**EXHIBIT
99.1**
  ****
      ********
      ****
      ****RENEWAL
      ANNUAL INFORMATION FORM****
      ****
      ****
      ****For
      the year ended December 31,
      2004****
      ****
      ****
      ****
      ****
      ****
      ****
      ****
      ****
      **March
      14, 2005**
      ****
      ****
      ****





**TABLE
OF CONTENTS**





GLOSSARY
      OF TERMS
    
    
    iiiABBREVIATIONS
      AND CONVERSIONS
    
    
    vPRESENTATION
      OF ENERPLUS' OIL AND GAS RESERVES AND PRODUCTION
    INFORMATION
    
    
    viPRESENTATION
      OF ENERPLUS' FINANCIAL INFORMATION
    
    
    ixDESCRIPTION
      OF DISTRIBUTABLE INCOME
    
    
    ixFORWARD-LOOKING
      STATEMENTS
    
    
    ixSTRUCTURE
      OF ENERPLUS RESOURCES FUND
    
    
    1GENERAL
      DEVELOPMENT OF ENERPLUS RESOURCES FUND
    
    
    3Historical
      Overview
    
    
    3Update
      on Mutual Fund Trust Status and Taxation Matters
    
    
    4Update
      on Unitholder Limited Liability and Index Inclusion
    
    
    5OIL
      AND NATURAL GAS RESERVES
    
    
    6Summary
      of Aggregate Enerplus Reserves
    
    
    7Summary
      of Sproule Report
    
    
    8Summary
      of GLJ Report
    
    
    12Reconciliation
      of Reserves
    
    
    14Reconciliation
      of Changes in Net Present Value of Future Net Revenue
    
    
    16Undeveloped
      Reserves
    
    
    16Proved
      and Probable Reserves Not on Production
    
    
    16OPERATIONAL
      INFORMATION
    
    
    17Overview
    
    
    17Description of
      Principal Properties and Operations
    
    
    17Summary
      of Production Locations
    
    
    21Oil and
      Natural Gas Wells and Unproved Properties
    
    
    23Exploration and
      Development Activities
    
    
    23Quarterly
      Production History
    
    
    24Quarterly
      Netback History
    
    
    24Abandonment and
      Reclamation Costs
    
    
    25Tax
      Horizon
    
    
    25Costs
      Incurred
    
    
    25Marketing
      Arrangements and Forward Contracts
    
    
    26Environment,
      Health and Safety
    
    
    26Impact
      of Environmental Protection Requirements
    
    
    27Additional
      Operational Information
    
    
    27INFORMATION
      RESPECTING ENERPLUS RESOURCES FUND
    
    
    28






- i
-




TABLE OF CONTENTS




Description of
      the Trust Units and the Trust Indenture
    
    
    28Description of
      the Royalty Agreements and Subordinated Note
    
    
    35Management and
      Corporate Governance
    
    
    36Unitholder
      Rights Plan
    
    
    36DEBT
      OF ENERPLUS
    
    
    37Bank
      Credit Facility
    
    
    37Senior
      Unsecured Notes
    
    
    38DISTRIBUTIONS
      TO UNITHOLDERS
    
    
    39Distributable
      Income
    
    
    39Distribution
      History
    
    
    39U.S.
      Tax Reporting Matters
    
    
    40INDUSTRY
      CONDITIONS
    
    
    41RISK
      FACTORS
    
    
    46MARKET
      FOR SECURITIES
    
    
    58DIRECTORS
      AND OFFICERS
    
    
    59INTEREST
      OF MANAGEMENT AND OTHERS IN MATERIAL TRANSACTIONS
    
    
    61MATERIAL
      CONTRACTS AND DOCUMENTS AFFECTING THE RIGHTS OF
      SECURITYHOLDERS
    
    
    62INTERESTS
      OF EXPERTS
    
    
    62REGISTRAR
      AND TRANSFER AGENT
    
    
    62ADDITIONAL
      INFORMATION
    
    
    62APPENDIX
      "A" - REPORT ON RESERVES DATA BY INDEPENDENT QUALIFIED RESERVESEVALUATOR
    
    
    A-1APPENDIX
      "B" - REPORT ON RESERVES DATA BY INDEPENDENT QUALIFIED RESERVESEVALUATOR
    
    
    B-1APPENDIX
      "C" - REPORT OF MANAGEMENT AND DIRECTORS ON RESERVES DATA AND OTHER
      INFORMATION
    
    
    C-1APPENDIX
      "D" - AUDIT COMMITTEE DISCLOSURE
    
    
    D-1









- ii
-




**GLOSSARY
OF TERMS**
  Unless
the context otherwise requires, in this Annual Information Form, the following
terms and abbreviations have the meanings set forth below. **Additional
terms relating to oil and natural gas reserves and operations have the meanings
set forth under "Presentation of Enerplus' Oil and Gas Reserves and Production
Information."**
  **"bitumen"** means a highly viscous crude oil which is too thick to flow in its native state
and which cannot be produced without altering its viscosity. The density of
bitumen is generally less than 10 o  API;
  **"Deer
Creek"** means
Deer Creek Energy Limited, the operator of the Joslyn Creek
Project;
  **"ECT"** means Enerplus Commercial Trust, a trust organized under the laws of Alberta
(the trustee of which is Enerplus ECT Resources Ltd., an Alberta corporation)
and an indirect wholly owned subsidiary of the Fund;
  **"EGEM"** means Enerplus Global Energy Management Company, an indirect wholly owned
subsidiary of the Fund which, prior to its acquisition by Enerplus from a third
party, provided management and administrative services to Enerplus;
  **"EnerMark"** means EnerMark Inc., a corporation organized under the *Business
Corporations Act* (Alberta) and a wholly owned subsidiary of the Fund;
  **"Enerplus"** means Enerplus Resources Fund and its subsidiaries, taken as a
whole;
  **"Enerplus
Oil & Gas"** means Enerplus Oil & Gas Ltd., a corporation organized under the *Business
Corporations Act* (Alberta) and a wholly owned subsidiary of ERC;
  **"ERC"** means Enerplus Resources Corporation, a corporation organized under the *Business
Corporations Act* (Alberta) and a wholly owned subsidiary of EnerMark;
  **"Fund"** means Enerplus Resources Fund;
  " **GAAP** "
means generally accepted accounting principles;
  **"GLJ"** means Gilbert Laustsen Jung Associates Ltd., independent petroleum
consultants;
  **"GLJ
Report"** means the independent engineering evaluation of Enerplus' interest in the Joslyn
Creek Project prepared by GLJ dated February 22, 2005 and effective December 31,
2004, utilizing commodity price forecasts of Sproule (for internal consistency
in Enerplus' reserves reporting) dated December 31, 2004;
  " **Joslyn
Creek Project** "
or the **"Project"** means
the development of Oil Sands Lease #24 located in the Athabasca oil sands
fairway of northeastern Alberta, in which Enerplus has a 16% working interest
and Deer Creek has an 84% working interest and is the operator of the
project;
  **"Joslyn
Lease"** means
the sections of land contained within Alberta Oil Sands Lease No. 7280060T24 and
Alberta Oil Sands Permit No. 7099110070;
    - iii
-
  " **NI
51-101** "
means National Instrument 51-101, Standards of Disclosure for Oil and Gas
Activities, adopted by the Canadian securities regulatory
authorities;
  **"SAGD"** means Steam Assisted Gravity Drainage, an *in
situ* production process used to recover bitumen from oil sands;
  **"Sproule"** means Sproule Associates Limited, independent petroleum
consultants;
  **"Sproule
Report"** means the independent engineering evaluation of Enerplus' conventional oil, NGLs
and natural gas interests prepared by Sproule dated February 3, 2005 and
effective December 31, 2004, utilizing commodity price forecasts of Sproule
dated December 31, 2004;
  " **subsidiary** "
has the meaning assigned thereto in the *Securities
Act* (Alberta);
  **"Tax
Act"** means
the *Income
Tax Act* (Canada);
  **"Trust
Indenture"** means the Amended and Restated Trust Indenture dated January 1, 2004 among
EnerMark, ERC and the Trustee, as may be amended, supplemented or restated from
time to time;
  **"Trust
Units"** means the trust units of the Fund, each representing an equal undivided
beneficial interest in the Fund; and
  **"Trustee"** means CIBC Mellon Trust Company, or its successor as trustee of the
Fund.
   - iv
-
  **ABBREVIATIONS
AND CONVERSIONS**
  In
this Annual Information Form, the following abbreviations have the meanings set
forth below.
  **AECO**
      ****
      **API**
    Alberta
      Energy Company interconnect with the Nova System, theCanadian
      benchmark for natural gas pricing purposes
      American
      Petroleum Institute
    
    **Mbbls**
    one
      thousand barrels**MBOE**
    one
      thousand barrels of oil equivalent**Mcf**
    one
      thousand cubic feet****bbls****
    barrels,
      with each barrel representing 34.972 imperial gallons or 42 U.S.
      gallons
    
    **Mcf/d**
    one
      thousand cubic feet per day****bbls/d**
      **Bcf****
    barrels
      per day
      billion
      cubic feet
    
    **MMbbls**
    one
      million barrels**MMBOE**
    one
      million barrels of oil equivalent******Bcf/d******
    billion
      cubic feet per day
    
    **MMBTU**
    one
      million British Thermal Units****BOE****
    barrels
      of oil equivalent converting 6 Mcf of natural gas to one barrel of oil
      equivalent and one barrel of natural gas liquids to one barrel of oil
      equivalent. The factor used to convert natural gas and natural gas liquids
      to oil equivalent is not based on either energy content or prices but is a
      commonly used industry benchmark.
    
    **MMcf**
      **MMcf/d**
      **NGLs**
      **WTI**
    one
      million cubic feet
      one million cubic feet per day
      natural gas liquids
      West
      Texas Intermediate at Cushing, Oklahoma, the benchmark for North American
      crude oil pricing purposes****BOE/d****
    barrels
      of oil equivalent per day
    
    ****
 
 In
this Annual Information Form, unless otherwise indicated, all dollar amounts are
in Canadian dollars and all references to "$" are to Canadian
dollars.
  The
following table sets forth certain standard conversions between Standard
Imperial Units and the International System of Units (or metric
units).
  **To
      Convert From**
    
    **To**
    
    **Multiply
      By**Mcf
    
    cubic
      metres
    
    28.174cubic
      metres
    
    cubic
      feet
    
    35.494bbls
    
    cubic
      metres
    
    0.159cubic
      metres
    
    bbls
    
    6.293feet
    
    metres
    
    0.305metres
    
    feet
    
    3.281miles
    
    kilometres
    
    1.609kilometres
    
    miles
    
    0.621acres
    
    hectares
    
    0.4047hectares
    
    acres
    
    2.471
  - v
-
  **PRESENTATION
OF ENERPLUS'**
 **OIL
AND GAS RESERVES AND PRODUCTION INFORMATION**
  **Disclosure
of Information**
  **In
this Annual Information Form, all estimates of oil and natural gas reserves and
production are presented on a "company interest" basis (as defined below),
unless expressly indicated that they have been presented on a "gross" or "net"
basis. Enerplus' actual oil and natural gas reserves and future production may
be greater than or less than the estimates provided in this Annual Information
Form. The estimated future net revenue from the production of Enerplus' oil and
natural gas reserves does not represent the fair market value of Enerplus'
reserves.**
  The
United States Securities and Exchange Commission (the "SEC") generally permits
oil and gas issuers, in their filings with the SEC, to disclose only proved
reserves net of royalties and interests of others that an issuer has
demonstrated by actual production or conclusive formation tests to be
economically and legally producible under existing economic and operating
conditions. Canadian securities laws permit oil and gas issuers, in their
filings with Canadian securities regulators, to disclose not only Proved
Reserves but also Probable Reserves (each as defined in NI 51-101 and described
below), and to disclose reserves and production on a "gross" basis before
deducting royalties. Probable Reserves are higher risk and are generally
believed to be less likely to be accurately estimated or recovered than Proved
Reserves. Enerplus has prepared this Annual Information Form in accordance with
Canadian disclosure requirements, and as a result, Enerplus has disclosed
reserves designated as "Probable Reserves" and "Proved plus Probable Reserves".
The SEC's guidelines strictly prohibit reserves in these categories from being
included in filings with the SEC that are required to be prepared in accordance
with U.S. disclosure requirements. Moreover, Enerplus has determined and
disclosed estimated future net revenue from its reserves using both constant and
forecast prices and costs, whereas the SEC generally requires that prices and
costs be held constant at levels in effect at the date of the reserve
report.
  Enerplus
has adopted the standard of 6 Mcf:1 BOE when converting natural gas to BOEs.
BOEs may be misleading, particularly if used in isolation. A BOE conversion
ratio of 6 Mcf:1 BOE is based on an energy equivalency conversion method
primarily applicable at the burner tip and does not represent a value
equivalency at the wellhead.
  **Note
to Reader Regarding Oil and Gas Information, Definitions and National Instrument
51-101**
  The
oil and gas operational and reserves information contained in this Annual
Information Form contains the information required to be included in the
Statement of Reserves Data and Other Oil and Gas Information pursuant to NI
51-101 adopted by the Canadian securities regulatory authorities and has been
prepared and prescribed in accordance with Form 51-101F1. Readers should also
refer to the Report on Reserves Data by Sproule attached hereto as Appendix "A",
the Report on Reserves Data by GLJ attached hereto as Appendix "B" and the
Report of Management and Directors on Oil and Gas Disclosure attached hereto as
Appendix "C". The effective date for the Statement of Reserves Data and Other
Oil and Gas Information contained in this Annual Information Form is December
31, 2004 and the information contained in the Annual Information Form has been
prepared as of March 14, 2005.
  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.
   - vi
-
  **Interests
in Reserves, Production, Wells and Properties**
  " **company
interest** "
means, in relation to Enerplus' interest in production or reserves, its working
interest (operating or non-operating) share before deduction of royalties and
including any royalty interests of Enerplus.
  " **gross** "
means:
  (i)
    in
      relation to Enerplus' interest in production or reserves, its working
      interest (operating or non-operating) share before deduction of royalties
      and without including any royalty interests of
Enerplus;(ii)
    in
      relation to wells, the total number of wells in which Enerplus has an
      interest; and(iii)
    in
      relation to properties, the total area of properties in which Enerplus has
      an interest.
 
 " **net** "
means:
  (i)
    in
      relation to Enerplus' interest in production or reserves, its working
      interest (operating or non-operating) share after deduction of royalty
      obligations, plus Enerplus' royalty interests in production or
      reserves;(ii)
    in
      relation to Enerplus' interest in wells, the number of wells obtained by
      aggregating Enerplus' working interest in each of its gross wells;
      and(iii)
    in
      relation to Enerplus' interest in a property, the total area in which
      Enerplus has an interest multiplied by the working interest owned by
      Enerplus.
 
 " **working
interest** "
means the percentage of undivided interest held by Enerplus in the oil and/or
natural gas or mineral lease granted by the mineral owner, Crown or freehold,
which interest gives Enerplus the right to "work" the property (lease) to
explore for, develop, produce and market the leased substances.
  **Reserves
Categories**
  " **Proved
Reserves** "
are those reserves that can be estimated with a high degree of certainty to be
recoverable. It is likely that the actual remaining quantities recovered will
exceed the estimated Proved Reserves.
  " **Probable
Reserves** "
are those additional reserves that are less certain to be recovered than Proved
Reserves. It is equally likely that the actual remaining quantities recovered
will be greater or less than the sum of the estimated Proved plus Probable
Reserves.
  " **Possible
Reserves** "
are those additional reserves that are less certain to be recovered than
Probable Reserves. It is unlikely that the actual remaining quantities recovered
will exceed the sum of the estimated Proved plus Probable plus Possible
Reserves.
  **Development
and Production Status**
  Each
of the reserves categories (Proved, Probable and Possible) may be divided into
developed and undeveloped categories:
  " **Developed
Reserves** "
are those reserves that are expected to be recovered from existing wells and
installed facilities or, if facilities have not been installed, that would
involve a low expenditure (for example, when compared to the cost of drilling a
well) to put the reserves on production. The developed category may be
subdivided into Producing and Non-Producing.
  •
    "**Developed
      Producing Reserves**"
      are those reserves that are expected to be recovered from completion
      intervals open at the time of the estimate. These reserves may be
      currently producing or, if shut-in, they
  - vii
-
  
 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, Probable, Possible) to
which they are assigned.
  **Levels
of Certainty for Reported Reserves**
  The
qualitative certainty levels referred to in the definitions above are applicable
to individual reserves entities (which refers to the lowest level at which
reserves calculations are performed) and to reported reserves (which refers to
the highest-level sum of individual entity estimates for which reserves
estimates are presented). Reported reserves should target the following levels
of certainty under a specific set of economic conditions:
  •
    at
      least a 90 percent probability that the quantities actually recovered will
      equal or exceed the estimated Proved Reserves;•
    at
      least a 50 percent probability that the quantities actually recovered will
      equal or exceed the sum of the estimated Proved plus Probable Reserves;
      and•
    at
      least a 10 percent probability that the quantities actually recovered will
      equal the sum of the estimated Proved plus Probable plus Possible
      Reserves.
  Description
of Price and Cost Assumptions
 
 " **Constant
prices and costs** "
means, unless expressly noted otherwise, prices and costs used in an estimate
that are:
  (i)
    Enerplus'
      prices and costs as at December 31, 2004, held constant throughout the
      estimated lives of the properties to which the estimate applies;
      and(ii)
    if,
      and only to the extent that, there are fixed or presently determinable
      future prices or costs to which Enerplus is legally bound by a contractual
      or other obligation to supply a physical product, including those for an
      extension period of a contract that is likely to be extended, those prices
      or costs rather than the prices or costs referred to in paragraph
      (i).
 
