announcing that no change would be made to the tax treatment of income
      trusts in Canada and calling an end to the consultation process initiated in
      September 2005.




Notwithstanding
      the above, there is no assurance that the TCP Exception will continue to be
      available to the Fund or that the Canadian federal government will not introduce
      new changes or proposals to tax regulations directed at non-resident ownership
      which, given the Fund's level non-resident ownership, may result in the Fund
      losing its mutual fund trust status or could otherwise detrimentally affect
      Enerplus and the market price of the Trust Units. Enerplus intends to continue
      to take the necessary measures in order to ensure the Fund continues to qualify
      as a mutual fund trust under the Tax Act. For additional information
      regarding these matters, including the ability of Enerplus to adopt non-resident
      ownership constraints if required in order to ensure that the Fund maintains
      its
      mutual fund status and the consequences if the Fund lost its mutual fund trust
      status, see "Information Respecting Enerplus Resources Fund  - Description
      of the Trust Units and the Trust Indenture  - Non-Resident Ownership
      Provisions" and "Risk Factors  - There would be material adverse
      consequences if the Fund lost its status as a mutual fund trust under Canadian
      tax laws".





70







See
      "General Development of Enerplus Resources Fund  - Federal Government
      Pronouncements on Income Trusts and Mutual Fund Trust Status".




Enerplus
      may not be able to take steps necessary to ensure that the Fund maintains its
      mutual fund trust status. Even if the Fund is successful in taking such
      measures, these measures could be adverse to certain holders of Trust Units,
      particularly "non-residents" of Canada (as defined in the Tax Act).
      The directors of Enerplus could impose a specific limit on the number of Trust
      Units that could be beneficially owned by non-residents of Canada, similar
      to
      the non-resident ownership restrictions in place for other income funds and
      royalty trusts in Canada, or could implement a dual-class unit structure what
      would effectively limit the aggregate number of Trust Units that could be owned
      by non-residents of Canada. Steps could be taken to ensure that no additional
      Trust Units are issued or transferred to non-residents, including limiting
      or
      suspending the trading of the Trust Units on the NYSE. If it is necessary to
      reduce the level of non-resident ownership below a certain level, non-residents
      may be required to sell all or a portion of their Trust Units. In these
      circumstances, the Trust Units would continue to trade on the TSX and
      non-residents of Canada would continue to be able to sell their Trust Units
      on
      that exchange. There can be no assurance that such circumstances would not
      detrimentally affect the market price of the Trust Units. See "Description
      of
      the Trust Units and the Trust Indenture  - Non-Resident Ownership
      Provisions."




Additionally,
      legislation may be implemented to limit the investment in income funds and
      royalty trusts by certain investors or to change the manner in which these
      entities are taxed. Tax authorities having jurisdiction over Enerplus or the
      unitholders may disagree with how Enerplus calculates its income for tax
      purposes or could change administrative practices to Enerplus' detriment or
      the
      detriment of its unitholders.




***There
      would be material adverse tax consequences if the Fund lost its status as a
      mutual fund trust under Canadian tax laws.***




Enerplus
      intends that the Fund will continue to qualify as a mutual fund trust for
      purposes of the Tax Act. The Fund may not, however, always be able to
      satisfy any future requirements for the maintenance of mutual fund trust status.
      See "--  Changes in tax and other laws may adversely affect unitholders"
      above and "General Development of Enerplus Resources Fund  - Federal
      Government Pronouncements on Income Trusts and Mutual Fund Trust Status". Should
      the status of the Fund as a mutual fund trust be lost or successfully challenged
      by a relevant tax authority, certain adverse consequences may arise for the
      Fund
      and its unitholders. Some of the significant consequences of losing mutual
      fund
      trust status are as follows:




•
            The
                Fund would be taxed on certain types of income distributed to unitholders,
                including income generated by the royalties held by the Fund. Payment
                of
                this tax may have adverse consequences for some unitholders, particularly
                unitholders that are not residents of Canada and residents of Canada
                that
                are otherwise exempt from Canadian income
                tax.




•
            The
                Fund would cease to be eligible for the capital gains refund mechanism
                available under Canadian tax laws if it ceased to be a mutual fund
                trust.




•
            Trust
                Units held by unitholders that are not residents of Canada would
                become
                taxable Canadian property. These non-resident holders would be subject
                to
                Canadian income tax on any gains realized on a disposition of Trust
                Units
                held by them.




•
            Trust
                Units would not constitute qualified investments for registered retirement
                savings plans ("**RRSPs**"),
                registered retirement income funds ("**RRIFs**"),
                registered education savings plans ("**RESPs**")
                or deferred profit sharing plans ("**DPSPs**").
                If, at the end of any month, one of these exempt plans holds Trust
                Units
                that are not qualified investments, the plan must pay a tax equal
                to 1% of
                the fair market value of the Trust Units at the time the Trust Units
                were
                acquired by the exempt plan. An RRSP or RRIF holding non-qualified
                Trust
                Units would be subject to taxation on income attributable to the
                Trust
                Units. If an RESP holds non-qualified Trust Units, it may have its
                registration revoked by the Canada
                Revenue Agency.




•
            The
                Fund would no longer be exempt from the application of the alternative
                minimum tax provisions of the
                Tax Act.





71





***The
      rights of an Enerplus unitholder differ from those associated with other types
      of investments.***




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 a corporation involved
      in the oil and gas business. The Trust Units represent an equal fractional
      beneficial interest in the Fund. Although the Trust Indenture generally provides
      a unitholder of the Fund with substantially all of the same protections, rights
      and remedies as a shareholder would have under the *Business
      Corporations Act* (Alberta), the ownership of the Trust Units does not provide unitholders with
      the statutory rights normally associated with ownership of shares of a
      corporation, including, for example, the right to bring "oppression" or
      "derivative" actions. Additionally, the Fund and/or its unitholders may not
      be
      able to benefit from or utilize insolvency or restructuring legislation to
      the
      same extent as if the Fund were a corporation. The unavailability of these
      statutory rights may also reduce the ability of the Fund's unitholders to seek
      legal remedies against other parties on Enerplus' behalf.




The
      Trust Units are also unlike conventional debt instruments in that there is
      no
      principal amount owing directly to unitholders. The Trust Units will have no
      value when reserves from Enerplus' properties can no longer be economically
      produced or marketed. Unitholders will only be able to obtain a return of the
      capital they invested during the period when reserves may be economically
      recovered and sold. Accordingly, the distributions unitholders receive over
      the
      life of an investment may not meet or exceed the initial
      capital investment.




***Changes
      in market-based factors may adversely affect the trading price of the Trust
      Units.***




The
      market price of the Trust Units is primarily a function of anticipated
      distributions to unitholders and the value of the properties owned by Enerplus.
      The market price of the Trust Units is therefore sensitive to a variety of
      market based factors including, but not limited to, interest rates and the
      comparability of the Fund's Trust Units to other yield-oriented securities.
      Any
      changes in these market-based factors may adversely affect the trading price
      of
      the Trust Units.




