Exhibit
      99.1




**ANNUAL INFORMATION FORM**

              

              **For the year ended
                December 31, 2006**

              


              


              
              
              
              
              
              
              
              
              
              
              
              


              

              **March 12,
                2007**


















**TABLE OF CONTENTS**




**Page**GLOSSARY
              OF
              TERMS
            
            iiiABBREVIATIONS AND CONVERSIONS
            
            vPRESENTATION OF ENERPLUS' OIL AND GAS
              RESERVES,
              RESOURCES AND PRODUCTION INFORMATION
            
            viPRESENTATION OF ENERPLUS' FINANCIAL
              INFORMATION
            
            xFORWARD-LOOKING STATEMENTS AND
              INFORMATION
            
            xSTRUCTURE OF ENERPLUS RESOURCES FUND
            
            1GENERAL DEVELOPMENT OF ENERPLUS RESOURCES
              FUND
            
            3Historical Overview
            
            3Developments in the Past Three
              Years
            
            3Events Subsequent to 2006 Year-End
            
            5OIL AND NATURAL GAS RESERVES
            
            6Overview of Reserves
            
            6Summary of Aggregate Enerplus
              Reserves
            
            7Summary of Conventional Oil and Natural
              Gas
              Reserves
            
            9Summary of Joslyn Project Bitumen
              Reserves
            
            18Reconciliation of Reserves
            
            21Reconciliation of Changes in Net Present
              Value of Future Net Revenue
            
            25Undeveloped Reserves
            
            26Proved and Probable Reserves Not on
              Production
            
            27OPERATIONAL INFORMATION
            
            27Overview
            
            27Description of Principal Properties
              and
              Operations
            
            27Summary of Principal Production
              Locations
            
            37Oil and Natural Gas Wells and Unproved
              Properties
            
            38Exploration and Development
              Activities
            
            38Quarterly Production History
            
            39Quarterly Netback History
            
            40Abandonment and Reclamation Costs
            
            42Tax Horizon
            
            42Costs Incurred
            
            42Marketing Arrangements and Forward
              Contracts
            
            43Environment, Health and Safety
            
            43Impact of Environmental Protection
              Requirements
            
            45Additional Operational Information
            
            45INFORMATION RESPECTING ENERPLUS RESOURCES
              FUND
            
            46Description of the Trust Units and the
              Trust
              Indenture
            
            46Description of the Royalty Agreements
              and
              EnerMark's Subordinated Notes
            
            52Management and Corporate Governance
            
            54Unitholder Rights Plan
            
            54DEBT OF ENERPLUS
            
            55Bank Credit Facility
            
            55Senior Unsecured Notes
            
            56DISTRIBUTIONS TO UNITHOLDERS
            
            57Cash Distributions
            
            57Distribution History
            
            58Canadian Tax Reporting Matters
            
            58U.S. Tax Reporting Matters
            
            58INDUSTRY CONDITIONS
            
            59RISK FACTORS
            
            63MARKET FOR SECURITIES
            
            77DIRECTORS AND OFFICERS
            
            78INTEREST OF MANAGEMENT AND OTHERS IN
              MATERIAL
              TRANSACTIONS
            
            81MATERIAL CONTRACTS AND DOCUMENTS AFFECTING
              THE
              RIGHTS OF SECURITYHOLDERS
            
            81INTERESTS OF EXPERTS
            
            82REGISTRAR AND TRANSFER AGENT
            
            82ADDITIONAL INFORMATION
            
            82APPENDIX "A" — REPORT ON RESERVES
              DATA BY INDEPENDENT QUALIFIED RESERVES EVALUATOR OR AUDITOR
            
            A-1APPENDIX "B" — REPORT ON RESERVES
              DATA BY INDEPENDENT QUALIFIED RESERVES EVALUATOR OR AUDITOR
            
            B-1APPENDIX "C" — REPORT ON RESERVES
              DATA BY INDEPENDENT QUALIFIED RESERVES EVALUATOR OR AUDITOR
            
            C-1APPENDIX "D" — REPORT OF MANAGEMENT
              AND DIRECTORS ON RESERVES DATA AND OTHER INFORMATION
            
            D-1APPENDIX "E" — AUDIT & RISK
              MANAGEMENT COMMITTEE DISCLOSURE
            
            E-1APPENDIX "F" — SFAS NO. 69
              SUPPLEMENTAL RESERVE INFORMATION
            
            F-1








**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,
      resources and operations have the meanings set forth under "Presentation of
      Enerplus' Oil and Gas Reserves, Resources 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 10o 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 February 1, 2007 and effective
      December 31, 2006, utilizing commodity price forecasts of Sproule
      (for internal consistency in Enerplus' reserves reporting) dated
      December 31, 2006;




" **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 an indirect 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 an indirect wholly owned subsidiary
      of
      the Fund;




" **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 an indirect wholly owned subsidiary of the Fund;




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




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




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




" **GLJ Joslyn Resources
      Report** " means the independent engineering
      evaluation of the contingent resources attributable to Enerplus' interest in
      the
      Joslyn Project prepared by GLJ dated February 2, 2007 and effective
      December 31, 2006;




" **GLJ Reserves
      Report** " means the independent engineering
      evaluation of the reserves attributable to Enerplus' interest in the Joslyn
      Project prepared by GLJ dated January 29, 2007 and effective
      December 31, 2006, utilizing commodity price forecasts
      of Sproule (for internal consistency in Enerplus' reserves reporting) dated
      December 31, 2006;




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




" **Income Trust Tax
      Proposals** " has the meaning ascribed thereto under
      "General Development of the Fund — Developments in the Past Three
      Years — Federal Government Pronouncements on Income Trusts";




" **Joslyn
      Bitumen** " means the bitumen produced from the Joslyn
      Project;








iii




" **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;




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




" **North Mine** "
      means the northern portion of the Joslyn Lease, currently designated as
      a mineable portion of the Joslyn Project;




" **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;




" **SEC** "
      means the United States Securities and Exchange Commission;




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




" **South Mine** "
      means the southern portion of the Joslyn Lease on which potential
      future bitumen resources have been identified;




" **Sproule
      Report** " means the independent engineering
      evaluation of Enerplus' Canadian conventional oil, NGLs and natural gas
      interests prepared by Sproule dated February 14, 2007 and effective
      December 31, 2006, utilizing commodity price forecasts
      of Sproule dated December 31, 2006;




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




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




" **Total** "
      means Total E&P Canada Ltd., a wholly owned subsidiary of
      Total S.A., which (through its subsidiary, Deer Creek Energy Limited)
      is the operator of the Joslyn Project;




" **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(1)**
            
            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.**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




Note:


(1) A
      BOE
      conversion ratio of 6 Mcf:1 BOE is based on an energy equivalency conversion
      method primarily at the burner tip and does not represent a value equivalency
      at
      the wellhead.




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, RESOURCES AND PRODUCTION INFORMATION**




**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, 2006 and the information contained
      in the Annual Information Form has been prepared as of March 12, 2007.




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




**Disclosure of Reserves and Production 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. Furthermore, the estimates of future net revenue
      attributable to Enerplus' reserves in this Annual Information Form do not give
      effect to the Income Trust Tax Proposals: see "Oil and Natural Gas
      Reserves — Overview of Reserves" for additional
      information.**




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 with
      reasonable certainty 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 and similar payments, as well as on a "net" basis.
      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. As a consequence, Enerplus'






vi




production volumes and reserve estimates may not be comparable
      to those made by companies utilizing United States disclosure standards.
      Furthermore, Enerplus has disclosed certain "contingent resources". For a
      description of the definition of, and the risks and uncertainties surrounding
      the disclosure of, contingent resources, see "— Disclosure of Contingent
      Resources for the Joslyn Project" below.




Notwithstanding the
      above, Enerplus has included as Appendix "F" to this Annual
      Information Form certain disclosure relating to Enerplus' oil and gas reserves
      and operations in accordance with U.S. Financial Accounting Standards
      Board's Statement No. 69 — Disclosures
      About Oil and Gas Producing Activities , which complies
      with the SEC's guidelines regarding disclosure of oil and gas reserves.




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.




**Disclosure of Contingent Resources for the Joslyn
      Project**




In this Annual
      Information Form, Enerplus has disclosed estimated volumes of "contingent
      resources" that have been prepared by GLJ pursuant to the GLJ Joslyn Resources
      Report and which relate to certain potential mineable portions of the Joslyn
      Lease. " **Resources** " are
      oil and gas volumes that are estimated to have originally existed in the earth's
      crust as naturally occurring accumulations but are not capable of being
      classified as "reserves" as described below. " **Contingent resources** " is a
      recognized category of resources in the COGE Handbook and is defined as "those
      quantities of oil and gas estimated on a given date to be potentially
      recoverable from known accumulations but are not currently economic". However,
      as indicated in the COGE Handbook, criteria other than economics may cause
      a
      quantity to be classified as a resource rather than a reserve. Section 5 of
      Volume 2 of the COGE Handbook states that the following issues are
      contingencies that affect the classification as resources rather than reserves:
      ownership considerations; drilling requirements; testing requirements;
      regulatory considerations; infrastructure and market considerations; timing
      of
      production and development; and economic requirements. Contingent resources
      may
      also include those quantities of hydrocarbons that are estimated to be
      potentially recoverable using technology that is under development. **Resources and contingent resources do not constitute,
      and should
      not be confused with, reserves.** See "Risk
      Factors — Risks Related to Enerplus' Business and
      Operations — Enerplus' actual reserves and resources will vary from
      its reserve and resource estimates, and those variations could be material."




There is no
      certainty that Enerplus will produce any portion of the volumes currently
      classified as "contingent resources". The primary contingencies which currently
      prevent the classification of Enerplus' disclosed contingent resources
      associated with the Joslyn Project as "reserves" consist of current
      uncertainties around the specific scope of the Joslyn Project (and in particular
      the finalization of an overall lease development plan), timing of the proposed
      development as it relates to proposed changes in the lease development plan,
      proposed reliance on technologies that have not yet been demonstrated to be
      commercially applicable in oil sands applications, the uncertainty regarding
      marketing plans for production from the subject areas and improved estimation
      of
      project costs. Enerplus believes that development of the Joslyn Project will
      proceed, including the development of the contingent resources associated with
      the North Mine and South Mine as disclosed in this Annual Information Form.
      However, there are a number of inherent risks and contingencies associated
      with
      such development, including commodity price fluctuations, project costs and
      those other risks and contingencies described above and under "Risk Factors"
      in
      this Annual Information Form and particularly under "Risk
      Factors — Risks Related to Enerplus' Business and
      Operations — The Joslyn Project is in the early development stage and
      is subject to numerous risks."




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




In addition to
      the terms having defined meanings set forth in NI 51-101, the terms set
      forth below have the following meanings when used in this Annual Information
      Form:




" **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. See "— Disclosure of Reserves and Production
      Information" above.






vii


" **gross** "
      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 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 and Levels of Certainty for
      Reported Reserves**




" **Reserves** "
      are those remaining
      quantities of oil and gas anticipated to be economically recoverable from known
      accumulations. Reserves may be divided into proved and probable categories
      (as
      well as possible reserves, which Enerplus does not report).




" **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.




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:


**Development and Production Status**




Each of the
      reserves categories reported by Enerplus (Proved and Probable) 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




viii




must
      have
      previously been on production, and the date of resumption of production must
      be
      known with reasonable certainty.




• " **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 or Probable) to which they
      are assigned.




**Description of Price and Cost Assumptions**




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


(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).


ix


**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 14 to the
      Fund's audited consolidated financial statements for the year ended
      December 31, 2006, which are available on the Fund's SEDAR profile at
www.sedar.com, on EDGAR at www.sec.gov as part of the
      Form 6-K filed with the SEC on February 23, 2007, and on Enerplus'
      website at www.enerplus.com.




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


**FORWARD-LOOKING STATEMENTS
      AND
      INFORMATION**




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:


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







x







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, 2006, which is
      available through the internet on Enerplus' SEDAR profile at
www.sedar.com, on EDGAR at www.sec.gov as part of the
      Form 6-K filed with the SEC on February 23, 2007, and on Enerplus'
      website at www.enerplus.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, on EDGAR at www.sec.gov and on Enerplus' website at
www.enerplus.com.








xi




**ENERPLUS
      RESOURCES FUND**


**Annual
      Information
      Formfor the year ended December 31, 2006**


**STRUCTURE
      OF ENERPLUS
      RESOURCES FUND**


**Enerplus Resources Fund**




Enerplus
      Resources Fund is an energy 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 its directly and indirectly owned subsidiaries 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, 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 maximize value and cash distributions to its unitholders
      over the long-term from the net cash flow generated by the operation and
      development of its Operating Subsidiaries' existing crude oil and natural gas
      properties and other energy-related assets and the strategic acquisition and
      rationalization of properties and assets. See "Operational
      Information — Overview".




**Operating Subsidiaries**




The Fund's
      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 and contingent bitumen resources 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 securities of each of EnerMark, ERC, Enerplus Oil & Gas,
      ECT and Enerplus USA are indirectly owned by the Fund.








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 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 coalbed methane (also known as
      natural gas from coal) project in central Alberta.




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 created
      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 and certain other provinces have adopted similar unitholder
      liability legislation. 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.








3




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 $5.8 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. This acquisition was
      accounted for as an asset acquisition in accordance with GAAP.




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.




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.




Participation in Joslyn Project and Other Oil Sands
      Projects




Enerplus
      initially acquired a 16% working interest in the Joslyn Project in 2002. The
      remaining 84% working interest is owned by Total, which acquired the original
      operator and majority owner of the Joslyn Project (Deer Creek Energy Limited)
      in
      2005. Total 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 Energy Limited prior to its
      acquisition by Total. Included in the sale is an area of mutual interest
      agreement which has been designed to allow Enerplus and Laricina to jointly
      pursue additional in-situ oil sands ventures.




S&P/TSX Index Inclusion




In 2005,
      Standard and Poor's announced that it would 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 and the remaining one-half weighting occurred in
      mid-March 2006.




Federal Government Pronouncements on Income Trusts




On
      October 31, 2006, the Canadian federal government (the " **Government** ") announced
      plans to
      introduce a tax on publicly traded income trusts (other than real estate
      investment trusts) to generally tax income trusts at the same
      effective tax rates as Canadian corporations (the " **Income Trust Tax Proposals** "). For
      existing income trusts, such as the Fund, the new tax measures would not be
      effective until 2011, provided that such trusts comply with certain "normal
      growth" parameters regarding equity growth until that time. Those parameters
      are
      designed to ensure that income trusts do not undertake what the Government
      has
      deemed to be "undue expansion" in an attempt to circumvent the Government's
      intention to halt the growth of the income trust industry in Canada. A "Notice
      of Ways and Means Motion" was passed in the Canadian Parliament shortly after








4




the Government announcement. This notice was a one-page
      summary of the Income Trust Tax Proposals and it did not identify any specific
      amendments to the Tax Act.




On
      December 15, 2006, the Government announced guidance regarding a "normal
      growth" safe harbour for future issuances of equity capital. The safe harbour
      amount will be measured by reference to the individual trust's market
      capitalization as of the end of trading on October 31, 2006 (which was
      approximately $7.5 billion for the Fund). For the period from
      November 1, 2006 to December 31, 2007, a trust's safe harbour amount
      will be 40 percent of the October 31, 2006 market capitalization
      benchmark, and for each of the years 2008 through and including 2010 a trust's
      safe harbour amount will be 20 percent of the benchmark, cumulatively
      allowing equity growth of up to 100 percent until 2011. In addition,
      Enerplus understands that income trusts will be able to issue equity to retire
      debt existing on October 31, 2006 without eroding their safe
      harbour limits. The guidance regarding "normal growth" is administrative in
      nature and is not law and can be revised without an Act of the
      Canadian Parliament.




On
      December 21, 2006, the Government released draft legislative proposals to
      amend the Tax Act with respect to the Income Trust Tax Proposals and
      requested comments from stakeholders. In late January 2007 the House of
      Commons Standing Committee on Finance (the " **Standing
      Committee** ") held special hearings on the Income
      Trust Tax Proposals and the draft legislation. On February 28, 2007, the
      Standing Committee released its report that recommended, among other things,
      that the proposed income trust tax be reduced from 31.5% to 10% with such
      tax to commence immediately and be refundable to Canadian investors or
      that the proposed transition period be extended from four years to ten years.
      The Government is not bound by any of the report recommendations and it is
      expected that the Government will proceed with the Income Trust Tax Proposals
      in
      their original form. As a result, at this time Enerplus is unable to determine
      the impact, if any, this report may have on the Income Trust Tax Proposals.




At this time,
      the draft legislation to give effect to the Income Trust Tax Proposals has
      not
      yet been introduced into the Canadian House of Commons and therefore has not
      been approved or declared in force by the Government. Accordingly, it is
      uncertain when the proposed legislation could be passed by the Canadian
      Parliament, if at all, or as to what form, if any, changes in Canadian income
      tax laws will take as a result of such proposal. Should the proposed tax
      legislation become substantially enacted, the Fund's future income taxes
      disclosed in its financial statements may be adjusted to include temporary
      differences between the accounting and tax bases of the Fund's assets and
      liabilities. In addition, the reported estimated net present value of future
      net
      revenues from Enerplus' oil and natural gas reserves may be adjusted to include
      an estimate of such revenues on an "after-tax" basis to reflect the impact
      of
      the income trust tax. Subject to clarity through the legislative process,
      Enerplus will assess alternative organizational structures during the four
      year
      transition period.




For additional
      information, see "Oil and Natural Gas Reserves — Overview of
      Reserves", "Operational Information — Tax Horizon" and "Risk
      Factors — Risks Relating to Enerplus' Structure and Ownership of the
      Trust Units" in this Annual Information Form.




**Events Subsequent to 2006 Year-End**




Acquisition of Gross Overriding Royalty Interests in
      U.S.




On
      January 31, 2007, Enerplus acquired various gross overriding royalty
      (" **GORR** ") interests
      in
      the state of Wyoming for total consideration of US$52 million
      (CDN$60 million). This acquisition represents a modest addition to
      Enerplus' assets in the United States and establishes a new area which
      Enerplus believes has significant natural gas development potential.




The subject
      assets produce natural gas from the EnCana Corporation-operated Jonah gas field
      in Wyoming, which is one of the largest natural gas fields in the U.S. The
      acquisition consisted of a GORR of approximately 0.5% on approximately
      650 producing natural gas wells in the Jonah field. Enerplus has
      acquired a net royalty interest that is equivalent
      to approximately 540 BOE/d of daily production and
      approximately 2.2 million BOE of Proved Reserves and 2.9 million BOE
      of Proved plus Probable Reserves based on independent third party engineering
      evaluations effective December 31, 2006. Enerplus believes the field has a
      significant number of additional infill drilling locations that will provide
      growth potential for the future. Enerplus will not be required to expend any
      future development capital on the assets. Enerplus expects the net operating
      cash flow per BOE, net of all applicable U.S. taxes, to be significantly
      higher than that of its existing production due to the nature of the GORR which
      is not subject to deductions for operating costs and royalties.








5




**OIL
      AND NATURAL GAS
      RESERVES**




**Overview of Reserves**




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 90% 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 rate
      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 rate assumptions utilized
      by Sproule.




The following
      tables summarize, as at December 31, 2006, Enerplus' oil, NGLs and natural
      gas reserves and the estimated net present values of future net revenues
      associated with such reserves, together with certain information, estimates
      and
      assumptions associated with such reserve estimates. The following reserves
      information does not include the various gross overriding royalty interests
      in
      Wyoming, U.S.A. acquired by Enerplus on January 31, 2007 as described under
      "General Development of Enerplus Resources Fund — Events Subsequent to
      2006 Year-End — Acquisition of Gross Overriding Royalty Interests in
      U.S.". 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 of Enerplus' bitumen reserves are located in Canada.




All estimates
      of 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 (which
      currently only consist of income taxes related to U.S. operations).
**All estimates of future net revenues associated with Enerplus' oil,
      NGLs
      and natural gas reserves are presented on the basis that Enerplus will not
      pay
      cash income taxes in Canada in the future due to Enerplus' current structure
      as
      an income trust and Canadian tax laws currently in effect, and do not give
      effect to the Income Trust Tax Proposals.** Enerplus'
      U.S. operations are subject to cash income taxes, and as a result Enerplus'
      U.S. reserves are disclosed net of the taxes Enerplus estimates will be
      payable after taking into account inter-company debt within Enerplus' structure.
      The Canadian federal government has announced the Income Trust Tax Proposals
      which are designed to generally tax income trusts such as Enerplus
      at the same effective tax rates as Canadian corporations, effective
      for the 2011 tax year. Such proposals are not yet approved or in force and
      it is
      uncertain as to what form, if any, changes in Canadian income tax laws will
      take
      as a result of such proposal. **Any changes in
      Canadian income tax laws that may result from the Income Trust Tax Proposals
      could adversely affect the estimated future net revenues associated with
      Enerplus' oil and gas reserves. If the draft legislation designed to give effect
      to the Income Trust Tax Proposals is enacted as currently proposed, Enerplus
      intends to provide updated reserves information which would present the
      estimated future net revenues from Enerplus' reserves on an after-tax basis
      that
      would reflect the impact of the income trust tax.** For additional information, see "General Development
      of Enerplus
      Resources Fund — Developments in the Past Three
      Years — Federal Government Pronouncements on Income Trusts",
      "Operational Information — Tax Horizon" and "Risk
      Factors — Risks Relating to Enerplus' Structure and Ownership of the
      Trust Units" in this Annual Information Form.




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 NGLs 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**








6




**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, Resources and Production
      Information" in conjunction with the following tables
      and notes.**




**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 Reserves 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 Reserves 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 ReservesAs of December 31, 2006Company Interest
      Reserves,Forecast Prices and Costs**


**OIL
              AND GAS NATURAL
              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
            
            
            66,458
            
            
            28,932
            
            
            2,479
            
            
            97,869
            
            
            11,434
            
            
            727,596
            
            
            230,569United States
            
            
            21,933
            
            
            —
            
            
            —
            
            
            21,933
            
            
            —
            
            
            13,626
            
            
            24,204**Total**
            
            
            88,391
            
            
            28,932
            
            
            2,479
            
            
            119,802
            
            
            11,434
            
            
            741,222
            
            
            254,773Proved
              Developed Non-ProducingCanada
            
            
            537
            
            
            —
            
            
            —
            
            
            537
            
            
            621
            
            
            17,317
            
            
            4,044United States
            
            
            871
            
            
            —
            
            
            —
            
            
            871
            
            
            —
            
            
            724
            
            
            992**Total**
            
            
            1,408
            
            
            —
            
            
            —
            
            
            1,408
            
            
            621
            
            
            18,041
            
            
            5,036Proved
              UndevelopedCanada
            
            
            3,509
            
            
            2,221
            
            
            6,251
            
            
            11,981
            
            
            635
            
            
            160,348
            
            
            39,341United States
            
            
            587
            
            
            —
            
            
            —
            
            
            587
            
            
            —
            
            
            450
            
            
            662**Total**
            
            
            4,096
            
            
            2,221
            
            
            6,251
            
            
            12,568
            
            
            635
            
            
            160,798
            
            
            40,003Total
              ProvedCanada
            
            
            70,504
            
            
            31,153
            
            
            8,730
            
            
            110,387
            
            
            12,690
            
            
            905,261
            
            
            273,954United States
            
            
            23,391
            
            
            —
            
            
            —
            
            
            23,391
            
            
            —
            
            
            14,800
            
            
            25,858**Total**
            
            
            93,895
            
            
            31,153
            
            
            8,730
            
            
            133,778
            
            
            12,690
            
            
            920,061
            
            
            299,812ProbableCanada
            
            
            16,872
            
            
            8,912
            
            
            47,998
            
            
            73,782
            
            
            3,777
            
            
            306,804
            
            
            128,693United States
            
            
            8,637
            
            
            —
            
            
            —
            
            
            8,637
            
            
            —
            
            
            37,221
            
            
            14,840**Total**
            
            
            25,509
            
            
            8,912
            
            
            47,998
            
            
            82,419
            
            
            3,777
            
            
            344,025
            
            
            143,533Total
              Proved plus ProbableCanada
            
            
            87,376
            
            
            40,065
            
            
            56,728
            
            
            184,169
            
            
            16,467
            
            
            1,212,065
            
            
            402,647United States
            
            
            32,028
            
            
            —
            
            
            —
            
            
            32,028
            
            
            —
            
            
            52,021
            
            
            40,698**Total**
            
            
            119,404
            
            
            40,065
            
            
            56,728
            
            
            216,197
            
            
            16,467
            
            
            1,264,086
            
            
            443,345








7




**Summary of Aggregate Net
      Present
      Valueof Future Net Revenue Attributable to Oil and Gas ReservesAs of
      December 31, 2006Company 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
              
              
              6,705
              
              
              4,479
              
              
              3,464
              
              
              2,877
              
              
              2,489
              
              
              6,705
              
              
              4,479
              
              
              3,464
              
              
              2,877
              
              
              2,489United States
              
              
              1,064
              
              
              821
              
              
              668
              
              
              565
              
              
              491
              
              
              804
              
              
              624
              
              
              509
              
              
              431
              
              
              375**Total**
              
              
              7,769
              
              
              5,300
              
              
              4,132
              
              
              3,442
              
              
              2,980
              
              
              7,509
              
              
              5,103
              
              
              3,973
              
              
              3,308
              
              
              2,864Proved
                  Developed Non-ProducingCanada
              
              
              120
              
              
              75
              
              
              56
              
              
              45
              
              
              39
              
              
              120
              
              
              75
              
              
              56
              
              
              45
              
              
              39United States
              
              
              39
              
              
              29
              
              
              24
              
              
              20
              
              
              16
              
              
              25
              
              
              19
              
              
              16
              
              
              13
              
              
              10**Total**
              
              
              159
              
              
              104
              
              
              80
              
              
              65
              
              
              55
              
              
              145
              
              
              94
              
              
              72
              
              
              58
              
              
              49Proved
                  UndevelopedCanada
              
              
              556
              
              
              385
              
              
              272
              
              
              196
              
              
              142
              
              
              556
              
              
              385
              
              
              272
              
              
              196
              
              
              142United States
              
              
              22
              
              
              15
              
              
              11
              
              
              8
              
              
              6
              
              
              26
              
              
              16
              
              
              10
              
              
              7
              
              
              5**Total**
              
              
              578
              
              
              400
              
              
              283
              
              
              204
              
              
              148
              
              
              582
              
              
              401
              
              
              282
              
              
              203
              
              
              147Total
                  ProvedCanada
              
              
              7,381
              
              
              4,939
              
              
              3,792
              
              
              3,118
              
              
              2,670
              
              
              7,381
              
              
              4,939
              
              
              3,792
              
              
              3,118
              
              
              2,670United States
              
              
              1,125
              
              
              865
              
              
              703
              
              
              593
              
              
              513
              
              
              855
              
              
              659
              
              
              535
              
              
              451
              
              
              390**Total
                  Proved Conventional Reserves**
              
              
              8,506
              
              
              5,804
              
              
              4,495
              
              
              3,711
              
              
              3,183
              
              
              8,236
              
              
              5,598
              
              
              4,327
              
              
              3,569
              
              
              3,060ProbableCanada
              
              
              2,721
              
              
              1,242
              
              
              745
              
              
              516
              
              
              387
              
              
              2,721
              
              
              1,242
              
              
              745
              
              
              516
              
              
              387United States
              
              
              630
              
              
              333
              
              
              198
              
              
              128
              
              
              88
              
              
              419
              
              
              217
              
              
              126
              
              
              78
              
              
              51**Total
                  Probable Conventional Reserves**
              
              
              3,351
              
              
              1,575
              
              
              943
              
              
              644
              
              
              475
              
              
              3,140
              
              
              1,459
              
              
              871
              
              
              594
              
              
              438**Total
                  Proved Plus Probable Conventional Reserves**
              
              
              11,857
              
              
              7,379
              
              
              5,438
              
              
              4,355
              
              
              3,658
              
              
              11,376
              
              
              7,057
              
              
              5,198
              
              
              4,163
              
              
              3,498**BITUMEN
                  RESERVES**Proved
                  Developed Producing
              