 " **Forecast
prices and costs** "
means future prices and costs that are:
  (i)
    generally
      accepted as being a reasonable outlook of the future;
  and(ii)
    if,
      and only to the extent that, there are fixed or presently determinable
      future prices or costs to which Enerplus is legally bound by a contractual
      or other obligation to supply a physical product, including those for an
      extension period of a contract that is likely to be extended, those prices
      or costs rather than the prices or costs referred to in paragraph
      (i).
  - vii
-
  **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, 2004.
  In
this Annual Information Form, unless otherwise indicated, all dollar amounts are
in Canadian dollars and all references to "$" are to Canadian
dollars.
  **DESCRIPTION
OF DISTRIBUTABLE INCOME**
  Throughout
this Annual Information Form, Enerplus uses the term "distributable income" to
refer to the amount of cash that has been or is to be available for distribution
to the Fund's unitholders. "Distributable income" is not a measure recognized by
Canadian GAAP and does not have a standardized meaning prescribed by GAAP, but
is an amount calculated in accordance with the terms of the Fund's Trust
Indenture. Therefore, distributable income of the Fund may not be comparable to
similar measures presented by other issuers, and investors are cautioned that
distributable income should not be construed as an alternative to net earnings,
cash flow from operating activities or other measures of financial performance
calculated in accordance with GAAP.
  **FORWARD-LOOKING
STATEMENTS**
  This
Annual Information Form contains forward-looking statements which are based on
Enerplus' current internal expectations, estimates, projections, assumptions and
beliefs. Forward-looking statements are made by Enerplus in light of its
experience and its perception of historical trends.
  All
statements that address expectations or projections about the future, including
statements about Enerplus' strategy for growth, expected future expenditures,
commodity prices, costs, schedules, production volumes, operating and financial
results and expected impact of future contractual commitments, are
forward-looking statements. Some of the forward-looking statements may be
identified by words such as "expects", "anticipates", "believes", "projects",
"plans" and similar expressions. These statements are not guarantees of future
performance and involve a number of risks and uncertainties. Such
forward-looking statements necessarily involve known and unknown risks and
uncertainties, which may cause Enerplus' actual performance and financial
results in future periods to differ materially from any projections of future
performance or results expressed or implied by such forward-looking statements.
  These
risks and uncertainties include, among other things, changes in general
economic, market and business conditions; changes or fluctuations in production
levels, commodity prices, currency exchange rates, capital expenditures,
reserves or reserves estimates and debt service requirements; changes to
legislation, investment eligibility or investment criteria; Enerplus' ability to
comply with current and future environmental or other laws; Enerplus' success at
acquisition, exploitation and development of reserves; actions by governmental
or regulatory authorities including increasing taxes, changes in investment or
other regulations; and the occurrence of unexpected events involved in the
operation and development of oil and gas properties. The foregoing factors are
not exhaustive.
  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, 2004, which
is available through the internet on Enerplus' SEDAR profile at www.sedar.com.
Readers are also referred to the risk factors described in this Annual
Information Form and in other documents Enerplus files from time to time with
securities regulatory authorities. Copies of these documents are available
without charge from Enerplus.
  
  - ix
-
   **ENERPLUS
RESOURCES FUND**
  **Renewal
Annual Information Form**
 **For
the year ended December 31, 2004**
  **STRUCTURE
OF ENERPLUS RESOURCES FUND**
  **Enerplus
Resources Fund**
  Enerplus
Resources Fund is an energy investment trust created in 1986 under the laws of
the Province of Alberta pursuant to the Trust Indenture. The Fund's assets
currently consist of the securities of several direct and indirect operating
subsidiaries (the primary of which are EnerMark, ERC, Enerplus Oil & Gas and
ECT), an unsecured note issued by EnerMark to the Fund and 95%, 99% and 99%
royalties on the crude oil and natural gas property interests of EnerMark, ERC
and Enerplus Oil & Gas, respectively. The head, principal and registered
office of Enerplus is located at The Dome Tower, Suite 3000, 333 - 7 th Avenue S.W., Calgary, Alberta, T2P 2Z1. The Trustee of the Fund is CIBC Mellon
Trust Company located at 600 The Dome Tower, 333 - 7 th Avenue S.W., Calgary, Alberta T2P 2Z1.
  The
Fund's primary focus is to maintain and enhance monthly cash distributions to
its unitholders from the net cash flow generated by the operation and
development of its operating subsidiaries' existing crude oil and natural gas
properties and the strategic acquisition of additional properties and assets.
See "Operational Information - Overview".
  **EnerMark
Inc., Enerplus Resources Corporation** **,
Enerplus Oil & Gas Ltd. and Enerplus Commercial Trust**
  Each
of EnerMark, ERC and Enerplus Oil & Gas are corporations organized under the *Business
Corporations Act* (Alberta) and ECT is a trust organized under the laws of Alberta. All of the
issued and outstanding common shares of EnerMark are directly owned by the Fund
and all of the trust units of ECT are indirectly owned by the Fund through its
wholly owned subsidiary, Enerplus Limited Partnership II (an Alberta limited
partnership). All of the issued and outstanding common shares of ERC are owned
by EnerMark and all of the issued and outstanding common shares of Enerplus Oil
& Gas are owned by ERC. **** The
board of directors of EnerMark is responsible for the governance of
Enerplus.
  EnerMark,
ERC, Enerplus Oil & Gas and ECT, together with the Fund's other direct and
indirect operating subsidiaries, acquire, exploit and operate crude oil and
natural gas assets in western Canada for the benefit of the Fund. See
"Operational Information" and "Oil and Natural Gas Reserves" for information
regarding the operations and oil and natural gas reserves of
Enerplus.
    - 1
-
   **Organization
Chart**
 The
simplified organizational structure of Enerplus, including the material
subsidiaries of the Fund and the flow of funds from EnerMark, ERC and Enerplus
Oil & Gas to the Fund and from the Fund to its unitholders, is set forth
below:
  
   - 2
-
   **GENERAL
DEVELOPMENT OF ENERPLUS RESOURCES FUND**
 **Historical
Overview**
  Enerplus
was formed in 1986 and has been traded on the TSX since that time. The Fund's
Trust Units are currently traded on the TSX under the symbol "ERF.UN". The Fund
was historically one of a group of royalty trusts, income funds and other
entities managed by companies within the Enerplus organization. In recent years,
Enerplus Resources Fund has grown significantly as a result of consolidation of
many of those entities, as discussed below, and a series of corporate and asset
acquisitions.
  *Merger
with Westrock Energy Income Fund I and Westrock Energy Income Fund
II*
  On
June 8, 2000, Enerplus, Westrock Energy Income Fund I ("Westrock I") and
Westrock Energy Income Fund II ("Westrock II") merged and continued as "Enerplus
Resources Fund". Enerplus, Westrock I and Westrock II were managed by affiliated
management companies which were part of the Enerplus organization (and each of
which was a predecessor of EGEM). The transaction was negotiated on an arm's
length basis on behalf of each of Enerplus, Westrock I and Westrock II by
independent special committees of the boards of directors responsible for each
entity.
  *Affiliation
with El Paso Corporation*
  On
August 3, 2000, an indirect wholly owned subsidiary of El Paso Corporation ("El
Paso") of Houston, Texas acquired the companies responsible for the management
of various public and private funds within the Enerplus organization, including
EGEM. On April 23, 2003, Enerplus acquired EGEM from El Paso, which resulted in
the termination of this affiliation, as described under "Management
Internalization Transaction" below.
  *Listing
on the New York Stock Exchange*
  On
November 17, 2000, the Trust Units were listed and posted for trading on
the New York Stock Exchange (the "NYSE") under the trading symbol "ERF".
Enerplus was the first Canadian royalty trust to have its securities trade on
the NYSE.
  *Merger
with EnerMark Income Fund*
  On
June 21, 2001, Enerplus and EnerMark Income Fund merged and continued as
"Enerplus Resources Fund". Enerplus and EnerMark Income Fund were managed by
affiliated management companies which were part of the Enerplus Group of
Companies. Although it was concluded that the merger was not subject to the
provisions governing "related party transactions" within the meaning of certain
Canadian securities laws, due to the common management of the two funds, the
Merger was effectively treated as a related party transaction by the funds and
their respective boards in order to avoid the perception of any conflict of
interest or any informational disadvantage arising from the merger, including
complying with certain valuation, disclosure and minority approval requirements.
The transaction was negotiated on an arm's length basis on behalf of Enerplus
and EnerMark Income Fund by independent special committees of the boards
responsible for each entity.
  EnerMark
Income Fund was created on April 3, 1996 as a result of a corporate
reorganization of Mark Resources Inc. by way of a plan of arrangement. From 1997
through 2000, EnerMark Income Fund made several corporate and asset
acquisitions, including the acquisitions of Quest Oil & Gas Inc. in 1997,
Derrick Energy Corporation in 1999 and Western Star Exploration Ltd., Pursuit
Resources Corp., EBOC Energy Ltd. and Cabre Exploration Ltd., in addition to a
significant asset acquisition in the Hanna, Alberta area in 2000.
  *Acquisition
of Celsius Energy Resources Ltd.*
  On
October 21, 2002, Enerplus acquired all of the outstanding shares of Celsius
Energy Resources Ltd. ("Celsius"), a private oil and gas producer based in
Calgary, Alberta, which was a wholly owned Canadian subsidiary of U.S.
   - 3
-
  based
Questar Market Resources Inc., for total consideration of $161.4 million, after
working capital adjustments. On October 22, 2002, Celsius was amalgamated with
EnerMark.
  *Acquisition
of PCC Energy Inc. and PCC Energy Corp.*
  On
March 5, 2003, Enerplus acquired all of the outstanding shares of PCC Energy
Inc. and PCC Energy Corp. (collectively, "PCC"), which were wholly owned
Canadian subsidiaries of U.S. based PetroCorp Incorporated, for total cash
consideration of $165.8 million, after working capital adjustments. A portion of
the PCC properties acquired are subject to a royalty arrangement structured as a
net profits interest ("NPI") with a private U.S. company. The NPI is accounted
for as a working interest of the U.S. company in these properties and as a
result is not included in Enerplus' reserves, production, or financial
information.
  *Management
Internalization Transaction*
  On
April 23, 2003, following receipt of unitholder approval, Enerplus acquired all
of the outstanding shares of EGEM from an indirect wholly owned subsidiary of El
Paso and incurred associated costs for a total cash consideration of $55.1
million. Prior to the acquisition, EGEM received management fees from Enerplus
for providing administrative and management services to the Fund and its
operating subsidiaries pursuant to a management agreement. As part of this
transaction, EGEM agreed to fix the total fees payable under the management
agreement from January 1, 2003 to April 23, 2003 at $3.0 million. Immediately
following completion of the transaction, EGEM assigned and transferred all of
its rights and obligations under the management agreement to EnerMark (a wholly
owned subsidiary of the Fund), and the management agreement was effectively
terminated.
  *Acquisition
of Ice Energy Limited*
  On
January 7, 2004, Enerplus completed the acquisition of all of the issued and
outstanding shares of Ice Energy Limited ("Ice Energy"). Enerplus previously
owned approximately 12.7% of the shares of Ice Energy which were acquired in a
prior transaction. The total purchase price for the all of the Ice Energy
shares, including those previously owned by Enerplus, and the existing debt was
approximately $130.5 million. As a result of this acquisition, Enerplus acquired
an interest in the Shackleton area of western Saskatchewan, which Enerplus
believes has long-term natural gas development potential. The acquired interests
also include a 50% working interest in a joint venture to develop a commercial
coal bed methane (also known as natural gas from coal) project in central
Alberta.
  *Acquisition
of Properties from ChevronTexaco*
  On
June 30, 2004, Enerplus completed the acquisition of conventional oil and
natural gas interests located in western Canada from ChevronTexaco for a net
purchase price 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. Production and operational results from these properties
have been included in Enerplus' 2004 production and operations from June 30,
2004, the closing date of the transaction.
  **Update
on Mutual Fund Trust Status and Taxation Matters**
  The
Canadian federal government has expressed concerns about a potential reduction
in future tax revenues due to the increased presence of income trusts in the
Canadian economy and the increased ownership of income trusts and other
flow-through entities by non-residents of Canada. Based on the most recent
information obtained by Enerplus through its transfer agent and financial
intermediaries in February 2005, an estimated 70% of the issued and outstanding
Trust Units were held by non-residents of Canada (as defined in the Tax Act) at
that time.
   - 4
-
  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"). The Fund is currently able
to take advantage of the TCP Exception, and as a result, the Fund's Trust
Indenture does not currently have a specific limit on the percentage of Trust
Units that may be owned by non-residents.
  On
March 23, 2004 the Canadian federal government announced proposed changes to the
Tax Act which would have effectively eliminated, over a period of time, the TCP
Exception currently relied on by Enerplus to maintain its mutual fund trust
status, and would have required the Fund to comply with the requirement that it
"not be maintained primarily for the benefit of non-residents" before January 1,
2007. In response to submissions from and discussions with stakeholders, the
Canadian federal government has currently suspended the implementation of those
proposed amendments. The Canadian Minister of Finance indicated in the February
23, 2005 federal budget that further consultations would be pursued with
stakeholders on taxation issues related to income trusts and other flow-through
entities. Therefore, the uncertainty remains as to whether or not the TCP
Exception will be available to the Fund or whether the Canadian federal
government will introduce changes to tax regulations directed at non-resident
ownership.
  At
this time, there is no assurance that the above proposals will not be finalized
or enacted as proposed, or that new proposals will not be made which could
detrimentally affect Enerplus. Enerplus intends to continue to take the
necessary measures in order to ensure the Fund continues to qualify as a mutual
fund trust under the Tax Act. For additional information regarding these
matters, including the ability of Enerplus to adopt non-resident ownership
constraints if required in order to ensure that the Fund maintains its mutual
fund status and the consequences if the Fund lost its mutual fund trust status,
see "Information Respecting Enerplus Resources Fund - Description of the Trust
Units and the Trust Indenture - Non-Resident Ownership Provisions", "Risk
Factors - Changes in tax and other laws may adversely affect unitholders" and
"Risk Factors - There would be material adverse consequences if the Fund lost
its status as a mutual fund trust under Canadian tax laws".
  Additionally,
in late 2004, the Canadian federal government announced changes to the Tax Act
that affect the taxation of distributions to non-resident Unitholders. An
estimated 5% of the Fund's current distributions to non-resident Unitholders are
deemed to be a return of capital, which previously were not subject to Canadian
withholding tax. Effective January 1, 2005, a Canadian withholding tax was
applied to the return of capital portion of distributions made to non-resident
investors. The tax, at a rate of 15%, is withheld from the distributions at
source.
  **Update
on Unitholder Limited Liability and Index Inclusion**
  Effective
July 1, 2004 the *Income
Trusts Liability Act* (Alberta)
was proclaimed in force. The Act creates a statutory limitation on the liability
of unitholders of income trusts organized under the laws of Alberta, such as the
Fund. The legislation provides that a unitholder will not be, as a beneficiary,
liable for any act, default, obligation or liability of the trustee that arises
after the legislation comes into effect. The legislation does not affect the
liability of unitholders with respect to any act, default, obligation or
liability that arose before July 1, 2004. For additional information, see "Risk
Factors - The limited liability of the Fund's unitholders is
uncertain".
  Additionally,
in December 2004 Ontario adopted unitholder limited liability legislation
similar to that implemented in Alberta. The removal of the legislative
uncertainty in Alberta and Ontario (as well as Québec, which historically has
had codified limited liability for trust unitholders) was seen as a significant
step that led Standard and Poor's to recently announce that it intended to
include income trusts in the S&P/TSX Composite Index in mid-2005, which
Enerplus anticipates will increase investor interest in the income trust sector.
Enerplus currently expects that it will qualify for inclusion in the S&P/TSX
Composite Index at that time.
    - 5
-
   **OIL
AND NATURAL GAS RESERVES**
 Enerplus'
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 88% of the net present
value (discounted at 10%) of Enerplus' Proved plus Probable conventional oil and
natural gas reserves. Enerplus has evaluated the balance of the conventional
properties using similar evaluation parameters, including the same forecast
price and cost assumptions utilized by Sproule. Sproule has reviewed Enerplus'
evaluation of these properties.
  Gilbert
Laustsen Jung Associates Ltd., a private independent petroleum consulting firm
based in Calgary, Alberta, has evaluated Enerplus' interests in the
SAGD-recoverable bitumen reserves of the Joslyn Creek Project using the same
forecast price and cost assumptions utilized by Sproule.
  Enerplus
follows the Canadian practice of reporting company interest and gross production
and reserve volumes, which are presented prior to the deduction of royalties and
similar payments. In the United States, production and reserve volumes are
reported on a net basis, after deducting these amounts. The Canadian practice of
using forecast prices and costs when estimating the quantities of reserves is
also followed by Enerplus. In the United States, reserve estimates are
calculated using prices and costs held constant at amounts in effect at the date
of the reserve report. Enerplus also follows the Canadian practice of reporting
the aggregate of Proved plus Probable reserves portion. As a consequence,
Enerplus' production volumes and reserve estimates may not be comparable to
those made by companies utilizing United States disclosure
standards.
  The
following tables summarize, as at December 31, 2004, Enerplus' oil, NGLs and
natural gas reserves **** and
the estimated net present values of future net cash revenues associated with
such reserves, based on forecast and constant price and cost assumptions. The
data contained in the tables is a summary of the evaluations, and as a result
the tables may contain slightly different numbers than the evaluations
themselves due to rounding. Additionally, the numbers in the tables may not add
due to rounding.
  **All
future net revenues are stated prior to provision for interest, general and
administrative expenses and after deduction of royalties and estimated future
capital expenditures. Future net revenues have been presented on the basis that
no income taxes will be paid by Enerplus in the future and therefore after-tax
future net revenues from Enerplus' oil and gas reserves are equal to the
before-tax future net revenues. See "Operational Information - Tax Horizon".**
  **It
should not be assumed that the present worth of estimated future cash flows
shown below is representative of the fair market value of the reserves. There is
no assurance that such price and cost assumptions will be attained and variances
could be material. The recovery and reserve estimates of Enerplus' crude oil,
NGLs and natural gas reserves provided herein are estimates only. Actual
reserves may be greater than or less than the estimates provided herein. Readers
should review the definitions and information contained in "Presentation of
Enerplus' Oil and Gas Reserves and Production Information" in conjunction with
the following tables and notes.**
  
   - 6
-
  **Summary
of Aggregate Enerplus Reserves**
  The
following tables summarize the aggregate company interest reserves volumes and
net present value of future net revenue contained in the Sproule Report relating
to Enerplus' conventional crude oil and natural gas reserves and the GLJ Report
relating to Enerplus' interest in the SAGD-recoverable bitumen reserves of the
Joslyn Creek Project, based on forecast price and cost assumptions. Detailed
separate summaries of the Sproule Report and the GLJ Report, including certain
assumptions incorporated into those reports, and presentation of Enerplus' oil
and gas reserves in accordance with NI 51-101 are contained in the tables
following the summary report below.
  **Summary
of Aggregate Oil and Gas Reserves**
 **and
Net Present Value of Future Net Revenue**
 **As
of December 31, 2004**
  ***Company
Interest Reserves,***
 ***Forecast
Prices and Costs***
  **OIL
      AND GAS RESERVES****Light
      and**
    