***The
      limited liability of the Fund's unitholders is
      uncertain.***




Notwithstanding
      the fact that Alberta (the Fund's governing jurisdiction) has adopted
      legislation purporting to limit trust unitholder liability, because of
      uncertainties in the law relating to investment trusts, there is a risk that
      a
      unitholder could be held personally liable for obligations of the Fund in
      respect of contracts or undertakings which the Fund enters into and for certain
      liabilities arising otherwise than out of contracts including claims in tort,
      claims for taxes and possibly certain other statutory liabilities. Enerplus
      has
      structured itself and attempted to conduct its business in a manner which
      mitigates the Fund's liability exposure and where possible, limit its liability
      to Fund property. However, such protective actions may not completely avoid
      unitholder liability. Notwithstanding Enerplus' attempts to limit unitholder
      liability, unitholders may not be protected from liabilities of the Fund to
      the
      same extent that a shareholder is protected from the liabilities of a
      corporation. Further, although the Fund has agreed to indemnify and hold
      harmless each unitholder from any costs, damages, liabilities, expenses, charges
      and losses suffered by a unitholder resulting from or arising out of the
      unitholder not having limited liability, Enerplus cannot assure prospective
      investors that any assets would be available in these circumstances to reimburse
      unitholders for any such liability. However, personal liability to unitholders
      of a trust in Canada is minimal where the beneficiaries are not controlling
      the
      day-to-day activities of the trust and there is no direct contact between the
      beneficiaries of the trust and parties who contract with the trust, each of
      which conditions is satisfied in the case of the Fund and its unitholders.
      Legislation that proposes to limit trust unitholder liability has been
      implemented in Alberta (which is the Fund's governing jurisdiction) but there
      is
      no assurance that such legislation will eliminate all risk of unitholder
      liability. Additionally, the Alberta legislation does not affect the liability
      of unitholders with respect to any act, default, obligation or liability that
      arose prior to July 1, 2004.




***The
      redemption rights of unitholders is limited.***




Unitholders
      have a limited right to require the Fund to repurchase Trust Units, which is
      referred to as a redemption right. See "Description of the Trust Units and
      the
      Trust Indenture  - Redemption Right". It is anticipated that the redemption
      right will not be the primary mechanism for unitholders to liquidate their





72





investment.
      The Fund's ability to pay cash in connection with a redemption is subject to
      limitations. Any securities which may be distributed in specie to unitholders
      in
      connection with a redemption may not be listed on any stock exchange and a
      market may not develop for such securities. In addition, there may be resale
      restrictions imposed by law upon the recipients of the securities pursuant
      to
      the redemption right.




**Risks
      Particular to United States and Other Non-Resident
      Unitholders**




In
      addition to the risk factors set forth above (and in particular those set
      forth under "Risks Related to Enerplus' Structure and the Ownership of the
      Trust
      Units  - Changes in tax and other laws may adversely affect unitholders"),
      the following risk factors are particular to unitholders who are not residents
      of Canada.




***United States
      unitholders may be subject to passive foreign investment company
      rules.***




The
      Fund may be a passive foreign investment company for United States federal
      income tax purposes for the 2005 taxable year and in subsequent taxable years.
      To date, Enerplus has received advice that the Fund should not be considered
      a
      passive foreign investment company for the years 2002, 2003 and 2004. If the
      Fund were classified as a passive foreign investment company, United States
      unitholders (other than most tax-exempt investors) would be subject to adverse
      tax rules. Under these adverse tax rules, United States unitholders
      generally would be required to allocate any gain or any excess distributions,
      which include any annual distributions other than in the first year the
      unitholder held Trust Units, that is greater than 125% of the average annual
      distributions received by that unitholder in the three preceding taxable years
      or, if shorter, that unitholder's holding period for Trust Units. The amount
      allocated to the current taxable year and any year prior to the first year
      in
      which Enerplus was a passive foreign investment company would be taxed as
      ordinary income in the current year. The amount allocated to each of the other
      taxable years would be subject to tax at the highest rate of tax in effect
      for
      the applicable class of taxpayer for that year, and an interest charge for
      the
      deemed deferral benefit would be imposed with respect to the resulting tax
      attributable to each of the other taxable years. Holders will not be able to
      make a "qualified electing fund" election or, with respect to the Fund's
      Operating Subsidiaries that were considered to be passive foreign investment
      companies, a "mark-to-market" election to protect themselves from these
      potential adverse consequences if Enerplus were ultimately determined to be
      a
      passive foreign investment company. United States unitholders are strongly
      urged to consult their own tax advisors regarding the United States federal
      income tax consequences of Enerplus' possible classification as a passive
      foreign investment company and the consequences of such
      classification.




***United States
      and other non-resident unitholders may be subject to additional
      taxation.***




The
      Canadian Tax Act and the tax treaties between Canada and other countries
      may impose additional withholding or other taxes on the cash distributions
      or
      other property paid by the Fund to unitholders who are not residents of Canada,
      and these taxes may change from time to time. For instance, since
      January 1, 2005, a 15% withholding tax is applied to return of capital
      portion of distributions made to non-resident unitholders. See "Distributions
      to
      Unitholders  - Additional Taxation Matters".




***The
      ability of United States and other non-resident unitholders investors to
      enforce civil remedies may be limited.***




The
      Fund is a trust organized under the laws of Alberta, Canada, and Enerplus'
      principal place of business is in Canada. Most of the directors and all of
      the
      officers of Enerplus are residents of Canada and most of the experts who provide
      services to Enerplus (such as its auditors and some of its independent reserve
      engineers) are residents of Canada, and all or a substantial portion of their
      assets and Enerplus' assets are located within Canada. As a result, it may
      be
      difficult for investors in the United States or other non-Canadian
      jurisdictions (a " **Foreign
      Jurisdiction** ")
      to effect service of process within such Foreign Jurisdiction upon such
      directors, officers and representatives of experts who are not residents of
      the
      Foreign Jurisdiction or to enforce against them judgments of courts of the
      applicable Foreign Jurisdiction based upon civil liability under the securities
      laws of such Foreign Jurisdiction, including United States federal
      securities laws or the securities laws of any state within the
      United States. In particular, there is doubt as to the enforceability in
      Canada against Enerplus or any of its directors, officers or representatives
      of
      experts who are not residents of the United States, in original actions or
      in actions for enforcement of judgments of United States courts of
      liabilities based solely upon the United States federal securities laws or
      the securities laws of any state within the United States.





73







**MARKET
      FOR SECURITIES**




The
      Trust Units are listed and posted for trading on the TSX and the NYSE. The
      trading symbol for the Trust Units on the TSX is "ERF.UN" and on the NYSE is
      "ERF".




The
      following table sets forth certain trading information for the Trust Units
      on
      the TSX in 2005.





**Month**
            
            **High**
            
            **Low**
            
            **Close**
            
            **Volume**January
            
            $
            48.00
            
            $
            41.90
            
            $
            47.12
            
            
            2,980,951February
            
            
            49.16
            
            
            44.25
            
            
            46.27
            
            
            4,730,319March
            
            
            48.79
            
            
            40.00
            
            
            43.88
            
            
            4,297,787April
            
            
            46.60
            
            
            41.55
            
            
            44.40
            
            
            4,477,469May
            
            
            45.56
            
            
            40.55
            
            
            44.31
            
            
            4,738,048June
            
            
            47.50
            
            
            44.20
            
            
            46.80
            
            
            3,624,328July
            
            
            49.00
            
            
            46.40
            
            
            48.90
            
            
            4,644,770August
            
            
            50.97
            
            
            44.82
            
            
            49.85
            
            
            8,410,988September
            
            
            55.14
            
            
            48.50
            
            
            54.91
            
            
            5,941,908October
            
            
            56.50
            
            
            45.79
            
            
            49.70
            
            
            7,846,506November
            
            
            54.28
            
            
            47.91
            
            
            53.50
            
            
            5,514,764December
            
            
            58.55
            
            
            53.50
            
            
            55.86
            
            
            5,070,256





The
      following table sets forth certain trading information for the Trust Units
      on
      the NYSE in 2005.