              
              20
              
              
              16
              
              
              13
              
              
              11
              
              
              10
              
              
              20
              
              
              16
              
              
              13
              
              
              11
              
              
              10Proved
                  Undeveloped
              
              
              39
              
              
              20
              
              
              10
              
              
              4
              
              
              1
              
              
              39
              
              
              20
              
              
              10
              
              
              4
              
              
              1**Total
                  Proved**
              
              
              59
              
              
              36
              
              
              23
              
              
              15
              
              
              11
              
              
              59
              
              
              36
              
              
              23
              
              
              15
              
              
              11Probable
              
              
              453
              
              
              104
              
              
              25
              
              
              2
              
              
              (8
              )
              
              453
              
              
              104
              
              
              25
              
              
              2
              
              
              (8
              )**Total
                  Proved Plus Probable Bitumen Reserves**
              
              
              512
              
              
              140
              
              
              48
              
              
              17
              
              
              3
              
              
              512
              
              
              140
              
              
              48
              
              
              17
              
              
              3**TOTAL
                  CONVENTIONAL RESERVES AND BITUMEN RESERVES**
              
              
              12,369
              
              
              7,519
              
              
              5,486
              
              
              4,372
              
              
              3,661
              
              
              11,888
              
              
              7,197
              
              
              5,246
              
              
              4,180
              
              
              3,501








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
      ReservesAs of December 31, 2006** **Forecast Prices
      and Costs**


**OIL
                  AND NATURAL GAS RESERVES****Light
                  & 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
              
              
              66,458
              
              
              65,681
              
              
              60,673
              
              
              28,932
              
              
              28,911
              
              
              25,889
              
              
              727,596
              
              
              704,228
              
              
              587,410United States
              
              
              21,933
              
              
              21,933
              
              
              18,280
              
              
              —
              
              
              —
              
              
              —
              
              
              13,626
              
              
              13,626
              
              
              11,375**Total**
              
              
              88,391
              
              
              87,614
              
              
              78,953
              
              
              28,932
              
              
              28,911
              
              
              25,889
              
              
              741,222
              
              
              717,854
              
              
              598,785Proved
                  Developed Non-ProducingCanada
              
              
              537
              
              
              537
              
              
              277
              
              
              —
              
              
              —
              
              
              —
              
              
              17,317
              
              
              16,897
              
              
              13,562United States
              
              
              871
              
              
              871
              
              
              727
              
              
              —
              
              
              —
              
              
              —
              
              
              724
              
              
              724
              
              
              608**Total**
              
              
              1,408
              
              
              1,408
              
              
              1,004
              
              
              —
              
              
              —
              
              
              —
              
              
              18,041
              
              
              17,621
              
              
              14,170Proved
                  UndevelopedCanada
              
              
              3,509
              
              
              3,500
              
              
              3,184
              
              
              2,221
              
              
              2,219
              
              
              1,890
              
              
              160,348
              
              
              156,655
              
              
              136,033United States
              
              
              587
              
              
              587
              
              
              493
              
              
              —
              
              
              —
              
              
              —
              
              
              450
              
              
              450
              
              
              377**Total**
              
              
              4,096
              
              
              4,087
              
              
              3,677
              
              
              2,221
              
              
              2,219
              
              
              1,890
              
              
              160,798
              
              
              157,105
              
              
              136,410Total
                  Proved ReservesCanada
              
              
              70,504
              
              
              69,718
              
              
              64,134
              
              
              31,153
              
              
              31,130
              
              
              27,779
              
              
              905,261
              
              
              877,780
              
              
              737,005United States
              
              
              23,391
              
              
              23,391
              
              
              19,500
              
              
              —
              
              
              —
              
              
              —
              
              
              14,800
              
              
              14,800
              
              
              12,360**Total**
              
              
              93,895
              
              
              93,109
              
              
              83,634
              
              
              31,153
              
              
              31,130
              
              
              27,779
              
              
              920,061
              
              
              892,580
              
              
              749,365Probable
                  ReservesCanada
              
              
              16,872
              
              
              16,690
              
              
              15,077
              
              
              8,912
              
              
              8,903
              
              
              8,035
              
              
              306,804
              
              
              299,699
              
              
              253,635United States
              
              
              8,637
              
              
              8,637
              
              
              7,091
              
              
              —
              
              
              —
              
              
              —
              
              
              37,221
              
              
              37,221
              
              
              30,985**Total**
              
              
              25,509
              
              
              25,327
              
              
              22,168
              
              
              8,912
              
              
              8,903
              
              
              8,035
              
              
              344,025
              
              
              336,920
              
              
              284,620Total
                  Proved Plus Probable ReservesCanada
              
              
              87,376
              
              
              86,408
              
              
              79,211
              
              
              40,065
              
              
              40,033
              
              
              35,814
              
              
              1,212,065
              
              
              1,177,479
              
              
              990,640United States
              
              
              32,028
              
              
              32,028
              
              
              26,591
              
              
              —
              
              
              —
              
              
              —
              
              
              52,021
              
              
              52,021
              
              
              43,345**Total**
              
              
              119,404
              
              
              118,436
              
              
              105,802
              
              
              40,065
              
              
              40,033
              
              
              35,814
              
              
              1,264,086
              
              
              1,229,500
              
              
              1,033,985


(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
              
              
              11,434
              
              
              11,241
              
              
              7,978
              
              
              228,090
              
              
              223,205
              
              
              192,441United States
              
              
              —
              
              
              —
              
              
              —
              
              
              24,204
              
              
              24,204
              
              
              20,175**Total**
              
              
              11,434
              
              
              11,241
              
              
              7,978
              
              
              252,294
              
              
              247,409
              
              
              212,616Proved
                  Developed Non-ProducingCanada
              
              
              621
              
              
              606
              
              
              437
              
              
              4,044
              
              
              3,958
              
              
              2,975United States
              
              
              —
              
              
              —
              
              
              —
              
              
              992
              
              
              992
              
              
              828**Total**
              
              
              621
              
              
              606
              
              
              437
              
              
              5,036
              
              
              4,950
              
              
              3,803Proved
                  UndevelopedCanada
              
              
              635
              
              
              634
              
              
              441
              
              
              33,090
              
              
              32,462
              
              
              28,187United States
              
              
              —
              
              
              —
              
              
              —
              
              
              662
              
              
              662
              
              
              556**Total**
              
              
              635
              
              
              634
              
              
              441
              
              
              33,752
              
              
              33,124
              
              
              28,743Total
                  Proved ReservesCanada
              
              
              12,690
              
              
              12,481
              
              
              8,856
              
              
              265,224
              
              
              259,625
              
              
              223,603United States
              
              
              —
              
              
              —
              
              
              —
              
              
              25,858
              
              
              25,858
              
              
              21,559**Total**
              
              
              12,690
              
              
              12,481
              
              
              8,856
              
              
              291,082
              
              
              285,483
              
              
              245,162Probable
                  ReservesCanada
              
              
              3,777
              
              
              3,708
              
              
              2,665
              
              
              80,695
              
              
              79,252
              
              
              68,049United States
              
              
              —
              
              
              —
              
              
              —
              
              
              14,840
              
              
              14,840
              
              
              12,256**Total**
              
              
              3,777
              
              
              3,708
              
              
              2,665
              
              
              95,535
              
              
              94,092
              
              
              80,305Total
                  Proved Plus Probable ReservesCanada
              
              
              16,467
              
              
              16,189
              
              
              11,521
              
              
              345,919
              
              
              338,877
              
              
              291,652United States
              
              
              —
              
              
              —
              
              
              —
              
              
              40,698
              
              
              40,698
              
              
              33,815**Total**
              
              
              16,467
              
              
              16,189
              
              
              11,521
              
              
              386,617
              
              
              379,575
              
              
              325,467












10




**Summary of Net Present Value of
      Future
      Net RevenueAttributable to Conventional Oil and Gas ReservesAs of
      December 31, 2006**




**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
              
              
              6,705
              
              
              4,479
              
              
              3,464
              
              
              2,877
              
              
              2,489
              
              
              6,705
              
              
              4,479
              
              
              3,464
              
              
              2,877
              
              
              2,489United States
              
              
              1,064
              
              
              821
              
              
              668
              
              
              565
              
              
              491
              
              
              804
              
              
              624
              
              
              509
              
              
              431
              
              
              375**Total**
              
              
              7,769
              
              
              5,300
              
              
              4,132
              
              
              3,442
              
              
              2,980
              
              
              7,509
              
              
              5,103
              
              
              3,973
              
              
              3,308
              
              
              2,864Proved
                  Developed Non-ProducingCanada
              
              
              120
              
              
              75
              
              
              56
              
              
              45
              
              
              39
              
              
              120
              
              
              75
              
              
              56
              
              
              45
              
              
              39United States
              
              
              39
              
              
              29
              
              
              24
              
              
              20
              
              
              16
              
              
              25
              
              
              19
              
              
              16
              
              
              13
              
              
              10**Total**
              
              
              159
              
              
              104
              
              
              80
              
              
              65
              
              
              55
              
              
              145
              
              
              94
              
              
              72
              
              
              58
              
              
              49Proved
                  UndevelopedCanada
              
              
              556
              
              
              385
              
              
              272
              
              
              196
              
              
              142
              
              
              556
              
              
              385
              
              
              272
              
              
              196
              
              
              142United States
              
              
              22
              
              
              15
              
              
              11
              
              
              8
              
              
              6
              
              
              26
              
              
              16
              
              
              10
              
              
              7
              
              
              5**Total**
              
              
              578
              
              
              400
              
              
              283
              
              
              204
              
              
              148
              
              
              582
              
              
              401
              
              
              282
              
              
              203
              
              
              147Total
                  ProvedCanada
              
              
              7,381
              
              
              4,939
              
              
              3,792
              
              
              3,118
              
              
              2,670
              
              
              7,381
              
              
              4,939
              
              
              3,792
              
              
              3,118
              
              
              2,670United States
              
              
              1,125
              
              
              865
              
              
              703
              
              
              593
              
              
              513
              
              
              855
              
              
              659
              
              
              535
              
              
              451
              
              
              390**Total**
              
              
              8,506
              
              
              5,804
              
              
              4,495
              
              
              3,711
              
              
              3,183
              
              
              8,236
              
              
              5,598
              
              
              4,327
              
              
              3,569
              
              
              3,060ProbableCanada
              
              
              2,721
              
              
              1,242
              
              
              745
              
              
              516
              
              
              387
              
              
              2,721
              
              
              1,242
              
              
              745
              
              
              516
              
              
              387United States
              
              
              630
              
              
              333
              
              
              198
              
              
              128
              
              
              88
              
              
              419
              
              
              217
              
              
              126
              
              
              78
              
              
              51**Total**
              
              
              3,351
              
              
              1,575
              
              
              943
              
              
              644
              
              
              475
              
              
              3,140
              
              
              1,459
              
              
              871
              
              
              594
              
              
              438Total
                  Proved Plus ProbableCanada
              
              
              10,102
              
              
              6,181
              
              
              4,537
              
              
              3,634
              
              
              3,057
              
              
              10,102
              
              
              6,181
              
              
              4,537
              
              
              3,634
              
              
              3,057United States
              
              
              1,755
              
              
              1,198
              
              
              901
              
              
              721
              
              
              601
              
              
              1,274
              
              
              876
              
              
              661
              
              
              529
              
              
              441**Total**
              
              
              11,857
              
              
              7,379
              
              
              5,438
              
              
              4,355
              
              
              3,658
              
              
              11,376
              
              
              7,057
              
              
              5,198
              
              
              4,163
              
              
              3,498








11




**Summary of Conventional Oil and
      Gas
      ReservesAs of December 31, 2006** **Constant Prices
      and Costs**




**OIL
                  AND NATURAL GAS RESERVES****Light
                  & 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
              
              
              66,969
              
              
              66,192
              
              
              61,156
              
              
              29,050
              
              
              29,030
              
              
              25,993
              
              
              708,394
              
              
              685,157
              
              
              571,488United States
              
              
              21,898
              
              
              21,898
              
              
              18,250
              
              
              —
              
              
              —
              
              
              —
              
              
              13,602
              
              
              13,602
              
              
              11,354**Total**
              
              
              88,867
              
              
              88,090
              
              
              79,406
              
              
              29,050
              
              
              29,030
              
              
              25,993
              
              
              721,996
              
              
              698,759
              
              
              582,842Proved
                  Developed Non-ProducingCanada
              
              
              541
              
              
              541
              
              
              284
              
              
              —
              
              
              —
              
              
              —
              
              
              17,078
              
              
              16,641
              
              
              13,358United States
              
              
              870
              
              
              870
              
              
              727
              
              
              —
              
              
              —
              
              
              —
              
              
              723
              
              
              723
              
              
              607**Total**
              
              
              1,411
              
              
              1,411
              
              
              1,011
              
              
              —
              
              
              —
              
              
              —
              
              
              17,801
              
              
              17,364
              
              
              13,965Proved
                  UndevelopedCanada
              
              
              3,516
              
              
              3,507
              
              
              3,188
              
              
              2,273
              
              
              2,271
              
              
              1,937
              
              
              156,018
              
              
              152,370
              
              
              132,615United States
              
              
              586
              
              
              586
              
              
              492
              
              
              —
              
              
              —
              
              
              —
              
              
              449
              
              
              449
              
              
              377**Total**
              
              
              4,102
              
              
              4,093
              
              
              3,680
              
              
              2,273
              
              
              2,271
              
              
              1,937
              
              
              156,467
              
              
              152,819
              
              
              132,992Total
                  Proved ReservesCanada
              
              
              71,026
              
              
              70,240
              
              
              64,628
              
              
              31,323
              
              
              31,301
              
              
              27,930
              
              
              881,490
              
              
              854,168
              
              
              717,461United States
              
              
              23,354
              
              
              23,354
              
              
              19,469
              
              
              —
              
              
              —
              
              
              —
              
              
              14,774
              
              
              14,774
              
              
              12,338**Total**
              
              
              94,380
              
              
              93,594
              
              
              84,097
              
              
              31,323
              
              
              31,301
              
              
              27,930
              
              
              896,264
              
              
              868,942
              
              
              729,799Probable
                  ReservesCanada
              
              
              16,928
              
              
              16,747
              
              
              15,135
              
              
              9,038
              
              
              9,028
              
              
              8,146
              
              
              301,380
              
              
              294,292
              
              
              249,213United States
              
              
              8,660
              
              
              8,660
              
              
              7,111
              
              
              —
              
              
              —
              
              
              —
              
              
              37,212
              
              
              37,212
              
              
              30,977**Total**
              
              
              25,588
              
              
              25,407
              
              
              22,246
              
              
              9,038
              
              
              9,028
              
              
              8,146
              
              
              338,592
              
              
              331,504
              
              
              280,190Total
                  Proved Plus Probable ReservesCanada
              
              
              87,954
              
              
              86,987
              
              
              79,763
              
              
              40,361
              
              
              40,329
              
              
              36,076
              
              
              1,182,870
              
              
              1,148,460
              
              
              966,674United States
              
              
              32,014
              
              
              32,014
              
              
              26,580
              
              
              —
              
              
              —
              
              
              —
              
              
              51,986
              
              
              51,986
              
              
              43,315**Total**
              
              
              119,968
              
              
              119,001
              
              
              106,343
              
              
              40,361
              
              
              40,329
              
              
              36,076
              
              
              1,234,856
              
              
              1,200,446
              
              
              1,009,989




(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
              
              
              11,275
              
              
              11,082
              
              
              7,866
              
              
              225,360
              
              
              220,496
              
              
              190,262United States
              
              
              —
              
              
              —
              
              
              —
              
              
              24,165
              
              
              24,165
              
              
              20,143**Total**
              
              
              11,275
              
              
              11,082
              
              
              7,866
              
              
              249,525
              
              
              244,661
              
              
              210,405Proved
                  Developed Non-ProducingCanada
              
              
              619
              
              
              602
              
              
              435
              
              
              4,006
              
              
              3,917
              
              
              2,946United States
              
              
              —
              
              
              —
              
              
              —
              
              
              991
              
              
              991
              
              
              828**Total**
              
              
              619
              
              
              602
              
              
              435
              
              
              4,997
              
              
              4,908
              
              
              3,774Proved
                  UndevelopedCanada
              
              
              632
              
              
              631
              
              
              439
              
              
              32,424
              
              
              31,804
              
              
              27,667United States
              
              
              —
              
              
              —
              
              
              —
              
              
              660
              
              
              660
              
              
              554**Total**
              
              
              632
              
              
              631
              
              
              439
              
              
              33,084
              
              
              32,464
              
              
              28,221Total
                  Proved ReservesCanada
              
              
              12,526
              
              
              12,315
              
              
              8,740
              
              
              261,790
              
              
              256,217
              
              
              220,875United States
              
              
              —
              
              
              —
              
              
              —
              
              
              25,816
              
              
              25,816
              
              
              21,525**Total**
              
              
              12,526
              
              
              12,315
              
              
              8,740
              
              
              287,606
              
              
              282,033
              
              
              242,400Probable
                  ReservesCanada
              
              
              3,706
              
              
              3,637
              
              
              2,612
              
              
              79,902
              
              
              78,461
              
              
              67,429United States
              
              
              —
              
              
              —
              
              
              —
              
              
              14,863
              
              
              14,863
              
              
              12,274**Total**
              
              
              3,706
              
              
              3,637
              
              
              2,612
              
              
              94,765
              
              
              93,324
              
              
              79,703Total
                  Proved Plus Probable ReservesCanada
              
              
              16,232
              
              
              15,952
              
              
              11,352
              
              
              341,692
              
              
              334,678
              
              
              288,304United States
              
              
              —
              
              
              —
              
              
              —
              
              
              40,679
              
              
              40,679
              
              
              33,799**Total**
              
              
              16,232
              
              
              15,952
              
              
              11,352
              
              
              382,371
              
              
              375,357
              
              
              322,103










13




**Summary of Net Present Value
      of
      Future Net RevenueAttributable to Conventional Oil and Gas ReservesAs of
      December 31, 2006**




**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
              
              
              5,259
              
              
              3,618
              
              
              2,816
              
              
              2,336
              
              
              2,013
              
              
              5,259
              
              
              3,618
              
              
              2,816
              
              
              2,336
              
              
              2,013United States
              
              
              1,009
              
              
              785
              
              
              639
              
              
              539
              
              
              466
              
              
              775
              
              
              606
              
              
              495
              
              
              418
              
              
              362**Total**
              
              
              6,268
              
              
              4,403
              
              
              3,455
              
              
              2,875
              
              
              2,479
              
              
              6,034
              
              
              4,224
              
              
              3,311
              
              
              2,754
              
              
              2,375Proved
                  Developed Non-ProducingCanada
              
              
              82
              
              
              54
              
              
              41
              
              
              34
              
              
              29
              
              
              82
              
              
              54
              
              
              41
              
              
              34
              
              
              29United States
              
              
              36
              
              
              27
              
              
              22
              
              
              18
              
              
              15
              
              
              24
              
              
              17
              
              
              14
              
              
              11
              
              
              10**Total**
              
              
              118
              
              
              81
              
              
              63
              
              
              52
              
              
              44
              
              
              106
              
              
              71
              
              
              55
              
              
              45
              
              
              39Proved
                  UndevelopedCanada
              
              
              356
              
              
              236
              
              
              157
              
              
              103
              
              
              65
              
              
              356
              
              
              236
              
              
              157
              
              
              103
              
              
              65United States
              
              
              20
              
              
              14
              
              
              10
              
              
              7
              
              
              5
              
              
              26
              
              
              17
              
              
              11
              
              
              8
              
              
              5**Total**
              
              
              376
              
              
              250
              
              
              167
              
              
              110
              
              
              70
              
              
              382
              
              
              253
              
              
              168
              
              
              111
              
              
              70Total
                  ProvedCanada
              
              
              5,697
              
              
              3,908
              
              
              3,014
              
              
              2,473
              
              
              2,107
              
              
              5,697
              
              
              3,908
              
              
              3,014
              
              
              2,473
              
              
              2,107United States
              
              
              1,065
              
              
              826
              
              
              671
              
              
              564
              
              
              486
              
              
              825
              
              
              640
              
              
              520
              
              
              437
              
              
              377**Total**
              
              
              6,762
              
              
              4,734
              
              
              3,685
              
              
              3,037
              
              
              2,593
              
              
              6,522
              
              
              4,548
              
              
              3,534
              
              
              2,910
              
              
              2,484ProbableCanada
              
              
              1,817
              
              
              921
              
              
              581
              
              
              411
              
              
              313
              
              
              1,817
              
              
              921
              
              
              581
              
              
              411
              
              
              313United States
              
              
              478
              
              
              264
              
              
              160
              
              
              103
              
              
              69
              
              
              328
              
              
              176
              
              
              102
              
              
              63
              
              
              39**Total**
              
              
              2,295
              
              
              1,185
              
              
              741
              
              
              514
              
              
              382
              
              
              2,145
              
              
              1,097
              
              
              683
              
              
              474
              
              
              352Total
                  Proved Plus ProbableCanada
              
              
              7,514
              
              
              4,829
              
              
              3,595
              
              
              2,884
              
              
              2,420
              
              
              7,514
              
              
              4,829
              
              
              3,595
              
              
              2,884
              
              
              2,420United States
              
              
              1,543
              
              
              1,090
              
              
              831
              
              
              667
              
              
              555
              
              
              1,153
              
              
              816
              
              
              622
              
              
              500
              
              
              416**Total**
              
              
              9,057
              
              
              5,919
              
              
              4,426
              
              
              3,551
              
              
              2,975
              
              
              8,667
              
              
              5,645
              
              
              4,217
              
              
              3,384
              
              
              2,836








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 the following price
      forecasts supplied by Sproule and the following inflation and exchange rate
      assumptions:





**CRUDE
                  OIL**
              
              **NATURAL
                  GAS**
              
              **NATURAL
                  GAS LIQUIDS****Edmonton
                  Par Price****Year**
              
              **WTI**
                **Cushing
                  Oklahoma**
              
              **Edmonton**
                **Par
                  Price 40° API**
              
              **Hardisty**
                **Heavy**
                **12° API**
              
              **Cromer
                  Medium 29.3° 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)**2007
              
              
              65.73
              
              
              74.10
              
              
              42.98
              
              
              63.72
              
              
              7.72
              
              
              7.85
              
              
              43.94
              
              
              55.23
              
              
              75.88
              
              
              5.0
              
              
              0.872008
              
              
              68.82
              
              
              77.62
              
              
              45.02
              
              
              66.75
              
              
              8.59
              
              
              8.39
              
              
              46.03
              
              
              57.85
              
              
              79.49
              
              
              4.0
              
              
              0.872009
              
              
              62.42
              
              
              70.25
              
              
              40.74
              
              
              60.41
              
              
              7.74
              
              
              7.65
              
              
              41.66
              
              
              52.36
              
              
              71.94
              
              
              3.0
              
              
              0.872010
              
              
              58.37
              
              
              65.56
              
              
              38.03
              
              
              56.38
              
              
              7.55
              
              
              7.48
              
              
              38.88
              
              
              48.87
              
              
              67.14
              
              
              2.0
              
              
              0.872011
              
              
              55.20
              
              
              61.90
              
              
              35.90
              
              
              53.24
              
              
              7.72
              
              
              7.63
              
              
              36.71
              
              
              46.14
              
              
              63.40
              
              
              2.0
              
              
              0.87Thereafter
              
              
              +2.0
              %
              
              +2.0
              %
              
              +2.0
              %
              
              +2.0
              %
              
              (1
              )
              
              (2
              )
              
              +2.0
              %
              
              +2.0
              %
              
              +2.0
              %
              
              2.0
              
              
              0.87





Notes:


(1)  Escalation
      is 1.7% per year until 2017 and 2% per year thereafter.




(2)  Escalation
      is 1.5% per year until 2017 and 2% per year thereafter.




In 2006,
      Enerplus received a weighted average price (net of transportation costs but
      before hedging) of $49.22/bbl for heavy crude oil, $65.91/bbl for light and
      medium crude oil, $50.90/bbl for NGLs and $6.81/Mcf for natural gas.