    
    
    
    
    
    
    
    
    **Natural
      Gas****RESERVES**
    
    **Medium
      Oil**
    
    **Heavy
      Oil**
    
    **Bitumen**
    
    **Total
      Oil**
    **Liquids**
    
    **Natural
      Gas**
    
    **Total****CATEGORY**
    
    **(Mbbls)**
    
    **(Mbbls)**
    
    **(Mbbls)**
    
    ****(Mbbls)****
    **(Mbbls)**
    
    **(Bcf)**
    
    **(MBOE)**Proved
      ReservesProved
      Developed Producing
    
    
    70,078
    
    
    28,274
    
    
    -
    
    
    98,352
    
    
    11,293
    
    
    804.3
    
    
    243,696Proved
      Developed Non-Producing
    
    
    104
    
    
    66
    
    
    -
    
    
    170
    
    
    623
    
    
    26.3
    
    
    5,176Proved
      Undeveloped
    
    
    2,857
    
    
    3,029
    
    
    -
    
    
    5,886
    
    
    860
    
    
    141.0
    
    
    30,245Total
      Proved Reserves
    
    
    73,039
    
    
    31,369
    
    
    -
    
    
    104,408
    
    
    12,776
    
    
    971.6
    
    
    279,117Probable
      Reserves
    
    
    17,180
    
    
    9,603
    
    
    47,747
    
    
    74,530
    
    
    3,292
    
    
    295.7
    
    
    127,105Total
      Proved Plus Probable Reserves
    
    
    90,219
    
    
    40,972
    
    
    47,747
    
    
    178,938
    
    
    16,068
    
    
    1,267.3
    
    
    406,222
  **NET
      PRESENT VALUE OF FUTURE NET REVENUE,****RESERVES**
    
    **DISCOUNTED
      AT (%/YEAR)****CATEGORY**
    
    **0%**
    
    **5%**
    
    **10%**
    
    **15%**
    
    **20%****(in
      $ millions)**Proved
      ReservesProved
      Developed Producing
    
    $
    4,339
    
    $
    2,993
    
    $
    2,362
    
    $
    1,990
    
    $
    1,742Proved
      Developed Non-Producing
    
    
    84
    
    
    60
    
    
    46
    
    
    37
    
    
    31Proved
      Undeveloped
    
    
    388
    
    
    254
    
    
    175
    
    
    125
    
    
    91Total
      Proved Reserves
    
    
    4,811
    
    
    3,307
    
    
    2,583
    
    
    2,152
    
    
    1,864Probable
      Reserves
    
    
    1,499
    
    
    715
    
    
    440
    
    
    312
    
    
    238Joslyn
      Creek SAGD Probable Bitumen Reserves
    
    
    357
    
    
    139
    
    
    52
    
    
    15
    
    
    (4
    )Total
      Proved Plus Probable Reserves
    
    $
    6,667
    
    $
    4,161
    
    $
    3,075
    
    $
    2,479
    
    $
    2,098
 - 7
-
  **Summary
of Sproule Report**
  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, as contained in the Sproule Report. This summary of the
Sproule Report does not include the reserves attributable to Enerplus' interest
in the SAGD-recoverable bitumen reserves from the Joslyn Creek Project, which
are summarized under the heading "Summary of GLJ Report" below.
 
 **Summary
of Enerplus' Conventional Oil and Gas Reserves**
 **and
Net Present Value of Future Net Revenue**
 **As
of December 31, 2004**
  ***Forecast
Prices and Costs***
  **OIL
      AND GAS RESERVES****LIGHT
      AND**
      **MEDIUM
      OIL**
    
    **HEAVY**
      **OIL**
    
    **NATURAL**
      **GAS****Company**
    
    
    
    
    
    **Company**
    
    
    
    
    
    **Company****RESERVES**
    
    **Interest**
    
    **Gross**
    
    **Net**
    
    **Interest**
    
    **Gross**
    
    **Net**
    
    **Interest**
    
    **Gross**
    
    **Net****CATEGORY**
    
    **(Mbbls)**
    
    **(Mbbls)**
    
    **(Mbbls)**
    
    **(Mbbls)**
    
    **(Mbbls)**
    
    **(Mbbls)**
    
    **(Bcf)**
    
    **(Bcf)**
    
    **(Bcf)**Proved
      ReservesProved
      Developed Producing
    
    
    70,078
    
    
    69,410
    
    
    63,755
    
    
    28,274
    
    
    28,232
    
    
    24,358
    
    
    804.3
    
    
    780.8
    
    
    639.3Proved
      Developed Non-Producing
    
    
    104
    
    
    104
    
    
    96
    
    
    66
    
    
    65
    
    
    53
    
    
    26.3
    
    
    25.9
    
    
    20.6Proved
      Undeveloped
    
    
    2,857
    
    
    2,818
    
    
    2,421
    
    
    3,029
    
    
    3,029
    
    
    2,560
    
    
    141.0
    
    
    136.0
    
    
    118.7Total
      Proved Reserves
    
    
    73,039
    
    
    72,332
    
    
    66,272
    
    
    31,369
    
    
    31,326
    
    
    26,971
    
    
    971.6
    
    
    942.7
    
    
    778.6Probable
      Reserves
    
    
    17,180
    
    
    16,936
    
    
    14,892
    
    
    9,603
    
    
    9,596
    
    
    8,264
    
    
    295.7
    
    
    288.9
    
    
    243.2Total
      Proved Plus Probable Reserves
    
    
    90,219
    
    
    89,268
    
    
    81,164
    
    
    40,972
    
    
    40,922
    
    
    35,235
    
    
    1,267.3
    
    
    1,231.6
    
    
    1,021.8
 **OIL
      AND GAS RESERVES****NATURAL
      GAS LIQUIDS**
    
    **TOTAL****Company**
    
    
    
    
    
    **Company****RESERVES**
    
    **Interest**
    
    **Gross**
    
    **Net**
    
    **Interest**
    
    **Gross**
    
    **Net****CATEGORY**
    
    **(Mbbls)**
    
    **(Mbbls)**
    
    **(Mbbls)**
    
    **(MBOE)**
    
    **(MBOE)**
    
    **(MBOE)**Proved
      ReservesProved
      Developed Producing
    
    
    11,293
    
    
    11,124
    
    
    7,902
    
    
    243,696
    
    
    238,893
    
    
    202,572Proved
      Developed Non-Producing
    
    
    623
    
    
    622
    
    
    435
    
    
    5,176
    
    
    5,120
    
    
    4,012Proved
      Undeveloped
    
    
    860
    
    
    853
    
    
    605
    
    
    30,245
    
    
    29,363
    
    
    25,369Total
      Proved Reserves
    
    
    12,776
    
    
    12,599
    
    
    8,942
    
    
    279,117
    
    
    273,376
    
    
    231,953Probable
      Reserves
    
    
    3,292
    
    
    3,244
    
    
    2,318
    
    
    79,358
    
    
    77,928
    
    
    66,009Total
      Proved Plus Probable Reserves
    
    
    16,068
    
    
    15,843
    
    
    11,260
    
    
    358,475
    
    
    351,304
    
    
    297,962
 **NET
      PRESENT VALUE OF FUTURE NET REVENUE,****RESERVES**
    
    **DISCOUNTED
      AT (%/YEAR)****CATEGORY**
    
    **0%**
    
    **5%**
    
    **10%**
    
    **15%**
    
    **20%****(in
      $ millions)**Proved
      ReservesProved
      Developed Producing
    
    $
    4,339
    
    $
    2,993
    
    $
    2,362
    
    $
    1,990
    
    $
    1,742Proved
      Developed Non-Producing
    
    
    84
    
    
    60
    
    
    46
    
    
    37
    
    
    31Proved
      Undeveloped
    
    
    388
    
    
    254
    
    
    175
    
    
    125
    
    
    91Total
      Proved Reserves
    
    
    4,811
    
    
    3,307
    
    
    2,583
    
    
    2,152
    
    
    1,864Probable
      Reserves
    
    
    1,499
    
    
    715
    
    
    440
    
    
    312
    
    
    238Total
      Proved Plus Probable Reserves
    
    $
    6,310
    
    $
    4,022
    
    $
    3,023
    
    $
    2,464
    
    $
    2,102
 
   - 8
-
  **Summary
of Enerplus' Conventional Oil and Gas Reserves**
 **and
Net Present Value of Future Net Revenue**
 **As
of December 31, 2004**
  ***Constant
Prices and Costs***
  **OIL
      AND GAS RESERVES****LIGHT
      AND**
      **MEDIUM
      OIL**
    
    **HEAVY**
      **OIL**
    
    **NATURAL**
      **GAS****Company**
    
    
    
    
    
    **Company**
    
    
    
    
    
    **Company****RESERVES**
    
    **Interest**
    
    **Gross**
    
    **Net**
    
    **Interest**
    
    **Gross**
    
    **Net**
    
    **Interest**
    
    **Gross**
    
    **Net****CATEGORY**
    
    **(Mbbls)**
    
    **(Mbbls)**
    
    **(Mbbls)**
    
    **(Mbbls)**
    
    **(Mbbls)**
    
    **(Mbbls)**
    
    **(Bcf)**
    
    **(Bcf)**
    
    **(Bcf)**Proved
      ReservesProved
      Developed Producing
    
    
    73,192
    
    
    72,524
    
    
    66,495
    
    
    26,692
    
    
    26,649
    
    
    23,519
    
    
    819.9
    
    
    796.3
    
    
    652.1Proved
      Developed Non-Producing
    
    
    105
    
    
    104
    
    
    95
    
    
    59
    
    
    59
    
    
    50
    
    
    26.6
    
    
    26.2
    
    
    20.9Proved
      Undeveloped
    
    
    2,972
    
    
    2,933
    
    
    2,493
    
    
    2,710
    
    
    2,710
    
    
    2,345
    
    
    141.8
    
    
    136.8
    
    
    119.4Total
      Proved Reserves
    
    
    76,269
    
    
    75,561
    
    
    69,083
    
    
    29,461
    
    
    29,418
    
    
    25,914
    
    
    988.3
    
    
    959.3
    
    
    792.4Probable
      Reserves
    
    
    18,128
    
    
    17,883
    
    
    15,644
    
    
    8,876
    
    
    8,869
    
    
    7,794
    
    
    300.4
    
    
    293.6
    
    
    247.3Total
      Proved Plus Probable Reserves
    
    
    94,397
    
    
    93,444
    
    
    84,727
    
    
    38,337
    
    
    38,287
    
    
    33,708
    
    
    1,288.7
    
    
    1,252.9
    
    
    1,039.7
 **OIL
      AND GAS RESERVES****NATURAL
      GAS LIQUIDS**
    
    **TOTAL****Company**
    
    
    
    
    
    **Company****RESERVES**
    
    **Interest**
    
    **Gross**
    
    **Net**
    
    **Interest**
    
    **Gross**
    
    **Net****CATEGORY**
    
    **(Mbbls)**
    
    **(Mbbls)**
    
    **(Mbbls)**
    
    **(MBOE)**
    
    **(MBOE)**
    
    **(MBOE)**Proved
      ReservesProved
      Developed Producing
    
    
    11,629
    
    
    11,459
    
    
    8,117
    
    
    248,168
    
    
    243,349
    
    
    206,818Proved
      Developed Non-Producing
    
    
    625
    
    
    623
    
    
    436
    
    
    5,225
    
    
    5,165
    
    
    4,054Proved
      Undeveloped
    
    
    868
    
    
    861
    
    
    609
    
    
    30,180
    
    
    29,298
    
    
    25,347Total
      Proved Reserves
    
    
    13,122
    
    
    12,943
    
    
    9,162
    
    
    283,573
    
    
    277,812
    
    
    236,219Probable
      Reserves
    
    
    3,405
    
    
    3,359
    
    
    2,391
    
    
    80,470
    
    
    79,036
    
    
    67,047Total
      Proved Plus Probable Reserves
    
    
    16,527
    
    
    16,302
    
    
    11,553
    
    
    364,043
    
    
    356,848
    
    
    303,266
 **NET
      PRESENT VALUES OF FUTURE NET REVENUE,****RESERVES**
    
    **DISCOUNTED
      AT (%/YEAR)****CATEGORY**
    
    **0%**
    
    **5%**
    
    **10%**
    
    **15%**
    
    **20%****(in
      $ millions)**Proved
      ReservesProved
      Developed Producing
    
    $
    5,133
    
    $
    3,439
    
    $
    2,639
    
    $
    2,172
    
    $
    1,863Proved
      Developed Non-Producing
    
    
    107
    
    
    75
    
    
    58
    
    
    46
    
    
    38Proved
      Undeveloped
    
    
    519
    
    
    342
    
    
    237
    
    
    171
    
    
    126Total
      Proved Reserves
    
    
    5,759
    
    
    3,856
    
    
    2,934
    
    
    2,389
    
    
    2,027Probable
      Reserves
    
    
    1,646
    
    
    807
    
    
    502
    
    
    354
    
    
    268Total
      Proved Plus Probable Reserves
    
    $
    7,405
    
    $
    4,663
    
    $
    3,436
    
    $
    2,743
    
    $
    2,295
 
  - 9
-
  
 **Notes:**
 
 (1)
    The
      estimated net present value of future net revenue includes the Alberta
      Royalty Tax Credit based on current legislation in place on December 31,
      2004.(2)
    Natural
      gas reserves are reported at a base pressure of 14.65 pounds per square
      inch and a base temperature of 60o F.(3)
    Prices
      for oil F.O.B. Edmonton are based upon 40o API oil having less than 0.4%
      sulphur. Prices for natural gas are based upon a base pressure of 14.65
      pounds per square inch and base temperature of 60oF. The wellhead oil
      prices were adjusted for quality and transportation based on historical
      actual prices. The natural gas prices were adjusted, where necessary,
      based on historical pricing based on heating values and the differing
      costs of service applied by various purchasers. The natural gas liquids
      prices were adjusted to reflect historical average prices
      received.(4)
    The
      forecast price and cost case assumes no legislative or regulatory
      amendments, and includes the effects of inflation. The estimated future
      net revenue to be derived from the production of the reserves includes an
      inflation rate of 2.5% per year until 2008 and 1.5% per year thereafter,
      an exchange rate of Cdn$1.00=US$0.84 and the following price forecasts
      supplied by Sproule:
  **CRUDE
      OIL**
    
    
    
    **NATURAL
      GAS LIQUIDS****WTI**
    
    **Edmonton**
    
    **Hardisty**
    
    **Cromer**
    
    
    
    **Edmonton
      Par Price****Cushing**
    
    **Par
      Price**
    
    **Heavy**
    
    **Medium**
    
    **NATURAL
      GAS**
    
    
    
    
    
    **Pentanes****Oklahoma**
    
    **40°
      API**
    
    **12°
      API**
    
    **29.3°
      API**
    
    **AECO
      Gas Price**
    
    **Propanes**
    
    **Butanes**
    
    **Plus****Year**
    
    **($US/bbl)**
    
    **($Cdn/bbl)**
    
    **($Cdn/bbl)**
    
    **($Cdn/bbl)**
    
    **($Cdn/MMBTU)**
    
    **($Cdn/bbl)**
    
    **($Cdn/bbl)**
    
    **($Cdn/bbl)**2005
    
    
    44.29
    
    
    51.25
    
    
    28.91
    
    
    44.53
    
    
    6.97
    
    
    32.09
    
    
    38.20
    
    
    52.492006
    
    
    41.60
    
    
    48.03
    
    
    28.12
    
    
    41.87
    
    
    6.66
    
    
    30.07
    
    
    34.01
    
    
    49.192007
    
    
    37.09
    
    
    42.64
    
    
    26.19
    
    
    37.27
    
    
    6.21
    
    
    26.70
    
    
    30.20
    
    
    43.672008
    
    
    33.46
    
    
    38.31
    
    
    25.06
    
    
    33.43
    
    
    5.73
    
    
    23.98
    
    
    27.13
    
    
    39.232009
    
    
    31.84
    
    
    36.36
    
    
    23.60
    
    
    31.70
    
    
    5.37
    
    
    22.76
    
    
    25.75
    
    
    37.24Thereafter
    
    
    +1.5
    %
    
    +1.5
    %
    
    +1.5
    %
    
    +1.5
    %
    
    +1.5
    %
    
    +1.5
    %
    
    +1.5
    %
    
    +1.5
    %
 
 In
      2004, Enerplus received a weighted average price (net of transportation
      costs but before hedging) of $34.98/bbl of heavy crude oil, $47.87/bbl of
      light and medium crude oil, $38.14/bbl of NGLs and $6.56/Mcf of natural
      gas.(5)
    The
      constant price and cost case assumes the continuance of product prices at
      December 31, 2004 and operating costs projected for 2005, and the
      continuance of current laws and regulations. Product prices have not been
      escalated beyond this date nor have operating and capital costs been
      increased on an inflationary basis. The future net revenue to be received
      from the production of the reserves was based on an exchange rate of
      Cdn$1.00=US$0.84 and the following prices in effect as at December 31,
      2004:
  **CRUDE
      OIL**
    
    
    
    **NATURAL
      GAS LIQUIDS****WTI**
    
    **Edmonton**
    
    **Hardisty**
    
    **Cromer**
    
    
    
    **Edmonton
      Par Price****Cushing**
    
    **Par
      Price**
    
    **Heavy**
    
    **Medium**
    
    **NATURAL
      GAS**
    
    
    
    
    
    **Pentanes****Oklahoma**
    
    **40°
      API**
    
    **12°
      API**
    
    **29.3°
      API**
    
    **AECO
      Gas Price**
    
    **Propanes**
    
    **Butanes**
    
    **Plus****($US/bbl)**
    
    **($Cdn/bbl)**
    
    **($Cdn/bbl)**
    
    **($Cdn/bbl)**
    
    **($Cdn/MMBTU)**
    
    **($Cdn/bbl)**
    
    **($Cdn/bbl)**
    
    **($Cdn/bbl)**44.04
    
    
    46.51
    
    
    15.26
    
    
    32.10
    
    
    6.78
    
    
    36.11
    
    
    39.78
    
    
    51.80
  (6)
    The
      undiscounted total future net revenue by reserves category as of December
      31, 2004, using both constant and forecast prices and costs, is set forth
      below:
  **Reserves
      Category**
    