**Month**
            
            **High**
            
            **Low**
            
            **Close**
            
            **Volume**January
            
            US$
            38.72
            
            US$
            34.20
            
            US$
            37.93
            
            
            4,663,900February
            
            
            39.76
            
            
            35.82
            
            
            37.59
            
            
            4,898,700March
            
            
            39.20
            
            
            32.86
            
            
            36.26
            
            
            6,825,100April
            
            
            38.26
            
            
            33.36
            
            
            35.33
            
            
            6,670,900May
            
            
            36.59
            
            
            32.00
            
            
            35.30
            
            
            5,601,800June
            
            
            38.50
            
            
            35.50
            
            
            38.20
            
            
            4,086,600July
            
            
            40.08
            
            
            38.01
            
            
            39.91
            
            
            4,038,800August
            
            
            42.15
            
            
            36.80
            
            
            42.03
            
            
            6,626,200September
            
            
            47.52
            
            
            41.29
            
            
            47.20
            
            
            5,553,400October
            
            
            48.44
            
            
            38.76
            
            
            42.00
            
            
            10,874,300November
            
            
            46.54
            
            
            40.19
            
            
            45.80
            
            
            5,549,100December
            
            
            50.29
            
            
            46.00
            
            
            47.98
            
            
            5,065,400








74







**DIRECTORS
      AND OFFICERS**




**Directors
      of EnerMark**




The
      directors of EnerMark are nominated by the unitholders of the Fund at each
      annual meeting of unitholders. All directors serve until the next annual meeting
      or until a successor is elected or appointed. The name, municipality of
      residence, year of appointment as a director of EnerMark and principal
      occupation for the past five years for each director of EnerMark are set forth
      below.





**Name
                and Residence**
            
            **Director
                Since**
            
            **Principal
                Occupation for Past Five Years**Edwin
                Dodge(3)(4)(6)
              Calgary,
                Alberta, Canada
            
            May 2004
            
            Corporate
                director since 2004. Prior thereto, Chief Operating Officer of Canadian
                Pacific Railway Limited ("**CPR**")
                (a public Canadian national rail company) since 2001. Prior thereto,
                various senior roles with CPR and its predecessors.Gordon
                J. Kerr(10)
              Calgary,
                Alberta, Canada
            
            May 2001
            
            President
                and Chief Executive Officer of Enerplus since May 2001
                (and Chief Financial Officer of Enerplus until December 2001).
                Prior thereto, Executive Vice President and Chief Financial Officer
                of
                Enerplus.Douglas
                R. Martin(1)(7)
              Calgary,
                Alberta, Canada
            
            July 2000
            
            President
                of Charles Avenue Capital Corp. (a private merchant banking
                company).Robert
                Normand(2)(4)(8)
              Rosemere,
                Québec, Canada
            
            June 2001
            
            Corporate
                director.Glen
                D. Roane(2)(4)
              Canmore,
                Alberta, Canada
            
            June 2004
            
            Corporate
                director.W.C.
                (Mike) Seth
              Calgary,
                Alberta, Canada
            
            September 2005
            
            President
                of Seth Consultants Ltd. (a private consulting firm) since March
                1, 2006.
                Prior thereto, Chairman of McDaniel & Associates
                Consultants Ltd. ("**McDaniel**")
                (a petroleum engineering consulting firm) since July 2005. Prior
                thereto, President and Managing Director of McDaniel.Donald
                T. West(5)(6)
              Calgary,
                Alberta, Canada
            
            April 2003
            
            Businessman.Harry
                B. Wheeler(2)(5)
              Calgary,
                Alberta, Canada
            
            January 2001
            
            President
                of Colchester Investments Ltd. (a private investment
                firm).Robert
                L. Zorich(3)(6)(9)
              Houston,
                Texas, USA
            
            January 2001
            
            Managing
                Director of EnCap Investments L.P. (a private firm that provides
                private equity financing to the oil and gas industry).


___________


Notes:


(1)
            Chairman
                of the board of directors and ex officio member of all committees
                of the
                board of directors.




(2)
            The
                Audit and Risk Management Committee is comprised of Robert Normand
                as
                Chairman, Harry B. Wheeler and Glen D.
                Roane.




(3)
            The
                Corporate Governance and Nominating Committee is comprised of Robert
                L.
                Zorich as Chairman, Edwin Dodge and
                W.C. (Mike) Seth.




(4)
            The
                Compensation and Human Resources Committee is comprised of Glen D.
                Roane
                as Chairman, Robert Normand and
                Edwin Dodge.




(5)
            The
                Reserves Committee is comprised of Harry B. Wheeler as Chairman,
                W.C.
                (Mike) Seth and
                Donald T. West.




(6)
            The
                Environment, Health and Safety Committee is comprised of Donald T.
                West as
                Chairman, Edwin Dodge and Robert L.
                Zorich.




(7)
            From
                1991 to 2000, Mr. Martin was director of Coho Energy, Inc.
                ("**Coho**"), an oil and natural gas corporation that was
                listed on the TSE and NASDAQ. In 1999, Coho filed for protection
                under
                United States federal bankruptcy law, from which it was released in
                April, 2000. The directors of Coho were not held responsible for
                any
                actions. Mr. Martin resigned as a director of Coho in April of
                2000.





75












(8)
            Mr. Normand
                served as a director of Concert Industries Ltd.
                ("**Concert**") when it and its Canadian operating
                subsidiaries announced on August 5, 2003 that it had filed for
                protection under the *Companies' Creditors Arrangement Act*
                ("**CCAA**"). Concert was restructured and a plan of
                compromise and arrangement for its operating subsidiaries was approved
                in
                December 2004 allowing them to emerge from the CCAA proceedings.
                Mr. Normand no longer serves as a director of
                Concert.




(9)
            In
                late 1997, Mr. Zorich was appointed to the board of directors of Benz
                Energy Inc. ("**Benz**"), a Vancouver Stock Exchange
                (later the Canadian Venture Exchange and now the TSX Venture Exchange)
                listed company at the time, as a representative of Mr. Zorich's
                employer, EnCap Investments L.P., which had provided certain
                financing to Benz. On November 8, 2000, Benz, together with its
                wholly-owned subsidiary, Texstar Petroleum Inc., jointly filed a
                petition for protection under United States federal bankruptcy law,
                and on January 19, 2001, the shares of Benz were made subject to a
                cease trade order by the Alberta Securities Commission and suspended
                from
                trading on the Canadian Venture Exchange Inc. for failing to file
                required financial information.




(10)
            Prior
                to the completion of the acquisition of EGEM by Enerplus on April 23,
                2003, the executive services of Enerplus Resources Fund were provided
                by
                EGEM and its predecessors pursuant to a management agreement. All
                references to Enerplus in the above table prior to April 23, 2003
                should be construed as references to EGEM, but for simplicity, Enerplus
                has been utilized throughout the above
                table.