Constant Prices and Costs




The constant
      price and cost case assumes the continuance of product prices at
      December 31, 2006 and operating costs projected for 2007, 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 the following prices in effect as at
      December 31, 2006 and the following inflation and exchange rate
      assumptions:




**CRUDE
                  OIL**
              
              **NATURAL
                  GAS**
              
              **NATURAL
                  GAS LIQUIDS****Edmonton
                  Par Price****WTI**
                **Cushing
                  Oklahoma**
              
              **Edmonton**
                **Par
                  Price 40° API**
              
              **Hardisty**
                **Heavy**
                **12° API**
              
              **Cromer**
                **Medium
                  29.3° 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)**Constant
              
              
              61.05
              
              
              67.59
              
              
              40.06
              
              
              62.45
              
              
              6.13
              
              
              5.52
              
              
              42.06
              
              
              54.00
              
              
              71.51
              
              
              —
              
              
              0.858




15






Undiscounted Future Net Revenue by Reserves Category




The
      undiscounted total future net revenue by reserves category as of
      December 31, 2006, using both constant and forecast prices and costs, is
      set forth below:




**RESERVES
                  CATEGORY**
              
              **Revenue**
              
              **Royalties**
                **and
                  Production**
                **Taxes**
              
              **Operating**
                **Costs**
              
              **Development
                  Costs**
              
              **Abandonment
                  and Reclamation Costs**
              
              **Future
                  Net Revenue**
                **Before**
                **Income
                  Taxes**
              
              **Income**
                **Taxes**
              
              **Revenue**
                **After**
                **Income**
                **Taxes****(in $ millions)****Constant
                  Prices and Costs**Proved
                  ReservesCanada
              
              
              11,600
              
              
              1,651
              
              
              3,711
              
              
              425
              
              
              116
              
              
              5,697
              
              
              —
              
              
              5,697United States
              
              
              1,581
              
              
              396
              
              
              98
              
              
              15
              
              
              7
              
              
              1,065
              
              
              240
              
              
              825Total
              
              
              13,181
              
              
              2,047
              
              
              3,809
              
              
              440
              
              
              123
              
              
              6,762
              
              
              240
              
              
              6,522Proved
                  Plus Probable ReservesCanada
              
              
              14,972
              
              
              2,147
              
              
              4,725
              
              
              467
              
              
              119
              
              
              7,514
              
              
              —
              
              
              7,514United States
              
              
              2,369
              
              
              596
              
              
              134
              
              
              88
              
              
              8
              
              
              1,543
              
              
              390
              
              
              1,153Total
              
              
              17,341
              
              
              2,743
              
              
              4,859
              
              
              555
              
              
              127
              
              
              9,057
              
              
              390
              
              
              8,667**Forecast
                  Prices and Costs**Proved
                  ReservesCanada
              
              
              14,793
              
              
              2,190
              
              
              4,570
              
              
              457
              
              
              195
              
              
              7,381
              
              
              —
              
              
              7,381United States
              
              
              1,661
              
              
              416
              
              
              98
              
              
              15
              
              
              7
              
              
              1,125
              
              
              270
              
              
              855Total
              
              
              16,454
              
              
              2,606
              
              
              4,668
              
              
              472
              
              
              202
              
              
              8,506
              
              
              270
              
              
              8,236Proved
                  Plus Probable ReservesCanada
              
              
              19,928
              
              
              2,946
              
              
              6,150
              
              
              502
              
              
              228
              
              
              10,102
              
              
              —
              
              
              10,102United States
              
              
              2,649
              
              
              666
              
              
              133
              
              
              87
              
              
              8
              
              
              1,755
              
              
              481
              
              
              1,274Total
              
              
              22,577
              
              
              3,612
              
              
              6,283
              
              
              589
              
              
              236
              
              
              11,857
              
              
              481
              
              
              11,376




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, 2006, 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)
                
                
                1,198
                
                
                1,278Heavy
                  Oil(a)
                
                
                456
                
                
                492Natural
                  Gas(b)
                
                
                1,360
                
                
                2,022Proved
                    Plus Probable Reserves
                
                Light
                  and Medium Crude Oil(a)
                
                
                1,400
                
                
                1,493Heavy
                  Oil(a)
                
                
                527
                
                
                566Natural
                  Gas(b)
                
                
                1,668
                
                
                2,478**United States**Proved
                    Reserves
                
                Light
                  and Medium Crude Oil(a)
                
                
                671
                
                
                703Heavy
                  Oil(a)
                
                
                —
                
                
                —Natural
                  Gas(b)
                
                
                —
                
                
                —Proved
                    Plus Probable Reserves
                
                Light
                  and Medium Crude Oil(a)
                
                
                831
                
                
                901Heavy
                  Oil(a)
                
                
                —
                
                
                —Natural
                  Gas(b)
                
                
                —
                
                
                —


Notes:
 (a)  Including
        solution gas and other by-products.
  (b)  Including
        by-products, but excluding solution gas from oil wells.




16




Estimated Production for Estimates of Future Net Revenue




The volume of
      company interest production from Proved plus Probable Reserves estimated for
      2007 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**
            
            **Estimated
              2007AggregateProduction**
            
            **Estimated
              2007Average
              DailyProduction**
            
            **Estimated
              2007AggregateProduction**
            
            **Estimated
              2007Average
              DailyProduction**Crude OilLight and Medium Crude Oil
            
            6,125
            
            Mbbls
            
            16,780
            
            bbls/d
            
            4,201
            
            Mbbls
            
            11,509
            
            bbls/dHeavy
              Oil
            
            3,088
            
            Mbbls
            
            8,460
            
            bbls/d
            
            —
            
            —Total Crude Oil
            
            9,213
            
            Mbbls
            
            25,240
            
            bbls/d
            
            4,201
            
            Mbbls
            
            11,509
            
            bbls/dNatural
              Gas Liquids
            
            1,577
            
            Mbbls
            
            4,322
            
            bbls/d
            
            —
            
            —Total Liquids
            
            10,790
            
            Mbbls
            
            29,562
            
            bbls/d
            
            4,201
            
            Mbbls
            
            11,509
            
            bbls/dNatural
              Gas
            
            96,428
            
            MMcf
            
            264,185
            
            Mcf/d
            
            3,183
            
            MMcf
            
            8,722
            
            Mcf/dTotal
            
            26,861
            
            MBOE
            
            73,593
            
            BOE/d
            
            4,731
            
            MBOE
            
            12,962
            
            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**2007
              
              
              120
              
              
              115
              
              
              130
              
              
              125
              
              
              120
              
              
              115
              
              
              130
              
              
              1252008
              
              
              119
              
              
              103
              
              
              132
              
              
              114
              
              
              125
              
              
              108
              
              
              139
              
              
              1202009
              
              
              69
              
              
              54
              
              
              84
              
              
              66
              
              
              75
              
              
              59
              
              
              92
              
              
              722010
              
              
              45
              
              
              33
              
              
              50
              
              
              35
              
              
              51
              
              
              37
              
              
              56
              
              
              402011
              
              
              30
              
              
              20
              
              
              30
              
              
              20
              
              
              35
              
              
              23
              
              
              35
              
              
              23Remainder
              
              
              42
              
              
              19
              
              
              41
              
              
              20
              
              
              51
              
              
              24
              
              
              50
              
              
              23Total
              
              
              425
              
              
              344
              
              
              467
              
              
              380
              
              
              457
              
              
              366
              
              
              502
              
              
              403
   **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)****UNITED
                  STATES**2007
              
              
              15
              
              
              15
              
              
              88
              
              
              84
              
              
              15
              
              
              15
              
              
              87
              
              
              832008
              
              
              —
              
              
              —
              
              
              —
              
              
              —
              
              
              —
              
              
              —
              
              
              —
              
              
              —2009
              
              
              —
              
              
              —
              
              
              —
              
              
              —
              
              
              —
              
              
              —
              
              
              —
              
              
              —2010
              
              
              —
              
              
              —
              
              
              —
              
              
              —
              
              
              —
              
              
              —
              
              
              —
              
              
              —2011
              
              
              —
              
              
              —
              
              
              —
              
              
              —
              
              
              —
              
              
              —
              
              
              —
              
              
              —Remainder
              
              
              —
              
              
              —
              
              
              —
              
              
              —
              
              
              —
              
              
              —
              
              
              —
              
              
              —Total
              
              
              15
              
              
              15
              
              
              88
              
              
              84
              
              
              15
              
              
              15
              
              
              87
              
              
              83










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' 15% working interest in the SAGD-recoverable
      bitumen reserves of the Joslyn Project as of December 31, 2006, including
      certain assumptions relating to the determination of those reserves and values,
      as contained in the GLJ Reserves Report. The following estimated reserves
      are incremental to the estimated contingent resources associated with the North
      Mine and South Mine portions of the Joslyn Project disclosed below under
      "Operational Information — Description of Principal Properties and
      Operations — Oil Sands — Summary of Certain Joslyn Project
      Contingent Bitumen Resources".


**Summary of Enerplus' Interest
      in the
      SAGD Bitumen Reserves of theJoslyn Lease and Net Present Value of Future Net
      RevenueAs of December 31, 2006Forecast Prices and Costs**


****


**BITUMEN**
              **RESERVES**
            
            **NET PRESENT VALUE OF FUTURE NET REVENUE**
              **BEFORE AND AFTER INCOMES TAXES, DISCOUNTED**
              **AT (%/YEAR)****RESERVES
              CATEGORY**
            
            **Gross**
            
            **Net**
            
            **0%**
            
            **5%**
            
            **10%**
            
            **15%**
            
            **20%**(Mbbls)
            
            (Mbbls)
            
            (in $ millions)Proved
              Developed Producing
            
            
            2,479
            
            
            2,454
            
            
            20
            
            
            16
            
            
            13
            
            
            11
            
            
            10Proved
              Undeveloped
            
            
            6,251
            
            
            6,188
            
            
            39
            
            
            20
            
            
            10
            
            
            4
            
            
            1Total
              Proved
            
            
            8,730
            
            
            8,642
            
            
            59
            
            
            36
            
            
            23
            
            
            15
            
            
            11Probable
            
            
            47,998
            
            
            44,701
            
            
            453
            
            
            104
            
            
            25
            
            
            2
            
            
            (8
            )Total
              Proved Plus Probable
            
            
            56,728
            
            
            53,343
            
            
            512
            
            
            140
            
            
            48
            
            
            17
            
            
            3


**Constant Prices and Cost**


****


**BITUMEN**
              **RESERVES**
            
            **NET PRESENT VALUE OF FUTURE NET REVENUE**
              **BEFORE AND AFTER INCOMES TAXES, DISCOUNTED**
              **AT (%/YEAR)****RESERVES
              CATEGORY**
            
            **Gross**
            
            **Net**
            
            **0%**
            
            **5%**
            
            **10%**
            
            **15%**
            
            **20%**(Mbbls)
            
            (Mbbls)
            
            (in $ millions)Proved
              Developed Producing
            
            
            2,714
            
            
            2,687
            
            
            34
            
            
            27
            
            
            21
            
            
            18
            
            
            15Proved
              Undeveloped
            
            
            6,016
            
            
            5,702
            
            
            71
            
            
            39
            
            
            23
            
            
            13
            
            
            7Total
              Proved
            
            
            8,730
            
            
            8,389
            
            
            105
            
            
            66
            
            
            44
            
            
            31
            
            
            22Probable
            
            
            48,149
            
            
            42,154
            
            
            530
            
            
            148
            
            
            51
            
            
            18
            
            
            4Total
              Proved Plus Probable
            
            
            56,879
            
            
            50,543
            
            
            635
            
            
            214
            
            
            95
            
            
            49
            
            
            26




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 exchange rate of
      Cdn$1.00=US$0.87 and the price and inflation rate forecasts set forth below
      supplied by Sproule as at December 31, 2006 (but utilized by GLJ for
      internal consistency in Enerplus' reserves reporting). The forecast net prices
      for 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. The










18


forecast net prices for Joslyn Bitumen assume the sale
      of a
      bitumen-diluent blended product until mid-2008 and a bitumen-synthetic crude
      oil
      blend thereafter, as per the operator's current plans.


**CRUDE
                  OIL**
              
              
              **NATURAL
                  GAS****Year**
              
              
              **WTI**
                **Cushing
                  Oklahoma**
              
              
              **Edmonton**
                **Par
                  Price**
                **40°API**
              
              
              **Bow
                  River**
                **Medium**
                **24.9°API**
              
              
              **Joslyn**
                **Bitumen**
              
              
              **30
                  day spot**
                **@
                  AECO**
              
              
              **Inflation**
                **Rate****($US/bbl)**
              
              
              **($Cdn/bbl)**
              
              
              **($Cdn/bbl)**
              
              
              **($Cdn/bbl)**
              
              
              **($Cdn/mmbtu)**
              
              
              **(%)**2007
              
              
              65.73
              
              
              74.10
              
              
              53.35
              
              
              34.10
              
              
              7.72
              
              
              5.02008
              
              
              68.82
              
              
              77.62
              
              
              55.89
              
              
              33.67
              
              
              8.59
              
              
              4.02009
              
              
              62.42
              
              
              70.25
              
              
              50.58
              
              
              27.91
              
              
              7.74
              
              
              3.02010
              
              
              58.37
              
              
              65.56
              
              
              47.20
              
              
              25.84
              
              
              7.55
              
              
              2.02011
              
              
              55.20
              
              
              61.90
              
              
              44.57
              
              
              24.24
              
              
              7.72
              
              
              2.0Thereafter
              
              
              +2.0
              %
              
              +2.0
              %
              
              +2.0
              %
              
              (1
              )
              
              (2
              )
              
              2.0





Notes:


(1)    Escalation
      is approximately 2.2% per year thereafter.




(2)    Escalation
      is 1.7% per year until 2017 and 2% per year thereafter.




Constant Prices and Costs




The constant
      price and cost case assumes the continuance of product prices at
      December 31, 2006 and operating costs projected for 2007, and the
      continuance of current laws and regulations. The constant bitumen price was
      based on December 31, 2006 posted reference prices and differentials, and
      was not materially different than the bitumen price derived using the average
      year differential methodology described in Canadian Securities Administrators
      Staff Notice 51-315. 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$0.858 and the following prices
      in
      effect as at December 31, 2006:




**CRUDE
              OIL**
            
            **NATURAL
              GAS****WTI
Cushing
Oklahoma**
            
            **EdmontonPar
              Price40°API**
            
            **Bow
              RiverMedium 24.9°API**
            
            **JoslynBitumen**
            
            **30 day
              spot@ AECO**($US/bbl)
            
            ($Cdn/bbl)
            
            ($Cdn/bbl)
            
            ($Cdn/bbl)
            
            ($Cdn/mmbtu)Constant
            
            61.05
            
            67.59
            
            48.84
            
            29.53
            
            6.13




Undiscounted Future Net Revenue by Reserves Category





The
      undiscounted
      total future net revenue by reserves category as of December 31, 2006,
      using both constant and forecast prices and costs, is set forth below:




**RESERVES
                  CATEGORY**
              
              **Revenue**
              
              **Royalties
                  and Production Taxes**
              
              **Operating**
                **Costs**
              
              **Development**
                **Costs**
              
              **Abandonment**
                **and
                  Reclamation**
                **Costs**
              
              **Future Net**
                **Revenue
                  Before Income**
                **Taxes**
              
              **Income**
                **Taxes**
              
              **Revenue
                  After Income**
                **Taxes****(in $ millions)****Constant
                  Prices and Costs**Proved
                  Reserves
              
              
              258
              
              
              10
              
              
              115
              
              
              27
              
              
              1
              
              
              105
              
              
              —
              
              
              105Probable
                  Reserves
              
              
              1,422
              
              
              177
              
              
              528
              
              
              184
              
              
              3
              
              
              530
              
              
              —
              
              
              530Total
                  Proved Plus Probable Reserves
              
              
              1,680
              
              
              187
              
              
              643
              
              
              211
              
              
              4
              
              
              635
              
              
              —
              
              
              635**Forecast
                  Prices and Costs**Proved
                  Reserves
              
              
              245
              
              
              3
              
              
              151
              
              
              31
              
              
              1
              
              
              59
              
              
              —
              
              
              59Probable
                  Reserves
              
              
              1,878
              
              
              139
              
              
              996
              
              
              284
              
              
              6
              
              
              453
              
              
              —
              
              
              453Total
                  Proved Plus Probable Reserves
              
              
              2,123
              
              
              142
              
              
              1,147
              
              
              315
              
              
              7
              
              
              512
              
              
              —
              
              
              512








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, 2006, 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 Reserves
            
            Bitumen
            
            44
            
            23Probable
              Reserves
            
            Bitumen
            
            51
            
            25Total
              Proved Plus Probable Reserves
            
            Bitumen
            
            95
            
            48




Estimated Production for Estimates of Future Net Revenue




The volume of
      gross production from the Proved plus Probable Reserves in 2007 estimated by
      GLJ
      in preparing the estimated net present values of future net revenue is
      as follows:




**Product
              Type**
            
            **Estimated 2007**
              **Aggregate Production**
            
            **Estimated
              2007 Average Daily
              Production**Bitumen
            
            172
                Mbbls
            
            471
                bbls/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)**2007
              
              
              9
              
              
              9
              
              
              8
              
              
              82008
              
              
              —
              
              
              —
              
              
              10
              
              
              92009
              
              
              —
              
              
              —
              
              
              12
              
              
              92010
              
              
              —
              
              
              —
              
              
              23
              
              
              162011
              
              
              —
              
              
              —
              
              
              1
              
              
              1Remainder
              
              
              18
              
              
              8
              
              
              157
              
              
              26Total
              
              
              27
              
              
              17
              
              
              211
              
              
              69
 
 **Forecast
                  Prices and Costs****Proved
                  Reserves**
              
              **Proved Plus Probable
                  Reserves****Year**
              
              **Undiscounted**
              
              **Discounted**
                **at
                  10%/year**
              
              **Undiscounted**
              
              **Discounted**
                **at
                  10%/year****(in $ millions)**2007
              
              
              9
              
              
              9
              
              
              8
              
              
              82008
              
              
              —
              
              
              —
              
              
              11
              
              
              92009
              
              
              —
              
              
              —
              
              
              13
              
              
              102010
              
              
              —
              
              
              —
              
              
              25
              
              
              182011
              
              
              —
              
              
              —
              
              
              1
              
              
              1Remainder
              
              
              22
              
              
              10
              
              
              257
              
              
              36Total
              
              
              31
              
              
              19
              
              
              315
              
              
              82










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, 2005 to
      December 31, 2006, by country and in total, using forecast prices
      and costs.




Reconciliation of Company Interest
      Reserves




**CANADA**
              
              **Light &
                  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,
                  2005**
              
              
              73,249
              
              
              17,498
              
              
              90,747
              
              
              32,901
              
              
              8,495
              
              
              41,396
              
              
              9,453
              
              
              43,700
              
              
              53,153Acquisitions
              
              
              984
              
              
              451
              
              
              1,435
              
              
              —
              
              
              —
              
              
              —
              
              
              —
              
              
              —
              
              
              —Divestments
              
              
              (30
              )
              
              (5
              )
              
              (35
              )
              
              —
              
              
              —
              
              
              —
              
              
              (591
              )
              
              (2,738
              )
              
              (3,329
              )Discoveries
              
              
              —
              
              
              1
              
              
              1
              
              
              48
              
              
              18
              
              
              66
              
              
              —
              
              
              —
              
              
              —Extensions
              
              
              1,648
              
              
              407
              
              
              2,055
              
              
              11
              
              
              9
              
              
              20
              
              
              —
              
              
              6,935
              
              
              6,935Technical
                  Revisions
              
              
              (2,191
              )
              
              (2,414
              )
              
              (4,605
              )
              
              1,058
              
              
              337
              
              
              1,395
              
              
              (132
              )
              
              101
              
              
              (31
              )Economic
                  Factors
              
              
              226
              
              
              47
              
              
              273
              
              
              58
              
              
              10
              
              
              68
              
              
              —
              
              
              —
              
              
              —Improved
                  Recovery
              
              
              2,806
              
              
              887
              
              
              3,693
              
              
              327
              
              
              43
              
              
              370
              
              
              —
              
              
              —
              
              
              —Production
              
              
              (6,188
              )
              
              —
              
              
              (6,188
              )
              
              (3,250
              )
              
              —
              
              
              (3,250
              )
              
              —
              
              
              —
              
              
              —**December 31,
                  2006**
              
              
              70,504
              
              
              16,872
              
              
              87,376
              
              
              31,153
              
              
              8,912
              
              
              40,065
              
              
              8,730
              
              
              47,998
              
              
              56,728
  **CANADA**
              
              **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,
                  2005**
              
              
              13,084
              
              
              3,539
              
              
              16,623
              
              
              952,624
              
              
              309,572
              
              
              1,262,196
              
              
              287,458
              
              
              124,827
              
              
              412,285Acquisitions
              
              
              160
              
              
              72
              
              
              232
              
              
              5,518
              
              
              2,219
              
              
              7,737
              
              
              2,063
              
              
              893
              
              
              2,956Divestments
              
              
              (1
              )
              
              (1
              )
              
              (2
              )
              
              (145
              )
              
              (13
              )
              
              (158
              )
              
              (647
              )
              
              (2,745
              )
              
              (3,392
              )Discoveries
              
              
              27
              
              
              8
              
              
              35
              
              
              4,095
              
              
              845
              
              
              4,940
              
              
              757
              
              
              168
              
              
              925Extensions
              
              
              671
              
              
              217
              
              
              888
              
              
              26,180
              
              
              9,593
              
              
              35,773
              
              
              6,693
              
              
              9,167
              
              
              15,860Technical
                  Revisions
              
              
              372
              
              
              (62
              )
              
              310
              
              
              (4,956
              )
              
              (22,147
              )
              
              (27,103
              )
              
              (1,717
              )
              
              (5,730
              )
              
              (7,447
              )Economic
                  Factors
              
              
              (17
              )
              
              (5
              )
              
              (22
              )
              
              (5,304
              )
              
              (1,642
              )
              
              (6,946
              )
              
              (616
              )
              
              (223
              )
              
              (839
              )Improved
                  Recovery
              
              
              30
              
              
              9
              
              
              39
              
              
              23,981
              
              
              8,377
              
              
              32,358
              
              
              7,159
              
              
              2,336
              
              
              9,495Production
              
              
              (1,636
              )
              
              —
              
              
              (1,636
              )
              
              (96,732
              )
              
              —
              
              
              (96,732
              )
              
              (27,196
              )
              
              —
              
              
              (27,196
              )**December 31,
                  2006**
              
              
              12,690
              
              
              3,777
              
              
              16,467
              
              
              905,261
              
              
              306,804
              
              
              1,212,065
              
              
              273,954
              
              
              128,693
              
              
              402,647
 
 **UNITED
                  STATES**
              
              **Light &
                  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,
                  2005**
              
              
              23,595
              
              
              5,574
              
              
              29,169
              
              
              —
              
              
              —
              
              
              —
              
              
              —
              
              
              —
              
              
              —Acquisitions
              
              
              401
              
              
              202
              
              
              603
              
              
              —
              
              
              —
              
              
              —
              
              
              —
              
              
              —
              
              
              —Divestments
              
              
              —
              
              
              —
              
              
              —
              
              
              —
              
              
              —
              
              
              —
              
              
              —
              
              
              —
              
              
              —Discoveries
              
              
              —
              
              
              —
              
              
              —
              
              
              —
              
              
              —
              
              
              —
              
              
              —
              
              
              —
              
              
              —Extensions
              
              
              440
              
              
              982
              
              
              1,422
              
              
              —
              
              
              —
              
              
              —
              
              
              —
              
              
              —
              
              
              —Technical
                  Revisions
              
              
              584
              
              
              37
              
              
              621
              
              
              —
              
              
              —
              
              
              —
              
              
              —
              
              
              —
              
              
              —Economic
                  Factors
              
              
              —
              
              
              —
              
              
              —
              
              
              —
              
              
              —
              
              
              —
              
              
              —
              
              
              —
              
              
              —Improved
                  Recovery
              
              
              2,122
              
              
              1,842
              
              
              3,964
              
              
              —
              
              
              —
              
              
              —
              
              
              —
              
              
              —
              
              
              —Production
              
              
              (3,751
              )
              
              —
              
              
              (3,751
              )
              
              —
              
              
              —
              
              
              —
              
              
              —
              
              
              —
              
              
              —**December 31,
                  2006**
              
              
              23,391
              
              
              8,637
              
              
              32,028
              
              
              —
              
              
              —
              
              
              —
              
              
              —
              
              
              —
              
              
              —




(continues on next page)








21


(continued)





**UNITED
                  STATES**
              
              **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,
                  2005**
              
              
              —
              
              
              —
              
              
              —
              
              
              13,152
              
              
              32,946
              
              
              46,098
              
              
              25,787
              
              
              11,065
              
              
              36,852Acquisitions
              
              
              —
              
              
              —
              
              
              —
              
              
              341
              
              
              230
              
              
              571
              
              
              458
              
              
              240
              
              
              698Divestments
              
              
              —
              
              
              —
              
              
              —
              
              
              —
              
              
              —
              
              
              —
              
              
              —
              
              
              —
              
              
              —Discoveries
              
              
              —
              
              
              —
              
              
              —
              
              
              —
              
              
              —
              
              
              —
              
              
              —
              
              
              —
              
              
              —Extensions
              
              
              —
              
              
              —
              
              
              —
              
              
              384
              
              
              1,095
              
              
              1,479
              
              
              504
              
              
              1,164
              
              
              1,668Technical
                  Revisions
              
              
              —
              
              
              —
              
              
              —
              
              
              1,732
              
              
              (1,002
              )
              
              730
              
              
              872
              
              
              (129
              )
              
              743Economic
                  Factors
              
              
              —
              
              
              —
              
              
              —
              
              
              —
              
              
              —
              
              
              —
              
              
              —
              
              
              —
              
              
              —Improved
                  Recovery
              
              
              —
              
              
              —
              
              
              —
              
              
              1,364
              
              
              3,952
              
              
              5,316
              
              
              2,350
              
              
              2,500
              
              
              4,850Production
              
              
              —
              
              
              —
              
              
              —
              
              
              (2,173
              )
              
              —
              
              
              (2,173
              )
              
              (4,113
              )
              
              —
              
              
              (4,113
              )**December 31,
                  2006**
              
              
              —
              
              
              —
              
              
              —
              
              
              14,800
              
              
              37,221
              
              
              52,021
              
              
              25,858
              
              
              14,840
              
              
              40,698
  **TOTAL
                  ENERPLUS**
              
              **Light &
                  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,
                  2005**
              
              
              96,844
              
              
              23,072
              
              
              119,916
              
              
              32,901
              
              
              8,495
              
              
              41,396
              
              
              9,453
              
              
              43,700
              
              
              53,153Acquisitions
              
              
              1,385
              
              
              653
              
              
              2,038
              
              
              —
              
              
              —
              
              
              —
              
              
              —
              
              
              —
              
              
              —Divestments
              
              
              (30
              )
              
              (5
              )
              
              (35
              )
              
              —
              
              
              —
              
              
              —
              
              
              (591
              )
              
              (2,738
              )
              
              (3,329
              )Discoveries
              
              
              —
              
              
              1
              
              
              1
              
              
              48
              
              
              18
              
              
              66
              
              
              —
              
              
              —
              
              
              —Extensions
              
              
              2,088
              
              
              1,389
              
              
              3,477
              
              
              11
              
              
              9
              
              
              20
              
              
              —
              
              
              6,935
              
              
              6,935Technical
                  Revisions
              
              
              (1,607
              )
              
              (2,377
              )
              
              (3,984
              )
              
              1,058
              
              
              337
              
              
              1,395
              
              
              (132
              )
              
              101
              
              
              (31
              )Economic
                  Factors
              
              
              226
              
              
              47
              
              
              273
              
              
              58
              
              
              10
              
              
              68
              
              
              —
              
              
              —
              
              
              —Improved
                  Recovery
              
              
              4,928
              
              
              2,729
              
              
              7,657
              
              
              327
              
              
              43
              
              
              370
              
              
              —
              
              
              —
              
              
              —Production
              
              
              (9,939
              )
              
              —
              
              
              (9,939
              )
              
              (3,250
              )
              
              —
              
              
              (3,250
              )
              
              —
              
              
              —
              
              
              —**December 31,
                  2006**
              
              
              93,895
              
              
              25,509
              
              
              119,404
              
              
              31,153
              
              
              8,912
              
              
              40,065
              
              
              8,730
              
              
              47,998
              
              
              56,728
  **TOTAL
                  ENERPLUS**
              
              **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,
                  2005**
              
              
              13,084
              
              
              3,539
              
              
              16,623
              
              
              965,776
              
              
              342,518
              
              
              1,308,294
              
              
              313,245
              
              
              135,892
              
              
              449,137Acquisitions
              
              
              160
              
              
              72
              
              
              232
              
              
              5,859
              
              
              2,449
              
              
              8,308
              
              
              2,521
              
              
              1,133
              
              
              3,654Divestments
              
              
              (1
              )
              
              (1
              )
              
              (2
              )
              
              (145
              )
              
              (13
              )
              
              (158
              )
              
              (647
              )
              
              (2,745
              )
              
              (3,392
              )Discoveries
              
              
              27
              
              
              8
              
              
              35
              
              
              4,095
              
              
              845
              
              
              4,940
              
              
              757
              
              
              168
              
              
              925Extensions
              
              
              671
              
              
              217
              
              
              888
              
              
              26,564
              
              
              10,688
              
              
              37,252
              
              
              7,197
              
              
              10,331
              
              
              17,528Technical
                  Revisions
              
              
              372
              
              
              (62
              )
              