    **Revenue**
    
    **Royalties**
    
    **Operating**
      **Costs**
    
    **Development**
      **Costs**
    
    **Abandonment**
      **and**
      **Reclamation**
      **Costs**
    
    **Future
      Net**
      **Revenue****(in
      $ millions)****Constant
      Prices and Costs**Proved
      Reserves
    
    
    10,733
    
    
    1,897
    
    
    2,724
    
    
    255
    
    
    98
    
    
    5,759Proved
      Plus Probable Reserves
    
    
    13,680
    
    
    2,422
    
    
    3,434
    
    
    309
    
    
    109
    
    
    7,406**Forecast
      Prices and Costs**Proved
      Reserves
    
    
    10,212
    
    
    1,661
    
    
    3,311
    
    
    280
    
    
    149
    
    
    4,811Proved
      Plus Probable Reserves
    
    
    13,310
    
    
    2,166
    
    
    4,319
    
    
    337
    
    
    178
    
    
    6,310
 
  - 10
-
  
 (7)
    The
      net present value of future net revenue by reserves category and
      production group as of December 31, 2004, using both constant and forecast
      prices and costs and discounted at 10% per year, is set forth
      below:
  **Future
      Net Revenue Before and After Income Taxes**
      **(Discounted
      at 10%/year)****Reserves
      Category**
    
    
    **Production
      Group**
    
    
    **Constant
      Prices and Costs**
    
    
    **Forecast
      Prices and Costs****(in
      $ millions)**Proved
      Reserves
    
    
    Light
      and Medium Crude Oil(a)
    
    
    820
    
    
    628Heavy
      Oil
    
    
    74
    
    
    186Natural
      Gas(b)
    
    
    2,040
    
    
    1,769Proved
      Plus Probable Reserves
    
    
    Light
      and Medium Crude Oil(a)
    
    
    936
    
    
    723Heavy
      Oil
    
    
    99
    
    
    230Natural
      Gas(b)
    
    
    2,401
    
    
    2,070
  (a)
    Includes
      solution gas and other by-products.(b)
    Includes
      by-products but excludes solution gas from oil
wells.
  (8)
    The
      volume of gross production from Proved plus Probable Reserves estimated by
      Sproule for 2005****in
      preparing the estimated net present values of future net revenue is as
      follows.
  **Product
      Type**
    
    **Aggregate
      Estimated 2005 Production**
    
    **Daily
      Estimated**
      **2005
      Production**Crude
      oilLight
      and medium crude oil
    
    
    6,664
      Mbbls
    
    
    18,256
      bbls/dHeavy
      oil
    
    
    3,419
      Mbbls
    
    
    9,367
      bbls/dTotal
      crude oil
    
    
    10,083
      Mbbls
    
    
    27,623
      bbls/dNatural
      gas liquids
    
    
    1,514
      Mbbls
    
    
    4,147
      bbls/dTotal
      liquids
    
    
    11,597
      Mbbls
    
    
    31,770
      bbls/dNatural
      gas
    
    
    103,879
      MMcf
    
    
    284,600
      Mcf/dTotal
    
    
    28,910
      MBOE
    
    
    79,203
      BOE/d
 
 (9)
    The
      amount of development costs deducted in the estimation of net present
      value of future net revenue is as follows (see also "Operational
      Information - 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)**2005
    
    
    113
    
    
    108
    
    
    141
    
    
    1352006
    
    
    37
    
    
    32
    
    
    51
    
    
    442007
    
    
    22
    
    
    17
    
    
    27
    
    
    212008
    
    
    17
    
    
    12
    
    
    21
    
    
    152009
    
    
    6
    
    
    4
    
    
    9
    
    
    6Remainder
    
    
    60
    
    
    26
    
    
    60
    
    
    25**Total**
    
    
    255
    
    
    199
    
    
    309
    
    
    246
 
 **Forecast
      Prices and Costs****Proved
      Reserves**
    
    **Proved
      Plus**
      **Probable
      Reserves****Year**
    
    **Undiscounted**
    
    **Discounted
      at**
      **10%/year**
    
    **Undiscounted**
    
    **Discounted
      at**
      **10%/year****(in
      $ millions)**2005
    
    
    118
    
    
    112
    
    
    147
    
    
    1402006
    
    
    39
    
    
    34
    
    
    54
    
    
    472007
    
    
    24
    
    
    19
    
    
    29
    
    
    232008
    
    
    19
    
    
    14
    
    
    24
    
    
    172009
    
    
    7
    
    
    4
    
    
    10
    
    
    6Remainder
    
    
    73
    
    
    31
    
    
    73
    
    
    32**Total**
    
    
    280
    
    
    214
    
    
    337
    
    
    265
    - 11
-
  **Summary
of GLJ Report**
  The
following tables and notes summarize the reserves volumes and net present value
of future net revenue attributable to Enerplus' 16% interest in the
SAGD-recoverable bitumen reserves of the Joslyn Creek Project, including certain
assumptions relating to the determination of those reserves and values, as
contained in the GLJ Report.
  **Summary
of Enerplus' Interest in the SAGD Bitumen Reserves of the**
 **Joslyn
Creek Lease and Net Present Values of Future Net Revenue**
 **As
of December 31, 2004**
  ***Forecast
Prices and Costs***
  **BITUMEN**
    
    **NET
      PRESENT VALUE OF FUTURE NET REVENUE,****RESERVES**
    
    **DISCOUNTED
      AT (%/YEAR)****RESERVES**
    
    **Gross**
    
    **Net****CATEGORY**
    
    **(Mbbls)**
    
    **(Mbbls)**
    
    **0%**
    
    **5%**
    
    **10%**
    
    **15%**
    
    **20%******
    
    
    
    **(in
      $ millions)**Total
      Probable Reserves
    
    
    47,747
    
    
    43,640
    
    $
    357
    
    $
    139
    
    $
    52
    
    $
    15
    
    $
    (4
    )
 
 ***Constant
Prices and Costs***
  **BITUMEN**
    
    **NET
      PRESENT VALUE OF FUTURE NET REVENUE,****RESERVES**
    
    **DISCOUNTED
      AT (%/YEAR)****RESERVES**
    
    **Gross**
    
    **Net****CATEGORY**
    
    **(Mbbls)**
    
    **(Mbbls)**
    
    **0%**
    
    **5%**
    
    **10%**
    
    **15%**
    
    **20%******
    
    
    
    **(in
      $ millions)**Total
      Probable Reserves
    
    
    47,747
    
    
    44,313
    
    $
    240
    
    $
    92
    
    $
    32
    
    $
    5
    
    $
    (8
    )
 ****
 **Notes:**
 
 (1)
    Prices
      for oil F.O.B. Edmonton are based upon 40o API oil having less than 0.4%
      sulphur. Prices for natural gas, which are utilized in the calculation of
      operating costs for the Joslyn Creek Project, are based upon a base
      pressure of 14.65 pounds per square inch and base temperature of
      60oF.(2)
    The
      forecast price and cost case assumes no legislative or regulatory
      amendments, and includes the effects of inflation. The estimated future
      net revenue to be derived from the production of the reserves was based on
      an inflation rate of 2.5% per year until 2008 and 1.5% per year
      thereafter, an exchange rate of Cdn$1.00=US$0.84 and the price forecasts
      set forth below supplied by Sproule as at December 31, 2004 (but utilized
      by GLJ for internal consistency in Enerplus' reserves reporting). The
      forecast net prices for bitumen produced from the Joslyn Creek Project
      ("Joslyn Bitumen") are calculated by subtracting blending costs,
      transportation and quality differentials from the forecast prices for Bow
      River Medium crude oil for the relevant
periods.
  **CRUDE
      OIL****Year**
    
    **WTI**
      **Cushing**
      **Oklahoma**
      **($US/bbl)**
    
    **Edmonton**
      **Par
      Price**
      **40°
      API**
      **($Cdn/bbl)**
    
    **Bow
      River**
      **Medium**
      **($Cdn/bbl)**
    
    **Joslyn**
      **Bitumen**
      **($Cdn/bbl)**
    
    **NATURAL
      GAS AECO Gas Price**
      **($Cdn/MMBTU)**2005
    
    
    44.29
    
    
    51.25
    
    
    36.26
    
    
    19.02
    
    
    6.972006
    
    
    41.60
    
    
    48.03
    
    
    34.89
    
    
    19.50
    
    
    6.662007
    
    
    37.09
    
    
    42.64
    
    
    32.11
    
    
    19.33
    
    
    6.212008
    
    
    33.46
    
    
    38.31
    
    
    30.68
    
    
    20.80
    
    
    5.732009
    
    
    31.84
    
    
    36.36
    
    
    29.08
    
    
    19.55
    
    
    5.37Thereafter
    
    
    +1.5
    %
    
    +1.5
    %
    
    +1.5
    %
    
    +1.5
    %
    
    +1.5
    %
 
  - 12
-
  
 (3)
    The
      constant price and cost case assumes the continuance of product prices at
      December 31, 2004 and operating costs projected for 2005, and the
      continuance of current laws and regulations. In accordance with Canadian
      Securities Administrators Staff Notice 51-315, the constant price of
      bitumen produced from the Joslyn Creek Project ("Joslyn Bitumen") was
      calculated by deducting the 2004 average price differential of a barrel of
      WTI crude oil and a barrel of Joslyn Bitumen from the December 31, 2004
      price for a barrel of WTI crude oil of US$44.04/bbl. Product prices have
      not been escalated beyond this date nor have operating and capital costs
      been increased on an inflationary basis. The future net revenue to be
      received from the production of the reserves was based on an exchange rate
      of Cdn$1.00=US$0.832 and the following prices in effect as at December 31,
      2004:
  **CRUDE
      OIL****WTI
      Cushing**
      **Oklahoma**
      **($US/bbl)**
    
    **Edmonton
      Par**
      **Price
      40° API**
      **($Cdn/bbl)**
    
    **Joslyn
      Bitumen**
      **($Cdn/bbl)**
    
    **NATURAL
      GAS**
      **AECO
      Gas Price**
      **($Cdn/MMBTU)**44.04
    
    
    46.51
    
    
    19.88
    
    
    6.78
 
 (4)
    The
      undiscounted total future net revenue of the Probable Reserves as of
      December 31, 2004, using both constant and forecast prices and costs, is
      set forth below:
  **Reserves
      Category**
    
    **Revenue**
    
    **Royalties**
    
    **Operating**
      **Costs**
    
    **Development**
      **Costs**
    
    **Abandonment**
      **and
      Reclamation Costs**
    
    **Future
      Net**
      **Revenue****(in
      $ millions)****Constant
      Prices and Costs**Probable
      Reserves
    
    
    949
    
    
    68
    
    
    412
    
    
    226
    
    
    2
    
    
    240**Forecast
      Prices and Costs**Probable
      Reserves
    
    
    1,173
    
    
    108
    
    
    439
    
    
    266
    
    
    3
    
    
    357
 
 (5)
    The
      net present value of future net revenue by reserves category and
      production group as of December 31, 2004, using both constant and forecast
      prices and costs and discounted at 10% per year, is set forth
      below:
  **Future
      Net Revenue Before and After Income Taxes**
      **(Discounted
      at 10%/year)****Reserves
      Category**
    
    **Production
      Group**
    
    **Constant
      Prices and Costs**
    
    **Forecast
      Prices and Costs****(in
      $ millions)**Probable
      Reserves
    
    Bitumen
    
    
    32
    
    
    52
 (6)
    The
      volume of gross production from the Probable Reserves in 2005 estimated by
      GLJ in preparing the estimated net present values of future net revenue is
      as follows:
  **Product
      Type**
    
    **Aggregate
      Estimated 2005 Production**
    
    **Daily
      Estimated**
      **2005
      Production**Bitumen
    
    
    19
      Mbbls
    
    
    53
      bbls/d
 
 (7)
    The
      amount of development costs deducted in the estimation of net present
      value of future net revenue attributable to the Probable Reserves is as
      follows (see also "Operational Information - Development
      Activities"):
  **Constant
      Prices and Costs**
    
    **Forecast
      Prices and Costs****Year**
    
    **Undiscounted**
    
    **Discounted
      at**
      **10%/year**
    
    **Undiscounted**
    
    **Discounted
      at**
      **10%/year**2005
    
    
    27
    
    
    26
    
    
    27
    
    
    262006
    
    
    -
    
    
    -
    
    
    -
    
    
    -2007
    
    
    -
    
    
    -
    
    
    -
    
    
    -2008
    
    
    36
    
    
    26
    
    
    39
    
    
    282009
    
    
    -
    
    
    -
    
    
    -
    
    
    -Remainder
    
    
    163
    
    
    56
    
    
    200
    
    
    67**Total**
    
    
    226
    
    
    108
    
    
    266
    
    
    121
 
  - 13
-
  **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, 2003 to December 31,
2004, using forecast prices and costs.
  *Reconciliation
of Company Interest Reserves*
  **Light
      and Medium**
      **Crude
      Oil**
    
    **Heavy
      Oil**
    
    **Bitumen****Factors**
    
    **Proved**
      **(Mbbls)**
    
    **Probable**
      **(Mbbls)**
    
    **Proved**
      **Plus
      Probable**
      **(Mbbls)**
    
    **Proved**
      **(Mbbls)**
    
    **Probable**
      **(Mbbls)**
    
    **Proved**
      **Plus**
      **Probable**
      **(Mbbls)**
    
    **Proved**
      **(Mbbls)**
    
    **Probable**
      **(Mbbls)**
    
    **Proved**
      **Plus
      Probable**
      **(Mbbls)****December
      31, 2003**
    
    
    **65,773**
    
    
    **20,342**
    
    
    **86,115**
    
    
    **25,290**
    
    
    **7,465**
    
    
    **32,755**
    
    
    **-**
    
    
    **-**
    
    
    **-**Acquisitions
    
    
    9,753
    
    
    7,963
    
    
    17,716
    
    
    2,052
    
    
    1,089
    
    
    3,141
    
    
    -
    
    
    -
    
    
    -Dispositions
    
    
    (22
    )
    
    (22
    )
    
    (44
    )
    
    (152
    )
    
    (273
    )
    
    (425
    )
    
    -
    
    
    -
    
    
    -Extensions
    
    
    180
    
    
    797
    
    
    977
    
    
    (739
    )
    
    (81
    )
    
    (820
    )
    
    -
    
    
    47,747
    
    
    47,747Technical
      Revisions
    
    
    1,295
    
    
    (12,226
    )
    
    (10,931
    )
    
    7,378
    
    
    1,355
    
    
    8,733
    
    
    -
    
    
    -
    
    
    -Discoveries
    
    
    322
    
    
    69
    
    
    391
    
    
    -
    
    
    -
    
    
    -
    
    
    -
    
    
    -
    
    
    -Economic
      Factors
    
    
    700
    
    
    200
    
    
    900
    
    
    200
    
    
    -
    
    
    200
    
    
    -
    
    
    -
    
    
    -Improved
      Recovery
    
    
    1,433
    
    
    57
    
    
    1,490
    
    
    296
    
    
    48
    
    
    344
    
    
    -
    
    
    -
    
    
    -Production
    
    
    (6,395
    )
    
    -
    
    
    (6,395
    )
    
    (2,956
    )
    
    -
    
    
    (2,956
    )
    
    -
    
    
    -
    
    
    -**December
      31, 2004**
    
    
    **73,039**
    
    
    **17,180**
    
    
    **90,219**
    
    
    **31,369**
    
    
    **9,603**
    
    
    **40,972**
    
    
    **-**
    
    
    **47,747**
    
    
    **47,747**
  **Natural
      Gas Liquids**
    
    **Associated
      and**
      **Non-Associated
      Gas**
      **(Natural
      Gas)**
    
    **Total****Factors**
    
    **Proved**
      **(Mbbls)**
    
    **Probable**
      **(Mbbls)**
    
    **Proved**
      **Plus**
      **Probable**
      **(Mbbls)**
    
    **Proved**
      **(Bcf)**
    
    **Probable**
      **(Bcf)**
    
    **Proved**
      **Plus
      Probable**
      **(Bcf)**
    
    **Proved**
      **(MBOE)**
    
    **Probable**
      **(MBOE)**
    
    **Proved**
      **Plus
      Probable (MBOE)****December
      31, 2003**
    
    
    **13,571**
    
    
    **3,742**
    
    
    **17,313**
    
    
    **867.2**
    
    
    **284.1**
    
    
    **1,151.3**
    
    
    **249,168**
    
    
    **78,898**
    
    
    **328,066**Acquisitions
    
    
    526
    
    
    282
    
    
    808
    
    
    94.3
    
    
    77.5
    
    
    171.8
    
    
    28,043
    
    
    22,249
    
    
    50,292Dispositions
    
    
    (13
    )
    
    (16
    )
    
    (29
    )
    
    (2.3
    )
    
    (2.1
    )
    
    (4.4
    )
    
    (570
    )
    
    (657
    )
    
    (1,227
    )Extensions
    
    
    217
    
    
    78
    
    
    295
    
    
    16.4
    
    
    1.5
    
    
    17.9
    
    
    2,391
    
    
    48,792
    
    
    51,183Technical
      Revisions
    
    
    (267
    )
    
    (857
    )
    
    (1,124
    )
    
    15.7
    
    
    (78.0
    )
    
    (62.3
    )
    
    11,020
    
    
    (24,727
    )
    
    (13,707
    )Discoveries
    
    
    44
    
    
    16
    
    
    60
    
    
    0.9
    
    
    0.3
    
    
    1.2
    
    
    518
    
    
    140
    
    
    658Economic
      Factors
    
    
    100
    
    
    -
    
    
    100
    
    
    3.2
    
    
    1.0
    
    
    4.2
    
    
    1,533
    
    
    367
    
    
    1,900Improved
      Recovery
    
    
    208
    
    
    47
    
    
    255
    
    
    75.4
    
    
    11.4
    
    
    86.8
    
    
    14,512
    
    
    2,043
    
    
    16,555Production
    
    
    (1,610
    )
    
    -
    
    
    (1,610
    )
    
    (99.2
    )
    
    -
    
    
    (99.2
    )
    
    (27,498
    )
    