**Officers
      of EnerMark**




The
      name, municipality of residence, position held and principal occupation for
      the
      past five years for each officer of EnerMark are set out below:





**Name
                and Residence**
            
            **Office**
            
            **Principal
                Occupation for Past Five Years****(1)**Gordon
                J. Kerr
              Calgary,
                Alberta, Canada
            
            President
                and Chief Executive Officer
            
            President
                and Chief Executive Officer of Enerplus since May 2001
                (and Chief Financial Officer of Enerplus until December 2001).
                Prior thereto, Executive Vice President and Chief Financial Officer
                of
                Enerplus.Heather
                J. Culbert
              Calgary,
                Alberta, Canada
            
            Senior
                Vice President, Corporate Services
            
            Senior
                Vice President, Corporate Services of Enerplus since March 2001.
                Prior thereto, Vice President, Management Information Systems &
                Administration of Enerplus.Ian
                C. Dundas
              Calgary,
                Alberta, Canada
            
            Senior
                Vice President, Business Development
            
            Senior
                Vice President, Business Development since July 2004. Prior thereto,
                Vice President and Director, Business Development of Enerplus since
                February 2003. Prior thereto, Vice President of EGEM since
                August 2001. Prior thereto, Chief Financial Officer of
                Medmira Inc., (a public biotechnology
                company).Garry
                A. Tanner
              Calgary,
                Alberta, Canada
            
            Senior
                Vice President and Chief Operating Officer
            
            Senior
                Vice President and Chief Operating Officer of Enerplus since
                February 2003. Prior thereto, Senior Vice President,
                New Business Development of EGEM since August 2001 and Senior
                Vice President of El Paso Merchant Energy (a merchant trading
                company).Eric
                P. Tremblay
              Calgary,
                Alberta, Canada
            
            Senior
                Vice President, Capital Markets
            
            Senior
                Vice President, Capital Markets of Enerplus.Robert
                J. Waters
              Calgary,
                Alberta, Canada
            
            Senior
                Vice President and Chief Financial Officer
            
            Senior
                Vice President and Chief Financial Officer of Enerplus since
                December 2001. Prior thereto, Vice President, Finance and Chief
                Financial Officer of Pengrowth Corporation (a subsidiary of an oil
                and gas income trust).Jo-Anne
                M. Caza
              Calgary,
                Alberta, Canada
            
            Vice
                President,
              Investor
                Relations
            
            Vice
                President of Investor Relations of Enerplus.





76





**Name
                  and Residence**
              
              **Office**
              
              **Principal
                  Occupation for Past Five Years****(1)**


Rodney
                D. Gray
              Calgary,
                Alberta, Canada
            
            Vice
                President, Finance
            
            Vice
                President, Finance of Enerplus since February 2005. Prior thereto,
                Controller, Finance of Enerplus since June 2002. Prior thereto,
                independent consultant since September 2001. Prior thereto,
                Controller and Manager, Financial Reporting with Berkley Petroleum
                Corp.
                (an oil and gas exploration and production
                company)Larry
                W. Hammond
              Calgary,
                Alberta, Canada
            
            Vice
                President, Operations
            
            Vice
                President, Operations of Enerplus since July 2005. Prior thereto,
                Team Leader with EnCana Corporation (an oil and gas exploration and
                production company).David
                A. McCoy
              Calgary,
                Alberta, Canada
            
            Vice
                President, General Counsel & Corporate Secretary
            
            Vice
                President, General Counsel & Corporate Secretary of Enerplus
                since December 2002. Prior thereto, Consultant, Offshore &
                International Operations, with EnCana Corporation (an oil and gas
                exploration and production company) since 2002. Prior thereto, Vice
                President, General Counsel & Government Affairs with Conoco
                Canada Limited (an oil and gas exploration and production
                company).Daniel
                M. Stevens
              Calgary,
                Alberta, Canada
            
            Vice
                President, Development Services
            
            Vice
                President, Development Services of Enerplus since February 2003.
                Prior thereto, Manager, Drilling and Completions of
                Enerplus.Wayne
                G. Ford
              Calgary,
                Alberta, Canada
            
            Controller,
                Operations
            
            Controller,
                Operations of Enerplus since August 2001. Prior thereto, Controller
                of Argonauts Group Ltd. (an oil and gas exploration and
                production company).Jodine
                J. Jenson Labrie
              Cochrane,
                Alberta, Canada
            
            Controller,
                Finance
            
            Controller,
                Finance of Enerplus since March 2006. Prior thereto, Manager,
                Finance and Senior Financial Accountant of Enerplus since
                September 2003. Prior thereto, 2nd Vice President of American
                Chartered Bank (a U.S. bank located in Illinois, U.S.A.) since
                October 2002. Prior thereto, Senior Manager, Financial Advisory
                Services of KPMG Financial Services Inc. (an accounting and
                financial services firm).


___________


Note:


(1)
            Prior
                to the completion of the acquisition of EGEM by Enerplus on April 23,
                2003, the executive services of Enerplus Resources Fund were provided
                by
                EGEM and its predecessors pursuant to a management agreement. All
                references to Enerplus in the above table prior to April 23, 2003
                should be construed as references to EGEM, but for simplicity, Enerplus
                has been utilized throughout the above table. Where an individual's
                principal occupation has been disclosed as being with EGEM, that
                individual undertook significant activities on behalf of EGEM other
                than
                the management of Enerplus Resources
                Fund.




As
      of February 28, 2006, the directors and officers named above beneficially
      own, directly or indirectly, an aggregate of 415,501 Trust Units,
      representing approximately 0.35% of the outstanding Trust Units as of that
      date.





77







Certain
      of the directors and officers named above may be directors or officers of
      issuers which are in competition with Enerplus, and as such may encounter
      conflicts of interests in the administration of their duties with respect to
      Enerplus. See "Risk Factors  - Potential Conflicts of
      Interest".




**Audit
      Committee Disclosure**




The
      disclosure regarding Enerplus' Audit Committee required under Multilateral
      Instrument 52-110 adopted by certain of the Canadian securities
      regulatory authorities is contained in Appendix "E" to this Annual
      Information Form.




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




To
      the knowledge of the directors and executive officers of EnerMark, none of
      the
      directors or executive officers of EnerMark and no person or company that is
      the
      direct or indirect beneficial owner of, or who exercises control or direction
      over, more than 10% of any class or series of the Fund's securities, nor any
      associate or affiliate of any of the foregoing, has had any material interest,
      direct or indirect, in any material transaction with Enerplus since
      January 1, 2003 or in any proposed transaction that would materially affect
      Enerplus.




**MATERIAL
      CONTRACTS AND DOCUMENTS AFFECTING THE RIGHTS OF
      SECURITYHOLDERS**




Enerplus
      is not a party to any contracts material to its business or operations, other
      than contracts entered into in the normal course of business.




A
      copy of the Trust Indenture, which is described under "Information Respecting
      Enerplus Resources Fund  - Description of the Trust Units and the Trust
      Indenture", was publicly filed on January 5, 2004 and is available on the
      Fund's SEDAR profile at www.sedar.com. A copy of the Fund's unitholder rights
      plan agreement, which is described under "Information Respecting Enerplus
      Resources Fund  - Unitholder Rights Plan", was publicly filed on
      April 12, 2005 and is available on the Fund's SEDAR profile at
      www.sedar.com.




**INTERESTS
      OF EXPERTS**




Sproule
      prepared the Sproule Report in respect of the reserves attributable to Enerplus'
      Canadian conventional oil and natural gas properties, a summary of which is
      contained in this Annual Information Form. As of the date of the Sproule Report,
      the "designated professionals" (as defined in Form 51-102F2  - *Annual
      Information Form* of the Canadian securities regulatory authorities) of Sproule, as a group,
      beneficially owned, directly or indirectly, less than 1% of the Fund's
      outstanding Trust Units. D&M prepared the D&M Report in respect of
      Enerplus' U.S. conventional oil and natural gas properties, a summary of
      which is contained in this Annual Information Form. As of the date of the
      D&M Report, the designated professionals of D&M, as a group,
      beneficially owned, directly or indirectly, less than 1% of the Fund's
      outstanding Trust Units. GLJ prepared the GLJ Report in respect of the SAGD
      reserves attributable to Enerplus' working interest in the Joslyn Project,
      a
      summary of which is contained in this Annual Information Form. As of the date
      of
      the GLJ Report, the designated professionals of GLJ, as a group, beneficially
      owned, directly or indirectly, less than 1% of the Fund's outstanding Trust
      Units.