              310
              
              
              (3,224
              )
              
              (23,149
              )
              
              (26,373
              )
              
              (845
              )
              
              (5,859
              )
              
              (6,704
              )Economic
                  Factors
              
              
              (17
              )
              
              (5
              )
              
              (22
              )
              
              (5,304
              )
              
              (1,642
              )
              
              (6,946
              )
              
              (616
              )
              
              (223
              )
              
              (839
              )Improved
                  Recovery
              
              
              30
              
              
              9
              
              
              39
              
              
              25,345
              
              
              12,329
              
              
              37,674
              
              
              9,509
              
              
              4,836
              
              
              14,345Production
              
              
              (1,636
              )
              
              —
              
              
              (1,636
              )
              
              (98,905
              )
              
              —
              
              
              (98,905
              )
              
              (31,309
              )
              
              —
              
              
              (31,309
              )**December 31,
                  2006**
              
              
              12,690
              
              
              3,777
              
              
              16,467
              
              
              920,061
              
              
              344,025
              
              
              1,264,086
              
              
              299,812
              
              
              143,533
              
              
              443,345




22






Reconciliation of Net Reserves


**CANADA**
              
              **Light &
                  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,
                  2005**
              
              
              66,427
              
              
              14,967
              
              
              81,394
              
              
              29,365
              
              
              6,131
              
              
              35,496
              
              
              9,358
              
              
              41,150
              
              
              50,508Acquisitions
              
              
              921
              
              
              424
              
              
              1,345
              
              
              —
              
              
              —
              
              
              —
              
              
              —
              
              
              —
              
              
              —Divestments
              
              
              (29
              )
              
              (5
              )
              
              (34
              )
              
              —
              
              
              —
              
              
              —
              
              
              (532
              )
              
              (2,597
              )
              
              (3,129
              )Discoveries
              
              
              —
              
              
              —
              
              
              —
              
              
              40
              
              
              16
              
              
              56
              
              
              —
              
              
              —
              
              
              —Extensions
              
              
              1,452
              
              
              362
              
              
              1,814
              
              
              10
              
              
              8
              
              
              18
              
              
              —
              
              
              6,519
              
              
              6,519Technical
                  Revisions
              
              
              (1,952
              )
              
              (1,489
              )
              
              (3,441
              )
              
              796
              
              
              1,838
              
              
              2,634
              
              
              (184
              )
              
              (371
              )
              
              (555
              )Economic
                  Factors
              
              
              182
              
              
              21
              
              
              203
              
              
              48
              
              
              9
              
              
              57
              
              
              —
              
              
              —
              
              
              —Improved
                  Recovery
              
              
              2,517
              
              
              797
              
              
              3,314
              
              
              250
              
              
              33
              
              
              283
              
              
              —
              
              
              —
              
              
              —Production
              
              
              (5,384
              )
              
              —
              
              
              (5,384
              )
              
              (2,730
              )
              
              —
              
              
              (2,730
              )
              
              —
              
              
              —
              
              
              —**December 31,
                  2006**
              
              
              64,134
              
              
              15,077
              
              
              79,211
              
              
              27,779
              
              
              8,035
              
              
              35,814
              
              
              8,642
              
              
              44,701
              
              
              53,343
  **CANADA**
              
              **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,
                  2005**
              
              
              9,107
              
              
              2,470
              
              
              11,577
              
              
              766,200
              
              
              252,478
              
              
              1,018,678
              
              
              241,957
              
              
              106,798
              
              
              348,755Acquisitions
              
              
              123
              
              
              62
              
              
              185
              
              
              4,162
              
              
              1,737
              
              
              5,899
              
              
              1,738
              
              
              775
              
              
              2,513Divestments
              
              
              (1
              )
              
              —
              
              
              (1
              )
              
              (107
              )
              
              (10
              )
              
              (117
              )
              
              (579
              )
              
              (2,604
              )
              
              (3,183
              )Discoveries
              
              
              18
              
              
              6
              
              
              24
              
              
              2,847
              
              
              592
              
              
              3,439
              
              
              533
              
              
              120
              
              
              653Extensions
              
              
              461
              
              
              153
              
              
              614
              
              
              20,007
              
              
              7,436
              
              
              27,443
              
              
              5,258
              
              
              8,281
              
              
              13,539Technical
                  Revisions
              
              
              289
              
              
              (28
              )
              
              261
              
              
              103
              
              
              (14,856
              )
              
              (14,753
              )
              
              (1,036
              )
              
              (2,524
              )
              
              (3,560
              )Economic
                  Factors
              
              
              (17
              )
              
              (5
              )
              
              (22
              )
              
              (4,070
              )
              
              (1,319
              )
              
              (5,389
              )
              
              (465
              )
              
              (196
              )
              
              (661
              )Improved
                  Recovery
              
              
              21
              
              
              7
              
              
              28
              
              
              22,347
              
              
              7,577
              
              
              29,924
              
              
              6,512
              
              
              2,100
              
              
              8,612Production
              
              
              (1,145
              )
              
              —
              
              
              (1,145
              )
              
              (74,484
              )
              
              —
              
              
              (74,484
              )
              
              (21,673
              )
              
              —
              
              
              (21,673
              )**December 31,
                  2006**
              
              
              8,856
              
              
              2,665
              
              
              11,521
              
              
              737,005
              
              
              253,635
              
              
              990,640
              
              
              232,245
              
              
              112,750
              
              
              344,995
  **UNITED
                  STATES**
              
              **Light &
                  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,
                  2005**
              
              
              19,815
              
              
              4,673
              
              
              24,488
              
              
              —
              
              
              —
              
              
              —
              
              
              —
              
              
              —
              
              
              —Acquisitions
              
              
              333
              
              
              167
              
              
              500
              
              
              —
              
              
              —
              
              
              —
              
              
              —
              
              
              —
              
              
              —Divestments
              
              
              —
              
              
              —
              
              
              —
              
              
              —
              
              
              —
              
              
              —
              
              
              —
              
              
              —
              
              
              —Discoveries
              
              
              —
              
              
              —
              
              
              —
              
              
              —
              
              
              —
              
              
              —
              
              
              —
              
              
              —
              
              
              —Extensions
              
              
              367
              
              
              787
              
              
              1,154
              
              
              —
              
              
              —
              
              
              —
              
              
              —
              
              
              —
              
              
              —Technical
                  Revisions
              
              
              371
              
              
              (33
              )
              
              338
              
              
              —
              
              
              —
              
              
              —
              
              
              —
              
              
              —
              
              
              —Economic
                  Factors
              
              
              —
              
              
              —
              
              
              —
              
              
              —
              
              
              —
              
              
              —
              
              
              —
              
              
              —
              
              
              —Improved
                  Recovery
              
              
              1,727
              
              
              1,497
              
              
              3,224
              
              
              —
              
              
              —
              
              
              —
              
              
              —
              
              
              —
              
              
              —Production
              
              
              (3,113
              )
              
              —
              
              
              (3,113
              )
              
              —
              
              
              —
              
              
              —
              
              
              —
              
              
              —
              
              
              —**December 31,
                  2006**
              
              
              19,500
              
              
              7,091
              
              
              26,591
              
              
              —
              
              
              —
              
              
              —
              
              
              —
              
              
              —
              
              
              —
  (continues
        on next
        page)








23




(continued)


**UNITED
                  STATES**
              
              **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,
                  2005**
              
              
              —
              
              
              —
              
              
              —
              
              
              11,044
              
              
              27,655
              
              
              38,699
              
              
              21,656
              
              
              9,282
              
              
              30,938Acquisitions
              
              
              —
              
              
              —
              
              
              —
              
              
              283
              
              
              191
              
              
              474
              
              
              380
              
              
              199
              
              
              579Divestments
              
              
              —
              
              
              —
              
              
              —
              
              
              —
              
              
              —
              
              
              —
              
              
              —
              
              
              —
              
              
              —Discoveries
              
              
              —
              
              
              —
              
              
              —
              
              
              —
              
              
              —
              
              
              —
              
              
              —
              
              
              —
              
              
              —Extensions
              
              
              —
              
              
              —
              
              
              —
              
              
              321
              
              
              896
              
              
              1,217
              
              
              420
              
              
              937
              
              
              1,357Technical
                  Revisions
              
              
              —
              
              
              —
              
              
              —
              
              
              1,405
              
              
              (968
              )
              
              437
              
              
              605
              
              
              (194
              )
              
              411Economic
                  Factors
              
              
              —
              
              
              —
              
              
              —
              
              
              —
              
              
              —
              
              
              —
              
              
              —
              
              
              —
              
              
              —Improved
                  Recovery
              
              
              —
              
              
              —
              
              
              —
              
              
              1,111
              
              
              3,211
              
              
              4,322
              
              
              1,912
              
              
              2,032
              
              
              3,944Production
              
              
              —
              
              
              —
              
              
              —
              
              
              (1,804
              )
              
              —
              
              
              (1,804
              )
              
              (3,414
              )
              
              —
              
              
              (3,414
              )**December 31,
                  2006**
              
              
              —
              
              
              —
              
              
              —
              
              
              12,360
              
              
              30,985
              
              
              43,345
              
              
              21,559
              
              
              12,256
              
              
              33,815
  **TOTAL
                  ENERPLUS**
              
              **Light &
                  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,
                  2005**
              
              
              86,242
              
              
              19,640
              
              
              105,882
              
              
              29,365
              
              
              6,131
              
              
              35,496
              
              
              9,358
              
              
              41,150
              
              
              50,508Acquisitions
              
              
              1,254
              
              
              591
              
              
              1,845
              
              
              —
              
              
              —
              
              
              —
              
              
              —
              
              
              —
              
              
              —Divestments
              
              
              (29
              )
              
              (5
              )
              
              (34
              )
              
              —
              
              
              —
              
              
              —
              
              
              (532
              )
              
              (2,597
              )
              
              (3,129
              )Discoveries
              
              
              —
              
              
              —
              
              
              —
              
              
              40
              
              
              16
              
              
              56
              
              
              —
              
              
              —
              
              
              —Extensions
              
              
              1,819
              
              
              1,149
              
              
              2,968
              
              
              10
              
              
              8
              
              
              18
              
              
              —
              
              
              6,519
              
              
              6,519Technical
                  Revisions
              
              
              (1,581
              )
              
              (1,522
              )
              
              (3,103
              )
              
              796
              
              
              1,838
              
              
              2,634
              
              
              (184
              )
              
              (371
              )
              
              (555
              )Economic
                  Factors
              
              
              182
              
              
              21
              
              
              203
              
              
              48
              
              
              9
              
              
              57
              
              
              —
              
              
              —
              
              
              —Improved
                  Recovery
              
              
              4,244
              
              
              2,294
              
              
              6,538
              
              
              250
              
              
              33
              
              
              283
              
              
              —
              
              
              —
              
              
              —Production
              
              
              (8,497
              )
              
              —
              
              
              (8,497
              )
              
              (2,730
              )
              
              —
              
              
              (2,730
              )
              
              —
              
              
              —
              
              
              —**December 31,
                  2006**
              
              
              83,634
              
              
              22,168
              
              
              105,802
              
              
              27,779
              
              
              8,035
              
              
              35,814
              
              
              8,642
              
              
              44,701
              
              
              53,343
  **TOTAL
                  ENERPLUS**
              
              **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,
                  2005**
              
              
              9,107
              
              
              2,470
              
              
              11,577
              
              
              777,244
              
              
              280,133
              
              
              1,057,377
              
              
              263,613
              
              
              116,080
              
              
              379,693Acquisitions
              
              
              123
              
              
              62
              
              
              185
              
              
              4,445
              
              
              1,928
              
              
              6,373
              
              
              2,118
              
              
              974
              
              
              3,092Divestments
              
              
              (1
              )
              
              —
              
              
              (1
              )
              
              (107
              )
              
              (10
              )
              
              (117
              )
              
              (579
              )
              
              (2,604
              )
              
              (3,183
              )Discoveries
              
              
              18
              
              
              6
              
              
              24
              
              
              2,847
              
              
              592
              
              
              3,439
              
              
              533
              
              
              120
              
              
              653Extensions
              
              
              461
              
              
              153
              
              
              614
              
              
              20,328
              
              
              8,332
              
              
              28,660
              
              
              5,678
              
              
              9,218
              
              
              14,896Technical
                  Revisions
              
              
              289
              
              
              (28
              )
              
              261
              
              
              1,508
              
              
              (15,824
              )
              
              (14,316
              )
              
              (431
              )
              
              (2,718
              )
              
              (3,149
              )Economic
                  Factors
              
              
              (17
              )
              
              (5
              )
              
              (22
              )
              
              (4,070
              )
              
              (1,319
              )
              
              (5,389
              )
              
              (465
              )
              
              (196
              )
              
              (661
              )Improved
                  Recovery
              
              
              21
              
              
              7
              
              
              28
              
              
              23,458
              
              
              10,788
              
              
              34,246
              
              
              8,424
              
              
              4,132
              
              
              12,556Production
              
              
              (1,145
              )
              
              —
              
              
              (1,145
              )
              
              (76,288
              )
              
              —
              
              
              (76,288
              )
              
              (25,087
              )
              
              —
              
              
              (25,087
              )**December 31,
                  2006**
              
              
              8,856
              
              
              2,665
              
              
              11,521
              
              
              749,365
              
              
              284,620
              
              
              1,033,985
              
              
              253,804
              
              
              125,006
              
              
              378,810




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, 2005 to December 31, 2006 using constant
      prices and costs and discounted at 10% per year.




Canada
            
            **Year Ended**
              **December 31, 2006**(in $ millions)**Period
              and Factor**Estimated Future Net Revenue at
              December 31, 2005
            
            4,827Sales and Transfers of Oil, Natural
              Gas and
              NGLs Produced, Net of Production Costs and Royalties
            
            (816
            )Net Change in Prices, Production Costs
              and
              Royalties Related to Future Production
            
            (1,928
            )Changes in Previously Estimated Development
              Costs Incurred During the Period
            
            166Changes in Estimated Future Development
              Costs
            
            (206
            )Net Change Resulting from Extensions
              and
              Improved Recovery
            
            665Net Change Resulting from
              Discoveries
            
            11Changes from Acquisitions of
              Reserves
            
            17Changes from Dispositions of
              Reserves
            
            (3
            )Net Change Resulting from Revisions
              in
              Quantity Estimates
            
            (54
            )Accretion of Discount
            
            379Net
              Changes in Income Taxes
            
            —Estimated
              Future Net Revenue at December 31, 2006
            
            3,058






United States
            
            **Year Ended**
              **December 31, 2006**(in $ millions)**Period and Factor**Estimated Future Net Revenue at
              December 31, 2005
            
            579Sales and Transfers of Oil, Natural
              Gas and
              NGLs Produced, Net of Production Costs and Royalties
            
            (212
            )Net Change in Prices, Production Costs
              and
              Royalties Related to Future Production
            
            (35
            )Changes in Previously Estimated Development
              Costs Incurred During the Period
            
            74Changes in Estimated Future Development
              Costs
            
            (4
            )Net Change Resulting from Extensions
              and
              Improved Recovery
            
            49Net Change Resulting from
              Discoveries
            
            —Changes from Acquisitions of
              Reserves
            
            14Changes from Dispositions of
              Reserves
            
            —Net Change Resulting from Revisions
              in
              Quantity Estimates
            
            (76
            )Accretion of Discount
            
            63Net
              Changes in Income Taxes
            
            68Estimated
              Future Net Revenue at December 31, 2006
            
            520




(continues on next page)








25




(continued)




Total
              Enerplus
            
            **Year Ended**
              **December 31, 2006**(in $ millions)**Period and Factor**Estimated Future Net Revenue at
              December 31, 2005
            
            5,406Sales and Transfers of Oil, Natural
              Gas and
              NGLs Produced, Net of Production Costs and Royalties
            
            (1,028
            )Net Change in Prices, Production Costs
              and
              Royalties Related to Future Production
            
            (1,963
            )Changes in Previously Estimated Development
              Costs Incurred During the Period
            
            240Changes in Estimated Future Development
              Costs
            
            (210
            )Net Change Resulting from Extensions
              and
              Improved Recovery
            
            714Net Change Resulting from
              Discoveries
            
            11Changes from Acquisitions of
              Reserves
            
            31Changes from Dispositions of
              Reserves
            
            (3
            )Net Change Resulting from Revisions
              in
              Quantity Estimates
            
            (130
            )Accretion of Discount
            
            442Net
              Changes in Income Taxes
            
            68Estimated
              Future Net Revenue at December 31, 2006
            
            3,578




**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
              
              12,8732006
              
              282
              
              2,551
              
              —
              
              150
              
              31.0
              
              8,150
 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
              
              4,7992006
              
              39
              
              1,052
              
              6,935
              
              90
              
              13.0
              
              10,283
 
 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, 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 7,729 MBOE of Proved plus Probable Reserves which are capable
      of
      production but which, as of December 31, 2006, 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 cash
      distributions to unitholders 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, along with 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 crude oil waterfloods, shallow natural gas, coalbed methane and bitumen
      in western Canada and Bakken oil development in Montana and North Dakota.
      Enerplus also invests in the 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 aspects justify the
      risk
      to Enerplus. 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, 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
      mitigation is important 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, an active price risk management program and other risk mitigation
      actions. Enerplus typically experiences a greater than 99% drilling success
      by
      avoiding a large component of higher risk exploration type drilling. Enerplus
      also tends to take smaller working interests in higher risk play types to limit
      exposure in any one well without sacrificing the ability to participate in
      attractive areas such as the Deep Basin or the Foothills areas of Alberta.
      However, Enerplus generally allocates approximately 15% to 20% of its annual
      capital expenditures to longer-term opportunities in oil sands, land, seismic
      and higher risk drilling activities.




**Description of Principal Properties and Operations**




Outlined
      below is a
      description of Enerplus' oil and natural gas operations and 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 Reserves








27




Report
      or D&M Report, as applicable, using
      forecast prices and costs. See "Presentation of Enerplus' Oil and Gas Reserves,
      Resources and Production Information".




All
      of 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, North Dakota and, since
      January 31, 2007, Wyoming. All of Enerplus' major properties have related
      field production facilities and infrastructure to accommodate Enerplus'
      production. Production volumes for the year ended December 31, 2006 from
      Enerplus' properties consisted of approximately 47% crude oil and NGLs and
      53%
      natural gas on a BOE basis. Enerplus' 2006 production was comprised of average
      daily production of 36,134 bbls/d of crude oil, 4,483 bbls/d of NGLs
      and 271.0 MMcf/d of natural gas for a total of 85,779 BOE/d, an
      increase of 8% on a BOE basis when compared to 2005 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. Approximately 64% of
      Enerplus' 2006 production was operated by Enerplus and the remaining 36%
      was operated by industry partners. As at December 31, 2006, the oil and
      natural gas property interests held by Enerplus were estimated to contain Proved
      plus Probable Reserves of 119.4 MMbbls of light and medium crude oil,
      40.1 MMbbls of heavy crude oil, 56.7 MMbbls of bitumen,
      16.5 MMbbls of NGLs and 1,264.1 Bcf of natural gas, for a total of
      443.3 MMBOE. See "Oil and Natural Gas Reserves".




Enerplus'
      operations are
      organized into a business unit structure with five geographically distinct
      business units. Within each business unit, there are two or three teams of
      engineers, geologists, landmen and other technical support staff focused on
      segmented areas within the business unit. Enerplus believes that this structure
      has enabled it to better focus its activities, improve its operational and
      technical performance and enhance the generation and execution of attractive
      capital investment opportunities.




Enerplus'
      acquisition and
      development activities are generally focused on "resource plays", which are
      typically large and aerially 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 relatively predictable production and decline
      profiles, the timing, cost, production rates and reserve additions associated
      with the resource play can be more accurately predicted. Production from
      resource plays generally exhibits low declines over the long term, with a long
      reserve life. Enerplus' resource plays include shallow natural gas and coalbed
      methane in southeast and central Alberta and southwest Saskatchewan, 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 and Coalbed Methane










Shallow
      natural gas has
      been a core development area for Enerplus since the late 1990s. The shallow
      natural gas formations in southern Alberta and southwest Saskatchewan consist
      of
      massive, tightly packed sandstone that covers an area of over 10,000 square
      kilometres. These zones are typically less than 800 metres in depth and
      upper Cretaceous in age, with most production coming from the Milk River,
      Medicine Hat, and Second White Specks producing zones.




Enerplus
      has been
      investing in coalbed methane (" **CBM** ") assets since
      2004. Alberta
      contains significant amounts of coal distributed throughout the southern Plains,
      Foothills, and Mountain regions. The major coal zones in the Plains region
      are
      found in the Scollard (or Ardley), Horseshoe Canyon, Belly River, and
      Mannville geological zones, or strata. Enerplus is currently focused on the
      Horseshoe Canyon formation in the Trochu, Bashaw and Joffre areas in Alberta's
      southern Plains region, which do not have the water handling issues often
      associated with CBM production.




Shallow
      natural gas and
      CBM are similar resource plays in that the key to success with each is the
      ability to execute large, multi-well development programs efficiently and to
      manage the post-drilling operations of these low pressure wells.




Approximately
      16% of
      Enerplus' production for the year ended December 31, 2006 and approximately
      22% of Enerplus' estimated Proved plus Probable Reserves as at December 31,
      2006 were comprised of shallow natural gas and CBM. Approximately 67% of this
      production is operated by Enerplus. In 2006, Enerplus' five largest shallow
      natural gas producing properties were the Bantry, Hanna Garden, Verger,
      Shackleton, Medicine Hat South and Countess properties, while its largest CBM
      producing areas were Bashaw, Trochu and Joffre, all of which are located in
      Alberta with the exception of Shackleton, which is in southwest Saskatchewan.
      All of these properties have associated pipeline infrastructure and compression
      facilities.




Enerplus
      invested
      approximately $94 million in its shallow natural gas and CBM assets in 2006
      to drill 430 gross (249.5 net) wells. The majority of this investment
      occurred at Enerplus' Hanna Garden, Shackleton, Bantry and Medicine Hat shallow
      natural gas properties and its Joffre, Bashaw and Trochu CBM properties.
      Enerplus originally planned to invest $123 million in these properties in
      2006 but deferred some of this program due to inflationary pressures and weaker
      natural gas prices. In 2007, Enerplus currently plans to invest approximately








29




$43 million
      in these assets to drill
      approximately 360 gross (150 net) wells. Enerplus has chosen to
      reduce investment on shallow natural gas and CBM projects in 2007 as compared
      to
      2006 due to uncertainty on near-term natural gas prices and the desire to
      maintain investment levels on crude oil projects.




Waterflood
      Crude Oil







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 more
      predictable and stable declines and higher recovery of reserves. Infill drilling
      and well/injector optimization are effective methods of enhancing reserve
      recovery even further. Approximately 20% of Enerplus' production for the year
      ended December 31, 2006 and approximately 24% of Enerplus' estimated Proved
      plus Probable Reserves as at December 31, 2006 were related to waterflood
      assets. In 2006, Enerplus' five largest waterflood producing properties were
      Joarcam, Pembina 5 Way, Giltedge, the Medicine Hat Glauconitic C Unit and
      Mitsue, all of which are located in Alberta. All of Enerplus' major
      waterflood areas have associated crude oil production installations for emulsion
      treating and injection or water disposal. In addition, the Joarcam property
      also
      has facilities for natural gas compression, dehydration and processing.




Enerplus
      invested
      $65.8 million on waterflood development in 2006 including participation in
      the drilling of 40 gross (29.7 net) wells and related infrastructure,
      facility/injector optimization and re-completions. The majority of this
      investment occurred at Enerplus' five largest waterflood properties
      described above.




In
      2007, Enerplus currently plans to invest approximately $65 million on
      waterflood projects to drill 76 gross (41 net) wells, which is
      consistent with Enerplus' investment in this play type in 2005 and 2006.








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 separate acquisitions of Lyco Energy Corporation 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 (42o API) and some associated natural gas. As
      Enerplus' single largest producing property, the Sleeping Giant project
      represented approximately 13% of Enerplus' production in 2006 and 9% of
      Enerplus' Proved plus Probable Reserves as at December 31, 2006. The
      property is predominantly operated by Enerplus.




During
      2006 Enerplus
      invested $116.7 million to drill 41 gross (26.5 net) wells. While
      the majority of these wells were spaced at two wells per section, Enerplus
      initiated an increased density drilling program by drilling 6 gross
      (4 net) "third well per section" wells. Based upon results to date, ten
      additional increased density wells have been planned for 2007 and continued
      success may lead to additional increased density wells.




In
      2007, Enerplus plans to invest approximately $70 million in this resource
      play to drill 26 gross (17 net) oil wells and re-fracture stimulate
      12 gross (8 net) wells. Development activity in 2007 will complete the
      second well per section program in the primary Bakken field area and focus
      on
      identifying and proving up new opportunities in the general area. Enerplus
      owns
      approximately 114,000 net acres of undeveloped land in Montana and North
      Dakota, portions of which it plans to test in 2007. The primary target on the
      undeveloped lands is the Bakken formation, however the lands are also
      prospective for the Ratcliffe, Mission Canyon, Birdbear, Duperow and Red River
      geological formations. Key focus areas for Enerplus include: (i) expanding
      the existing primary Bakken field boundaries including drilling a trendline
      Bakken exploration well on its lands in North Dakota and evaluating/testing
      the
      Glacier area northwest of its current primary field area; (ii) proving up
      additional increased density drilling opportunities; (iii) accelerating its
      successful re-fracturing program; (iv) exploring the Bakken and other
      formations in Montana and North Dakota including completing a seismic program
      over a portion of the Montana lands with the intent to drill Red River
      development and exploration wells; and (v) evaluating longer term potential
      which may include improved recovery via potential waterflood or
      gas injection.








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 Limited. In
      2005, Deer Creek Energy Limited was acquired by Total, a wholly owned subsidiary
      of Total S.A., a major international oil and gas company with experience in
      the extraction and refining of heavy oil. Total is the operator of the Joslyn
      Project and intends to recover the bitumen located on the Joslyn Lease through
      a
      combination of phased SAGD and mining development. In 2006, Enerplus sold a
      1%
      working interest in the Joslyn Project in exchange for equity in Laricina
      Energy Ltd. (" **Laricina** "), a private
      oil sands focused company led by the former Chief Executive
      Officer of Deer Creek Energy Limited. Included in the sale is an area of mutual
      interest agreement which has been designed to allow Enerplus and Laricina to
      jointly pursue additional in-situ oil sands ventures. Following the sale to
      Laricina, Enerplus now has a 15% working interest in the Joslyn Project.




Enerplus
      believes that
      oil sands production will represent an increasing proportion of its production
      in the future. Enerplus is progressing on both SAGD and mine development at
      the
      Joslyn Lease and is currently one of the only conventional oil and gas income
      trusts participating in long term development of oil sands through either SAGD
      or mining. Enerplus has developed an internal oil sands team with significant
      industry experience which is supporting the development of the Joslyn Lease
      and
      also pursuing new grassroots efforts independently and in conjunction with
      Laricina. In support of these efforts, Enerplus invested approximately
      $3 million in 2006 to acquire a non-operated working interest in several
      land positions with in-situ thermal development potential with Laricina.
      Enerplus has budgeted $6 million in 2007 to further delineate these lands
      in early 2007.