    -
    
    
    (27,498
    )**December
      31, 2004**
    
    
    **12,776**
    
    
    **3,292**
    
    
    **16,068**
    
    
    **971.6**
    
    
    **295.7**
    
    
    **1,267.3**
    
    
    **279,117**
    
    
    **127,105**
    
    
    **406,222**
 
  
   - 14
-
  *Reconciliation
of Net Reserves*
  **Light
      and Medium**
      **Crude
      Oil**
    
    **Heavy
      Oil**
    
    **Bitumen****Factors**
    
    **Proved**
      **(Mbbls)**
    
    **Probable**
      **(Mbbls)**
    
    **Proved**
      **Plus
      Probable**
      **(Mbbls)**
    
    **Proved**
      **(Mbbls)**
    
    **Probable**
      **(Mbbls)**
    
    **Proved**
      **Plus**
      **Probable**
      **(Mbbls)**
    
    **Proved
      (Mbbls)**
    
    **Probable
      (Mbbls)**
    
    **Proved**
      **Plus
      Probable**
      **(Mbbls)****December
      31, 2003**
    
    
    **59,748**
    
    
    **17,696**
    
    
    **77,444**
    
    
    **21,857**
    
    
    **6,474**
    
    
    **28,331**
    
    
    **-**
    
    
    **-**
    
    
    **-**Acquisitions
    
    
    8,662
    
    
    6,995
    
    
    15,657
    
    
    1,754
    
    
    941
    
    
    2,695
    
    
    -
    
    
    -
    
    
    -Dispositions
    
    
    (20
    )
    
    (19
    )
    
    (39
    )
    
    (130
    )
    
    (235
    )
    
    (365
    )
    
    -
    
    
    -
    
    
    -Extensions
    
    
    150
    
    
    689
    
    
    839
    
    
    (518
    )
    
    (164
    )
    
    (682
    )
    
    -
    
    
    43,640
    
    
    43,640Technical
      Revisions
    
    
    1,157
    
    
    (10,795
    )
    
    (9,638
    )
    
    6,027
    
    
    1,183
    
    
    7,210
    
    
    -
    
    
    -
    
    
    -Discoveries
    
    
    292
    
    
    62
    
    
    354
    
    
    -
    
    
    -
    
    
    -
    
    
    -
    
    
    -
    
    
    -Economic
      Factors
    
    
    452
    
    
    104
    
    
    556
    
    
    143
    
    
    26
    
    
    169
    
    
    -
    
    
    -
    
    
    -Improved
      Recovery
    
    
    1,126
    
    
    160
    
    
    1,286
    
    
    241
    
    
    39
    
    
    280
    
    
    -
    
    
    -
    
    
    -Production
    
    
    (5,295
    )
    
    -
    
    
    (5,295
    )
    
    (2,403
    )
    
    -
    
    
    (2,403
    )
    
    -
    
    
    -
    
    
    -**December
      31, 2004**
    
    
    **66,272**
    
    
    **14,892**
    
    
    **81,164**
    
    
    **26,971**
    
    
    **8,264**
    
    
    **35,235**
    
    
    **-**
    
    
    **43,640**
    
    
    **43,640**
  **Natural
      Gas Liquids**
    
    **Associated
      and**
      **Non-Associated
      Gas**
      **(Natural
      Gas)**
    
    **Total****Factors**
    
    **Proved**
      **(Mbbls)**
    
    **Probable**
      **(Mbbls)**
    
    **Proved**
      **Plus**
      **Probable**
      **(Mbbls)**
    
    **Proved**
      **(Bcf)**
    
    **Probable**
      **(Bcf)**
    
    **Proved**
      **Plus
      Probable**
      **(Bcf)**
    
    **Proved**
      **(MBOE)**
    
    **Probable**
      **(MBOE)**
    
    **Proved**
      **Plus
      Probable**
      **(MBOE)****December
      31, 2003**
    
    
    **9,464**
    
    
    **2,624**
    
    
    **12,088**
    
    
    **684.1**
    
    
    **229.5**
    
    
    **913.6**
    
    
    **205,086**
    
    
    **65,044**
    
    
    **270,130**Acquisitions
    
    
    364
    
    
    199
    
    
    563
    
    
    79.2
    
    
    68.9
    
    
    148.1
    
    
    23,980
    
    
    19,618
    
    
    43,598Dispositions
    
    
    (9
    )
    
    (11
    )
    
    (20
    )
    
    (2.0
    )
    
    (2.0
    )
    
    (4.0
    )
    
    (492
    )
    
    (596
    )
    
    (1,088
    )Extensions
    
    
    126
    
    
    44
    
    
    170
    
    
    12.5
    
    
    0.8
    
    
    13.3
    
    
    1,841
    
    
    44,342
    
    
    46,183Technical
      Revisions
    
    
    (11
    )
    
    (559
    )
    
    (570
    )
    
    13.0
    
    
    (66.1
    )
    
    (53.1
    )
    
    9,335
    
    
    (21,187
    )
    
    (11,852
    )Discoveries
    
    
    31
    
    
    11
    
    
    42
    
    
    0.7
    
    
    0.3
    
    
    1.0
    
    
    440
    
    
    123
    
    
    563Economic
      Factors
    
    
    36
    
    
    (24
    )
    
    12
    
    
    2.8
    
    
    0.6
    
    
    3.4
    
    
    1,098
    
    
    206
    
    
    1,304Improved
      Recovery
    
    
    144
    
    
    34
    
    
    178
    
    
    65.7
    
    
    11.2
    
    
    76.9
    
    
    12,461
    
    
    2,099
    
    
    14,560Production
    
    
    (1,203
    )
    
    -
    
    
    (1,203
    )
    
    (77.4
    )
    
    -
    
    
    (77.4
    )
    
    (21,796
    )
    
    -
    
    
    (21,796
    )**December
      31, 2004**
    
    
    **8,942**
    
    
    **2,318**
    
    
    **11,260**
    
    
    **778.6**
    
    
    **243.2**
    
    
    **1,021.8**
    
    
    **231,953**
    
    
    **109,649**
    
    
    **341,602**
 
  - 15
-
  **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 from
December 31, 2003 to December 31, 2004 using constant prices and costs and
discounted at 10% per year.
 
 **Year
      Ended****Period
      and Factor**
    
    **December
      31, 2004******
    
    **(in
      $ millions)**Estimated
      Future Net Revenue at Beginning of Year
    
    $
    2,221.7Sales
      and Transfers of Oil, Natural Gas and NGLs Produced, Net of ProductionCosts
      and Royalties
    
    
    (697.2
    )Net
      Change in Prices, Production Costs and Royalties Related to FutureProduction
    
    
    522.7Changes
      in Previously Estimated Development Costs Incurred During the
      Period
    
    
    (106.8
    )Changes
      in Estimated Future Development Costs
    
    
    (176.9
    )Net
      Change Resulting from Extensions and Improved Recovery
    
    
    284.8Net
      Change Resulting from Discoveries
    
    
    7.6Changes
      from Acquisitions of Reserves
    
    
    496.8Changes
      from Dispositions of Reserves
    
    
    (33.0
    )Net
      Change Resulting from Revisions in Quantity Estimates
    
    
    227.8Accretion
      of Discount
    
    
    186.3Net
      Change in Income Taxes
    
    
    N/AEstimated
      Future Net Revenue at End of Year
    
    $
    2,933.8
 
 **Undeveloped
Reserves**
 
 The
following table discloses the volumes of Undeveloped Reserves of Enerplus as at
December 31, 2004 that were first attributed in 2003 and 2004.
  **Proved
      Undeveloped Reserves**
    
    **Probable
      Undeveloped Reserves****Crude
      Oil**
    
    
    
    
    
    
    
    **Crude
      Oil****Year**
    
    **Heavy**
      **(Mbbls)**
    
    **Light**
      **and**
      **Medium**
      **(Mbbls)**
    
    **NGLs**
      **(Mbbls)**
    
    **Natural**
      **Gas**
      **(Bcf)**
    
    **Total**
      **(MBOE)**
    
    **Heavy**
      **(Mbbls)**
    
    **Light**
      **and**
      **Medium**
      **(Mbbls)**
    
    **Bitumen**
      **(Mbbls)**
    
    **NGLs**
      **(Mbbls)**
    
    **Natural**
      **Gas**
      **(Bcf)**
    
    **Total**
      **(MBOE)**2003
    
    
    950
    
    
    320
    
    
    35
    
    
    27.5
    
    
    5,888
    
    
    74
    
    
    263
    
    
    -
    
    
    80
    
    
    33.9
    
    
    6,0672004
    
    
    189
    
    
    1,182
    
    
    55
    
    
    63.0
    
    
    11,920
    
    
    950
    
    
    1,808
    
    
    47,747
    
    
    40
    
    
    25.0
    
    
    54,711
 
 Enerplus
attributes Proved and Probable Undeveloped Reserves based on accepted
engineering and geological practices as defined under NI 51-101. These practices
include the determination of reserves based on the presence of commercial test
rates from either production tests or drill stem tests, extensions of known
accumulations based upon either geological or geophysical information and the
optimization of existing fields. Enerplus has been very active for the last
several years in drilling and developing these Undeveloped Reserves volumes, and
based on Enerplus' estimates of future capital expenditures, Enerplus expects to
continue this activity.
  **Proved
and Probable Reserves Not on Production**
  Enerplus
has approximately 7,479 MBOE of Proved plus Probable Reserves which are capable
of production but which, as of December 31, 2004, 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 Creek 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 awaiting production until production from another
formation or zone in the same well bore is completed, or are related to reserves
volumes which require the completion of infrastructure before production can
begin.
 
 ****
   - 16
-
   OPERATIONAL INFORMATION
 
 **Overview**
  Enerplus'
operational strategies and activities are directed towards maximizing value and
distributable income over the long-term. Enerplus utilizes its extensive
operating experience and employs prudent oil and gas business practices to
increase value through accretive acquisitions and development and optimization
activities on new and existing oil and gas properties. Enerplus achieves this
value creation through a focused and disciplined acquisition strategy, an active
development program directed towards lower risk development, continuous
optimization of its existing assets and active management of risk.
  Enerplus'
focused acquisition strategy is generally directed towards mature longer-life
assets with lower risk development potential which fit within core strategic
areas and complement its 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. This strategy provides Enerplus with the
flexibility to respond to acquisition opportunities on a timely
basis.
  Enerplus
actively develops its properties through lower risk development projects which
include infill drilling, step-out drilling, joint venture arrangements,
farmouts, waterflood implementation and expansions and other activities.
Enerplus is currently focused on waterfloods, shallow natural gas and attractive
joint venture activities in select areas. 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 for 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 debottlenecking; enhancement of
artificial lift, water injection, fluid handling, and fluid processing; water
injection and facility optimization; and other activities. These activities are
typically smaller projects with attractive rates of return given the limited
capital investment required and rapid payback. Enerplus uses a variety of
technical and operating experts, both internal and external, to achieve these
results.
  Risk
management is a key strategy for Enerplus. This is achieved through a
disciplined acquisition focus which is generally concentrated on mature,
longer-life properties which typically have more predictable production and
reserves, lower risk development activities, partnering on higher risk
activities through joint venture or farmout arrangements, an active hedging
program and other risk mitigation actions. Enerplus typically experiences a
greater than 98% drilling success by avoiding a large component of exploration
type drilling which is typically higher risk. 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.
  **Description
of Principal Properties and Operations**
  Outlined
below is a description of Enerplus' oil and natural gas operations and each of
the Enerplus business units and their principal producing properties including,
where applicable, the additional properties or working interests acquired
through acquisitions during 2004. All production information represents
Enerplus' "company interest" in 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 or GLJ Report, as applicable, using forecast prices and
costs. See "Presentation of Enerplus' Oil and Gas Reserves 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.
All of Enerplus' major properties have related field production facilities and
infrastructure to accommodate Enerplus' production. Production volumes for the
year ended December 31, 2004 from Enerplus' properties consisted of
approximately 40% crude oil and NGLs and 60% natural gas on a
   - 17
-
  BOE
basis. Enerplus' 2004 production was comprised of average daily production of
25,550 bbls/d of crude oil, 4,398 bbls/d of NGLs and 271.1 MMcf/d of natural gas
for a total of 75,130 BOE/d, an increase of 8% when compared to the previous
year. During 2003, production consisted of 24,597 bbls/d of crude oil, 4,666
bbls/d of NGLs and 240.9 MMcf/d of natural gas for a total of 69,414 BOE/d. As
at December 31, 2004, the oil and natural gas property interests held by
Enerplus were estimated to contain Proved plus Probable Reserves of 195.0 MMbbls
of crude oil and NGLs and 1,267 Bcf of natural gas for a total of 406.2 MMBOE.
See "Oil and Natural Gas Reserves".
  Enerplus'
operations are organized into a business unit structure, with four
geographically distinct Enerplus-operated business units which accounted for
approximately 60% of 2004 average daily production, and a joint venture business
unit which accounted for approximately 40% of 2004 daily production. Enerplus
believes that this structure has enabled it to better focus its activities and
improve its operational and technical performance, operating results and capital
efficiency. Each of these five business units is a profit centre with a distinct
team of engineers, geologists, operations personnel and landmen. Skill sets
within each business unit are tailored to compliment the unique demands and
opportunities within each area. Outlined below is a description of each business
unit, along with a description of the Joslyn Creek Project in which Enerplus
participates.
  *Joint
Venture Business Unit*
  The
Joint Venture Business Unit accounted for approximately 40% of Enerplus' 2004
production and encompasses all partner-operated properties in western Canada
from northeastern British Columbia to southeastern Saskatchewan. These
properties provide exposure to a wide variety of reservoirs, play types, and
enhanced recovery projects that offer diversification to Enerplus' asset base.
This business unit also provides exposure to higher impact (i.e., higher
risk/reward) and more technically complex projects than Enerplus might otherwise
pursue on its own.
  Production
from this business unit for the year ended December 31, 2004 averaged 6,010
bbls/d of crude oil, 2,655 bbls/d of NGLs and 131.0 MMcf/d of natural gas for a
total of 30,490 BOE/d. The key producing properties within this business unit
include (i) the sweet, liquids rich natural gas plays in the Deep Basin region
which encompasses the Elmworth, Karr, Wapiti, and South Wapiti producing fields,
primarily operated by Burlington Resources Canada Ltd., Devon Canada Corporation
and BP Canada Energy Company, (ii) interests in the deep sour gas natural play
in the Hanlan, Alberta region operated by Petro-Canada, (iii) interests in the
Mount Benjamin property also operated by Petro-Canada, and (iv) interests in the
shallow natural gas property in the Shackleton area of southwestern Saskatchewan
which are operated by Profico Energy Management Ltd. and Devon Canada
Corporation.
  During
2004, the acquisition of Ice Energy and certain assets from ChevronTexaco added
approximately 1,600 and 2,400 BOE/d of production, respectively, to the Joint
Venture Business Unit. Most of this production is generated from the Shackleton
shallow natural gas area and the Mitsue area which is a waterflood project
operated by Acclaim Energy Trust. These acquisitions also brought significant
development opportunities to Enerplus such as the natural gas from coal ("NGC")
development project in the Joffre area of central Alberta, where a total of 78
gross (39 net) wells are planned to be drilled in 2005.
  Major
production facilities within this business unit include (i) a 6% interest in the
Elmworth Gas Plant, (ii) a 3% interest in the Wapiti Gas Plant, (iii) a 10%
interest in the Progress Gas Plant, (iv) an 8.5% in the Hanlan-Robb Sour Gas
Plant, (v) an 8% interest in a sweetening and absorption facility at Minnehik
Buck Lake, (vi) a 2% interest in the Ram River sweetening and refrigeration
facility, and (vii) a 22% interest in an emulsion treating and water disposal
facility at Hayter.
  Excluding
the Joslyn Creek Project, Enerplus expects the amount of 2005 capital
expenditures for this partner-operated business unit to remain comparable
with 2004, with approximately 85% of Enerplus' Joint Venture Business Unit
capital budget focused on natural gas-weighted projects and 15% on oil-weighted
projects.
   - 18
-
  *Southern
Business Unit*
  The
Southern Business Unit is Enerplus' largest and most active operated development
area encompassing long-life properties in southern Alberta and Saskatchewan. It
contains Enerplus' core shallow natural gas development areas as well as a broad
range of crude oil interests. The majority of Enerplus' operated natural gas
production and development drilling is conducted in this business unit with over
280 operated shallow natural gas wells drilled in 2004. In addition, Enerplus
successfully developed an NGC project in its Trochu field which it acquired from
Ice Energy in early 2004, and Enerplus has continued to test other NGC
opportunities in its Hanna and Bantry fields. Enerplus acquired ChevronTexaco's
Bantry Mannville oil pools effective June 30, 2004, including a Sunburst pool
that offers significant development potential. These pools, along with the
Medicine Hat Glauconitic "C" Pool waterflood, contribute significant crude oil
production to the business unit.
  Production
from this business unit for the year ended December 31, 2004 averaged 3,702
bbls/d of crude oil, 33 bbls/d of NGLs and 66.8 MMcf/d of natural gas for a
total of 14,874 BOE/d. The Southern Business Unit's key natural gas producing
properties include Hanna Garden Plains, Bantry, Verger, Countess and Medicine
Hat South, all of which have a large contiguous land base, pipeline
infrastructure and compression and dehydration facilities. The major crude oil
producing properties for this business unit are the previously mentioned Bantry
Mannville oil pools and the Medicine Hat Glauconitic "C" Pool. Both oil
producing areas include emulsion treating and waterhandling facilities. Various
other minor properties contribute to the remainder of this business unit's
production.
  Enerplus
plans to continue shallow natural gas development drilling in 2005, including
higher density drilling within existing producing areas. In 2004 more than 70
wells were drilled in four areas to test the viability of high density drilling,
with encouraging initial results. In addition, delineation of the natural gas
bearing coal beds will continue in 2005 and could offer significant additional
upside to take advantage of the land base and infrastructure. Enerplus also
plans to continue crude oil development of the Medicine Hat Glauconitic "C" Pool
and Bantry Sunburst pool.
  *Eastern
Business Unit*
  The
Eastern Business Unit focuses on waterflood development projects and encompasses
operated properties and lands in eastern Alberta, throughout Saskatchewan and in
western Manitoba (which were acquired from ChevronTexaco on June 30, 2004). This
business unit is predominantly oil weighted with properties producing light
sweet, medium quality and conventional heavy oil. The majority of these oil
properties have well established secondary recovery projects designed to improve
production and enhance recoverable oil reserves. Optimization of these secondary
recovery projects is key to maximizing the value of the assets in this business
unit.
  Production
from this business unit for the year ended December 31, 2004 averaged 11,352
bbls/d of crude oil, 160 bbls/d of NGLs and 10.7 MMcf/d of natural gas for a
total of 13,297 BOE/d. The key properties within this business unit include
Joarcam, Giltedge, Gleneath and the newly-acquired Virden area. Significant
crude oil production installations for emulsion treating and injection or water
disposal are found at Joarcam, Giltedge, Gleneath, Virden, Silver Heights,
Shorncliff, Cadogan and Kessler. In addition, Joarcam also has facilities for
natural gas compression, dehydration and processing.
  Joarcam
is Enerplus' second largest single producing field, producing both light sweet
crude oil and natural gas, and has experienced a significant decrease in the
production decline rate since Enerplus acquired and assumed operatorship of the
property in late 2000. Through a series of optimization and development efforts,
Enerplus has improved the decline rate from approximately 30% per year to
approximately 10% per year.
  The
key waterflood recovery projects in this business unit were further reviewed in
2004 to ensure that they were fully optimized. These reviews provided
opportunities to infill drill, recomplete and restimulate wells to improve
production capability and enhance oil recovery. Development activities for 2005
will build on Enerplus' historical success and continue to focus on improving
and expanding its existing waterfloods to increase production and
recovery.
   - 19
-
  *Central
Business Unit*
  The
Central Business Unit is a mature producing area which covers the west-central
portion of Alberta and provides a variety of production predominantly weighted
to light quality sweet crude oil and liquids rich natural gas. Crude oil
production in this business unit comes from reservoirs with long-life, low
decline production profiles while gas is produced from large reserve natural gas
pools.
  Production
from this business unit for the year ended December 31, 2004 averaged 2,739
bbls/d of crude oil, 1,163 bbls/d of NGLs and 33.4 MMcf/d of natural gas for a
total of 9,473 BOE/d. The Central Business Unit's key producing property is
Pembina 5 Way, a primarily crude oil producing area with significant facilities
for emulsion treating and water injection. Other significant properties within
this business unit include Ferrier, Sylvan Lake, Kaybob South, and Pine
Creek.
  Development
activity during 2004 was targeted at shallow natural gas drilling in Sylvan Lake
and both shallow and deeper tests in Westerose. The Central Business Unit also
commenced an aggressive infill drilling program in the Pembina 5-Way area. This
program is anticipated to continue throughout 2005 pending successful results
from the initial drilling phase.
  *Northern
Business Unit*
  The
Northern Business Unit consists of all Enerplus-operated lands and production in
northwestern Alberta and northeastern British Columbia. This business unit's
production is predominantly natural gas with some light crude oil and NGLs.
Enerplus' acquisition of properties from ChevronTexaco in June 2004 provided the
Northern Business Unit with its largest property at Chinchaga in northern
Alberta, which is expected to account for over 30% of this area's anticipated
2005 total production.
  Two
other key areas are Valhalla, where Enerplus operates compression and
dehydration facilities, and Progress. Other fields in this area include Bonanza,
Pouce Coupe, Firebird and Inga. Production from this business unit for the year
ended December 31, 2004 averaged 1,747 bbls/d of crude oil, 387 bbls/d of NGLs
and 29.2 MMcf/d of natural gas for a total of 6,996 BOE/d.
  During
2004, development activities were directed to improving production through
infill drilling at Progress and Pouce Coupe. In the latter part of the year
considerable activity was directed to enhancing natural gas production at
Chinchaga, including the addition of wellsite compressors, and optimizing
natural gas and oil production in the Firebird area. Natural gas production was
added late in the year from the Dahl and Whitecourt areas through additional
well tie-ins and optimization and reactivations of existing wells.
  Development
activities for 2005 will target oil production enhancement opportunities at
Firebird and Pouce Coupe. Other activities include the development of the Inga
fields in northeastern British Columbia to enhance oil production and to
evaluate additional natural gas potential.
  *Joslyn
Creek Project*
  The
Joslyn Lease is located approximately 60 kilometres north of Fort McMurray in
northern Alberta and contains over 50,000 acres of land and oil sands rights in
the McMurray formation. Deer Creek, the operator of the Project, has been
evaluating and developing the Joslyn Creek Project since 1998 and has developed
a strategy to recover the bitumen located on the Joslyn Lease through
multi-phased SAGD and mining development. In August 2002, Enerplus acquired a
16% working interest in the Joslyn Creek Project from Deer Creek. During 2004, a
number of significant milestones were achieved in the development of the Joslyn
Lease including:
  •
    completion
      of the SAGD Phase I well pair pilot during the third quarter as planned
      with initial non-commercial production rates in line with expectations.
      Enerplus expects production to reach the forecast target rate of 600
      bbls/d gross (96 bbls/d net to Enerplus) in late
2005;
  - 20
-
  