The
      auditors of the Fund are Deloitte & Touche LLP, Chartered
      Accountants, Calgary, Alberta. Deloitte & Touche LLP has confirmed
      that it is independent with the Rules of Professional Conduct of the Institute
      of Chartered Accountants of Alberta.




**REGISTRAR
      AND TRANSFER AGENT**




The
      registrar and transfer agent for the Trust Units is CIBC Mellon Trust
      Company, at its principal offices in Calgary, Alberta, Toronto, Ontario and
      Montréal, Québec. The co-transfer agent for the Trust Units is Mellon Investor
      Services LLC in New York, New York.





78







**ADDITIONAL
      INFORMATION**




Additional
      information relating to the Fund may be found on the Fund's company profile
      on
      the SEDAR website at www.sedar.com. Additional information, including directors'
      and officers' remuneration and indebtedness, principal holders of the Fund's
      securities and securities authorized for issuance under equity compensation
      plans, as applicable, is contained in the Fund's information circular dated
      February 28, 2006 for its 2006 annual general meeting of Unitholders.
      Furthermore, additional financial information relating to the Fund is provided
      in the Fund's audited consolidated financial statements and management's
      discussion and analysis for year ended December 31, 2005.





79












**APPENDIX
      "A"**




**REPORT
      ON RESERVES DATA BY INDEPENDENT**


**QUALIFIED
      RESERVES EVALUATOR OR AUDITOR**




*Terms
      to which a meaning is ascribed in National Instrument 51-101 have the
      same meaning herein* .




To
      the board of directors of Enerplus Resources Fund
      (the "Company"):




1.
            We
                have evaluated and reviewed the Company's Reserves Data as at
                December 31, 2005. The Reserves Data consist of the
                following:




(a)
            (i) proved
                and proved plus probable oil and gas reserves estimated as at
                December 31, 2005 using forecast prices and costs;
                and




(ii) the
                related estimated future net revenue;
                and




(b)
            (i) proved
                oil and gas reserve quantities were estimated as at December 31, 2005
                using constant prices and costs;
                and




(ii) the
                related estimated future net
                revenue.




2.
            The
                Reserves Data are the responsibility of the Company's management.
                Our
                responsibility is to express an opinion on the Reserves Data based
                on our
                evaluation.




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




3.
            Those
                standards require that we plan and perform an evaluation to obtain
                reasonable assurance as to whether the reserves data are free of
                material
                misstatement. An evaluation also includes assessing whether the reserves
                data are in accordance with principles and definitions presented
                in the
                COGE Handbook.




4.
            The
                following table sets forth the estimated future net revenue attributed
                to
                proved plus probable reserves, estimated using forecast prices and
                costs
                on a before tax basis and calculated using a discount rate of 10%,
                included in the reserves data of the Company evaluated by us as of
                December 31, 2005, and identifies the respective portions thereof
                that we have audited, evaluated and reviewed and reported on to the
                Company's management and the Board of
                Directors:





**Net Present
                Value of future Net Revenue**
              **(10% discount
                rate)****Independent
                Qualified**
              **Reserves
                Evaluator or Auditor**
            
            **Description
                and**
              **Preparation
                Date of**
              **Evaluation
                Report**
            
            **Location
                of**
              **Reserves
                (Country**
              **or
                Foreign**
              **Geographic
                Area)**
            
            **Audited**
            
            **Evaluated**
            
            **Reviewed**
            
            **Total**(in $
                millions)Sproule
                Associates Limited
            
            Evaluation
              of the P&NG Reserves of Enerplus Resources Fund, as of December 31,
              2005, prepared July, 2005 to January, 2006
            
            Canada
            
            
            Nil
            
            $
            4,402.9
            
            $
            525.9
            
            $
            4,928.8





5.
            In
                our opinion, the reserves data evaluated by us have, in all material
                respects, been determined and are in accordance with the COGE
                Handbook.




6.
            We
                have no responsibility to update the report referred to in
                paragraph 4 for events and circumstances occurring after its
                preparation date.




7.
            Because
                the reserves data are based on judgements regarding future events,
                actual
                results will vary and the variations may be
                material.





A-1







Executed
      as to our report referred to above:





Sproule
                Associates Limited
              Calgary,
                Alberta, Canada
              February 28,
                2006
            /s/
                DOUG KING
              Doug
                King, P. Eng.
              Associate/s/
                HANS J. FIRLA
              
              Hans
                J. Firla, P. Eng.
              Associate/s/
                R. KEITH MACLEOD
              
              R.
                Keith MacLeod, P. Eng.
              Executive
                Vice-President/s/
                MICHAEL W. MAUGHAN
              
              Michael
                W. Maughan, C.P.G., P. Geol.
              Manager,
                Geoscience & Associate/s/
                KEN H. CROWTHER
              Ken
                H. Crowther, P. Eng.
              President








A-2










**APPENDIX
      "B"**




**REPORT
      ON RESERVES DATA BY INDEPENDENT**


**QUALIFIED
      RESERVES EVALUATOR OR AUDITOR**




*Terms
      to which a meaning is ascribed in National Instrument 51-101 have the
      same meaning herein.*




To
      the board of directors of Enerplus Resources Fund
      (the "Company"):




1.
            We
                have prepared an evaluation of the Company's reserves data as at
                December 31, 2005. The reserves data consist of the
                following:




(a)
            (i)  proved
                and proved
                plus probable oil and gas reserves estimated as at December 31, 2005
                using forecast prices and costs;
                and




(ii)
            the
                related estimated future net revenue;
                and




(b)
            (i)  proved
                oil and gas
                reserves estimated as at December 31, 2005, using constant prices and
                costs; and




(ii)
            the
                related estimated future net
                revenue.




2.
            The
                reserves data are the responsibility of the Company's management.
                Our
                responsibility is to express an opinion on the reserves data based
                on our
                evaluation.




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




3.
            Those
                standards require that we plan and perform an evaluation to obtain
                reasonable assurance as to whether the reserves data are free of
                material
                misstatement. An evaluation also includes assessing whether the reserves
                data are in accordance with principles and definitions presented
                in the
                COGE Handbook.




4.
            The
                following table sets forth the estimated future net revenue (before
                deduction of income taxes) attributed to proved plus probable reserves,
                estimated using forecast prices and costs and calculated using a
                discount
                rate of 10%, included in the reserves data of the Company evaluated
                by us
                for the year ended December 31, 2005, and identifies the respective
                portions thereof that we have audited, evaluated and reviewed and
                reported
                on to the Company's board of
                directors:





**Net Present
                Value of future Net Revenue**
              **(10% discount
                rate)****Independent
                Qualified Reserves**
              **Evaluator
                or Auditor**
            
            **Description
                and**
              **Preparation
                Date of**
              **Evaluation
                Report**
            
            **Location
                of Reserves**
              **(Country
                or Foreign**
              **Geographic
                Area)**
            
            **Audited**
            
            **Evaluated**
            
            **Reviewed**
            
            **Total**(in $
                thousands)GLJ
                Petroleum Consultants Ltd.
            
            January
                20, 2006
            
            Canada
            
            
            -
            $
            36,282
            
            
            -
            
            $
            36,282





5.
            In
                our opinion, the reserves data respectively evaluated by us have,
                in all
                material respects, been determined and are in accordance with the
                COGE
                Handbook.