In
      2006, Enerplus spent approximately $36.1 million at the Joslyn Lease to
      advance both the SAGD ($33.1 million) and the mining ($3 million)
      developments. Activity included the drilling of approximately 280 gross
      additional delineation wells over both SAGD and mining areas, including an
      additional 4.5 sections of land acquired in late 2005. Capital was invested
      to advance the progress of the SAGD development including the








32




completion
      of central plant facilities, the
      commissioning and start-up of the water treatment system and the initiation
      of
      steam injection into SAGD well pairs.




Joslyn SAGD Operations




SAGD
      Phase I of the Joslyn Project consisted of a pilot project facility and a
      single well pair which commenced production (to a maximum of
      200 bbls/d on a gross basis (30 bbls/d net to Enerplus)) in 2004 and
      was designed to provide useful information for the future operations of SAGD
      Phase II. The 10,000 bbls/d (1,500 bbls/d net to Enerplus) SAGD
      Phase II project (which now includes the single well pair previously
      forming SAGD Phase I) was scheduled for start-up (i.e. initial
      steaming) in the first half of 2006. The start-up of Phase II well pairs
      was delayed by a steam to surface incident that occurred on May 18, 2006.
      However, by December 31, 2006 more than one half of the well pairs were
      receiving steam and bitumen production volumes continue to increase. This delay
      did not affect Enerplus' corporate production guidance for 2006 as Enerplus
      did
      not expect any commercial production volumes in 2006. Based on information
      provided by Total, as the operator of the Joslyn Project, Enerplus continues
      to
      expect SAGD Phase II to reach peak production of 10,000 bbls/d
      (gross) in 2008. However due to reduced operating pressures, this may require
      additional wells to be drilled and capital expenditures to be made in 2007
      and
      2008. Enerplus' 2007 capital spending on the SAGD operations is currently
      budgeted at $21 million, which includes the continued start-up and ramp up
      of SAGD Phase II well pairs, and the possible addition of new well pairs
      late in the year.




The
      regulatory approval process continues for Phase III of the SAGD
      development, as the operator responded to additional Supplemental Information
      Requests by regulators in the fourth quarter of 2006. Enerplus expects
      regulatory approval for SAGD Phase III to occur in the second quarter
      of 2007. Currently, SAGD Phase III represents a proposed 15,000 bbls/d
      expansion of the existing facilities to a potential of 25,000 bbls/d of
      gross SAGD production. A portion of the SAGD Phase III volumes are
      currently booked as Probable Reserves by Enerplus. If current development plans
      are modified and a decision is made to instead mine some of the identified
      SAGD
      areas, Enerplus' existing SAGD Phase III Probable Reserve bookings could be
      impacted. Although Enerplus believes that mining typically provides
      approximately twice the recovery of the original bitumen in place as compared
      to
      SAGD projects, there could be timing differences between reserves bookings
      associated with the existing SAGD Phase III development plans versus
      possible expansion of mine development plans.




Enerplus
      and Total are
      continuing to review the optimal lease development and bitumen resource recovery
      plan given the flexibility which exists for both SAGD and mining operations.
      Although meaningful progress was made in 2006, the complexities of determining
      the optimal development plan have extended the timeline anticipated. Enerplus
      expects an extensive full lease development plan to be completed in 2007.
      Enerplus does not expect this to impact current SAGD operations or the timing
      for start-up of the initial phase of the mine.




Joslyn Mining Operations




Development
      of the mining
      portion of the Joslyn Project progressed in 2006 with the filing for regulatory
      approval for development of the mining resources located in the North Mine
      in February 2006. Total is currently working on responses to the first
      round of Supplemental Information Requests from the regulators and Enerplus
      expects Total to file an update early in the second quarter of 2007. Under
      current plans, the North Mine represents 100,000 bbls/d of gross bitumen
      production (15,000 bbls/d net to Enerplus) at a currently estimated
      cost of approximately $500 million, net to Enerplus.




Additional
      future
      mineable bitumen resources have been identified by Total on the South Mine
      portion of the Joslyn Lease. However, no regulatory applications have yet been
      filed with respect to the development of the South Mine. At this time, Enerplus
      estimates the future development of the South Mine to cost approximately
      $500 million, net to Enerplus.




Based
      on information provided by Total, Enerplus continues to expect start-up of
      the
      North Mine in 2013 with peak production expected in 2014, with start-up of
      the South Mine currently anticipated in 2016 and full production expected in
      2017. Enerplus expects its 2007 capital spending to be approximately
      $13 million to progress the regulatory approval process, engineering and
      additional delineation of the mining development.








33




Enerplus
      currently
      recognizes certain portions of the Joslyn mining operations as contingent
      resources but expects to eventually classify certain of the contingent resources
      as Probable Reserves as more uncertainties around the Joslyn Project are
      resolved. This would result in Enerplus including additional Probable Reserves
      (and the corresponding future development capital) associated with the Joslyn
      Project in its future reserves reporting. The timing of such reclassification
      as
      reserves remains uncertain, and may extend past 2007. Key factors impacting
      the
      timing of future reserves bookings include confirmation of project timing and
      sanction, regulatory approvals, project scope and marketing plans for the lease.
      However, a determination of those reserves or the value associated with those
      reserves cannot be made at this time.




As
      a
      result of the factors described above, no assurance can be provided as to the
      specific details surrounding the future development of the North Mine or the
      South Mine.




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




**Sanctioned
              Projects**
            
            **JoslynProjectProduction/Throughput**
            
            **NetProduction/Throughput(1)**
            
            **EstimatedNet
              FutureDevelopmentCapital(1)**
            
            **Start
              Up(2)**
            
            **FullProduction/Throughput(3)**(bbls/d)
            
            (bbls/d)
            
            ($ millions)SAGD Phase I and II
            
            10,000
            
            1,500
            
            31
            
            2006
            
            2008**Future Development
              Projects**SAGD Phase III
            
            15,000
            
            2,250
            
            284
            
            TBD
            
            TBDNorth Mine
            
            100,000
            
            15,000
            
            500
            
            2013
            
            2014South Mine
            
            100,000
            
            15,000
            
            500
            
            2016
            
            2017







Notes:
 (1) The
        net
        information presented in this table reflects Enerplus' 15% working interest.
        GLJ's estimates of SAGD production may vary from Total's estimates of production
        described above.
  (2) Start-up
        for
        SAGD refers to initial steaming. Start up for mining refers to initial
        extraction.
  (3) Full
        production refers to full project production/throughput.




Summary of Certain Joslyn Project Contingent Bitumen
      Resources




**For
      additional information regarding the disclosure of the
      contingent resources associated with the Joslyn Project, see "Presentation
      of
      Enerplus' Oil and Gas Reserves, Resources and Production
      Information — Disclosure of Contingent Resources for the Joslyn
      Project".**




GLJ,
      a private independent petroleum consulting firm based in Calgary, Alberta,
      has
      evaluated, estimated and subsequently prepared the GLJ Joslyn Resources Report
      with respect to the contingent bitumen resources associated with Enerplus'
      15%
      interest in the Joslyn Project in accordance with the standards contained in
      the
      COGE Handbook. The GLJ Joslyn Resources Report has provided the contingent
      resource estimates on a bitumen basis rather than a synthetic crude oil basis
      as, at present, the most likely development scenario will produce a fungible
      bitumen product that does not require an upgrader solution. However, Total,
      as
      the operator of the Joslyn Project, continues to evaluate an upgrader solution
      for the Joslyn Project.




The
      estimated volumes set forth below are associated with two separate mine
      development decisions, being the North Mine and the South Mine, and consequently
      such contingent resources are not likely to be reclassified as reserves at
      the
      same time. At this time, Enerplus does not intend to disclose any estimates
      of
      the contingent resources associated with other potentially mineable portions
      of
      the Joslyn Lease. The North Mine and the South Mine have been identified by
      Total as the projects most likely to proceed in the near-term, with significant
      uncertainty surrounding the development of additional mineable areas.




The
      operator of the Joslyn Project and Enerplus are considering an optimal
      development plan for the Joslyn Project which may result in a decision to mine
      the SAGD Phase III areas, to which GLJ has assigned approximately
      300 MMbbls of Proved plus Probable gross lease reserves (45 MMbbls net
      to Enerplus' interest, which reserves are included in Enerplus' reported
      reserves under "Oil and Gas Reserves — Summary of Joslyn Project
      Bitumen Reserves" above). However, if this decision is made, Enerplus
      anticipates that this would likely result in the designation of an additional
      "West" mining area where Enerplus anticipates that, at a minimum, these same
      volumes would be recovered. None of the estimated contingent resources relating
      to the North or South Mines presented herein correspond to the area of the
      Joslyn Project currently proposed for SAGD development to which reserves have
      been assigned.








34






The
      contingent resource estimates for the North Mine and South Mine set forth below
      are presented as "Low", "Best" and "High" estimates of recoverable volumes,
      with
      the "Low" estimate considered to be a conservative estimate of the quantity
      that
      will actually be recovered from the accumulation, the "Best" estimate considered
      to be the best estimate, and the "High" estimate considered to be an optimistic
      estimate. The "Low", "Best" and "High" estimates reflect some comparability
      with
      the reserves categories of "Proved", "Proved plus Probable" and "Proved plus
      Probable plus Possible", respectively. **The recovery
      and resource estimates provided herein are estimates only. Actual contingent
      resources (and any volumes that may be reclassified as reserves) and future
      production from such contingent resources may be greater than or less than
      the
      estimates provided herein.**


**Contingent
                  Bitumen Resources****Gross
                  Lease**
              
              
              **Company
                  Gross****Mine**
              
              
              **Low**
              
              
              **Best**
              
              
              **High**
              
              
              **Low**
              
              
              **Best**
              
              
              **High****(million
                  barrels)**North
                  Mine
              
              
              760
              
              
              930
              
              
              1,160
              
              
              114
              
              
              140
              
              
              174South
                  Mine
              
              
              320
              
              
              550
              
              
              810
              
              
              48
              
              
              83
              
              
              122**Total**
              
              
              1,080
              
              
              1,480
              
              
              1,970
              
              
              162
              
              
              223
              
              
              296


35




Other Conventional Assets










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 2006 daily production from these other conventional properties was
      approximately 43,225 BOE/d or approximately 50% of Enerplus' production. These
      other conventional reserves accounted for approximately 32% of Enerplus'
      estimated total Proved plus Probable Reserves as of December 31, 2006.




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 ConocoPhillips Canada, 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
      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.
      Operated conventional properties in southeast Saskatchewan include Tatagwa,
      Colgate, Heward and Neptune, as well as Routledge, Manitoba. Medium density
      oil
      production in these areas is generally pressure supported by natural
      water drive.








36




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
      invested
      approximately $175 million on development activities on its other
      conventional assets during 2006 to drill 275 gross (53.5 net) wells, of
      which 13 gross (11.9 net) wells were drilled in southeast Saskatchewan
      and 76 gross (6.0 net) wells were drilled on Enerplus' Deep
      Basin/Foothills properties. Enerplus currently plans to invest approximately
      $192 million on development activities on its other conventional properties
      in 2007. Major planned activities include investing approximately
      $36 million and drilling 88 gross (10 net) natural gas wells in
      the Deep Basin/Foothills area, investing approximately $38 million and
      drilling 29 gross (21.9 net) oil wells in southeast Saskatchewan and
      investing approximately $8 million and drilling 5 gross (5 net)
      oil wells at its Bantry North property.




**Summary of Principal Production Locations**




During
      the year ended
      December 31, 2006, on a BOE basis, 74% of Enerplus' production was derived
      from Alberta, 13% from Montana, 8% from Saskatchewan, 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, 2006. All properties listed in the table
      (other than "Other") are located in Alberta unless otherwise noted.


**2006 Average Daily Production**


**Product****Crude
                  Oil****Property**
              
              **Heavy**
              
              **Light
                  and**
                **Medium**
              
              **NGLs**
              
              **Natural
                  Gas**
              
              **Total****(bbls/d)**
              
              **(bbls/d)**
              
              **(bbls/d)**
              
              **(Mcf/d)**
              
              **(BOE/d)**Sleeping
                  Giant, Montana, U.S.A.
              
              —
              
              10,276
              
              —
              
              5,953
              
              11,268Bantry
              
              3,052
              
              —
              
              80
              
              29,940
              
              8,122Joarcam
              
              —
              
              2,062
              
              89
              
              5,926
              
              3,139Pembina
                  5 Way
              
              —
              
              2,116
              
              141
              
              1,928
              
              2,578Hanna
                  Garden
              
              —
              
              4
              
              4
              
              12,689
              
              2,123Pine
                  Creek
              
              —
              
              7
              
              502
              
              8,973
              
              2,005Verger
              
              —
              
              —
              
              —
              
              12,011
              
              2,002Chinchaga
              
              —
              
              —
              
              —
              
              11,890
              
              1,982Giltedge
              
              1,893
              
              —
              
              —
              
              143
              
              1,917Medicine
                  Hat Glauconitic "C"
              
              1,534
              
              —
              
              —
              
              829
              
              1,672Elmworth
              
              —
              
              —
              
              423
              
              7,089
              
              1,605Benjamin
              
              —
              
              —
              
              8
              
              9,234
              
              1,547Shackleton,
                  Saskatchewan
              
              —
              
              —
              
              —
              
              8,663
              
              1,444Valhalla
              
              —
              
              295
              
              84
              
              5,633
              
              1,318Progress
              
              —
              
              442
              
              66
              
              4,165
              
              1,202Medicine
                  Hat South
              
              —
              
              —
              
              —
              
              7,124
              
              1,187Mitsue
              
              —
              
              823
              
              129
              
              1,153
              
              1,144South
                  Wapiti
              
              —
              
              14
              
              296
              
              4,572
              
              1,072Enchant
              
              —
              
              375
              
              28
              
              3,901
              
              1,053Shorncliff
              
              986
              
              —
              
              5
              
              281
              
              1,038Virden,
                  Manitoba
              
              —
              
              1,038
              
              —
              
              1
              
              1,038Other
              
              1,439
              
              9,778
              
              2,628
              
              128,874
              
              35,323**TOTAL**
              
              **8,904**
              
              **27,230**
              
              **4,483**
              
              **270,972**
              
              **85,779**






37




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




The
      following table summarizes, as at December 31, 2006, 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
              
              
              3,267
              
              
              1,275.4
              
              
              6,201
              
              
              3,080.6
              
              
              983
              
              
              347.0
              
              
              561
              
              
              195.1
              
              
              775.3
              
              
              271.5Saskatchewan
              
              
              2,355
              
              
              452.8
              
              
              837
              
              
              452.1
              
              
              296
              
              
              31.9
              
              
              13
              
              
              5.7
              
              
              204.4
              
              
              124.0British
                  Columbia
              
              
              202
              
              
              24.2
              
              
              143
              
              
              30.6
              
              
              39
              
              
              4.7
              
              
              62
              
              
              15.6
              
              
              164.2
              
              
              73.9Manitoba
              
              
              558
              
              
              310.8
              
              
              —
              
              
              —
              
              
              14
              
              
              7.9
              
              
              —
              
              
              —
              
              
              56.2
              
              
              52.5Montana
              
              
              174
              
              
              92.1
              
              
              —
              
              
              —
              
              
              1
              
              
              0.5
              
              
              —
              
              
              —
              
              
              73.9
              
              
              43.7North
                  Dakota
              
              
              2
              
              
              1.5
              
              
              —
              
              
              —
              
              
              —
              
              
              —
              
              
              —
              
              
              —
              
              
              90.9
              
              
              70.1Oil
                  Sands (Alberta)
              
              
              18
              
              
              2.9
              
              
              —
              
              
              —
              
              
              —
              
              
              —
              
              
              —
              
              
              —
              
              
              21.1
              
              
              6.5Total
              
              
              6,576
              
              
              2,159.7
              
              
              7,181
              
              
              3,563.3
              
              
              1,333
              
              
              392.0
              
              
              636
              
              
              216.4
              
              
              1,386.0
              
              
              642.2


Enerplus
      expects its rights
      to explore, develop and exploit on approximately 105,000 net acres of Unproved
      Properties to ordinarily expire prior to December 31, 2007. 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 generally allocates approximately 15% to 20% of
      its
      annual capital expenditures to longer-term opportunities in oil sands, land,
      seismic and higher risk drilling activities. 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
      2006, Enerplus
      participated in the drilling of 790 gross oil and natural gas wells (360.8
      net
      wells) with virtually a 100% net well success rate, plus 7 gross
      (0.1 net) service wells. The majority of Enerplus' drilling activity was in
      the shallow natural gas areas around Hanna Garden, Medicine Hat, Verger and
      Bantry. The Fund also had active operated drilling and facility programs in
      oil
      dominated areas such as Pembina, Joarcam, southeast Saskatchewan and Montana.
      The Shackleton shallow natural gas area in southwest Saskatchewan, the Joffre
      CBM area in Alberta, the Deep Basin area of northwestern Alberta and the
      Foothills region of western Alberta were the focus areas of non-operated
      drilling activity in 2006. 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, 2006, 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
              
              157
              
              55.7
              
              5
              
              1.8
              
              41
              
              26.5
              
              —
              
              —Natural
                  gas wells
              
              506
              
              252.2
              
              69
              
              22.8
              
              —
              
              —
              
              —
              
              —Bitumen
                  recovery well pairs
              
              11
              
              1.7
              
              —
              
              —
              
              —
              
              —
              
              —
              
              —Service
                  wells
              
              7
              
              0.1
              
              —
              
              —
              
              —
              
              —
              
              —
              
              —Dry
                  and abandoned wells
              
              —
              
              —
              
              1
              
              0.1
              
              —
              
              —
              
              —
              
              —Total
              
              681
              
              309.7
              
              75
              
              24.7
              
              41
              
              26.5
              
              0
              
              0.0






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 (and subsequent development activities
      on
      such acquired properties) 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 2006 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
      2006.




**Year
                  Ended December 31, 2006****First
                  Quarter**
              
              **Second
                  Quarter**
              
              **Third
                  Quarter**
              
              **Fourth
                  Quarter**
              
              **Total
                  for Year****Canada**Crude
                  oilLight
                  and medium oil (bbls/d)
              
              
              17,280
              
              
              16,865
              
              
              16,658
              
              
              17,017
              
              
              **16,954**Heavy
                  oil (bbls/d)
              
              
              9,059
              
              
              9,047
              
              
              8,630
              
              
              8,886
              
              
              **8,904**Total
                  crude oil (bbls/d)
              
              
              26,339
              
              
              25,912
              
              
              25,288
              
              
              25,903
              
              
              **25,858**Natural
                  gas liquids (bbls/d)
              
              
              4,411
              
              
              4,856
              
              
              4,199
              
              
              4,467
              
              
              **4,483**Total
                  liquids (bbls/d)
              
              
              30,750
              
              
              30,768
              
              
              29,487
              
              
              30,370
              
              
              **30,341**Natural
                  gas (Mcf/d)
              
              
              265,354
              
              
              263,265
              
              
              260,381
              
              
              271,061
              
              
              **265,019**Total
                  Canada (BOE/d)
              
              
              74,976
              
              
              74,645
              
              
              72,884
              
              
              75,547
              
              
              **74,511****United States**Light
                  and medium crude oil (bbls/d)
              
              
              9,514
              
              
              10,476
              
              
              10,664
              
              
              10,436
              
              
              **10,276**Natural
                  gas (Mcf/d)
              
              
              5,411
              
              
              5,823
              
              
              5,911
              
              
              6,654
              
              
              **5,953**Total
                  United States (BOE/d)
              
              
              10,416
              
              
              11,447
              
              
              11,649
              
              
              11,545
              
              
              **11,268****Total
                  Enerplus**Crude
                  oilLight
                  and medium oil (bbls/d)
              
              
              26,794
              
              
              27,341
              
              
              27,322
              
              
              27,453
              
              
              **27,230**Heavy
                  oil (bbls/d)
              
              
              9,059
              
              
              9,047
              
              
              8,630
              
              
              8,886
              
              
              **8,904**Total
                  crude oil (bbls/d)
              
              
              35,853
              
              
              36,388
              
              
              35,952
              
              
              36,339
              
              
              **36,134**Natural
                  gas liquids (bbls/d)
              
              
              4,411
              
              
              4,856
              
              
              4,199
              
              
              4,467
              
              
              **4,483**Total
                  liquids (bbls/d)
              
              
              40,264
              
              
              41,244
              
              
              40,151
              
              
              40,806
              
              
              **40,617**Natural
                  gas (Mcf/d)
              
              
              270,765
              
              
              269,088
              
              
              266,292
              
              
              277,715
              
              
              **270,972**Total
                  Enerplus (BOE/d)
              
              
              85,392
              
              
              86,092
              
              
              84,533
              
              
              87,092
              
              
              **85,779**








39




**Quarterly Netback History**




The following
      tables set forth Enerplus' average netbacks received for each fiscal quarter
      in
      2006 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
      2006. 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,
              2006**Light
              and Medium Crude Oil ($ per
              bbl)
            
            **First
              Quarter**
            
            **Second
              Quarter**
            
            **Third
              Quarter**
            
            **Fourth
              Quarter**
            
            **Total
              for Year****Canada**Sales
              price(1)
            
            $
            58.76
            
            $
            72.23
            
            $
            70.93
            
            $
            57.09
            
            **$**
            **64.69**Royalties
            
            
            (9.39
            )
            
            (12.26
            )
            
            (10.46
            )
            
            (8.34
            )
            
            **(10.10**
            **)**Production
              costs(2)
            
            
            (13.38
            )
            
            (15.30
            )
            
            (14.79
            )
            
            (14.82
            )
            
            **(14.57**
            **)**Netback
            
            $
            35.99
            
            $
            44.67
            
            $
            45.68
            
            $
            33.93
            
            **$**
            **40.02****United States**Sales
              price(1)
            
            $
            64.93
            
            $
            72.50
            
            $
            74.00
            
            $
            59.85
            
            **$**
            **67.93**Royalties(3)
            
            
            (13.26
            )
            
            (14.60
            )
            
            (15.06
            )
            
            (12.63
            )
            
            **(13.91**
            **)**Production
              costs(2)
            
            
            (1.80
            )
            
            (1.60
            )
            
            (1.96
            )
            
            (1.79
            )
            
            **(1.79**
            **)**Netback
            
            $
            49.87
            
            $
            56.30
            
            $
            56.98
            
            $
            45.43
            
            **$**
            **52.23****Total
              Enerplus**Sales
              price(1)
            
            $
            60.95
            
            $
            72.34
            
            $
            72.13
            
            $
            58.14
            
            **$**
            **65.91**Royalties(3)
            
            
            (10.43
            )
            
            (12.81
            )
            
            (11.93
            )
            
            (9.65
            )
            
            **(11.21**
            **)**Production
              costs(2)
            
            
            (9.33
            )
            
            (10.11
            )
            
            (9.85
            )
            
            (9.94
            )
            
            **(9.81**
            **)**Netback
            
            $
            41.19
            
            $
            49.42
            
            $
            50.35
            
            $
            38.55
            
            **$**
            **44.89**






**Year
              Ended December 31,
              2006**Heavy
              Oil ($ per bbl)
            
            **First
              Quarter**
            
            **Second
              Quarter**
            
            **Third
              Quarter**
            
            **Fourth
              Quarter**
            
            **Total
              for Year****Canada/Total
              Enerplus**Sales
              price(1)
            
            $
            38.20
            
            $
            58.12
            
            $
            57.30
            
            $
            43.38
            
            **$**
            **49.22**Royalties
            
            
            (9.39
            )
            
            (12.26
            )
            
            (10.46
            )
            
            (8.34
            )
            
            **(10.10**
            **)**Production
              costs(2)
            
            
            (9.71
            )
            
            (10.61
            )
            
            (14.82
            )
            
            (14.91
            )
            
            **(12.49**
            **)**Netback
            
            $
            19.10
            
            $
            35.25
            
            $
            32.02
            
            $
            20.13
            
            **$**
            **26.63**






**Year
              Ended December 31,
              2006**Natural
              Gas Liquids ($ per bbl)
            
            **First
              Quarter**
            
            **Second
              Quarter**
            
            **Third
              Quarter**
            
            **Fourth
              Quarter**
            
            **Total
              for Year****Canada/Total
              Enerplus**Sales
              price(1)
            
            $
            50.57
            
            $
            52.33
            
            $
            54.63
            
            $
            46.15
            
            **$**
            **50.90**Royalties
            
            
            (12.97
            )
            
            (13.53
            )
            
            (14.48
            )
            
            (11.91
            )
            
            **(13.21**
            **)**Production
              costs(2)
            
            
            —
            
            
            —
            
            
            —
            
            
            —
            
            
            —Netback
            
            $
            37.60
            
            $
            38.80
            
            $
            40.15
            
            $
            34.24
            
            **$**
            **37.69**






40






**Year
              Ended December 31,
              2006**Natural
              Gas ($ per Mcf)
            
            **First
              Quarter**
            
            **Second
              Quarter**
            
            **Third
              Quarter**
            
            **Fourth
              Quarter**
            
            **Total
              for Year****Canada**Sales
              price(1)
            
            $
            8.32
            
            $
            6.17
            
            $
            6.09
            
            $
            6.57
            
            **$**
            **6.79**Royalties
            
            
            (1.82
            )
            
            (1.31
            )
            
            (1.09
            )
            
            (1.19
            )
            
            **(1.35**
            **)**Production
              costs(2)
            
            
            (1.16
            )
            
            (1.30
            )
            
            (0.97
            )
            
            (1.24
            )
            
            **(1.17**
            **)**Netback
            
            $
            5.34
            
            $
            3.56
            
            $
            4.03
            
            $
            4.14
            
            **$**
            **4.27****United States**Sales
              price(1)
            
            $
            8.61
            
            $
            8.25
            
            $
            7.69
            
            $
            6.81
            
            **$**
            **7.78**Royalties(3)
            
            
            (1.67
            )
            
            (1.60
            )
            
            (1.49
            )
            
            (1.32
            )
            
            **(1.51**
            **)**Production
              costs(2)
            
            
            —
            
            
            —
            
            
            —
            
            
            —
            
            
            —Netback
            
            $
            6.94
            
            $
            6.65
            
            $
            6.20
            
            $
            5.49
            
            **$**
            **6.27****Total
              Enerplus**Sales
              price(1)
            
            $
            8.33
            
            $
            6.22
            
            $
            6.13
            
            $
            6.58
            
            **$**
            **6.81**Royalties(3)
            
            
            (1.82
            )
            
            (1.31
            )
            
            (1.10
            )
            
            (1.19
            )
            
            **(1.35**
            **)**Production
              costs(2)
            
            
            (1.14
            )
            
            (1.28
            )
            
            (0.95
            )
            
            (1.21
            )
            
            **(1.14**
            **)**Netback
            
            $
            5.37
            
            $
            3.63
            
            $
            4.08
            
            $
            4.18
            
            **$**
            **4.32**






**Year
              Ended December 31,
              2006**Total
              ($ per BOE)
            
            **First
              Quarter**
            
            **Second
              Quarter**
            
            **Third
              Quarter**
            
            **Fourth
              Quarter**
            
            **Total
              for Year****Canada**Sales
              price(1)
            
            $
            50.67
            
            $
            48.58
            
            $
            47.91
            
            $
            44.29
            
            **$**
            **47.84**Royalties
            
            
            (10.17
            )
            
            (9.39
            )
            
            (8.25
            )
            
            (7.67
            )
            
            **(8.86**
            **)**Production
              costs(2)
            
            
            (8.37
            )
            
            (9.34
            )
            
            (8.59
            )
            
            (9.55
            )
            
            **(8.97**
            **)**Netback
            
            $
            32.13
            
            $
            29.85
            
            $
            31.07
            
            $
            27.07
            
            **$**
            **30.01****United States**Sales
              price(1)
            
            $
            63.78
            
            $
            70.55
            
            $
            71.64
            
            $
            58.02
            
            **$**
            **66.06**Royalties(3)
            
            
            (12.12
            )
            
            (13.36
            )
            
            (13.79
            )
            
            (11.42
            )
            
            **(12.68**
            **)**Production
              costs(2)
            
            
            (1.80
            )
            
            (1.60
            )
            
            (1.96
            )
            
            (1.79
            )
            
            **(1.79**
            **)**Netback
            
            $
            49.86
            
            $
            55.59
            
            $
            55.89
            
            $
            44.81
            
            **$**
            **51.59****Total
              Enerplus**Sales
              price(1)
            
            $
            52.27
            
            $
            51.50
            
            $
            51.18
            
            $
            46.11
            
            **$**
            **50.23**Royalties(3)
            
            
            (10.40
            )
            
            (9.92
            )
            
            (9.01
            )
            
            (8.16
            )
            
            **(9.36**
            **)**Production
              costs(2)
            
            
            (7.57
            )
            
            (8.31
            )
            
            (7.68
            )
            
            (8.52
            )
            
            **(8.02**
            **)**Netback
            
            $
            34.30
            
            $
            33.27
            
            $
            34.49
            
            $
            29.43
            
            **$**
            **32.85**




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
      budgets for and recognizes as a liability the estimated fair value of the future
      retirement obligations associated with its property, plant and equipment.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 $437 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 $194 million on an undiscounted basis and $24 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 $40 million on an undiscounted basis and $35 million
      discounted at 10% will be incurred in respect of abandonment and reclamation
      costs.