 •
    further
      delineation of both the SAGD and mining resource potential. Another 280
      core holes were drilled in 2004 to further quantify the resource potential
      and define specific project areas within the lease. A majority of these
      were completed in early 2004****with
      the remaining core holes drilled in late 2004 as part of the 2004/2005
      winter core hole program and are currently being
  evaluated;•
    acceleration
      of the Phase II development plans for a 10,000 bbl/d commercial SAGD
      project (1,600 bbls/d net to Enerplus). Over 70% of the facility
      engineering has been completed and construction commenced in January 2005
      with drilling scheduled to begin in mid-2005 and production anticipated to
      commence in 2006;•
    addition
      of 47.7 MMbbls of SAGD-recoverable Probable Reserves of bitumen net to
      Enerplus as presented in the GLJ Report; and•
    initiation
      of the regulatory application for SAGD Phase IIIA, the next 15,000 bbl/d
      expansion, which is expected to begin construction in late 2007. Enerplus
      anticipates that the regulatory application will be filed for SAGD Phase
      IIIA in the first half of 2005, followed closely by the regulatory
      application for a second 15,000 bbl/d expansion (SAGD Phase IIIB), which
      is currently anticipated to occur in 2009.
 
 Enerplus
expects to expend approximately $30 million on the Joslyn Creek Project in
2005.
  **Summary
of Production Locations**
  During
the year ended December 31, 2004, on a BOE basis, 87% of Enerplus' production
was derived from Alberta, 9% from Saskatchewan, 3% from British Columbia and 1%
from Manitoba. The following table describes the major properties in each of
Enerplus' five business units and the average daily production from those
properties during the year ended December 31, 2004:
  **2004
Average Daily Production**
  **Product****Crude
      Oil****Heavy**
    
    **Light
      and**
      **Medium**
    
    **NGLs**
    
    **Natural
      Gas**
    
    **Total****Business
      Unit and Property**
    
    **(bbls/d)**
    
    **(bbls/d)**
    
    **(bbls/d)**
    
    **(Mcf/d)**
    
    **(BOE/d)***Joint
      Venture Business Unit*Mount
      Benjamin
    
    
    -
    
    
    -
    
    
    15
    
    
    10,645
    
    
    **1,789**Elmworth
    
    
    -
    
    
    -
    
    
    373
    
    
    7,306
    
    
    **1,591**Pine
      Creek
    
    
    -
    
    
    -
    
    
    374
    
    
    6,842
    
    
    **1,514**Shackleton
    
    
    -
    
    
    -
    
    
    -
    
    
    8,376
    
    
    **1,396**Mitsue(2)
    
    
    -
    
    
    524
    
    
    59
    
    
    628
    
    
    **688**Bantry(2)
    
    
    107
    
    
    -
    
    
    7
    
    
    3,152
    
    
    **639**Hanlan
    
    
    -
    
    
    -
    
    
    6
    
    
    5,918
    
    
    **992**Verger
    
    
    -
    
    
    -
    
    
    -
    
    
    5,892
    
    
    **982**Hayter
    
    
    910
    
    
    -
    
    
    -
    
    
    48
    
    
    **918**South
      Wapiti
    
    
    -
    
    
    -
    
    
    183
    
    
    4,370
    
    
    **911**Ferrier
    
    
    -
    
    
    47
    
    
    208
    
    
    3,638
    
    
    **861**Basing-Shaw
    
    
    -
    
    
    -
    
    
    6
    
    
    4,123
    
    
    **693**Progress
    
    
    -
    
    
    50
    
    
    56
    
    
    3,154
    
    
    **632**Other
    
    
    695
    
    
    3,677
    
    
    1,368
    
    
    66,859
    
    
    **16,884****Total**
    
    
    **1,712**
    
    
    **4,298**
    
    
    **2,655**
    
    
    **130,951**
    
    
    **30,490**
  - 21
-
  **Product****Crude
      Oil****Heavy**
    
    **Light
      and**
      **Medium**
    
    **NGLs**
    
    **Natural
      Gas**
    
    **Total****Business
      Unit and Property**
    
    **(bbls/d)**
    
    **(bbls/d)**
    
    **(bbls/d)**
    
    **(Mcf/d)**
    
    **(BOE/d)**
 *Southern
      Business Unit*Bantry(2)
    
    
    1,301
    
    
    -
    
    
    -
    
    
    17,791
    
    
    **4,266**Hanna
      Garden
    
    
    -
    
    
    4
    
    
    1
    
    
    13,013
    
    
    **2,174**Medicine
      Hat
    
    
    1,626
    
    
    -
    
    
    -
    
    
    806
    
    
    **1,760**Verger
    
    
    -
    
    
    2
    
    
    -
    
    
    7,188
    
    
    **1,200**Medicine
      Hat South
    
    
    -
    
    
    -
    
    
    -
    
    
    6,768
    
    
    **1,128**Other
    
    
    72
    
    
    697
    
    
    32
    
    
    21,267
    
    
    **4,346**Total
    
    
    **2,999**
    
    
    **703**
    
    
    **33**
    
    
    **66,833**
    
    
    **14,874***Eastern
      Business Unit*Joarcam
    
    
    -
    
    
    2,299
    
    
    121
    
    
    6,276
    
    
    **3,466**Giltedge
    
    
    1,776
    
    
    -
    
    
    -
    
    
    243
    
    
    **1,817**Virden(1)
    
    
    -
    
    
    572
    
    
    -
    
    
    -
    
    
    **572**Gleneath
    
    
    -
    
    
    1,040
    
    
    22
    
    
    444
    
    
    **1,136**Silver
      Heights
    
    
    -
    
    
    823
    
    
    6
    
    
    432
    
    
    **901**Shorncliff
    
    
    819
    
    
    -
    
    
    11
    
    
    123
    
    
    **851**Other
    
    
    770
    
    
    3,253
    
    
    -
    
    
    3,190
    
    
    **4,554**Total
    
    
    **3,365**
    
    
    **7,987**
    
    
    **160**
    
    
    **10,708**
    
    
    **13,297***Central
      Business Unit*Pembina
      5 Way
    
    
    -
    
    
    1,968
    
    
    122
    
    
    1,768
    
    
    **2,385**Pine
      Creek
    
    
    -
    
    
    3
    
    
    195
    
    
    3,793
    
    
    **830**Ferrier
    
    
    -
    
    
    9
    
    
    174
    
    
    3,735
    
    
    **806**Sylvan
      Lake
    
    
    -
    
    
    282
    
    
    101
    
    
    2,046
    
    
    **724**Other
    
    
    -
    
    
    477
    
    
    571
    
    
    22,083
    
    
    **4,728**Total
    
    
    -
    
    
    **2,739**
    
    
    **1,163**
    
    
    **33,425**
    
    
    **9,473***Northern
      Business Unit*Chinchaga(1)
    
    
    -
    
    
    -
    
    
    -
    
    
    8,000
    
    
    **1,333**Valhalla
    
    
    -
    
    
    251
    
    
    85
    
    
    6,861
    
    
    **1,480**Progress
    
    
    -
    
    
    582
    
    
    30
    
    
    2,733
    
    
    **1,068**Other
    
    
    -
    
    
    914
    
    
    272
    
    
    11,580
    
    
    **3,115**Total
    
    
    **-**
    
    
    **1,747**
    
    
    **387**
    
    
    **29,174**
    
    
    **6,996****TOTAL**
    
    
    **8,076**
    
    
    **17,474**
    
    
    **4,398**
    
    
    **271,091**
    
    
    **75,130**
 
 **Notes:**
 (1)
    Acquired
      June 30, 2004. Production from these properties is only included in
      Enerplus' operational results from such date, and accordingly the
      annualized average daily production presented is not indicative of a full
      year of production results from these properties.(2)
    Additional
      interests in this area were acquired by Enerplus on June 30, 2004.
      Production from these properties is only included in Enerplus' operational
      results from such date, and accordingly the annualized average daily
      production as presented is not indicative of a full year of production
      results from these properties.
  - 22
-
  **Oil
and Natural Gas Wells and Unproved Properties**
  The
following table summarizes, as at December 31, 2004, 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
    
    
    3,372
    
    
    1,321.0
    
    
    5,114
    
    
    2,570.9
    
    
    859
    
    
    362.7
    
    
    562
    
    
    236.1
    
    
    710.9
    
    
    308.4Saskatchewan
    
    
    2,303
    
    
    423.8
    
    
    659
    
    
    381.6
    
    
    240
    
    
    34.6
    
    
    19
    
    
    6.4
    
    
    170.8
    
    
    76.8British
      Columbia
    
    
    191
    
    
    21.6
    
    
    121
    
    
    28.1
    
    
    46
    
    
    6.3
    
    
    63
    
    
    14.6
    
    
    112.0
    
    
    46.7Manitoba
    
    
    559
    
    
    302.5
    
    
    -
    
    
    -
    
    
    15
    
    
    7.6
    
    
    -
    
    
    -
    
    
    9.4
    
    
    5.5Joslyn
      Creek Project
    
    
    1
    
    
    0.2
    
    
    -
    
    
    -
    
    
    -
    
    
    -
    
    
    -
    
    
    -
    
    
    24.0
    
    
    3.8Total
    
    
    6,426
    
    
    2,069.1
    
    
    5,894
    
    
    2,980.6
    
    
    1,160
    
    
    411.2
    
    
    644
    
    
    257.1
    
    
    1,027.1
    
    
    441.2
 
 Enerplus
expects its rights to explore, develop and exploit on approximately
88,000 **** net
acres of Unproved Properties to ordinarily expire prior to December 31, 2005.
Enerplus has no material work commitments on such properties and, where Enerplus
determines appropriate, it can continue 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. Higher risk exploration plays and non-core land
are generally farmed out, sold, or exchanged for other interests with more
attractive risk/return characteristics, however Enerplus will participate in
select exploration opportunities. 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 prospects with
attractive exploitation opportunities.
  During
2004, Enerplus participated in the drilling of **** 748
gross wells (367.1 net wells) with a 99% net well success rate. The majority of
Enerplus' drilling activity was in the shallow natural gas areas around Hanna
Garden, Medicine Hat, Verger, Countess and Bantry. **** The
Fund also had active operated drilling and facility programs in oil dominated
areas such as Pembina, Joarcam, Giltedge and Medicine Hat Glauconitic "C". The
Shackleton and Hatton shallow natural gas areas in southwestern Saskatchewan,
the Deep Basin area of northwestern Alberta and the Foothills region of western
Alberta were the focus areas of non-operated drilling activity in 2004. 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, 2004. **** Wells
have been designated as "development" or "exploratory" wells in accordance with
the definitions of such terms in NI 51-101. No "service wells" (as defined in NI
51-101) were drilled in 2004.
  **Development
      Wells**
    
    **Exploratory
      Wells****Category
      of Well**
    
    **Gross**
    
    **Net**
    
    **Gross**
    
    **Net**Crude
      oil wells
    
    
    99
    
    
    41.5
    
    
    1
    
    
    0.3Natural
      gas wells
    
    
    631
    
    
    319.2
    
    
    15
    
    
    5.4Dry
      and abandoned wells
    
    
    1
    
    
    0.2
    
    
    1
    
    
    0.5Total
    
    
    731
    
    
    360.9
    
    
    17
    
    
    6.2
 
 Enerplus
currently intends to focus its development activities in the Western Canadian
Sedimentary Basin although Enerplus also considers acquisitions outside of
Western Canada. **** Enerplus'
development activities are typically funded through debt which may be
subsequently repaid through internally generated cash flow that is withheld by
the Fund's operating subsidiaries from payments made to the Fund, as well as
through the issuance of Trust Units. Enerplus does not anticipate that the costs
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. See "Additional Operational Information - Acquisition and Development
Activities" below.
    - 23
-
   **Quarterly
Production History**
 The
following table sets forth Enerplus' average daily production volumes, on a
company interest basis, **** for
each fiscal quarter in 2004 and for the entire year.
  **Year
      Ended December 31, 2004****First**
      **Quarter**
    
    **Second**
      **Quarter**
    
    **Third**
      **Quarter**
    
    **Fourth**
      **Quarter**
    
    **Total
      for**
      **Year**Crude
      oilLight
      and medium oil (bbls/d)
    
    
    16,363
    
    
    15,960
    
    
    18,383
    
    
    19,159
    
    
    **17,474**Heavy
      oil (bbls/d)
    
    
    6,885
    
    
    6,422
    
    
    9,374
    
    
    9,593
    
    
    **8,076**Total
      crude oil (bbls/d)
    
    
    23,248
    
    
    22,382
    
    
    27,757
    
    
    28,752
    
    
    **25,550**Natural
      gas liquids (bbls/d)
    
    
    4,622
    
    
    4,367
    
    
    4,449
    
    
    4,157
    
    
    **4,398**Total
      liquids (bbls/d)
    
    
    27,870
    
    
    26,749
    
    
    32,206
    
    
    32,909
    
    
    **29,948**Natural
      gas (Mcf/d)
    
    
    262,096
    
    
    251,647
    
    
    277,641
    
    
    292,671
    
    
    **271,091**Total
      (BOE/d)
    
    
    71,553
    
    
    68,690
    
    
    78,480
    
    
    81,688
    
    
    **75,130**
 
 **Quarterly
Netback History**
  The
following tables set forth Enerplus' average netbacks received for each fiscal
quarter in 2004 and for the entire year (excluding any hedging gains or losses).
Netbacks are calculated on the basis of prices received before hedging 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.
  *Light
and Medium Crude Oil ($ per bbl)*
 
 **Year
      Ended December 31, 2004****First**
      **Quarter**
    
    **Second**
      **Quarter**
    
    **Third**
      **Quarter**
    
    **Fourth**
      **Quarter**
    
    **Total
      for**
      **Year**Sales
      price(1)
    
    $
    41.28
    
    $
    45.19
    
    $
    51.36
    
    $
    52.29
    
    $
    47.87Royalties
    
    
    (7.03
    )
    