6.
            We
                have no responsibility to update the report referred to in
                paragraph 4 for events and circumstances occurring after their
                respective preparation dates.




7.
            Because
                the reserves data are based on judgements regarding future events,
                actual
                results will vary and the variations may be
                material.




Executed
      as to our report referred to above:





GLJ
                Petroleum Consultants Ltd.
              Calgary,
                Alberta, Canada
              March 2,
                2006
            "*Dana
                B. Laustsen*"
              Dana
                B. Laustsen, P. Eng.
              Executive
                Vice-President








B-1










**APPENDIX
      "C"**




**REPORT
      ON RESERVES DATA BY INDEPENDENT**


**QUALIFIED
      RESERVES EVALUATOR OR AUDITOR**




*Terms
      to which a meaning is ascribed in National Instrument 51-101 have the
      same meaning herein.*




To
      the board of directors of Enerplus Resources Fund ("Enerplus"):




1.
            Pursuant
                to the request of Enerplus, we have evaluated and reviewed Lyco
                Energy Corp.'s reserves data as at December 31, 2005. The
                reserves data includes the
                following:





(a)
            (i)
            proved
                and proved plus probable oil and gas reserves estimated as at
                December 31, 2005 using forecast (as defined in our report) prices
                and costs; and(ii)
            the
                related estimated future net revenue; and(b)
            (i)
            proved
                and proved plus probable oil and gas reserves estimated as at
                December 31, 2005 using constant (as defined in our report) prices
                and costs; and(ii)
            the
                related estimated future net
                revenue.





2.
            The
                reserves data are the responsibility of Enerplus' management. Our
                responsibility is to express an opinion on the reserves data based
                on our
                evaluation.




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




3.
            Those
                standards require that we plan and perform an evaluation to assure
                reserve
                estimates are free of material misstatement and are in accordance
                with
                principles and definitions presented in the COGE
                Handbook.




4.
            The
                following table sets forth the estimated future net revenue (before
                deduction of income taxes) in thousands of United States dollars (M$)
                for proved plus probable reserves evaluated by us, estimated using
                forecast prices and costs and calculated using a discount rate of
                10%,
                evaluated as of December 31, 2005, and identifies the respective
                portions thereof that we have evaluated and reported to the Company's
                management:




**Net Present
                    Value of future Net Revenue**
                  **(10% discount
                    rate)****Independent
                    Qualified**
                  **Reserves
                    Evaluator**
                  **or Auditor**
              
              **Description
                    and**
                  **Preparation
                    Date of**
                  **Evaluation
                    Report**
              
              **Location
                    of**
                  **Reserves**
                  **(Country
                    or**
                  **Foreign**
                  **Geographic**
                  **Area)**
              
              **Audited**
              
              **Evaluated**
              
              **Reviewed**
              
              **Total**(in US$
                    thousands)DeGolyer
                    and MacNaughton
              
              Appraisal
                  Report as of December 31, 2005 on Certain Properties owned by Lyco
                  Energy
                  Corporation
              
              Montana
                    and
                  North
                    Dakota
              
              Not
                Applicable
              
              $
              720,254
              
              
              Not
                  Applicable
              
              $
              720,254




5.
            In
                our opinion, the reserves and revenue evaluated by us have, in all
                material respects, been determined and are in accordance with the
                COGE
                Handbook.




6.
            We
                have no responsibility to update our report referred to in
                paragraph 4 for events and circumstances occurring after the
                preparation date.




7.
            Because
                the reserves data are based on judgments regarding future events,
                actual
                results will vary and the variations may be
                material.









C-1







Executed
      as to our report referred to above:





DeGolyer
                and MacNaughton
              Dallas,
                Texas, USA
              January
                23, 2006
            Submitted,
              "DEGOLYER
                AND MACNAUGHTON"
              DeGolyer
                and MacNaughton/s/
PAUL
                J. SZATKOWSKI
              Paul
                J. Szatkowski, P.E.
              Senior
                Vice President
              DeGolyer
                and MacNaughton








C-2










**APPENDIX
      "D"**




**REPORT
      OF MANAGEMENT AND DIRECTORS**


**ON
      RESERVES DATA AND OTHER INFORMATION**




*Terms
      to which a meaning is described in National Instrument 51-101 have the
      same meaning herein.*




Management
      of EnerMark Inc. ("EnerMark"), on behalf of Enerplus Resources Fund
      (the "Fund") are responsible for the preparation and disclosure of
      information with respect to the Fund's oil and gas activities in accordance
      with
      securities regulatory requirements. This information includes reserves data,
      which consist of the following:




(a)
            (i)     
                proved and proved plus probable oil and gas reserves estimated as
                at
                December 31, 2005 using forecast prices and costs;
                and




(ii)
            the
                related estimated future net revenue;
                and




(b)
            (i) proved
                oil
                and gas reserves estimated as at December 31, 2005 using constant
                prices and costs; and




(ii)
            the
                related estimated future net
                revenue.




Independent
      qualified reserves evaluators have evaluated and reviewed the Fund's reserves
      data. The reports of the independent qualified reserves evaluators are presented
      as Appendices "A", "B", and "C" to this Annual Information
      Form.




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




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




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




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




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




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




(b)
            the
                filing of the reports of the independent qualified reserves evaluators
                on
                the reserves data; and




(c)
            the
                content and filing of this report.





D-1










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




**ENERPLUS
      RESOURCES FUND**


By
      EnerMark Inc.




" *Gordon
      J. Kerr* "





Gordon
      J. Kerr


President
      and Chief Executive Officer




" *Garry
      A. Tanner* "





Garry
      A. Tanner


Senior
      Vice President and


Chief
      Operating Officer




" *Harry
      B. Wheeler* "





Harry
      B. Wheeler


Director




" *W.C.
      (Mike) Seth* "





W.C.
      (Mike) Seth


Director






March 7,
      2006





D-2







**APPENDIX
      "E"**




**AUDIT
      COMMITTEE DISCLOSURE**


**PURSUANT
      TO MULTILATERAL INSTRUMENT 52-110**




**A.**
            **The
                Audit & Risk Management Committee's
                Charter**




Set
      forth below is the charter of the Audit & Risk Management Committee
      (the " **Committee** ")
      of the board of directors of EnerMark.




**I.**
            **AUTHORITY**




The
      Audit & Risk Management Committee (the "Committee") of the Board
      of Directors (the "Board") of EnerMark shall be comprised of three or more
      directors as determined from time to time by resolution of the Board. Consistent
      with the appointment of other Board committees, the members of the Committee
      shall be elected by the Board at the first meeting of the Board following each
      annual meeting of unitholders of Enerplus Resources Fund (the "Fund") or at
      such other time as may be determined by the Board. The Chairman of the Committee
      shall be designated by the Board, provided that if the Board does not so
      designate a Chairman, the members of the Committee, by majority vote, may
      designate a Chairman. The presence in person or by telephone of a majority
      of
      the Committee's members shall constitute a quorum for any meeting of the
      Committee. All actions of the Committee will require the vote of a majority
      of
      its members present at a meeting of the Committee at which a quorum is
      present.