**Tax Horizon**




Canada




No
      cash Canadian income taxes have been paid by the Fund or its Canadian Operating
      Subsidiaries for the year ended December 31, 2006. Under Enerplus' current
      structure and current Canadian tax laws, 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, under current Canadian tax laws, no
      Canadian income taxes would currently be expected to be incurred by the Fund
      or
      its Canadian Operating Subsidiaries in the future. However, as described in
      further detail under "General Development of Enerplus Resources
      Fund — Developments in the Past Three Years — Federal
      Government Pronouncements on Income Trusts", "Oil and Natural Gas
      Reserves — Overview of Reserves", and "Risk Factors — Risks
      Relating to Enerplus' Structure and Ownership of the Trust Units", the Canadian
      federal government has introduced the Income Trust Tax Proposals which, if
      enacted as legislation, would generally tax income trusts at the same
      effective tax rates as Canadian corporations. Should the proposed
      legislation become substantially enacted, the Fund's future income taxes
      disclosed in its financial statements may be adjusted to include temporary
      differences between the accounting and tax bases of the Fund's assets and
      liabilities. In addition, the reported estimated net present value of future
      net
      revenues from Enerplus' oil and natural gas reserves may be adjusted to include
      an estimate of such revenues on an "after-tax" basis to reflect the impact
      of
      the income trust tax.




United States




A
      total of $18.2 million of U.S. income related cash taxes were incurred
      with respect to U.S. operations during the year ended December 31,
      2006. 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 9 to the Fund's audited financial
      statements for the year ended December 31, 2006.




**Costs Incurred**




In the
      financial year ended December 31, 2006, Enerplus made the following
      expenditures:


**Property****Acquisition
                    Costs****Proved**
                
                
                **Unproved**
                
                
                **Exploration
                    Costs**
                
                
                **Development
                    Costs****($
                    in millions)**Canada
                
                $
                35.3
                
                $
                20.0
                
                $
                32.5
                
                $
                322.0United States
                
                
                16.0
                
                
                0.2
                
                
                1.2
                
                
                115.3**Total**
                
                $
                51.3
                
                $
                20.2
                
                $
                33.7
                
                $
                437.3


42




**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 $65.91/bbl for its light and medium crude oil, $49.22/bbl for its heavy
      crude
      oil and $50.90/bbl for its NGLs for the year ended December 31, 2006,
      compared to $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. Enerplus 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 shared equitably to all supply producers. In 2006, these
      aggregator 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 via
      three routes. 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
      2006 revenues attributable to natural gas (net of transportation costs but
      before the effects of commodity derivative instruments) was 43% compared to
      55%
      in 2005. The average price received by Enerplus (net of transportation
      costs but before the effects of commodity derivative instruments) for its
      natural gas in 2006 was $6.81/Mcf compared to $8.41/Mcf in the year ended
      December 31, 2005. Within its sales portfolio of aggregator, downstream and
      spot natural gas, Enerplus sold approximately 42% of its natural gas based
      on
      the daily AECO market, 42% based on the monthly AECO market and 16% against
      the
      day and month NYMEX indices.




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 market prices,
      which exposes Enerplus to the risks associated with commodity price fluctuations
      and foreign exchange rates. See "Risk Factors". Information regarding Enerplus'
      financial instruments is contained in Note 10 to the Fund's audited
      annual consolidated financial statements for the year ended December 31,
      2006 and under the headings "Pricing" and "Price Risk Management" in the Fund's
      management's discussion and analysis for the year ended December 31, 2006,
      each of which is available through the Internet on Enerplus' website at
www.enerplus.com, on Enerplus' SEDAR profile at www.sedar.com and
      on EDGAR at www.sec.gov.




**Environment, Health and Safety**




Enerplus
      places a high
      priority on preserving the quality of its environment and protecting the health
      and safety of its employees, contractors and the public in the communities
      in
      which it lives and works. Enerplus actively participates in industry-recognized
      programs at the highest possible levels in an effort to support continuous
      improvement.








43




In
      2006, Enerplus again received the Certificate of Recognition as part of the
      Partnership Program with Alberta Human Resources and the Workers' Compensation
      Board. This certificate is given to employers who develop health and safety
      management systems that meet established standards. Enerplus has maintained
      its
      Certificate of Recognition through annual reviews and audits every three years
      since 2000. The second independent audit of Enerplus' environment, health and
      safety (" **EHS** ")
      management system was conducted in 2006 and Enerplus received a 95% score.




Enerplus'
      actual safety
      performance declined in 2006 as compared to 2005. A total of eight employee
      recordable injury incidents were recorded in 2006, resulting in a lost time
      injury frequency rate of 0.53 per 200,000 man hours compared to
      0 incidents per 200,000 man hours in 2005. In addition, Enerplus'
      contractor lost-time injury frequency also increased from 0.46 per
      200,000 man hours in 2005 to a rate of 0.97 per 200,000 man hours
      in 2005. While the majority of these incidents were of a lesser severity,
      Enerplus is nevertheless concerned about the higher level of incidents. Enerplus
      is working to improve its safety performance through increased awareness in
      the
      field, personalizing safety messages so they have a more profound impact on
      personal decisions, and increasing the accountability for safety throughout
      the
      organization.




Enerplus
      is committed to
      meeting its responsibilities to protect the environment through a variety of
      programs and actively monitoring its compliance with all regulators. In
      particular, Enerplus engages in the following activities:


• Enerplus
        participated in the Environment, Health and Safety Stewardship Program developed
        by the Canadian Association of Petroleum Producers at the highest level,
        platinum. Enerplus' participation requires its commitment to continuous
        improvement in its EHS management practices including sound planning and
        implementation, open communication and demonstrated performance and a thorough
        external audit of its activities at least once every five years;
  • Enerplus
        increased its spending on reclamation and site abandonment by approximately
        48% to $6.1 million. Site abandonment and reclamation occurs when
        areas are returned to their original state once operations have been completed.
        Enerplus' reclamation activities resulted in 36 reclamation certificates
        being received with another 58 sites ready for review by Alberta
        Environment. This correlates to a 13% reduction in Enerplus' total reclamation
        sites from 2005;
  • Enerplus
        doubled its remediation spending in 2006 to $9.6 million and reduced its
        reportable spills by 18%. Remediation is the environmental clean-up of spills
        or
        issues, many of which are associated with older properties or changing
        regulations;
  • Enerplus
        enhanced its pipeline integrity efforts and reduced pipeline failures by
        13%
        year-over-year through its Pipeline Management Program and related activities.
        The Pipeline Management Program is designed to maintain the integrity of
        Enerplus' underground pipelines through on-going risk assessment. In 2006,
        90%
        of Enerplus' 6,000 kilometres of pipeline were assessed with appropriate
        actions taken to identify future pipeline leaks or breaks; and
  • Enerplus
        increased the number of internal emergency response drills to prepare its
        staff
        in the case of an emergency.
  In
        2007,
        Enerplus intends to spend approximately $16 million on EHS activities and
        particularly focus on, among other things, the following EHS activities and
        initiatives:


•  
        maintaining spending levels on abandonment and restoration activities;
  •  
        working to improve its safety performance through awareness in the field,
        personalizing safety messages to have a stronger impact on personal decisions
        and increasing the accountability throughout the organization for safety;
  •  
        evaluating Enerplus' impact on the environment. With growing concern over
        global
        warming and environmental matters, Enerplus is looking at additional ways
        it can
        minimize its environmental impact;
  •  
        evaluating and implementing options to increase safety presence and ownership
        of
        Enerplus' safety programs at the field level; and




44


•expanding
        its efforts relating to employee and contractor safety compliance through
        enhanced safety orientations, awareness and training sessions.
 
 Overall,
      Enerplus believes its EHS initiatives confirm its ongoing commitment to
      environmental stewardship and the health and safety of its employees,
      contractors and the general public in the communities in which it operates.




**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 "— Environment,
      Health and Safety" above. 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
      2006. See "Industry Conditions — Environmental Regulation" and
      "Risk Factors".




**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, liability coverage
      is also carried for directors and officers of Enerplus.




Personnel




As at
      December 31, 2006, Enerplus employed a total of 606 persons.








45




**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. A copy of the Trust Indenture was filed on the Fund's SEDAR profile
      at www.sedar.com on January 5, 2004 and on EDGAR at
www.sec.gov on December 7, 2006.




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., 662/3% 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 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,
      au thorities 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
      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 662/3% 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








46


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
      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










47


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
      662/3% 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.




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










48


non-residents
      exceeds a 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" 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 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 to Unitholders




The
      Fund makes distributions to unitholders from the cash payments that it receives,
      directly or indirectly, from its Operating Subsidiaries. It receives income
      from
      EnerMark, ERC and Enerplus Oil & Gas pursuant to the royalty
      agreements, as well as from dividend and distribution payments received,
      directly or indirectly, 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 cash distributions that are to be paid to the Fund's unitholders
      in any period, and the timing of those distributions, is within EnerMark's
      discretion.




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
      cash distributions, if any, that will be paid 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
      "net income" and "net realized capital gains" of the Fund (as defined in the
      Trust Indenture and not as calculated in accordance with GAAP), together with
      such other amounts as EnerMark may determine, for that period ending on the
      distribution record date to the extent those amounts were not previously
      declared payable. The authority to determine the amount of cash










49


distributions,
      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 (generally 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 cash that is determined to be necessary to pay any tax liability of the
      Fund,
      and those amounts will not be payable as distributions 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.




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








50




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
      662/3% 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.




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.








51




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
      662/3% 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




(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 EnerMark's
      Subordinated Notes**




The
      Fund's primary sources of cash are 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 and dividend and distribution payments received by the Fund
      from
      certain of its subsidiaries. Additionally, EnerMark makes interest and principal
      payments on unsecured, subordinated debt to another subsidiary of the Fund
      which
      subsequently pays distributions to the Fund. Outlined below is a










52


description of the royalties granted by EnerMark, ERC and
      Enerplus Oil & Gas to the Fund and the subordinated debt issued by
      EnerMark to another subsidiary of 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 income from their respective oil and natural gas properties
      and operations. The royalties are paid to the Fund 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 another subsidiary of the Fund,
      which subsequently pays distributions 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, directly or indirectly, from the Fund or its
      subsidiaries to EnerMark and principal repayments are made on the notes. The
      payment of principal and interest on the notes is subordinated to the 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
      and the Fund's subsidiary which directly holds the EnerMark notes have each
      entered into a subordination agreement pursuant to which the payment by EnerMark
      of obligations under the subordinated notes 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 Subsidiaries of the Fund




As
      stated above, the terms of the existing royalty agreements and the subordinated
      debt issued by EnerMark, together with the subordination agreements entered
      into
      by the Fund and the Fund's subsidiary that directly holds the subordinated
      notes
      and the terms of EnerMark's credit facilities and senior notes, result in the
      royalty, interest, distribution and dividend payments made directly or
      indirectly from the Fund's 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 made directly
      or
      indirectly from EnerMark, ERC,








53




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 2006 Annual Report and under the heading "Statement
      of
      Corporate Governance Practices" in the Fund's information circular and proxy
      statement dated March 12, 2007. 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 indirect 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 was filed as a "Security holder document"
      on
      April 12, 2005 on the Fund's SEDAR profile at www.sedar.com, was
      filed on EDGAR at www.sec.gov on February 6, 2007, and is
      available on the Fund's website at www.enerplus.com under "Governance".










54


**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 third party indebtedness of Enerplus
      is incurred directly by its primary Operating Subsidiary, EnerMark. As at
      December 31, 2006, 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 credit
      agreement with nine North American banks that currently is scheduled to mature
      in November 2009, subject to further extension by the lenders. As at
      December 31, 2006, $348.5 million was outstanding under this facility.
      This bank debt carries floating interest rates that Enerplus expects to range
      between 55.0 and 110.0 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;•  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).




55






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).




**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
                andDecember 19
            
            April 1
                andOctober 1Principal payments in five annual equal
              installments 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" and "Consolidated EBITDA"
      have the same meanings as "Consolidated Senior Debt" and "Consolidated EBITDA",
      respectively, in the definitions relating to the Bank Credit Facility.




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 7 to the
      Fund's audited annual consolidated financial statements for the year ended
      December 31, 2006 and under the heading "Liquidity and Capital
      Resources — Long-Term Debt" in Enerplus' management's discussion and
      analysis for the year ended December 31, 2006. 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 EnerMark's Subordinated Notes" and "Risk Factors".








56


**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.




**Cash Distributions**




The
      Fund may, on or before any distribution record date, declare cash distributions
      payable to the unitholders. See "Information Respecting Enerplus Resources
      Fund — Description of the Trust Units and the Trust
      Indenture — Distributions to Unitholders".




Although
      the Fund intends
      to make monthly cash distributions to its 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, directly or indirectly,
      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 distributions paid by the Fund to unitholders is dependent on
      the
      amount of cash flow paid to the Fund by its Operating Subsidiaries and can
      vary
      significantly from period to period for a number of reasons, including among
      other things (i) the Operating Subsidiaries' operational and financial
      performance (including fluctuations in the quantity of Enerplus' oil, NGLs
      and
      natural gas production and the sales price that Enerplus realizes for such
      production (after hedging contract receipts and payments)),
      (ii) fluctuations in the costs to produce oil, NGLs and natural gas and to
      administer and manage the Fund and its subsidiaries, (iii) the amount of
      cash required or retained for debt service or repayment, (iv) amounts
      required to fund capital expenditures and working capital requirements, and
      (v) foreign currency exchange rates and interest rates. Certain of these
      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 addition, the level
      of
      distributions per Trust Unit will be affected by the number of outstanding
      Trust
      Units. In the past, the level of cash retained has historically varied between
      10% and 40% of Enerplus' total annual cash flow from operating activities.
      For
      the year ended December 31, 2006, approximately 29% of the cash flow from
      operating activities was retained, resulting in a "payout ratio" of 71%.




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".










57


**Distribution History**




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**
              
              **2007**
              
              **2006**
              
              **2005**
              
              **2004**
              
              **2003**January(1)
              
              $0.42
              
              $
              0.42
              
              $
              0.35
              
              $
              0.35
              
              $
              0.30February
              
              0.42
              
              
              0.42
              
              
              0.35
              
              
              0.35
              
              
              0.32March
              
              0.42
              
              
              0.42
              
              
              0.35
              
              
              0.35
              
              
              0.35April
              
              N/A
              
              
              0.42
              
              
              0.35
              
              
              0.35
              
              
              0.35May
              
              N/A
              
              
              0.42
              
              
              0.35
              
              
              0.35
              
              
              0.37June
              
              N/A
              
              
              0.42
              
              
              0.35
              
              
              0.35
              
              
              0.37July
              
              N/A
              
              
              0.42
              
              
              0.35
              
              
              0.35
              
              
              0.37August
              
              N/A
              
              
              0.42
              
              
              0.37
              
              
              0.35
              
              
              0.37September
              
              N/A
              
              
              0.42
              
              
              0.37
              
              
              0.35
              
              
              0.37October
              
              N/A
              
              
              0.42
              
              
              0.37
              
              
              0.35
              
              
              0.37November
              
              N/A
              
              
              0.42
              
              
              0.42
              
              
              0.35
              
              
              0.35December
              
              N/A
              
              
              0.42
              
              
              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".**




**Canadian Tax Reporting Matters**




The
      Fund currently qualifies as a mutual fund trust under the Canadian Tax Act
      and
      each year the Fund has historically transferred all of its taxable income to
      unitholders by way of distributions. For Canadian tax purposes, approximately
      4%
      of the Fund's 2006 distributions was a tax-deferred return of capital,
      approximately 95% was taxable to unitholders as other income and less than
      1%
      was taxable eligible dividend income. See "Risk Factors — Risks
      Relating to Enerplus' Structure and the Ownership of the Trust Units".




**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, approximately 90% of
      the distributions paid by the Fund during 2006 were 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' 2006 distributions should
      be considered "Qualified Dividends" eligible for a reduced 15% rate of tax
      applicable to long term capital gains. This 15% tax rate is currently
      scheduled to expire at the end of 2010 and there is no assurance that this
      reduced tax rate for "Qualified Dividends" will be renewed by the U.S.
      government at such time. See "Risk Factors — Risks Related to
      Enerplus' Structure and the Ownership of the Trust Units" and "Risk
      Factors — Risks Particular to United States and Other
      Non-Resident Unitholders".




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.






58


**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 approximately 74% of Enerplus' 2006
      average daily production occurred). Enerplus also owns oil and natural gas
      properties and related assets in Montana, North Dakota and Wyoming 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, resulting in a market
      price for 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








59




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.




**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 in the Canadian provinces where Enerplus operates 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.








60




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 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.




The
      current Alberta royalty system for oil sands is scheduled to expire on
      June 30, 2007. The Government of Alberta has stated that it intends to
      conduct a thorough review and analysis of the current royalty regime in place
      in
      Alberta and in particular the royalty system applicable to the oil sands, with
      the panel appointed to review the oil sands royalty system expected to submit
      a
      final report with recommendations to the government by August 31, 2007. As
      a result, the government is expected to extend the existing oil sands royalty
      system until June 30, 2008. See "Risk Factors — Risks Related to
      Enerplus' Business and Operations".




**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








61




(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.




**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' Fram ework 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, and the Canadian federal government is currently evaluating other
      proposals and legislative measures that would achieve similar objectives. The
      upstream Canadian oil and gas sector is in discussions with various federal
      and
      provincial levels of government regarding the development of greenhouse 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 emissions and set 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.








62




**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.
      Unitholders and 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.




**In
      particular, Enerplus directs unitholders and prospective
      investors to the description of the risks under the heading "Risk
      Factors — Risks Related to Enerplus' Structure and the Ownership of
      the Trust Units — Changes in tax and other laws may adversely affect
      unitholders" as the Income Trust Tax Proposals could potentially have a
      significant impact on Enerplus' business, operations and financial condition,
      as
      well as the value of the Trust Units to unitholders.**




**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
      production and policy, including the ability of OPEC to set and maintain
      production levels in order to seek to influence 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 and resources to, and capacity of, transportation facilities;




• the
      availability of refining capacity;




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




• government
      regulations.






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








63




losses could occur under various circumstances, including
      if
      the other party to Enerplus' hedge does not perform its obligations under the
      hedge agreement.




**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, energy services 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, develop or expand its oil and gas reserves and resources 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 cash distributions
      may 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 Subsidiaries 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 U.S. Operating Subsidiaries or other direct or indirect
      subsidiaries of the Fund. 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 cash
      distributions 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 (including income tax laws and environmental laws) and other
      factors beyond the control of the Fund. In addition, the market value of the








64




Fund's Trust Units may decline if the Fund's cash
      distributions decline in the future, and that decline may be material.




**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. Furthermore, Enerplus conducts
      certain of its business and operations in the United States and as a result
      it also incurs certain expenses in United States dollars and is therefore
      exposed to foreign currency risk to the extent the value of the Canadian dollar
      decreases relative to the United States dollar. 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 7(b) to the Fund's audited
      consolidated financial statements for the year ended December 31, 2006.




**If Enerplus is unable to add or develop additional
      reserves or its resources, 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
      of reserves and resources, together with certain exploration activities. As
      a
      result, the level of Enerplus' future oil and natural gas reserves are highly
      dependent on its success in developing and exploiting its reserve and resource
      base and acquiring additional reserves and/or resources. 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 or resource 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 and to develop its resources
      will be impaired. Even if the necessary capital is available, Enerplus cannot
      assure prospective investors that it will be successful in acquiring additional
      reserves or resources on terms that meet its investment objectives. Without
      these 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 distributions to the Fund's unitholders.




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




The
      value of the Trust Units depends upon, among other things, the reserves and
      resources attributable to Enerplus' properties. Estimates of reserves and
      resources are by necessity projections, and thus are inherently uncertain.
      The
      process of estimating reserves or resources requires interpretations and
      judgements on the part of petroleum engineers, resulting in imprecise
      determinations, particularly with respect to new discoveries. Different
      engineers may make different estimates of reserve or resource quantities and
      revenues attributable thereto based on the same data. Ultimately, actual
      reserves and resources attributable to Enerplus' properties will vary and be
      revised from current estimates, and those variations and revisions may be
      material. The reserve and resource 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 and resources. 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 and resources;
   65
   •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 and resources.


Reserve
      and resource
      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 and resources could vary materially
      from its estimates. Additionally, all such estimates are, to some degree,
      uncertain and classifications of reserves and resources 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 and resources 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.




Estimates
      with respect to
      reserves and resources that may be developed and produced in the future
      (particularly oil sands reserves and resources) are often based upon volumetric
      or probabilistic calculations and upon analogy to similar types of reserves
      or
      resources, 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 or resources based upon
      production history may result in variations or revisions in the estimated
      reserves or resources, and any such variations or revisions could be material.




Reserve
      and resource
      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 reserves
      or 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. Additionally, if current development
      plans for the Joslyn Project are modified (and in particular with respect
      to SAGD Phase III, in respect of which Enerplus has booked certain Probable
      Reserves) and a decision is made to mine certain portions of the SAGD-designated
      part of the Joslyn Project, the volume and estimated value of the Probable
      Reserves assigned to Phase III of the SAGD portion of the Joslyn Project
      could be negatively impacted. Although mining typically provides approximately
      twice the recovery of bitumen in place as compared to SAGD projects, there
      could
      be timing differences between reserves bookings associated with the existing
      Phase III development plans versus possible expansion of mine development
      plans.




In
      addition, references to "contingent resources" or "resources" in this Annual
      Information Form do not constitute, and should be distinguished from, references
      to "reserves". "Reserves" are those remaining quantities of oil and gas
      anticipated to be economically recoverable from these known accumulations from
      a
      given date forward. "Resources" are oil and gas volumes that are estimated
      to
      have originally existed in the earth's crust as naturally accumulations but
      are
      not capable of being classified as "reserves", and "contingent resources" are
      a
      sub-category of resources that means those quantities of oil and gas estimated
      to be potentially recoverable from known accumulations but which cannot be
      classified as "reserves" for a variety of reasons, including that they may
      not
      be currently economic. See "Presentation of Enerplus' Oil and Natural Gas
      Reserves, Resources and Production Information".




**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
      Total and Enerplus have conducted 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.








66




**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 36% 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. This places greater reliance
      on
      third party operators in making estimates of future capital
      expenditures.




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 Total, and accordingly the future success of that Project
      is highly dependent on the strategies, operations and management of Total.
      The
      Joslyn Project is also subject to the risk that Total 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
      may be subject to the risk of default by Total in meeting its obligations to
      pay
      its proportionate share of expenditures of the Joslyn Project. Such default
      by
      Total 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.




**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










67


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
        (including, without limitation, with respect to Phase III of the SAGD
        project and future mining operations);
  • changes
        in Project scope;
  • violation
        of permit requirements;
  • disruption
        in the supply of energy;
  • availability
        of drilling rigs and services;
  • catastrophic
        events such as fires, earthquakes, storms or explosions; and
  • reliance
        on technologies that have not yet been demonstrated to be
        commercially applicable in oil sands applications.


Given the
      stage of development of the Joslyn Project, various changes to the Project
      may
      be made by Total 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, resource 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.




At the current
      time, there are no announced plans for construction of an upgrader to upgrade
      the quality of the Joslyn Bitumen produced by the Joslyn Project. As a result,
      there are a number of risks involved in transporting and marketing the Joslyn
      Bitumen, including securing supplies of condensate or synthetic light oil to
      blend with the bitumen in order to move it to market economically and, as there
      are fewer markets for non-upgraded bitumen, those markets typically demand
      a
      price discount relative to lighter crude oil.




**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 and/or resources, undeveloped lands, skilled personnel,
      access to drilling rigs, service rigs and other








68




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.




Furthermore,
      if the Income Trust Tax Proposals are implemented as proposed, Enerplus would
      effectively be taxed at a level similar to Canadian corporations starting in
      2011 (assuming Enerplus does not violate the "normal growth" safe harbour
      provisions). Therefore, Enerplus' proposed bids for Canadian corporate and
      property acquisitions may be affected and adjusted for the impact of the Income
      Trust Tax Proposals, and Enerplus may not have the same access to
      capital with respect to corporate and property acquisitions which it
      has previously experienced. The Income Trust Tax Proposals may put Enerplus
      at a
      competitive disadvantage to other industry participants such as pension resource
      corporations, U.S. flow-through entities such as master limited partnerships
      and
      limited liability companies, and U.S. corporations that are able to minimize
      Canadian tax through the use of inter-company debt and cross-border
      tax planning measures.




**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 in Canada and federal and state
      laws and regulations in the United States. 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,
      and
      the Canadian federal government is currently evaluating other proposals and
      legislative measures that would achieve similar environmental objectives.
      Although the outcome of this process is unknown at this time, the implementation
      of more stringent environmental legislation or regulatory requirements 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.




**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".








69




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. The Government of Alberta
      has stated that it intends to conduct a thorough review and analysis of the
      current royalty regime in place in Alberta and in particular the royalty system
      applicable to the oil sands. See "Industry Conditions — Royalties and
      Incentives".




**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 and resources 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.