    (7.64
    )
    
    (8.68
    )
    
    (9.31
    )
    
    (8.23
    )Production
      costs(2)
    
    
    (11.33
    )
    
    (13.99
    )
    
    (12.50
    )
    
    (10.63
    )
    
    (12.06
    )Netback
    
    $
    22.92
    
    $
    23.56
    
    $
    30.18
    
    $
    32.35
    
    $
    27.58
 
 *Heavy
Oil ($ per bbl)*
 
 **Year
      Ended December 31, 2004****First**
      **Quarter**
    
    **Second**
      **Quarter**
    
    **Third**
      **Quarter**
    
    **Fourth**
      **Quarter**
    
    **Total
      for**
      **Year**Sales
      price(1)
    
    $
    30.19
    
    $
    33.50
    
    $
    40.43
    
    $
    34.04
    
    $
    34.98Royalties
    
    
    (5.83
    )
    
    (6.55
    )
    
    (7.25
    )
    
    (6.35
    )
    
    (6.54
    )Production
      costs(2)
    
    
    (8.05
    )
    
    (9.15
    )
    
    (8.07
    )
    
    (8.63
    )
    
    (8.45
    )Netback
    
    $
    16.31
    
    $
    17.80
    
    $
    25.11
    
    $
    19.06
    
    $
    19.99
 
 *Natural
Gas Liquids ($ per bbl)*
 
 **Year
      Ended December 31, 2004****First**
      **Quarter**
    
    **Second**
      **Quarter**
    
    **Third**
      **Quarter**
    
    **Fourth**
      **Quarter**
    
    **Total
      for**
      **Year**Sales
      price(1)
    
    $
    29.73
    
    $
    36.52
    
    $
    41.52
    
    $
    45.46
    
    $
    38.14Royalties
    
    
    (7.15
    )
    
    (9.45
    )
    
    (10.64
    )
    
    (11.50
    )
    
    (9.64
    )Production
      costs(2)
    
    
    -
    
    
    -
    
    
    -
    
    
    -
    
    
    -Netback
    
    $
    22.58
    
    $
    27.07
    
    $
    30.88
    
    $
    33.96
    
    $
    28.50
 
  - 24
-
  *Natural
Gas ($ per Mcf)*
 
 **Year
      Ended December 31, 2004****First**
      **Quarter**
    
    **Second**
      **Quarter**
    
    **Third**
      **Quarter**
    
    **Fourth**
      **Quarter**
    
    **Total
      for**
      **Year**Sales
      price(1)
    
    $
    6.10
    
    $
    7.22
    
    $
    6.39
    
    $
    6.59
    
    $
    6.56Royalties
    
    
    (1.34
    )
    
    (1.56
    )
    
    (1.47
    )
    
    (1.43
    )
    
    (1.44
    )Production
      costs(2)
    
    
    (0.86
    )
    
    (1.03
    )
    
    (0.96
    )
    
    (0.96
    )
    
    (0.95
    )Netback
    
    $
    3.90
    
    $
    4.63
    
    $
    3.96
    
    $
    4.20
    
    $
    4.17
 
 *Total
($ per BOE)*
 
 **Year
      Ended December 31, 2004****First**
      **Quarter**
    
    **Second**
      **Quarter**
    
    **Third**
      **Quarter**
    
    **Fourth**
      **Quarter**
    
    **Total
      for**
      **Year**Sales
      price(1)
    
    $
    36.75
    
    $
    42.49
    
    $
    41.86
    
    $
    42.25
    
    $
    40.90Royalties
    
    
    (7.52
    )
    
    (8.69
    )
    
    (8.68
    )
    
    (8.65
    )
    
    (8.40
    )Production
      costs(2)
    
    
    (6.53
    )
    
    (7.81
    )
    
    (7.34
    )
    
    (6.93
    )
    
    (7.14
    )Netback
    
    $
    22.70
    
    $
    25.99
    
    $
    25.84
    
    $
    26.67
    
    $
    25.36
 
 **Notes:**
 (1)
    Net
      of transportation costs but****before
      hedging.(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
      productions 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 and capital taxes) and other
costs.
   **Abandonment
and Reclamation Costs**
 
 In
connection with its operations, Enerplus will incur abandonment and reclamation
costs for surface leases, wells, facilities and pipelines. Enerplus estimates
such costs through a model that incorporates data from Enerplus' operating
history, a cost formula used by the Alberta Energy Utilities Board and industry
information sources, 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 $384 million on an undiscounted basis and $56 million discounted
at 10%. The calculations of future net revenue under "Oil and Natural Gas
Reserves" **** above
have excluded approximately $203 million on an undiscounted basis and $29
million discounted at 10% as these calculations do not reflect any costs for
abandonment and reclamation for facilities and wells for which no reserves have
been attributed. In the next three financial years, Enerplus anticipates that a
total of approximately $22.5 million on an undiscounted basis and $19.5 million
discounted at 10% will be incurred in respect of abandonment and reclamation
costs.
 
 **Tax
Horizon**
  None
of the Fund or its operating subsidiaries were required to pay income taxes for
the year ended December 31, 2004. See Notes 1(h) and 11 to the Fund's audited
financial statements for the year ended December 31, 2004. Under Enerplus'
current structure and existing tax legislation, annual taxable income is
transferred from its operating entities to the Fund through interest, royalty
and other distribution payments. The Fund, in turn, allocates all of its taxable
income to unitholders through the payment of cash distributions and therefore no
cash income tax is expected to be incurred in the Fund or its operating
subsidiaries.
  **Costs
Incurred**
  In
the financial year ended December 31, 2004, Enerplus expended a total of $636
million on corporate and property acquisitions, as well as $207 million for
development and facilities costs.
    - 25
-
    **Marketing
Arrangements****and Forward Contracts**


**






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 hedging) of $47.87/bbl for its
light and medium crude oil, $34.98/bbl for its heavy crude oil and $38.14/bbl
for its NGLs for the year ended December 31, 2004, compared to $38.66/bbl for
its light and medium crude oil, $28.61/bbl for its heavy crude oil and
$33.43/bbl for its NGLs for the year ended December 31, 2003.




*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 and
sold downstream under long term transportation and sales contracts to a variety
of end users. The entire sales proceeds and transportation costs are pooled and
paid equitable to all supply producers. In 2004, these aggregators contracts
returned a price just slightly lower than the monthly Alberta spot market price.
As well, Enerplus has its own firm transportation commitments to deliver natural
gas into the U.S. midwest (Chicago) area. These contracts comprise 10 MMcf/d on
Foothills and Northern Border pipelines until October 31, 2008; 5 MMcf/d on the
Alliance Pipeline until October 31, 2015; and 5 MMcf/d to Marshfield, Illinois
on the TransCanada and Viking Pipelines 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 2004 revenues attributable to natural gas (net of transportation
costs but before hedging) was 58% compared to 59% in 2003. The average price
received by Enerplus (net of transportation costs but before hedging) for its
natural gas in 2004 was $6.56/Mcf compared to $6.30/Mcf in the year ended
December 31, 2003.




*Future
Commitments and Forward Contracts*




Enerplus
uses various types of financial instruments and fixed price physical sales
contracts to manage the risk related to fluctuating commodity prices. Absent
such hedging activities, all of the crude oil and NGLs and the majority of
natural gas production of Enerplus is sold into the open market at prevailing
spot prices, which exposes Enerplus to the risks associated with commodity price
fluctuations and foreign exchange rates. See "Risk Factors". Information
regarding Enerplus' financial and physical instruments is contained in Note 12
to the Fund's audited annual consolidated financial statements for the year
ended December 31, 2004 and under the headings "Pricing" and "Price Risk
Management" in the Fund's management's discussion and analysis for the year
ended December 31, 2004, each of which is available through the Internet on
Enerplus' SEDAR profile at www.sedar.com.




**Environment,
Health and Safety**




Enerplus
maintains a fully integrated environment, health and safety management system
that assists it in protecting the health and safety of its employees,
contractors and the public, as well as helping to preserve the quality of the
environment.




Enerplus
achieved a Certificate of Recognition in the Partnership Program with Alberta
Human Resources and the Workers' Compensation Board for the first time in 2000.
Enerplus has maintained this certificate through an annual review and an
extensive audit every three years, the last of which was successfully completed
in 2003.




Enerplus
continues to be an active Platinum Level participant (the highest level
attainable) in the Environment, Health and Safety Stewardship Program initiated
by the Canadian Association of Petroleum Producers ("CAPP"). Enerplus monitors
key benchmarks of recordable and lost time injuries for employees and
contractors and consistently outperforms the employee total recordable injury
frequency as measured against CAPP's benchmark







- 26
-





data.
However, in December 2004 Enerplus experienced its first two lost time employee
incidents since 1998. Both employees have since returned to work. Increased
focus on contractor safety during 2004 resulted in significant progress in
reducing contractor injury frequency rates. Contractor total recordable
frequency rates dropped from 3.64 total recordable incidents per 200,000 hours
in 2003 to 1.64 for 2004.




In
support of the environment, health and safety management system, Enerplus
maintains an active well abandonment and site restoration program and a
comprehensive integrity management program for its surface piping, facilities,
storage tanks and underground pipelines. Enerplus applies these programs to its
existing assets and any new assets it may acquire through a detailed due
diligence review as part of the acquisition process. As part of its ongoing
mitigation program in 2004, integrity inspections were conducted on 1,430 (31%)
of Enerplus' pressure vessels and 325 (19%) of its storage tanks. In addition,
over 95% of Enerplus' entire 5,500 kms of field gathering pipeline network is
risk assessed and flow modeled annually. Overall in 2004, Enerplus spent $6
million on its corrosion mitigation program, $4.6 million on site abandonment
and restoration, and $2.7 million on other related environment, health and
safety activities on its operated properties.




**Impact
of Environmental Protection Requirements**




Enerplus
carries out its activities and operations in compliance with all relevant and
applicable environmental regulations and good industry practice. See
"Information Respecting Enerplus Resources Fund - Operations of Enerplus -
Environmental Obligations". At present, Enerplus believes that it meets all
applicable environmental standards and regulations and has included appropriate
amounts in its capital expenditure budget to continue to meet its ongoing
environmental obligations. The costs incurred by Enerplus in respect of
continued environmental compliance and site restoration costs amounted to
approximately 3% of the total development expenditures incurred by Enerplus in
2004. 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, director and officer
liability coverage is also carried for directors and officers of
Enerplus.




*Personnel*




As
at December 31, 2004, Enerplus employed a total of 513 persons.









- 27
-







**INFORMATION
RESPECTING ENERPLUS RESOURCES FUND**


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




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




*General*




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




*Trust
Units and Other Securities of the Fund*




The
Fund is authorized to issue an unlimited number of Trust Units and each Trust
Unit represents an equal undivided beneficial interest in the Fund. All Trust
Units share equally in all distributions from the Fund and in the net assets of
the Fund upon the termination or winding-up of the Fund. Each Trust Unit
entitles the holder thereof to one vote at meetings of unitholders. No
unitholder will be liable to pay any further calls 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, authorities and obligations have been granted to EnerMark in the
Trust Indenture, including the responsibility for the general administration and
management of the day to day affairs and operations of the Fund. Other powers
and responsibilities may be delegated to such other persons as the Fund Trustee
may deem necessary or desirable. See "Responsibilities of and Delegation to
EnerMark" below.




The
Trustee shall be removed by notice in writing delivered by EnerMark to the
Trustee if the Trustee fails to meet certain criteria stated within the Trust
Indenture or with the approval of at least 66 2/3% of the votes cast at a







- 28
-





meeting
of unitholders called for that purpose. The Trustee or any successor may resign
upon 60 days notice to EnerMark. Such resignation or removal shall become
effective upon the acceptance of appointment by a successor trustee. If the
Trustee is removed by EnerMark, EnerMark may appoint a successor trustee. If the
Trustee resigns or is removed by unitholders, its successor must be either
appointed by EnerMark or the unitholders. If a successor trustee does not accept
its appointment as trustee, a court may appoint the successor
trustee.




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




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




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




*Responsibilities
of and Delegation to EnerMark*




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







- 29
-





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




*Certain
Restrictions on Powers of the Trustee and EnerMark*




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




(i)
    amend
      the Trust Indenture (except in certain circumstances described under
      "Amendments to the Trust Indenture" below);(ii)
    sell,
      assign, lease, exchange or otherwise dispose of, or agree to do so, all or
      substantially all of the property and assets of the Fund, other than
      (A) in conjunction with an internal reorganization of the direct or
      indirect assets of the Fund as a result of which the Fund has the same
      direct or indirect interest in such property and assets that it had prior
      to the reorganization, or (B) pursuant to a pledge relating to
      indebtedness of the Fund or its subsidiaries;(iii)
    authorize
      the termination, liquidation or winding-up of the Fund;
  or(iv)
    authorize
      the combination, merger or similar transaction between the Fund and any
      other person that is not an affiliate or associate of the Fund, except in
      connection with an internal reorganization of the Fund and its affiliates
      (but for greater certainty, a take-over bid by or on behalf of the Fund,
      an acquisition by or on behalf of the Fund by way of plan of arrangement
      or the acquisition by the Fund of all or substantially all of the assets
      of another person shall not be subject to the approval of the
      unitholders).





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




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




*Non-Resident
Ownership Provisions*




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







- 30
-





Indenture
also provides that, if at any time EnerMark becomes aware that the number of
Trust Units owned by non-residents exceeds the restricted number of Trust Units
as determined by EnerMark, or that such a situation is imminent, EnerMark, on
behalf of the Fund, will make a public announcement of the situation and will
take steps to ensure no additional Trust Units are issued or transferred to
non-residents, and may require non-residents (generally chosen in the inverse
order of acquisition or registration of the Trust Units) to sell their Trust
Units, or a portion thereof, in order to reduce the level of non-resident
ownership below the determined threshold. The Fund's transfer agent may require
declarations as to residency to effect these provisions.




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




For
additional information regarding non-resident ownership restrictions and
developments, see "General Development of Enerplus Resources Fund - Non-Resident
Ownership Matters and Mutual Fund Trust Status" and "Risk Factors".




*Investments
of the Fund*




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




*Distributions
of Distributable Income*




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




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




Once
a distribution record date has been set, the Fund must declare the amount of
distributable income and net realized capital gains, if any, that will be
distributed on or before that date and may pay out the distribution on the
corresponding distribution payment date. The Trust Indenture provides that
EnerMark, on behalf of the Fund and







- 31
-





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




*Meetings
of Unitholders and Voting*




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




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




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




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




*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:




(a)
    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





- 32
-










(b)
    the
      closing market price on the principal market on which the Trust Units are
      quoted for trading, on the date that the Trust Units were so tendered for
      redemption.





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




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




*Repurchase
of Trust Units*




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




*Term
and Termination of the* *Fund*




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




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




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.









- 33
-







*Reporting
to Unitholders*


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




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




*Auditors*




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




*Amendments
to the Trust Indenture*




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




(a)
    ensuring
      that the Fund will comply with any applicable laws or requirements of any
      governmental agency or authority of Canada or of any
    province;(b)
    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;(c)
    ensuring
      that such additional protection is provided for the interests of
      unitholders as the Trustee or EnerMark may consider
    expedient;(d)
    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;(e)
    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;(f)
    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





- 34
-










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






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




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




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




*Royalty
Agreements*




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




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




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




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




*Unsecured,
Subordinated Promissory Note of EnerMark*




EnerMark
has issued an unsecured, subordinated promissory note to the Fund. The
subordinated note bears interest at an annual rate of 8% and the principal
amount of the note varies as additional funds (generally from the issuance







- 35
-





of
Trust Units) are loaned from the Fund to EnerMark and principal repayments are
made on the note. The maturity date of the note is June 21, 2015. The payment of
principal and interest on the note 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 note. The Fund has entered
into a subordination agreement pursuant to which the payment to the Fund by
EnerMark of obligations under the subordinated note is subordinated and will
rank junior to the indebtedness of EnerMark to its lenders and the holders of
its senior unsecured notes.




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




As
stated above, the terms of the existing royalty agreements and the promissory
note issued by EnerMark to the Fund, together with the subordination agreements
entered into by the Fund and the terms of EnerMark's credit facilities and
senior notes, result in the royalty, interest, distribution and dividend
payments from the Fund's operating subsidiaries to the Fund being subordinate to
payments made, or required to be made, on indebtedness to third parties. As a
result, royalty, interest, distribution and dividend payments from EnerMark,
ERC, Enerplus Oil & Gas and ECT 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 2004 Annual Report **** and
under the heading "Statement of Corporate Governance Practices" in the Fund's
information circular and proxy statement dated February 24, 2005. Enerplus fully
complies with the provisions of Multilateral Instrument 52-109 - "Certification
of Disclosure in Issuer's Annual and Interim Filings" and Multilateral
Instrument 52-110 - "Audit Committees" adopted by the Canadian Securities
Administrators and intends to fully comply with all other securities regulatory
or stock exchange requirements relating to corporate governance. As mentioned
above, all governance and management functions for Enerplus are contained within
the Fund's wholly-owned operating subsidiary, EnerMark.




**Unitholder
Rights Plan**




On
March 5, 1999, the Fund entered into a Unitholder Rights Plan Agreement
(the "Rights Plan") with CIBC Mellon Trust Company, as Rights Agent, which was
approved by Enerplus' unitholders on April 23, 1999 and was renewed for an
additional three years by the Enerplus unitholders at the 2002 annual general
and special meeting of unitholders. The Rights Plan is proposed to be renewed
for an additional three years, through 2008, pending receipt of Enerplus
unitholder approval at the annual general and special meeting of unitholders to
be held on April 12, 2005. The Rights Plan generally provides that following any
person or entity acquiring 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
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 existing Rights Plan is
available through the Internet on Enerplus' SEDAR profile at www.sedar.com, as
it was filed as a "Security holders document" on February 25, 2005, and if
approved at the 2005 unitholder meeting, a copy of the renewed Rights Plan will
be similarly filed on Enerplus' SEDAR profile.