**II.**
            **PURPOSE
                OF THE COMMITTEE**




The
      Committee's mandate is to assist the Board in fulfilling its oversight
      responsibilities with respect to:




1.
            financial
                reporting and disclosure of the
                Fund;




2.
            the
                Fund's compliance with regulatory
                requirements;




3.
            external
                auditors' qualifications, appointment, fees and
                independence;




4.
            evaluating
                and monitoring the performance of the Fund's external
                auditors;




5.
            preparation
                of the Fund's continuous disclosure documents;
                and




6.
            monitoring
                the manner in which the financial risks of the Fund are being
                managed.




The
      Committee shall report to the Board on a regular basis with regard to such
      matters. The Committee has direct responsibility to recommend the appointment
      of
      the external auditors and authority to fix their remuneration. The Committee
      may
      take such actions as it deems necessary to satisfy itself that the Fund's
      auditors are independent of management. It is the objective of the Committee
      to
      maintain free and open means of communications (including the annual proxy
      information circular) among the Board, the external auditors, and the financial
      and senior management of EnerMark.




**III.**
            **COMPOSITION
                AND COMPETENCY OF THE
                COMMITTEE**




Each
      member of the Committee shall be unrelated and, as such, shall be free from
      any
      relationship that may interfere with the exercise of his or her independent
      judgement as a member of the Committee. All members of the Committee shall
      be
      financially literate as determined by the Board in the exercise of its business
      judgement, and shall include a working familiarity with basic finance and
      accounting practices and an ability to read and understand financial statements.
      At least one member of the Committee shall have accounting or related financial
      management expertise. Members are encouraged to enhance their understanding
      of
      current issues through means of their preference.




**IV.**
            **MEETINGS
                OF THE COMMITTEE**




The
      Committee shall meet with such frequency and of such intervals, as it shall
      determine is necessary to carry out its duties and responsibilities. As part
      of
      its purpose to foster open communications, the Committee shall meet at least
      quarterly with management and the Fund's external auditors in separate executive
      sessions to





E-1





discuss
      any matters that the Committee or each of these groups or persons believes
      should be discussed privately. The Chairman works with the Chief Financial
      Officer and external auditors to establish the agendas for Committee meetings,
      ensuring that each party's expectations are understood and addressed. The
      Committee, in its discretion, may ask members of management or others to attend
      its meetings (or portions thereof) and to provide pertinent information as
      necessary. The Committee shall maintain minutes of its meetings and records
      relating to those meetings and the Committee's activities and provide copies
      of
      such minutes to the Board.




**V.**
            **DUTIES
                AND ACTIVITIES OF THE
                COMMITTEE**




Evaluation
      and Appointment of External Auditors




1.
            Review
                its charter annually and recommend changes to the Board when
                necessary;




2.
            Make
                recommendations to the Board on the appointment of external auditors
                of
                the Fund and its subsidiaries;




3.
            Review
                and approve the Fund's external auditors' annual engagement letter
                and
                audit plans, including the proposed fees contained
                therein;




4.
            Review
                the performance of the external auditors and make recommendations
                to the
                Board regarding their replacement when circumstances warrant. The
                review
                shall take into consideration the evaluation made by management of
                the
                external auditor's performance. Approve payment of audit fees and
                pre-approve audit related and other authorized work
                fees;




5.
            Oversee
                the independence of the external auditors by, among other
                things;




(a)
            requiring
                the external auditors to deliver to the Committee on a periodic basis
                a
                formal written statement delineating all relationships between the
                external auditors and the Fund;




(b)
            reviewing
                and approving EnerMark's hiring policies regarding partners, employees
                and
                former partners and employees of current and formal external
                auditors;




(c)
            actively
                engaging in a dialogue with the external auditors with respect to
                any
                disclosed relationships or services that may impact the objectivity
                and
                independence of the external auditors and recommending that the Board
                take
                appropriate action to satisfy itself of the auditors'
                independence;




(d)
            pre-approve
                the nature of non-audit related services and the fees
                thereon;




(e)
            conducting
                private sessions with the external auditors and encouraging direct
                communications between the Chairman of the Committee and the audit
                partner; and




(f)
            instructing
                the Fund's external auditors that they are ultimately accountable
                to the
                Committee and the Board and that the Committee and the Board are
                responsible for the selection (subject to unitholder approval), evaluation
                and termination of the Fund's external
                auditors.




Oversight
      of Annual and Quarterly Statements and Management Discussion and
      Analysis




6.
            Review
                and approve, if appropriate, the annual audit plan of the external
                auditors, including the scope of audit activities, and monitor such
                plan's
                progress and results during the
                year;




7.
            Confirm,
                through private discussions with the external auditors and management,
                that no restrictions are being placed on the scope of the external
                auditors' work;




8.
            Ensure
                adequacy of financial results and disclosure in the management, discussion
                and analysis through the review of:




(a)
            external
                auditors' report, the annual and quarterly financial statements,
                the
                management's discussion and analysis, Sarbanes-Oxley processes and
                procedures, the certification process by the CEO and CFO, and any
                other
                pertinent reports and management's responses concerning the financial
                statements;





E-2







(b)
            the
                qualitative judgments of the external auditors about the appropriateness,
                not just the acceptability, of accounting principles and financial
                disclosure practices used or proposed to be adopted by the Fund and,
                particularly, their views about alternate accounting treatments and
                their
                effects on the financial results;




(c)
            the
                methods used to account for significant unusual
                transactions;




(d)
            the
                effect of significant accounting policies in controversial or emerging
                areas for which there is a lack of authoritative guidance or
                consensus;




(e)
            management's
                process for formulating sensitive accounting estimates and the
                reasonableness of these estimates;




(f)
            significant
                recorded and unrecorded audit
                adjustments;




(g)
            any
                material accounting issues among management and the external
                auditors;




(h)
            other
                matters required to be communicated to the Committee by the external
                auditors under generally accepted auditing standards by the external
                auditors; and




(i)
            management's
                acknowledgement of its responsibility towards the financial
                statements.




Oversight
      of Financial Reporting Process, Internal Controls and Certification
      Process




9.
            Establishment
                of the Fund's Whistleblower Policy for the submission, receipt, retention
                and treatment of complaints and concerns regarding accounting and
                auditing
                matters, and review of any developments and responses on reports
                received
                thereunder;




10.
            Review
                the adequacy and effectiveness of the financial reporting system
                and
                internal control policies and procedures with the external auditors
                and
                management. Ensure that EnerMark complies with all new regulations
                in this
                regard;




11.
            Review
                with management EnerMark and the Fund's administrative, operational
                and
                accounting internal controls, including controls and security of
                the
                computerized information systems, and evaluate whether EnerMark and
                the
                Fund are operating in accordance with prescribed policies, procedures
                and
                codes of conduct;




12.
            Review
                with management and the external auditors any reportable condition
                and
                material weaknesses affecting internal
                controls;




13.
            Receive
                periodic reports from the external auditors and management to assess
                the
                impact of significant accounting or financial reporting developments
                proposed by the CICA, the AICPA, the Financial Accounting Standards
                Board,
                the SEC, the relevant Canadian securities commissions, stock exchanges
                or
                other regulatory body, or any other significant accounting or financial
                reporting related matters that may have a bearing on EnerMark and
                the
                Fund;




14.
            Establish
                and maintain free and open means of communication between the Board,
                the
                Committee, the external auditors and
                management;




Review
      of Business Risks




15.
            Review
                with management the list of risks that they have identified and ensure
                that management has implemented appropriate systems to monitor, mitigate
                and report such business risks;




16.
            Review
                adequacy of the insurance coverage;




17.
            Review
                the implementation of the Fund's risk management
                policy;




18.
            Review
                the disclosure of identified risks in the annual disclosure documents
                sent
                to Unitholders to ensure that such disclosure meets with regulatory
                requirements and adequately describes risks to
                Unitholders;





E-3







Other
      Matters




19.
            Conduct
                or authorize investigations into any matters within the Committee's
                scope
                of responsibilities, including retaining outside counsel or other
                consultants or experts for this
                purpose;




20.
            Discuss
                press releases regarding earnings and other financial information
                provided
                to analysts and rating agencies;




21.
            Review
                the disclosure made in the Fund's Annual Report, Annual Information
                Form,
                Form 40-F and Information Circular regarding the
                Audit & Risk Management Committee;
                and




22.
            Perform
                such additional activities, and consider such other matters, within
                the
                scope of its responsibilities, as the Committee or the Board deems
                necessary or appropriate.