**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 of 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 distributions 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








70




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 and resources, the management and
      administration of all matters relating to Enerplus' properties and the
      administration of the Fund. The rapid increase in oil and gas prices and
      activity in recent years, 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. See "Directors and
      Officers — Trust Unit Ownership and Conflict of Interest". 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. Under U.S. GAAP, the carrying value of these
      properties and facilities, net of deferred income taxes, is limited to the
      present value of after-tax future net revenue from Proved Reserves, discounted
      at 10%, and based on constant prices at December 31, 2006. If the net
      capitalized costs exceed either of these limits, Enerplus must charge the amount
      of the excess against its Canadian or U.S. GAAP earnings, respectively.
      Additionally, if oil and natural gas prices decline, Enerplus' net capitalized
      cost may exceed these limits, 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.




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




From time to
      time, Enerplus conducts title reviews in accordance with industry practice
      prior
      to purchases of 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 (and, if applicable,
      resources) from the purchased assets could be jeopardized and, as a result,
      distributions to unitholders may be reduced. Furthermore, from time to
      time, Enerplus may have disputes with industry partners as to ownership rights
      of certain properties or resources, including disputes as to the rights of
      holders of coal rights versus the rights of holders of natural gas rights with
      respect to coalbed methane properties.




**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 or the taxation of the
      Fund's distributions to unitholders, 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








71




changed or interpreted in a manner which is detrimental
      to
      Enerplus' operations and financial structure, and therefore the unitholders.




Proposed Taxation of Income
      Trusts




As described
      above under "General Development of Enerplus Resources
      Fund — Developments in the Past Three Years — Federal
      Government Pronouncements on Income Trusts", on October 31, 2006, the
      Canadian federal government announced the Income Trust Tax Proposals
      to generally tax income trusts at the same effective tax rates as
      Canadian corporations, and draft legislation to implement these proposals was
      released in December 2006. At this time, the draft legislation to give
      effect to the Income Trust Tax Proposals has not yet been introduced into the
      Canadian House of Commons and therefore has not been approved or declared in
      force by the Canadian government. Accordingly, Enerplus is unable to determine
      the timing of when the proposed legislation could be passed in the Canadian
      Parliament, if at all, and it is uncertain as to what form, if any, changes
      in
      Canadian income tax laws will take as a result of such proposal. If implemented
      in their current or an alternative form, the Income Trust Tax Proposals could
      have a significant effect on the Fund's business, operations and financial
      conditions, including, among other things:




• the
        Fund may be required to pay taxes, or higher amounts of taxes, in the
        future or in years earlier than it would under existing tax laws, which could
        decrease the amount of cash distributions available to unitholders;
  • the
        ongoing structure of the Fund and its subsidiaries, including whether
        the Fund and its subsidiaries will continue to operate under the income trust
        model or convert to another model, including a corporate form, and the tax
        implications to the Fund, its subsidiaries and its unitholders as a result
        of
        any change on the Fund's structure;
  • the
        ability of the Fund to pay monthly cash distributions and the amount
        of such distributions could be adversely affected;
  • the
        estimated net present value of future net revenues from Enerplus'
        oil, NGLs and natural gas reserves may be decreased as a result of the
        application of taxes to which Enerplus has historically not been subject
        (see "Oil and Natural Gas Reserves — Overview of Reserves" and
        "Operational Information — Tax Horizon");
  • future
        income tax liability in the Fund's consolidated financial
        statements will increase to reflect temporary timing differences between
        the
        accounting and tax bases of the Fund's assets and liabilities, which Enerplus
        understands would likely be reflected as a non-cash charge to the Fund's
        consolidated statement of income, and the amount of such charge could be
        material;
  • at
        the current time, Enerplus does not expect the proposed tax on income
        trusts to have a material impact on its debt covenants;
  • the
        Fund's ability to raise capital may be restricted due to the market's
        reaction to the proposed tax, the related changes to the Fund's accounting
        and
        reserves, and the ongoing uncertainty concerning the Fund's future structure
        and
        business strategy; and
  • the
        trading price and liquidity of the Trust Units may be adversely
        affected.


Furthermore,
      the "normal growth" safe harbour guidance announced by the Canadian federal
      government on December 15, 2006 are administrative in nature and are not
      law and therefore can be revised without an Act of the Canadian Parliament.
      See
      "General Development of Enerplus Resources Fund — Developments in the
      Past Three Years — Federal Government Pronouncements on Income
      Trusts". Therefore, no assurance can be provided that such safe harbour
      provisions will remain in effect in the current form or that the Fund will
      not
      be subject to the proposed tax on income trusts (if any) prior
      to 2011.




Mutual Fund Trust Status




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








72




recent information obtained by Enerplus through its transfer
      agent and financial intermediaries, in January 2007 an estimated 70% 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 has determined
      that it currently meets the requirements 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.




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 of 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, as it currently exists. 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".




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".




Other Potential Legislative
      Changes




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 Developments in the
      Past Three Years — Federal Government Pronouncements on Income
      Trusts". 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.
   73
   •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.


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




The Trust
      Units 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 material 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 as the Fund is not a legally recognized entity within
      the definitions of statutes such as the Bankruptcy and
      Insolvency Act (Canada) or the Companies' Creditors
      Arrangement Act (Canada).
      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 not "deposits" within the meaning of the Canada
      Deposit Insurance Corporation Act (Canada) and are not
      insured under the provisions of that Act or any other legislation. Furthermore,
      the Fund is not a trust company and, accordingly, is not registered under any
      trust and loan company legislation as it does not carry on or intend to carry
      on
      the business of a trust company. In addition, although the Fund qualified at
      Closing as a "mutual fund trust" as defined by the Tax Act, the Fund is not
      a "mutual fund" as defined by applicable securities legislation.




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 or resources 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 or resources
      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








74


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 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.**




United States
      unitholders (meaning, for the purposes of this section, tax residents for
      United States federal income tax purposes as defined under
      Section 7701 of the United States Internal Revenue Code, as amended
**(**the"**Code**"**)**) should be aware
      that the United States Internal Revenue Service may determine that the Fund
      is a "passive foreign investment company" (a "**PFIC**") under
      Section 1297(a) of the Code for the 2006 taxable year
      and in subsequent taxable years. The Fund will be a PFIC if at least
      75 percent of its income consists of dividends, interest, and other passive
      items or if 50 percent or more of the average value of its assets
      (on a gross value basis) consist of assets that would produce passive
      income. To date, Enerplus has received advice that the Fund should not be
      considered a PFIC for the years 2002 through 2005, and Enerplus does not expect
      to be considered a PFIC for 2006 or 2007.




If the Fund is
      or becomes a PFIC, adverse United States federal income tax consequences
      may apply. Any gain recognized on the sale of Trust Units and any excess
      distributions (as defined under Section 1291(b) of the
      Code) paid on the Trust Units must be ratably allocated
      to each day in a United States unitholder's holding period for the Trust
      Units. The amount of any such gain or excess distribution allocated to prior
      years of such United States unitholder's holding period for the Trust Units
      generally will be subject to United States federal income tax at the
      highest tax rate applicable to ordinary income in each such prior year, and
      the
      United States unitholder will be required to pay interest on the resulting
      tax liability for each such prior year, calculated as if such tax liability
      had
      been due in each such prior year.




Alternatively, a United States unitholder that makes a "qualified
      electing fund" election generally will be subject to United States federal
      income tax on such United States unitholder's pro rata share of the Fund's
      "net capital
      gain" and "ordinary earnings" (calculated under United States federal
      income tax rules), regardless of whether such amounts are actually distributed
      by the Fund. United States unitholders should be aware that there can be no
      assurance that the Fund will satisfy record keeping requirements or that it
      will
      supply United States unitholders with required information under the
      "qualified electing fund" rules, in the event that the Fund is a PFIC and a
      United States unitholder wishes to make a "qualified electing fund"
      election. As a second alternative, a United States unitholder may make a
      "mark-to-market election" if the Fund is a PFIC and the Trust Units are
      marketable stock regularly traded on a securities exchange or other market
      the
      United States Secretary of the Treasury determines as adequate. A
      retroactive election is permitted only in accordance with the United States
      Treasury Regulations and in some circumstances will require the permission
      of
      the United States Commissioner of the Internal Revenue Service. Additionally,
      United States holders will not be able to make the "mark-to-market" election
      with respect to the Fund's Operating Subsidiaries should they be determined
      to
      be PFICs. A United States unitholder that makes a "mark-to-market election"
      generally will include in gross income, for each taxable year in which the
      Fund
      is a PFIC, an amount equal to the excess, if any, of (a) the fair market value
      of the Trust Units as of the close of such taxable year over (b) such United
      States unitholder's tax basis in such Trust Units. United States unitholders
      are
      strongly urged to consult their own tax advisors regarding the United States
      federal income tax consequences of the Fund's possible classification as a
      PFIC
      and the consequences of such classification.








75




**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. Since January 1, 2005, a 15%
      Canadian withholding tax is applied to return of capital portion of
      distributions made to non-resident unitholders. See "Distributions to
      Unitholders — U.S. Tax Reporting Matters".




Additionally,
      the reduced "Qualified Dividend" rate of 15% tax applied to the Fund's
      distributions under current U.S. tax laws is scheduled to expire at the end
      of
      2010 and there is no assurance that this reduced tax rate will be renewed by
      the
      U.S. government at such time.




Furthermore,
      it is unclear what impact the proposed changes to the Tax Act relating to
      the Income Trust Tax Proposals will have on the taxation of cash distributions
      or other property paid by the Fund to unitholders who are not residents of
      Canada. See "Risk Factors — Risks Released to Enerplus' Structure and
      Ownership of the Trust Units — Changes in tax and other laws may
      adversely affect unitholders".




**Non-resident unitholders are subject to foreign
      exchange risk on the distributions that they may receive from the Fund.**




The Fund's
      distributions are declared in Canadian dollars and converted to foreign
      denominated currencies at the spot exchange rate at the time of payment. As
      a
      consequence, investors are subject to foreign exchange risk. To the extent
      that
      the Canadian dollar weakens with respect to their currency, the amount of the
      distribution will be reduced when converted to their home currency.




**The ability of United States and other
      non-resident unitholder 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 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 and resource
      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.








76




**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 2006.




**Month**
            
            **High**
            
            **Low**
            
            **Close**
            
            **Volume**January
            
            $
            61.06
            
            $
            55.59
            
            $
            60.60
            
            
            3,727,732February
            
            
            64.36
            
            
            52.12
            
            
            57.67
            
            
            6,456,504March
            
            
            59.20
            
            
            56.00
            
            
            58.57
            
            
            6,486,261April
            
            
            60.56
            
            
            58.30
            
            
            59.91
            
            
            3,594,863May
            
            
            62.00
            
            
            53.55
            
            
            62.00
            
            
            8,581,020June
            
            
            63.87
            
            
            54.00
            
            
            63.00
            
            
            7,609,973July
            
            
            65.44
            
            
            60.00
            
            
            65.06
            
            
            5,335,279August
            
            
            66.00
            
            
            62.35
            
            
            64.25
            
            
            4,770,115September
            
            
            64.90
            
            
            50.69
            
            
            56.10
            
            
            8,328,428October
            
            
            62.22
            
            
            51.60
            
            
            60.81
            
            
            7,729,517November
            
            
            54.70
            
            
            43.86
            
            
            52.50
            
            
            15,136,661December
            
            
            54.18
            
            
            49.79
            
            
            50.68
            
            
            4,363,809





The following table sets forth certain trading
      information for the Trust Units on the NYSE in 2006.




**Month**
            
            **High**
            
            **Low**
            
            **Close**
            
            **Volume**January
            
            
            US$53.44
            
            
            US$47.95
            
            
            US$53.08
            
            
            5,185,400February
            
            
            56.05
            
            
            45.10
            
            
            50.67
            
            
            8,178,000March
            
            
            52.10
            
            
            48.11
            
            
            50.44
            
            
            4,830,700April
            
            
            53.60
            
            
            50.10
            
            
            53.59
            
            
            3,989,300May
            
            
            56.03
            
            
            46.51
            
            
            55.74
            
            
            6,955,100June
            
            
            58.00
            
            
            48.55
            
            
            56.24
            
            
            6,384,400July
            
            
            57.94
            
            
            53.30
            
            
            57.54
            
            
            3,457,500August
            
            
            59.45
            
            
            55.55
            
            
            58.29
            
            
            3,875,400September
            
            
            58.73
            
            
            45.41
            
            
            50.29
            
            
            9,360,700October
            
            
            55.44
            
            
            45.69
            
            
            54.30
            
            
            5,835,000November
            
            
            48.42
            
            
            38.50
            
            
            46.13
            
            
            18,847,900December
            
            
            46.75
            
            
            42.76
            
            
            43.61
            
            
            4,777,800








77




**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 V.
              Dodge(3)(4)(6)Vancouver, British Columbia, Canada
            
            May 2004
            
            Corporate director since 2004. Prior
              thereto,
              Chief Operating Officer of Canadian Pacific Railway Limited (a public
              Canadian national rail company).Gordon J. Kerr(10)Calgary,
              Alberta, Canada
            
            May 2001
            
            President and Chief Executive Officer
              of
              Enerplus.Douglas R.
              Martin(1)(7)Calgary, Alberta, Canada
            
            September 2000
            
            President of Charles Avenue Capital
              Corp.
              (a private merchant banking company).Robert L.
              Normand(2)(4)(8)Rosemere, Québec, Canada
            
            March 1998
            
            Corporate director.Glen D.
              Roane(2)(4)Canmore, Alberta, Canada
            
            June 2004
            
            Corporate director.W.C. (Mike) Seth(3)(5)Calgary,
              Alberta, Canada
            
            August 2005
            
            President of Seth Consultants Ltd.
              (a private consulting firm) since June 2006. From July 2005 to June
              2006, Mr. Seth was Chairman of McDaniel & Associates
              Consultants Ltd. ("**McDaniel**")
              (a petroleum
              engineering consulting firm). 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
& Risk Management Committee is comprised of Robert L. Normand as Chairman,
        Harry B. Wheeler and Glen D. Roane.
  (3) The
        Corporate
        Governance & Nominating Committee is comprised of Robert L. Zorich as
        Chairman, Edwin V. Dodge and W.C. (Mike) Seth.
  (4) The
        Compensation & Human Resources Committee is comprised of Glen D. Roane as
        Chairman, Robert L. Normand and Edwin V. 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 & Safety Committee is comprised of Donald T. West as
        Chairman, Edwin V. 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.
  (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
   78
  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. KerrCalgary, Alberta,
              Canada
            
            President & Chief Executive
              Officer
            
            President & Chief Executive Officer
              of Enerplus.Garry A. TannerCalgary, Alberta,
              Canada
            
            Executive Vice President & Chief
              Operating Officer
            
            Executive Vice President & Chief
              Operating Officer of Enerplus since April 2006. Prior thereto, Senior
              Vice
              President & Chief Operating Officer of Enerplus since
              February 2003. Prior thereto, Senior Vice President,
              New Business Development of EGEM and Senior Vice President of El Paso
              Merchant Energy (a merchant trading company).Ian C. DundasCalgary, Alberta,
              Canada
            
            Senior Vice President, Business
              Development
            
            Senior Vice President, Business Development
              since August 2004. Prior thereto, Vice President and Director,
              Business Development of Enerplus since January 2003. Prior thereto,
              Vice President of EGEM.Robert J. WatersCalgary, Alberta,
              Canada
            
            Senior Vice President & Chief
              Financial Officer
            
            Senior Vice President & Chief
              Financial Officer of Enerplus.Jo-Anne M. CazaCalgary, Alberta,
              Canada
            
            Vice President, Investor Relations
            
            Vice President, Investor Relations of
              Enerplus.Rodney D. GrayCalgary, 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.Larry P. HammondCalgary, 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).






79






**Name
              and Residence**
            ****
            **Office**
            ****
            **Principal
              Occupation for Past Five
              Years(1)**Lyonel G. KawaCalgary, Alberta,
              Canada
            
            Vice President, Information
              Services
            
            Vice President, Information Services
              since
              January 2007. Prior thereto, Manager, Information Systems and
              Technology with Burlington Resources Canada Ltd. (an oil and gas
              exploration and production company) since July 2004. Prior thereto,
              Team Leader with TransCanada Pipelines Ltd. (a public energy
              transportation and infrastructure company).Jennifer F. KouryCalgary, Alberta,
              Canada
            
            Vice President, Corporate Services
            
            Vice President, Corporate Services of
              Enerplus since October 2006. Prior thereto, a private
              consultant.Eric G. Le DainCalgary, Alberta,
              Canada
            
            Vice President, Marketing
            
            Vice President, Marketing of Enerplus
              since
              September 2006. Prior thereto, Executive Director of Energy Marketing
              of UBS Commodities Canada Ltd. (a financial services
              company).David A. McCoyCalgary, 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. StevensCrossfield, 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. FordCalgary, Alberta,
              Canada
            
            Controller, Operations
            
            Controller, Operations of
              Enerplus.Jodine J. Jenson LabrieCochrane, 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.




80






**Trust Units Ownership**




As of March 8,
      2007, the directors and officers named above beneficially own, directly or
      indirectly, an aggregate of 438,657 Trust Units, representing approximately
      0.4%
      of the outstanding Trust Units as of that date.




**Conflicts of Interest**




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. In
      situations where conflicts of interest arise, Enerplus expects the applicable
      director or officer to declare the conflict and, if a director of EnerMark,
      abstain from voting in respect of such matters on behalf of Enerplus.




Enerplus
      currently has equity investments in the some of the same companies as EnCap
      Investments L.P. (" **EnCap** "), of which
      Mr. Robert L. Zorich (a director of EnerMark) is a
      principal and the Managing Director. In the future, Enerplus may invest
      alongside EnCap on similar equity investments. In some circumstances, EnCap
      may
      have established its equity position at an earlier time and at a lower value
      than has Enerplus and may have differing investment and timing objectives
      relating to those investments as compared to Enerplus. In the future, Enerplus
      may also make offers to acquire companies where EnCap is an investor.
      Additionally, Mr. Glen D. Roane, a director of EnerMark, is Chair of a
      private energy services company that supplies products and services to Enerplus,
      and
      Mr. W.C. (Mike) Seth, a director of EnerMark, owns 50% of a private software
      company that provides software services to Enerplus.. Enerplus does not
      consider the level of products and services supplied by such companies to be
      material to Enerplus.




See "Risk
      Factors — Potential Conflicts of Interest".




**Audit & Risk Management Committee Disclosure**




The disclosure
      regarding Enerplus' Audit & Risk Management 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, 2004 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 filed on the Fund's SEDAR profile at www.sedar.com on
      January 5, 2004 and was filed on EDGAR at www.sec.gov on
      December 7, 2006. A copy of the Fund's Unitholder Rights Plan Agreement,
      which is described under "Information Respecting Enerplus Resources
      Fund — Unitholder Rights Plan", was filed on the Fund's SEDAR profile
      at www.sedar.com on April 12, 2005 and was filed on EDGAR at
www.sec.gov on February 6, 2007, and is available on the Fund's
      website at www.enerplus.com under "Governance".






81


**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 both the GLJ Reserves Report in respect
      of
      the SAGD reserves and the GLJ Joslyn Resources Report in respect of the
      contingent bitumen resources attributable to Enerplus' working interest in
      the
      Joslyn Project, a summary of which is contained in this Annual Information
      Form.
      As of the dates of each of the GLJ Reserves Report and the GLJ Joslyn
      Resources 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, Independent Registered
      Chartered Accountants, Calgary, Alberta. Deloitte & Touche LLP has
      confirmed that it is independent within the meaning of the Rules of Professional
      Conduct of the Institute of Chartered Accountants of Alberta, the
      Securities Acts administered by the Securities and Exchange Commission and
      the
      requirements of the Independence Standards Board.


**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.


**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, on the EDGAR website at
www.sec.gov and on the Fund's website at www.enerplus.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 March 12, 2007 for its
      2007 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, 2006. Unitholders who wish to receive printed copies of
      these documents free of charge should contact the Fund's Investor Relations
      department using the contact information included on the final page of this
      Annual Information Form.








82


**APPENDIX "A"REPORT ON
      RESERVES DATA BY INDEPENDENTQUALIFIED 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"):


(ii)  the
      related estimated future net revenue; and




(b)
      (i)     proved oil and gas reserve quantities were
      estimated as at December 31, 2006 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, 2006, 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 P&NG Reserves in Canada of Enerplus Resources Fund, as of December
                  31, 2006, prepared July 2006 to February 2007
              
              
              Canada
              
              
              Nil
              
              $
              4,103.6
              
              $
              433.1
              
              $
              4,536.7
 
 5. In
        our opinion, the reserves data evaluated by us have, in all material respects,
        been determined and are presented 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
            /s/ROBERT
              R. WARHOLMCalgary, Alberta, CanadaFebruary 12,
              2007
            Robert R. Warholm , P.
              Eng.Associate/s/MICHAEL
              W.
              MAUGHANMichael W. Maughan, C.P.G., P. Geol.Vice
              President, Geoscience/s/R.
              KEITH MACLEODR. Keith MacLeod, P. Eng.Executive
              Vice-President






A-2




**APPENDIX "B"REPORT ON
      RESERVES DATA BY INDEPENDENTQUALIFIED 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 EnerMark Inc. (the "Company"):





1.  We
      have prepared an evaluation of the Company's reserves data as at
      December 31, 2006. The reserves data consist of the following:





(a) (i)     proved
      and proved plus probable oil and gas reserves estimated as at December 31,
      2006, 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, 2006, 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, 2006, 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 7,
                2007
            
            Canada
            
            —
            
            $
            47,978
            
            —
            
            $
            47,978




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, CanadaJanuary 29,
              2007
            "Dana B. Laustsen"Dana
              B. Laustsen, P. Eng.






B-1




**APPENDIX "C"REPORT ON
      RESERVES DATA BY INDEPENDENTQUALIFIED 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 (USA) Corporation ("Enerplus"):


1.    
          Pursuant to the request of Enerplus, we have evaluated and reviewed the
          reserves
          data of certain properties as of December 31, 2006. The reserves data
          includes the following:
 
 (a)  (i)     proved
          and proved-plus-probable oil and gas reserves estimated as of December 31,
          2006, 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 of December 31, 2006, 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 percent, evaluated as
          of December 31, 2006, 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**
                
                **Description
                    and**
                  **Effective
                    Date**
                  **of
                    Evaluation******
                
                **Location
                    of**
                  **Reserves**
                  **(Country or**
                  **Foreign**
                  **Geographic
                    Area)******
                
                **Audited**
                
                
                **Evaluated******
                
                **Reviewed**
                
                
                **Total********(in US$
                    thousands)**DeGolyer
                    and MacNaughton
                
                Appraisal
                    Report as of December 31, 2006 on Certain Properties owned by
                    Enerplus Resources (USA) Corporation
                
                Montana
                    and North Dakota
                
                Not
                    Applicable
                
                $
                783,913
                
                Not
                    Applicable
                
                $
                783,913
 
 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
            Submitted,"DEGOLYER
              AND
              MACNAUGHTON"Dallas, Texas, USAFebruary 1,
              2007
            DeGolyer and MacNaughton/s/PAUL
              J.
              SZATKOWSKIPaul J. Szatkowski, P.E.Senior Vice
              PresidentDeGolyer and MacNaughton










C-2


**APPENDIX "D"REPORT OF
      MANAGEMENT AND DIRECTORSON 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:


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:




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 "







" Garry A. Tanner "







" Harry B. Wheeler "







" W.C. (Mike) Seth "







March 12, 2007








D-2


**APPENDIX "E"AUDIT & RISK
      MANAGEMENT COMMITTEE DISCLOSUREPURSUANT TO MULTILATERAL INSTRUMENT 52-110**


****


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




The charter of
      the Audit & Risk Management Committee (the " **Committee** ") of the board
      of
      directors of EnerMark is attached as Schedule 1 to this Appendix "E".




**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.




**C.    Relevant Education and
      Experience**




**Name
              (Director Since)**
            
            **Principal
              Occupation and Biography**Mr. Robert L. Normand (DSC, C.A.)(March
                1998)
              Other Public Directorships •    Quebecor
                World Inc. (commercial print media services) •    Aurizon
                Mines Ltd. (gold mining) •    ING
                Canada Inc. (property and casualty insurance) •    Sportscene
                Group Inc. (chain of restaurants) •    Fonds
                d'Investissement REA (mutual fund)
            
            Mr. Normand is a corporate director and
              has served as a director of several private and public corporations
              operating in various fields of the economy. In addition to serving
              as a
              director of the public companies listed herewith, he is presently a
              director of Greenfield Ethanol Inc. (a private manufacturing
              company). Mr. Normand acted as an external auditor for Richter
              Usher & Vineber and Coopers & Lybrand until 1968 and
              held accounting responsibilities with two companies before joining
              Gaz
              Métropolitain late in 1972 as Assistant Chief Financial Officer.
              Mr. Normand ultimately held the position of Chief Financial Officer
              from 1980 until his retirement in 1997. Mr. Normand graduated from
              l'École des Hautes Études Commerciales (Université de Montréal) in 1966
              (dec. commercial science), received a Chartered Accountant designation
              and
              became a member of the Québec Institute of Chartered Accountants the same
              year. Mr. Normand was President of the Financial Executives Institute
              Canada in 1992, Vice President U.S. in 1993 and is an active member
              of the Montréal Chapter. He is also a member of the Institute of Corporate
              Directors.


E-1






**Name
              (Director Since)**
            
            **Principal
              Occupation and Biography**Mr. Glen D. Roane (B.A.,
                MBA)(June 2004)
              Other Public Directorships •    Destiny
                Resource Services Corp. (oil and gas service business) •    Badger
                Income Fund (provider of non-destructive excavation
                services)
            
            Mr. Roane is a corporate director and
              has served as a board member of many TSX-listed companies including
              (in addition to those public entities listed herewith of which he
              currently serves s a director), Repap Enterprises Inc., Ranchero
              Energy Inc., Forte Resources Inc., Valiant Energy Inc.,
              Maxx Petroleum Ltd. and NQL Energy Services Inc., since his
              retirement from TD Asset Management Inc., a subsidiary of The
              Toronto-Dominion Bank (a publicly traded Canadian chartered bank) in
              1997. Mr. Roane spent almost 20 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. In addition to serving as a director of the
              public
              entities listed below, Mr. Roane is the Chairman of the board of
              directors of Flexpipe Systems Inc., a private energy services
              company. Mr. Roane holds a Bachelor of Arts and an MBA from Queen'
              University in Kingston, Ontario.Mr. Harry B. Wheeler (B.A.,
                B.Sc. (Geology))(January 2001)
              Other Public Directorships •    Nil
            
            Mr. Wheeler has been the President of
              Colchester Investments Ltd., a private investment firm, since 2000.
              From 1962 to 1966, Mr. Wheeler worked with Mobil Oil in Canada and
              Libya and from 1967 to 1972 was employed by International
              Resources Ltd., in London, England and Denver, Colorado. He was a
              Director of Quintette Coal Ltd., Vice President of Amalgamated
              Bonanza Petroleum Ltd. and operator of his private company before
              founding Cabre Exploration Ltd. ("Cabre"), a public oil and gas
              company, in 1980. Mr. Wheeler was Chairman of Cabre until it was
              acquired by EnerMark Income Fund (a predecessor of Enerplus) in
              December 2000. Mr. Wheeler is currently a director of the
              Alberta Motor Association and its subsidiary, Bridgewater Bank.
              Mr. Wheeler graduated from the University of British Columbia in 1962
              with a degree in Geology.




**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 2006 and 2005 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-2


**E.    External Auditor Service
      Fees**




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




**2006**
            
            **2005**(in $
              thousands)Audit
              fees(1)
            
            $
            763.9
            
            $
            409.2Audit-related
              fees(2)
            
            
            —
            
            
            —Tax
              fees(3)
            
            
            1,211.3
            
            
            138.5All
              other fees(4)
            
            
            —
            
            
            —$
            1,975.2
            
            $
            547.7







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-3


**SCHEDULE
      1 TO APPENDIX "E"**


**AUDIT & RISK MANAGEMENT
      COMMITTEECHARTER**




**I.     AUTHORITY**


****


The
      Audit & Risk Management Committee (the "Committee") of the Board
      of Directors (the "Board") of the Fund 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.




Because of the
      Committee's demanding role and responsibilities, the Corporate Governance and
      Nominating Committee reviews any invitation to Committee members to join the
      audit committee of any other company or corporation. Where a member of the
      Committee simultaneously serves on the audit committee of more than three
      (3) public companies, including the Committee, the Board determines whether
      such simultaneous service impairs the ability of such member to serve
      effectively on the Committee.




Members of the
      Committee do not receive any compensation from the Fund other than compensation
      as directors and committee members. Prohibited compensation includes fees paid,
      directly or indirectly, for services as consultant or as legal or financial
      advisor, regardless of the amount, but excludes any compensation approved by
      the
      Board and that is paid to the directors as members of the Board and
      its committees.




**II.    PURPOSE OF
      THE
      COMMITTEE**




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


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 senior
      management of the Fund.




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




Each member of
      the Committee shall be unrelated to the Fund 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 and at least one member of the Committee shall have
      accounting or related financial management expertise — "literate" or
      "literacy" and "expertise" as defined by applicable securities legislation.
      Members are encouraged to enhance their understanding of current issues through
      means of their preference.








E-4




**IV.    MEETINGS OF THE COMMITTEE**




The Committee
      shall meet with such frequency and at 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 Corporation's external auditors in separate executive
      sessions to 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**




Evaluating and monitoring the performance and independence
      of external auditors




1. Make
        recommendations to the Board on the appointment of external auditors of
        the Fund;
 
 2.  Review
        and approve the Fund's external auditors' annual engagement letter, including
        the proposed fees contained therein;
  3.   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 auditors' performance. Approve
        audit fees:
  (a) Review
        annually the external auditors' quality control, any material issues raised
        by
        the most recent quality control review, or peer review, of the firm, or any
        inquiry or
 investigation
        by governmental or professional authorities of the firm within the preceding
        five years, and any steps taken to deal with such issues;
  (b) Obtain
        assurances from the external auditors that the audit was conducted in accordance
        with Canadian and US generally accepted auditing standards; and
  (c) Ensure
        that management interacts professionally with the auditors and confirm such
        behavior annually with both parties.
 
 4. 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 detailing all relationships between the external auditors
        and
 the Fund;
  (b) reviewing
        and approving the Fund's hiring policies regarding partners, employees and
        former partners and employees of current and former 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;
 
 (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;


E-5


(g)
              have
                  a private meeting with the external auditors at every quarterly
                  Committee
                  meeting;(h)
              obtain
                  annually the auditors’ views on competency and integrity of the audit
                  committee and senior financial
                  executives;
  Oversight
        of annual and quarterly financial statements, management discussion and analysis
        and press releases


5.
              Review
                  and approve the annual audit plan of the external auditors, including
                  the
                  scope of audit activities, and monitor such plan’s progress and results
                  quarterly and at year end;
  6.
              Confirm,
                  through private discussions with the external auditors and management,
                  that no restrictions are being placed on the scope of the external
                  auditors’ work;
  7.
              Review
                  the appropriateness of management’s representation letter transmitted to
                  the external auditors;
  8.
              Receipt
                  of certifications from the CEO and
                  CFO;
  9.
              Review
                  with management the adequacy of financial results and disclosure
                  in the
                  management discussion and analysis and press release and recommend
                  approval to the Board:
  (a)
              obtain
                  satisfactory answers from management following the review of the
                  financial
                  documents;(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; and(i)
              management’s
                  acknowledgement of its responsibility towards the financial
                  statements.(j)
              significant
                  legal, compliance or regulatory matters that may have a material
                  effect on
                  the financial statements or the business of the organization (including
                  material notices to, or inquiries received from, governmental agencies);
                  and(k)
              receive
                  the report from the Reserves Committee over the appropriateness
                  of
                  reported reserves and resources.




Oversight
      of financial reporting process, internal controls, the continuous disclosure
      and
      certification process and compliance with regulatory requirements


10.
              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 any developments and responses on reports received
                  thereunder;11.
              Review
                  the adequacy and effectiveness of the financial reporting system
                  and
                  internal control policies and procedures with the external auditors
                  and
                  management. Ensure that the Fund complies with all new regulations
                  in this
                  regard;12.
              Review
                  with management the Fund’s internal controls, and evaluate whether the
                  Fund is operating in accordance with prescribed policies and
                  procedures;


E-6


13.
              Review
                  with management and the external auditors any reportable condition
                  and
                  material weaknesses affecting internal controls;14.
              Review
                  the management disclosure and oversight Committee’s CEO and CFO
                  certification processes to ensure compliance with US and Canadian
                  requirements.15.
              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 the
                  Fund;16.
              Review
                  annually the report of the external auditor on management’s assessment of
                  the Fund’s internal control over financial reporting describing any
                  material issues raised by the most recent reviews of internal controls
                  and
                  management information systems or by any inquiry or investigation
                  by
                  governmental or professional authorities and any recommendations
                  made and
                  steps taken to deal with any such issues;Review of Business
                Risks17.
              Review
                  with management the process followed to do the Fund’s risk assessment and
                  the policies to monitor, mitigate and report such business risks;Other Matters18.
              Review
                  of appointment or dismissal of senior financial executives;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.
              Review
                  the disclosure made in the Annual Report, Annual Information Form,
                  40-F
                  and the Information Circular regarding the Audit & Risk Management
                  Committee;21.
              Establish
                  and maintain a free and open means of communication between the
                  Board, the
                  Committee, the external auditors, and management;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; and23.
              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. This
                  review forms part of the review process undertaken by the Corporate
                  Governance and Nominating Committee, which reports its findings
                  to the
                  Board.


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 the Fund complies with all
      laws
      and regulations, the spirit and intent of this Charter is that the Committee
      shall take reasonable steps to encourage the Fund to act in full compliance
      therewith.






E-7


**APPENDIX "F"SFAS NO.
      69 SUPPLEMENTAL RESERVE INFORMATION**




The following
      disclosures have been prepared in accordance with the provisions of the
      Financial Accounting Standards Board's Statement
      No. 69 — Disclosures about Oil and Gas
      Producing Activities (" **SFAS No. 69** ").
      The
      disclosures include reserves and costs attributable to both our conventional
      crude oil and natural gas operations as well as our SAGD — recoverable
      bitumen activities related to the Joslyn Project. The Proved Reserves quantities
      disclosed herein are determined according to the definition of "proved reserves"
      under NI 51-101 which differs from the definition provided in the SEC
      rules, however the difference should not be material. See "Presentation of
      Enerplus' Oil and Gas Reserves, Resources and Production Information" in this
      Annual Information Form.




All cost
      information in this section is stated in Canadian dollars and is calculated
      in
      accordance with United States of America Generally Accepted Accounting
      Principles (" **U.S. GAAP** ").




**A.    Proved Bitumen, Oil and
      Natural Gas Reserve Quantities**




Users of this
      information should be aware that the process of estimating quantities of "Proved
      Developed" and "Proved Undeveloped" bitumen, oil and natural gas reserves is
      very complex, requiring significant subjective decisions in the evaluation
      of
      all available geological, engineering and economic data for each reservoir.
      The
      data for a given reservoir may also change substantially over time as a result
      of numerous factors including, but not limited to, additional development
      activity, evolving production history, and continual reassessment of the
      viability of production under varying economic conditions. Consequently,
      material revisions to existing reserve estimates occur from time to time.
      Although every reasonable effort is made to ensure that reserve estimates
      reported represent the most accurate assessments possible, the significance
      of
      the subjective decisions required and variances in available data for reservoirs
      make these estimates generally less precise than other estimates presented
      in
      connection with financial statement disclosures.




Proved
      Reserves are the estimated quantities of bitumen, oil, natural gas and natural
      gas liquids which geological and engineering data demonstrate with reasonable
      certainty to be recoverable in future years from known reservoirs under
      economic and operating conditions that existed at year end. Future fluctuations
      in prices, production rates, or changes in political or regulatory environments
      could cause the Fund's reserves to be materially different from
      that presented.




Proved
      Developed Reserves are reserves that can be expected to be recovered through
      existing wells with existing equipment and operating methods. Proved Undeveloped
      Reserves are reserves that are expected to be recovered from known accumulations
      where a significant expenditure is required.




Subsequent to
      December 31, 2006, no major discovery or other favorable or adverse event
      is believed to have caused a material change in the estimates of Proved Reserves
      as of that date.




The Fund's
      Proved bitumen oil, natural gas liquids, and natural gas reserves are located
      in
      western Canada, primarily in Alberta, British Columbia, and Saskatchewan, as
      well as in Montana and North Dakota (and since January 31, 2007,
      Wyoming) in the United States. The Fund's Proved Reserves summarized in the
      following








F-1


chart represent the Fund's lessor royalty, overriding royalty,
      and working interest share of the gross remaining reserves, after deduction
      of
      any Crown, freehold and overriding royalties:


**Canada**
              
              **United States**
              
              **Total****Oil
                  and**
                **NGLs**
              
              **Natural**
                **Gas**
              
              **Bitumen**
              
              **Oil
                  and**
                **NGLs**
              
              **Natural**
                **Gas**
              
              **Oil
                  and**
                **NGLs**
              
              **Natural**
                **Gas**
              
              **Bitumen****(Mbbls)**
              
              **(Mmcf)**
              
              **(Mbbls)**
              
              **(Mbbls)**
              
              **(Mmcf)**
              
              **(Mbbls)**
              
              **(Mbbls)**
              
              **(Mmcf)****Proved
                  Developed and Undeveloped Reserves at December 31,
                  2003**
              
              
              **93,418**
              
              
              **689,900**
              
              
              **—**
              
              
              **—**
              
              
              **—**
              
              
              **93,418**
              
              
              **689,900**
              
              
              **—**Purchases
                  of reserves in place
              
              
              12,437
              
              
              94,354
              
              
              —
              
              
              —
              
              
              —
              
              
              12,437
              
              
              94,354
              
              
              —Sales
                  of reserves in place
              
              
              (162
              )
              
              (1,860
              )
              
              —
              
              
              —
              
              
              —
              
              
              (162
              )
              
              (1,860
              )
              
              —Discoveries
                  and extensions
              
              
              2,704
              
              
              22,399
              
              
              —
              
              
              —
              
              
              —
              
              
              2,704
              
              
              22,399
              
              
              —Revisions
                  of previous estimates
              
              
              (1,449
              )
              
              (50,066
              )
              
              —
              
              
              —
              
              
              —
              
              
              (1,449
              )
              
              (50,066
              )
              
              —Improved
                  recovery
              
              
              6,113
              
              
              115,000
              
              
              —
              
              
              —
              
              
              —
              
              
              6,113
              
              
              115,000
              
              
              —Production
              
              
              (8,902
              )
              
              (77,369
              )
              
              —
              
              
              —
              
              
              —
              
              
              (8,902
              )
              
              (77,369
              )
              
              —**Proved
                  Developed and Undeveloped Reserves at December 31,
                  2004**
              
              
              **104,159**
              
              
              **792,358**
              
              
              **—**
              
              
              **—**
              
              
              **—**
              
              
              **104,159**
              
              
              **792,358**
              
              
              **—**Purchases
                  of reserves in place
              
              
              485
              
              
              6,440
              
              
              —
              
              
              20,198
              
              
              10,803
              
              
              20,683
              
              
              17,243
              
              
              —Sales
                  of reserves in place
              
              
              (2,258
              )
              
              (10,414
              )
              
              —
              
              
              —
              
              
              —
              
              
              (2,258
              )
              
              (10,414
              )
              
              —Discoveries
                  and extensions
              
              
              735
              
              
              33,834
              
              
              —
              
              
              —
              
              
              —
              
              
              735
              
              
              33,834
              
              
              —Revisions
                  of previous estimates
              
              
              9,189
              
              
              14,543
              
              
              9,215
              
              
              624
              
              
              792
              
              
              9,813
              
              
              15,335
              
              
              9,215Improved
                  recovery
              
              
              3,642
              
              
              28,700
              
              
              —
              
              
              —
              
              
              —
              
              
              3,642
              
              
              28,700
              
              
              —Production
              
              
              (9,283
              )
              
              (78,737
              )
              
              —
              
              
              (885
              )
              
              (486
              )
              
              (10,168
              )
              
              (79,223
              )
              
              —**Proved
                  Developed and Undeveloped Reserves at December 31,
                  2005**
              
              
              **106,669**
              
              
              **786,724**
              
              
              **9,215**
              
              
              **19,937**
              
              
              **11,109**
              
              
              **126,606**
              
              
              **797,833**
              
              
              **9,215**Purchases
                  of reserves in place
              
              
              1,044
              
              
              4,162
              
              
              —
              
              
              333
              
              
              283
              
              
              1,377
              
              
              4,445
              
              
              —Sales
                  of reserves in place
              
              
              (30
              )
              
              (107
              )
              
              (532
              )
              
              —
              
              
              —
              
              
              (30
              )
              
              (107
              )
              
              (532
              )Discoveries
                  and extensions
              
              
              1,981
              
              
              22,854
              
              
              —
              
              
              367
              
              
              321
              
              
              2,348
              
              
              23,175
              
              
              —Revisions
                  of previous estimates
              
              
              (1,895
              )
              
              (44,035
              )
              
              (294
              )
              
              218
              
              
              1,318
              
              
              (1,677
              )
              
              (42,717
              )
              
              (294
              )Improved
                  recovery
              
              
              2,788
              
              
              22,347
              
              
              —
              
              
              1,727
              
              
              1,111
              
              
              4,515
              
              
              23,458
              
              
              —Production
              
              
              (9,259
              )
              
              (74,484
              )
              
              —
              
              
              (3,113
              )
              
              (1,804
              )
              
              (12,372
              )
              
              (76,288
              )
              
              —**Proved
                  Developed and Undeveloped Reserves at December 31,
                  2006**
              
              
              **101,298**
              
              
              **717,461**
              
              
              **8,389**
              
              
              **19,469**
              
              
              **12,338**
              
              
              **120,767**
              
              
              **729,799**
              
              
              **8,389****Proved
                  Developed Reserves**December 31,
                  2003
              
              
              88,492
              
              
              605,700
              
              
              —
              
              
              —
              
              
              —
              
              
              88,492
              
              
              605,700
              
              
              —December 31,
                  2004
              
              
              98,712
              
              
              672,960
              
              
              —
              
              
              —
              
              
              —
              
              
              98,712
              
              
              672,960
              
              
              —December 31,
                  2005
              
              
              101,048
              
              
              652,825
              
              
              —
              
              
              13,354
              
              
              7,442
              
              
              114,402
              
              
              660,267
              
              
              —**December 31,
                  2006**
              
              
              **95,734**
              
              
              **584,846**
              
              
              **2,687**
              
              
              **18,977**
              
              
              **11,961**
              
              
              **114,711**
              
              
              **596,807**
              
              
              **2,687**




F-2




**B.    Capitalized Costs Related
      to Oil and Gas Producing Activities**




The
      capitalized costs and related accumulated depreciation, depletion and
      amortization, including impairments, relating to the Fund's oil and gas
      exploration, development and producing activities are as follows:




**2006**
            
            **2005**
            
            **2004**(in
              $ thousands)Capitalized
              costs(1)
            
            $
            4,689,444
            
            $
            4,141,627
            
            $
            3,145,699Less
              accumulated depletion, depreciation and
              amortization
            
            
            (1,608,186
            )
            
            (1,212,145
            )
            
            (892,786
            )Net
              capitalized costs
            
            $
            3,081,258
            
            $
            2,929,482
            
            $
            2,252,913







Note:
 (1) Includes
        capitalized costs of proved and unproved properties.
 
 **C.    Costs
      Incurred in Oil and Gas Property Acquisition, Exploration and Development
      Activities**




Costs incurred
      in connection with oil and gas producing activities are as follows:


**For
                  the Year Ended December 31, 2006****Canada**
              
              **United States**
              
              **Total****(in
                  $ thousands)**Acquisition
                  of properties:Proved
              
              $
              35,323
              
              $
              15,990
              
              $
              51,313Unproved
              
              
              20,006
              
              
              201
              
              
              20,207Exploration
                  costs
              
              
              32,510
              
              
              1,202
              
              
              33,712Development
                  costs
              
              
              325,459
              
              
              115,284
              
              
              440,743Asset
                  retirement costs
              
              
              17,743
              
              
              588
              
              
              18,331$
              431,041
              
              $
              133,265
              
              $
              564,306


**For
              the Year Ended
              December 31, 2005****Canada**
            
            **United States**
            
            **Total**(in
              $ thousands)Acquisition
              of properties:Proved
            
            $
            91,489
            
            $
            589,613
            
            $
            681,102Unproved
            
            
            10,633
            
            
            22,926
            
            
            33,559Exploration
              costs
            
            
            9,914
            
            
            1,750
            
            
            11,664Development
              costs
            
            
            319,038
            
            
            27,354
            
            
            346,392Asset
              retirement costs
            
            
            13,789
            
            
            1,766
            
            
            15,555$
            444,863
            
            $
            643,409
            
            $
            1,088,272








F-3


**For
                    the Year Ended December 31, 2004****Canada**
                
                **United States****(1)**
                
                **Total****(in
                    $ thousands)**Acquisition
                    of properties:Proved
                
                $
                623,166
                
                $
                —
                
                $
                623,166Unproved
                
                
                15,918
                
                
                —
                
                
                15,918Exploration
                    costs
                
                
                —
                
                
                —
                
                
                —Development
                    costs
                
                
                204,116
                
                
                —
                
                
                204,116Asset
                    retirement costs
                
                
                46,823
                
                
                —
                
                
                46,823$
                890,023
                
                $
                —
                
                $
                890,023


Note:
 (1) The
        Fund had no oil and gas producing activities in the United States
        during 2004.
 Property
          acquisition costs include costs incurred to purchase, lease, or otherwise
          acquire oil and gas properties, including an allocation of purchase price
          on
          business combinations that result in property acquisitions. Development
          costs
          include the costs of drilling and equipping development wells and facilities
          to
          extract, gather and store oil and gas, along with an allocation of overhead.
          Development costs also include capitalized interest for development projects
          that have not reached commercial production. Exploration costs include
          costs
          related to the discovery and the drilling and completion of exploratory
          wells in
          new crude oil and natural reservoirs. Asset retirement costs represent
          capitalized asset retirement costs during the year. No gains or losses
          on
          retirement activities were realized, due to settlements approximating the
          estimates.




**D.    Results of Operations for
      Oil and Gas Producing Activities**




The following
      table sets forth revenue and direct cost information relating to the Fund's
      oil
      and gas producing activities for the years ended December 31.


**For
                  the Year Ended December 31, 2006****Canada**
              
              **United States**
              
              **Total****(in
                  $ thousands)****(1)**RevenueSales(2)
              
              $
              1,082,644
              
              $
              219,519
              
              $
              1,302,163DeductProduction
                  Costs(3)
              
              
              266,493
              
              
              7,357
              
              
              273,850Depletion,
                  depreciation, amortization, accretion and impairment
              
              
              295,975
              
              
              111,232
              
              
              407,207Current
                  and Deferred income tax provision
              
              
              (55,409
              )
              
              19,845
              
              
              (35,564
              )Results
                  of operations for oil and gas producing activities
              
              $
              575,585
              
              $
              81,085
              
              $
              656,670
  **For
                  the Year Ended December 31, 2005****Canada**
              
              **United States**
              
              **Total****(in
                  $ thousands)****(1)**RevenueSales(2)
              
              $
              1,189,551
              
              $
              64,035
              
              $
              1,253,586DeductProduction
                  Costs(3)
              
              
              241,656
              
              
              2,067
              
              
              243,723Depletion,
                  depreciation, amortization, accretion and impairment
              
              
              297,678
              
              
              31,817
              
              
              329,495Current
                  and Deferred income tax provision
              
              
              25,248
              
              
              9,384
              
              
              34,632Results
                  of operations for oil and gas producing activities
              
              $
              624,969
              
              $
              20,767
              
              $
              645,736




F-4


**For
                    the Year Ended December 31, 2004****Canada**
                
                **United States****(4)**
                
                **Total****(in
                    $ thousands)****(1)**RevenueSales(2)
                
                $
                918,811
                
                $
                —
                
                $
                918,811DeductProduction
                    Costs(3)
                
                
                221,570
                
                
                —
                
                
                221,570Depletion,
                    depreciation, amortization, accretion and impairment
                
                
                251,494
                
                
                —
                
                
                251,494Current
                    and Deferred income tax provision (recovery)
                
                
                (35,926
                )
                
                —
                
                
                (35,926
                )Results
                    of operations for oil and gas producing activities
                
                $
                481,673
                
                $
                —
                
                $
                481,673
 Notes:


(1) The
      costs in
      the schedules exclude corporate overhead, interest expense and other costs
      which
      are not directly related to oil and gas producing activities.




(2) Sales
      are
      presented net of royalties and third party obligations.




(3) Production
      costs include transportation costs.




(4) The
      Fund had
      no oil and gas producing activities in the United States during 2004.




E.    Standardized
      Measure of Discounted Future Net Cash Flows Relating to Proved Bitumen, Oil
      and
      Natural Gas Reserve Quantities




The following
      information has been developed utilizing procedures described by
      SFAS No. 69 and based on bitumen crude oil and natural gas
      reserve and production volumes estimated by the independent engineering
      consultants of the Fund. It may be useful for certain comparison purposes,
      but
      should not be solely relied upon in evaluating the Fund or its performance.
      Further, information contained in the following table should not be considered
      as representative of realistic assessments of future cash flows, nor should
      the
      "standardized measure of discounted future net cash flows" be viewed as
      representative of the current value of the Fund's reserves.




The future
      cash flows presented below are based on sales prices, cost rates, and statutory
      income tax rates in existence as of the period end date. It is expected that
      material revisions to some estimates of bitumen, crude oil and natural gas
      reserves may occur in the future, development and production of the reserves
      may
      occur in periods other than those assumed, and actual prices realized and costs
      incurred may vary significantly from those used.




Management
      does not rely upon the following information in making investment
      and operating decisions. Such decisions are based upon a wide range of
      factors, including estimates of Probable Reserves as well as Proved Reserves,
      and varying price and cost assumptions considered more representative of a
      range
      of possible economic conditions that may be anticipated.




The following
      tables set forth the standardized measure of discounted future net cash flows
      from projected production of the Fund's bitumen, crude oil and natural
      gas reserves.


**As
                  at December 31, 2006****Canada**
              
              **United States**
              
              **Total****(in
                  $ millions)**Future
                  cash inflows
              
              $
              10,197
              
              $
              1,185
              
              $
              11,382Future
                  production costs
              
              
              3,826
              
              
              98
              
              
              3,924Future
                  development and asset retirement costs
              
              
              569
              
              
              22
              
              
              591Future
                  income tax expenses
              
              
              —
              
              
              240
              
              
              240Future
                  net cash flows
              
              $
              5,802
              
              $
              825
              
              $
              6,627Deduction:
                  10% annual discount factor
              
              
              2,744
              
              
              305
              
              
              3,049Standardized
                  measure of discounted future net cash flows
              
              $
              3,058
              
              $
              520
              
              $
              3,578




F-5


**As
                    at December 31, 2005****Canada**
                
                **United States**
                
                **Total****(in
                    $ millions)**Future
                    cash inflows
                
                $
                13,556
                
                $
                1,397
                
                $
                14,953Future
                    production costs
                
                
                3,720
                
                
                88
                
                
                3,808Future
                    development and asset retirement costs
                
                
                513
                
                
                90
                
                
                603Future
                    income tax expenses
                
                
                —
                
                
                311
                
                
                311Future
                    net cash flows
                
                $
                9,323
                
                $
                908
                
                $
                10,231Deduction:
                    10% annual discount factor
                
                
                4,496
                
                
                329
                
                
                4,825Standardized
                    measure of discounted future net cash flows
                
                $
                4,827
                
                $
                579
                
                $
                5,406
  **As
                    at December 31, 2004****Canada**
                
                **United States****(1)**
                
                **Total****(in
                    $ millions)**Future
                    cash inflows
                
                $
                8,836
                
                $
                —
                
                $
                8,836Future
                    production costs
                
                
                2,724
                
                
                —
                
                
                2,724Future
                    development and asset retirement costs
                
                
                353
                
                
                —
                
                
                353Future
                    income tax expenses
                
                
                —
                
                
                —
                
                
                —Future
                    net cash flows
                
                $
                5,759
                
                $
                —
                
                $
                5,759Deduction:
                    10% annual discount factor
                
                
                2,825
                
                
                —
                
                
                2,825Standardized
                    measure of discounted future net cash flows
                
                $
                2,934
                
                $
                —
                
                $
                2,934


Note:


(1) The
      Fund had
      no oil and gas producing activities in the United States during 2004.




F.     Changes
      in Standardized Measure of Discounted Future Cash Flow Relating to Proved Oil
      and Natural Gas Reserves




The following
      table summarizes the principal sources of change in the standardized measure
      of
      discounted future net cash flows:




**2006**
              
              **2005**
              
              **2004****(in
                  $ millions)**Beginning
                  of year
              
              $
              5,406
              
              $
              2,934
              
              $
              2,222Sales
                  of oil and natural gas produced, net of production costs
              
              
              (1,028
              )
              
              (1,009
              )
              
              (697
              )Net
                  changes in sales prices and production costs
              
              
              (1,963
              )
              
              2,170
              
              
              523Changes
                  in previously estimated development costs incurred during the
                  period
              
              
              240
              
              
              113
              
              
              (107
              )Changes
                  in estimated future development costs
              
              
              (210
              )
              
              (308
              )
              
              (177
              )Extension,
                  discoveries and improved recovery, net of related costs
              
              
              725
              
              
              424
              
              
              292Purchase
                  of reserves in place
              
              
              31
              
              
              952
              
              
              497Sales
                  of reserves in place
              
              
              (3
              )
              
              (30
              )
              
              (33
              )Net
                  change resulting from revisions in previous quantity
                  estimates
              
              
              (130
              )
              
              126
              
              
              228Accretion
                  of discount
              
              
              442
              
              
              230
              
              
              186Net
                  change income taxes
              
              
              68
              
              
              (196
              )
              
              —End
                  of year
              
              $
              3,578
              
              $
              5,406
              
              $
              2,934





Note:


(1) The
        schedules above are calculated using year-end prices, costs, statutory tax
        rates
        and existing Proved oil and gas reserves. The value of exploration properties
        and probable reserves, future exploration costs, future changes in oil and
        gas
        prices and in production and development costs are excluded.




F-6









































**Enerplus Resources
      Fund** The Dome Tower3000,
      333 - 7th Avenue S.W.Calgary, Alberta,
      CanadaT2P 2Z1Telephone: 403.298.2200Toll free:
      1.800.319.6462Fax:
      403.298.2211www.enerplus.com