**VI.**
            **OVERSIGHT
                OF VARIOUS FINANCIAL EXTERNAL
                REPORTS**




The
      Committee will oversee the adequacy of the financial reporting contained in
      the
      Annual Report, Annual Information Form, prospectuses, Form 40-F
      and any other document of the same nature.




**VII.**
            **INTERNAL
                FUNCTIONING OF THE
                COMMITTEE**




Once
      a year, the Committee reviews the adequacy of its Charter and brings to the
      attention of the Board required changes, if any, for approval. The Committee
      will also, annually, make a critical review of its past performance to ensure
      that it has assumed its responsibilities and executed all required tasks and
      will suggest changes if it failed to do so. This review will also cover
      individual members' performance.




While
      the Committee has the duties and responsibilities set forth in this Charter,
      the
      Committee is not responsible for planning or conducting the audit or for
      determining whether the Fund's financial statements are complete and accurate
      and are in accordance with generally accepted accounting principles. Similarly,
      it is not the responsibility of the Committee to resolve disagreements, if
      any,
      between management and the external auditors. While it is acknowledged that
      the
      Committee is not legally obliged to ensure that EnerMark and the Fund comply
      with all laws and regulations, the spirit and intent of this Charter is that
      the
      Committee shall take reasonable steps to encourage EnerMark and the Fund to
      act
      in full compliance therewith.




**B.**
            **Composition
                of the Audit & Risk Management
                Committee**




The
      members of the Committee are Robert L. Normand (Chair), Glen D. Roane and
      Harry B. Wheeler. Each member of the Committee is independent and
      financially literate within the meaning of Multilateral
      Instrument 52-110.





E-4







**C.**
            **Relevant
                Education and
                Experience**




**Name**
              **(Director
                Since)**
            
            **Principal
                Occupation and Biography**Mr. Robert
                L. Normand (CA)
              (June 2001)
              
              Other
                Public Directorships
              • Quebecor
                World Inc. (commercial print media services)
              • Cambior Inc.
                (gold mining)
              • Aurizon
                Mines (gold mining)
              • ING
                Canada Ltd. (property and casualty insurance)
              • Sportscene Group
                Inc. (chain of restaurants)
              • Fonds
                d'Investissement REA (mutual fund)
            
            Mr. Normand
                is a corporate director and serves on the board of several private
                and
                public corporations operating in various fields of the economy, including
                printing and media, mining and financial. Mr. Normand worked as an
                external auditor and held accounting responsibilities in two industries
                before joining Gaz Métropolitain in 1972 where he ultimately held the
                position of Chief Financial Officer until his retirement in 1997.
                Mr. Normand is a past President of the Financial Executives Institute
                Canada and past Vice President of the Financial Executives Institute
                U.S.Mr. Glen
                D. Roane (BA, MBA)
              (June 2004)
              
              Other
                Public Directorships
              • Destiny
                Resource Services Corp. (oil and gas service business)
              • Badger
                Income Fund (provider of non-destructive excavation services)
              • Valiant
                Energy Inc. (oil and gas producer)
            
            Mr. Roane
                is a corporate director and serves on the board of several private
                and
                public corporations operating primarily in the field of oil and gas
                production and service businesses. Until 1997, Mr. Roane spent almost
                twenty years in the Canadian financial services industry, working
                in
                increasingly senior roles in corporate banking, investment banking
                and the
                management of investments in marketable securities.Mr. Harry
                B. Wheeler (BSC (Geology))
              (January 2001)
              
              Other
                Public Directorships
              • Tenergy Ltd.
                (oil and gas exploration and production)
            
            Mr. Wheeler
                is the President of Colchester Investments, a private financial
                corporation. Mr. Wheeler has extensive experience in the oil and gas
                industry and was operator of his private company before founding
                Cabre
                Exploration Ltd. in 1980, and was Chairman of the Board until
                EnerMark Income Fund acquired Cabre in December 2000.
                Mr. Wheeler is currently a director of a number of public and private
                corporations.




**D.**
            **Pre-Approval
                Policies and
                Procedures**




The
      Committee has implemented a policy restricting the services that may be provided
      by the Fund's auditors and the fees paid to the Fund's auditors. Prior to the
      engagement of the Fund's auditors to perform both audit and non-audit services,
      the Committee pre-approves the provision of the services. In making their
      determination regarding non-audit services, the Committee considers the
      compliance with the policy and the provision of non-audit services in the
      context of avoiding impact on auditor independence. All audit and non-audit
      fees
      paid to Deloitte & Touche LLP in 2005 and 2004 were pre-approved
      by the Committee. Based on the Committee's discussions with management and
      the
      independent auditors, the Committee is of the view that the provision of the
      non-audit services by Deloitte & Touche LLP described above is
      compatible with maintaining that firm's independence from the Fund.





E-5







**E.**
            **External
                Auditor Service Fees**




The
      aggregate fees paid by the Fund to Deloitte & Touche LLP, the
      auditors of the Fund, for professional services rendered in the Fund's last
      two
      fiscal years are as follows:





**2005**
            
            **2004**(in $
                thousands)Audit
                fees(1)
            
            $
            409.2
            
            $
            338.7Audit-related
                fees(2)
            
            
            -
            
            
            -Tax
                fees(3)
            
            
            138.5
            
            
            19.9All
                other fees(4)
            
            
            -
            
            
            -$
            547.7
            
            $
            358.6


___________


Notes:


(1)
            Audit
                fees were for professional services rendered by Deloitte &
                Touche LLP for the audit of the Fund's annual financial statements
                and reviews of the Fund's quarterly financial statements, as well
                as
                services provided in connection with statutory and regulatory filings
                or
                engagements.




(2)
            Audit-related
                fees are for assurance and related services reasonably related to
                the
                performance of the audit or review of the Fund's financial statements
                and
                not reported under "Audit fees" above.




(3)
            Tax
                fees were for tax compliance, tax advice and tax planning. The fees
                were
                for services performed by the Fund's auditors' tax division except
                those
                tax services related to the audit.




(4)
            All
                other fees are fees for products and services provided by the Fund's
                auditors other than those described as "Audit fees", "Audit-related
                fees"
                and "Tax fees".





E-6

























































**Enerplus
      Resources Fund**


The
      Dome Tower


Suite 3000,
      333 - 7th Avenue S.W.


Calgary,
      Alberta, Canada


T2P 2Z1


Telephone:
      (403) 298-2200


Fax:
      (403) 298-2211


www.enerplus.com