****







- 36
-







DEBT OF ENERPLUS





The
Fund may, with the approval of the board of directors of EnerMark, borrow, incur
indebtedness, give any guarantee or enter into any subordination agreement on
behalf of the Fund, or pledge or provide any security interest or encumbrance on
any property of the Fund. At present, all indebtedness of Enerplus is incurred
directly by its primary operating subsidiary, EnerMark. As at December 31, 2004,
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**




In
November 2004, EnerMark finalized the new $850 million Bank Credit Facility. The
Bank Credit Facility is an unsecured, covenant-based three year committed credit
agreement with nine North American banks. As at December 31, 2004, $251.7
million was outstanding under this facility. This bank debt carries floating
interest rates that Enerplus expects to range between 65 and 87.5 basis points
over bankers' acceptance rates, depending on Enerplus' ratio of Consolidated
Senior Debt to Consolidated EBITDA (each as defined below).




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




•
    the
      ratio of Consolidated Senior Debt to Consolidated EBITDA at the end of any
      fiscal quarter shall not exceed 3:1, except that upon the completion of a
      Material Acquisition (as defined below), and for a period extending to the
      end of the second full quarter thereafter, this limit increases to
      3.5:1;•
    the
      ratio of Consolidated Total Debt (as defined below) to Consolidated EBITDA
      at the end of any fiscal quarter shall not exceed 4:1;
  and•
    the
      ratio of Consolidated Senior Debt to Total Capitalization (as defined
      below) shall not exceed 50%, except that upon the completion of a Material
      Acquisition, and for a period extending to the end of the second full
      quarter thereafter, this limit increases to
55%.





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




Consolidated
      EBITDA:
    The
      aggregate of the last four quarters' net income plus the sum
      of:•
    interest
      expense;•
    all
      provisions for federal, provincial or other income and capital
      taxes;•
    depletion,
      depreciation, amortization and accretion; and•
    other
      non-cash amounts.Consolidated
      Senior Debt:
    All
      indebtedness and obligations in respect of amounts borrowed excluding
      Subordinated Debt.Consolidated
      Total Debt:
    The
      aggregate of Consolidated Senior Debt and Subordinated
    Debt.Material
      Acquisition:
    An
      acquisition or series of acquisitions which increases the tangible assets
      of Enerplus by more than 5%





- 37
-








Subordinated
      Debt:
    Debt
      which, by its terms, is subordinated to the Bank Credit facility (but
      excludes convertible debentures which allow the Fund to issue Trust Units
      or other securities of the Fund in satisfaction of interest or
      principal).Total
      Capitalization:
    The
      aggregate of Consolidated Senior Debt and the Fund's unitholders' equity
      (calculated in accordance with GAAP as shown on the Fund's consolidated
      balance sheet).






**Senior
Unsecured Notes**




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




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





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




•
    the
      ratio of Consolidated EBITDA (as defined below) for the four immediately
      preceding fiscal quarters to consolidated interest expense shall be not
      less than 4.0 to 1.0;•
    Consolidated
      Debt (as defined below) is limited to 60% of the present value of
      Enerplus' Proved Reserves (discounted at 10% and based on forecast prices
      and costs); and•
    the
      ratio of Consolidated Debt to Consolidated EBITDA for each period of four
      consecutive fiscal quarters shall not exceed 3.0 to 1.0, but is permitted
      to be up to 3.5 to 1.0 for a maximum of six
months.





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




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




Additional
information regarding EnerMark's debt arrangements is contained in Note 8 to the
Fund's audited annual consolidated financial statements for the year ended
December 31, 2004 and under the heading "Liquidity and Capital Resources" in
Enerplus' management discussion and analysis for the year ended December 31,
2004.







- 38
-





Notwithstanding
that it is unsecured, the indebtedness of Enerplus to its lenders and senior
noteholders ranks senior to and is in priority to the royalty, interest,
distribution and dividend payments that are made to the Fund by its operating
subsidiaries, and therefore ahead of distributions from the Fund to its
unitholders. See "Information Respecting Enerplus Resources Fund - Description
of the Royalty Agreements and Subordinated Notes" and "Risk
Factors".




**DISTRIBUTIONS
TO UNITHOLDERS**




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




**Distributable
Income**




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




The
amount of cash flow paid to the Fund from its operating subsidiaries, and the
amount of cash distributions subsequently paid by the Fund to unitholders,
depends on numerous factors including the operating entities' financial
performance, debt covenants and obligations, working capital requirements and
future capital requirements. Such amounts are, in part, subject to the
discretion of the board of directors of EnerMark, which regularly evaluates the
Fund's distribution payout with respect to anticipated cash flows, debt levels,
capital expenditures plans and amounts to be retained to fund acquisitions and
expenditures. The level of cash retained has typically varied between 10% and
30% of Enerplus' total annual cash flow. For the year ended December 31, 2004,
approximately 21% of the cash available for distribution was
retained.




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




**Distribution
History**




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




The
cash flow available for distribution can vary significantly from period to
period for a number of reasons, including fluctuations in: (1) the sales price
that Enerplus realizes for its oil and natural gas production (after hedging
contract receipts and payments), (2) the quantity of oil and natural gas that
Enerplus produces, (3) the cost to produce oil and natural gas and administer
the Fund and its subsidiaries, (4) the amount of cash retained for debt service
or repayment or to fund capital expenditures, and (5) foreign currency exchange
rates and interest rates. In addition, the level of distributions per Trust Unit
will be affected by the number of outstanding Trust Units.







- 39
-





The
following cash distributions have been paid by Enerplus to its unitholders since
the beginning of 2002:




**Month
      of Record**
    
    **Cash
      Distribution Per Trust Unit****and
      Payment Date**
    
    **2005**
    
    **2004**
    
    **2003**
    
    **2002**January(1)
    
    $
    0.35
    
    $
    0.35
    
    $
    0.30
    
    $
    0.30February
    
    $
    0.35
    
    $
    0.35
    
    $
    0.32
    
    $
    0.25March
    
    
    N/A
    
    $
    0.35
    
    $
    0.35
    
    $
    0.20April
    
    
    N/A
    
    $
    0.35
    
    $
    0.35
    
    $
    0.20May
    
    
    N/A
    
    $
    0.35
    
    $
    0.37
    
    $
    0.28June
    
    
    N/A
    
    $
    0.35
    
    $
    0.37
    
    $
    0.28July
    
    
    N/A
    
    $
    0.35
    
    $
    0.37
    
    $
    0.28August
    
    
    N/A
    
    $
    0.35
    
    $
    0.37
    
    $
    0.28September
    
    
    N/A
    
    $
    0.35
    
    $
    0.37
    
    $
    0.28October
    
    
    N/A
    
    $
    0.35
    
    $
    0.37
    
    $
    0.30November
    
    
    N/A
    
    $
    0.35
    
    $
    0.35
    
    $
    0.30December
    
    
    N/A
    
    $
    0.35
    
    $
    0.35
    
    $
    0.30





**Note:**


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


****


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




**U.S.
Tax Reporting Matters**




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




Based
upon the computation of current and accumulated earnings and profit in
accordance with U.S. federal income tax principles, 94% of the distributions
paid by the Fund during 2004 should be considered to be dividends. Under the
Jobs and Growth Tax Relief Reconciliation Act of 2003 (P.L. 108-27, 117 Stat.
752), the dividend portion of Enerplus’ 2004 distribution should be considered
"Qualified Dividends" eligible for the reduced rate of tax applicable to long
term capital gains.













****







- 40
-







INDUSTRY CONDITIONS




The
oil and natural gas industry is subject to extensive controls and regulation
imposed by various levels of government. Regulatory approvals must be obtained
before drilling wells or constructing facilities. Failure to obtain such
approvals on a timely basis could result in delays or abandonment of projects
and increased costs. Although it is not expected that any of these controls or
regulations will affect Enerplus' operations in a manner materially different
than they would affect other Canadian oil and gas issuers of similar size, the
controls and regulations 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 in western
Canada.




**Pricing
and Marketing - Oil**




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




**Pricing
and Marketing - Natural Gas**




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




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




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




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




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.







- 41
-





**Provincial
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. 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.




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 and would
increase the net income and funds from operations of such
producers.




*Alberta*




Conventional
Oil and Gas Operations




Regulations
made pursuant to the *Mines
and Minerals Act* (Alberta) provide various incentives for exploring and developing oil reserves
in Alberta. Oil produced from horizontal extensions commenced at least five
years after the well was originally spudded may also qualify for a royalty
reduction. A 24 month, 8,000 cubic metre exemption is available for production
from a well that has not produced for a 12 month period, if resuming production
after February 1, 1993. Additionally, oil production from eligible new field and
new pool wildcat wells and deeper pool test wells spudded or deepened after
September 30, 1992 is entitled to a 12 month royalty exemption (to a maximum of
$1 million). Oil produced from low productivity wells, enhanced recovery schemes
(such as injection wells) and experimental projects is also subject to royalty
reductions.




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 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







- 42
-





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.




Oil
Sands Operations




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 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* (''EPEA''). 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.




Additionally,
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.




The
Province of Alberta imposes royalties of varying rates on the production of
crude oil from lands in which it owns the mineral rights. Alberta's current
royalty system for oil sands, introduced in September 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.




*British
Columbia*




In
British Columbia, the amount payable as a royalty in respect of oil depends on
the vintage of the oil, the type of oil, the quantity of oil produced in a month
and the value of the oil. Generally, the age of oil is based on whether the oil
is produced from a pool discovered before October 31, 1975 (old oil), between
October 31, 1975 and June 1, 1998 (new oil), or after June 1, 1998 (third tier
oil). The formula applied to determine the royalty payable results in higher
royalty rates as well production increases. The royalty rate on old oil is
between 0% and 35%, on new oil is between 0% and 25%, and on third tier oil is
between 0% and 15%. **** Oil
produced from newly discovered pools may be exempt from the payment of a royalty
for the first 36 months of production. The royalty payable on 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. 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 a
minimum of 8%. The royalty payable on non-conservation natural gas varies
between a minimum of 9% and 15% depending on when the well was spudded and when
the oil and gas rights were issued.




There
are a number of recent incentive announcements by the British Columbia
government including reduced royalty rates for low productivity natural gas
wells, royalty credits for deep gas exploration, royalty credits in exchange for
the construction of access roads and royalty credits for summer drilling, all of
which will reduce the royalties payable.







- 43
-





*Saskatchewan*




In
Saskatchewan, the amount payable as a royalty in respect of oil depends on the
vintage of the oil, the type of oil, the quantity of oil produced in a month and
the value of the oil. The royalty rate payable for old oil is between 20% and
45%, and for new oil and third tier oil is between 10% and 35%. The royalty
payable on natural gas in Saskatchewan 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 quantity produced in a given month, the
type of natural gas and the vintage of the natural gas. 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 rate payable for old gas is between 20% and 45%, and
for new gas and third tier gas is between 15% and 35%.




Effective
October 1, 2002, the Saskatchewan government revised its fiscal regime for the
oil and gas industry. Some royalties on wells existing as of that date will
remain unchanged and will therefore be subject to various periods of royalty/tax
deduction. The changes include new lower royalty and tax structures applicable
to both oil, natural gas and associated natural gas (natural gas produced from
oil wells), a new system of volume incentives and a reduced corporation capital
tax resource surcharge rate.




The
new fiscal regime for the Saskatchewan oil and gas industry provides an
incentive to encourage exploration and development through a revised royalty/tax
structure for oil and natural gas wells with a finished drilling date on or
after October 1, 2002 or incremental oil production due to a new or expanded
waterflood project with a commencement date on or after October 1, 2002. This
"fourth tier" Crown royalty rate, applicable to both oil and natural gas, is
price sensitive and ranges from a minimum 5% at a base price to a maximum of 30%
at a price above the base price. A fourth tier freehold tax structure,
calculated by subtracting a production tax factor of 12.5 percentage points from
the corresponding Crown royalty rates, has also been created which is applicable
to conventional oil, incremental oil from new or expanded waterfloods and
natural gas. The fourth tier royalty/tax structure is also applicable in respect
of associated natural gas that is gathered for use or sale which is produced
either from oil wells with a finished drilling date on or after October 1, 2002
and oil wells with a finished drilling date prior to October 1, 2002, where the
individual oil well has a gas-oil production ratio in any month of more than
3,500 cubic metres of natural gas per cubic metre of oil. In addition,
volume-based royalty/tax reduction incentives have been changed such that a
maximum royalty of 2.5% now applies to various volumes of both oil and natural
gas, depending on the depth and nature of the well (up to 16,000 cubic metres of
oil in the case of deep exploratory wells and 25,000 cubic metres of natural gas
produced from exploratory wells). The royalty/tax category with respect to
re-entry and short sectional horizontal oil wells has been eliminated such that
all horizontal oil wells with a finished drilling date on or after October 1,
2002 will receive fourth tier royalty/tax rates and incentive volumes. Further
changes include the reduction of the corporation capital tax resource surcharge
rate from 3.6% to 2.0% and, subject to certain restrictions, the expansion of
the deep oil well definition to include oil wells producing from a zone deeper
than 1,700 meters.




**Land
Tenure**




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




Oil
produced from oil sands owned by the Province of Alberta is produced under
provincial Crown oil sands leases. While such leases may historically have had
initial terms which varied in length, continuations beyond the initial terms are
now subject to standardized criteria as provided for in the *Oil
Sands Tenure Regulation* (Alberta). A lease may generally be continued after the initial term provided
certain minimum levels of exploration or production have been achieved and all
lease rentals (including escalating rentals) have been timely paid, subject to
certain exceptions.







- 44
-





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.
Compliance with such legislation can require significant expenditures. A breach
of such legislation may result in the imposition of material fines and
penalties, the revocation of necessary licenses and authorizations and civil
liability for pollution damage.




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




In
1994, the United Nations' Framework Convention on Climate Change came into force
and three years later led to the Kyoto Protocol which requires participating
countries, upon ratification, to reduce their emissions of carbon dioxide and
other greenhouse gases. Canada ratified the Kyoto Protocol in late 2002. The
upstream Canadian oil and gas sector is in discussions with various federal and
provincial levels of government regarding the development of green house gas
regulations for the industry. Although the Canadian federal government has not
released details of any implementation plan, it has stated that it intends to
limit the emission reduction targets for the industry and regulate the cost of
emission credits, which could result in increased capital expenditures and
operating costs.




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.







- 45
-





**RISK
FACTORS**




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




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




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




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




•
    global
      energy policy, including the ability of OPEC to set and maintain
      production levels and prices for oil;•
    political
      conditions, including the risk of hostilities in the Middle
      East;•
    currency
      fluctuations;•
    global
      and domestic economic conditions;•
    weather
      conditions;•
    the
      supply and price of imported oil and liquefied natural
  gas;•
    the
      production and storage levels of North American natural
    gas;•
    the
      level of consumer demand;•
    the
      price and availability of alternative fuels;•
    the
      proximity of reserves to, and capacity of, transportation
      facilities;•
    the
      effect of world-wide energy conservation measures; and•
    government
      regulations.





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




Enerplus
uses financial derivative instruments and other hedging mechanisms to try to
limit a portion of the adverse effects resulting from volatility in natural gas
and oil commodity prices. To the extent Enerplus hedges its commodity price
exposure, it may forego the benefits it would otherwise experience if commodity
prices were to increase. In addition, Enerplus' commodity hedging activities
could expose it to losses. These losses could occur







- 46
-





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,
reclamation and abandonment and labour costs are a few of Enerplus' operating
costs that are susceptible to material fluctuation.




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




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




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




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




***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 United States dollar price. Currently, Enerplus does not engage in
significant risk management activities related to foreign exchange rates, with
the exception of the cross-currency swap associated with the US$175 million of
senior unsecured notes issued by EnerMark in June 2002, as described in Note
8(b) to the Fund's audited consolidated financial statements for the year ended
December 31, 2004.







- 47
-





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




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




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




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




•
    historical
      production in the area compared with production rates from similar
      producing areas;•
    future
      commodity prices, production and development costs, royalties and capital
      expenditures;•
    initial
      production rates;•
    production
      decline rates;•
    ultimate
      recovery of reserves;•
    success
      of future exploitation activities;•
    marketability
      of production;•
    effects
      of government regulation; and•
    other
      government levies that may be imposed over the producing life of
      reserves.





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




Estimates
with respect to reserves that may be developed and produced in the future
(particularly oil sands reserves) are often based upon volumetric calculations
and upon analogy to similar types of reserves, rather than upon actual







- 48
-





production
history. Estimates based on these methods generally are less reliable than those
based on actual production history. Subsequent evaluation of the same reserves
based upon production history may result in variations in the estimated
reserves.




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




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




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




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




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




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




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




The
continuing production from a property, and to some extent the marketing of that
production, is dependent upon the ability of the operators of Enerplus'
properties. Approximately 40% of Enerplus' daily production is from properties
operated by third parties. To the extent a third-party operator fails to perform
these duties properly or becomes insolvent, Enerplus' cash flow may be reduced.
Third party operators also make estimates of future capital expenditures more
difficult.




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




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







- 49
-





***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 $US175 million of its
U.S. dollar denominated senior unsecured notes with fixed interest rates into
Canadian dollar denominated floating rate debt. **** Variations
in interest rates and scheduled principal repayments could result in significant
changes to the amount of the cash flows required to be applied by the operating
subsidiaries to their debt before payment of any amounts by them to the Fund.
The agreements governing this credit facility and the senior unsecured notes
each stipulate that if Enerplus is in default or fails to comply with certain
covenants, the Fund's ability to make distributions to unitholders may be
restricted. In addition, the Fund's right to receive payments from its operating
subsidiaries is expressly subordinated to the rights of the lenders under the
credit facility and the holders of the senior unsecured notes. See "Debt of
Enerplus".




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




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




***The
Joslyn Creek Project is an early development stage and is subject to numerous
risks.***




The
Joslyn Creek Project is currently in the development stage. There is a risk that
the Joslyn Creek Project will not be completed on time or on budget or at all.
Additionally, there is a risk that the Joslyn Creek 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 Creek
      Project to successfully proceed;•
    labour
      disputes, disruptions or declines in productivity;•
    increases
      in materials or labour costs;•
    inability
      to attract sufficient numbers of qualified workers;•
    delays
      in obtaining, or conditions imposed by, regulatory
    approvals;•
    changes
      in Project scope;





- 50
-










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





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




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




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




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




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




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




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.







- 51
-





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




The
oil and gas industry in Canada, including the oil sands industry, operates under
federal, provincial 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), the imposition of specific drilling
obligations, environmental protection controls, control over the development and
abandonment of fields and mine sites (including restrictions on production) and
possibly expropriation or cancellation of contract rights. See "Industry
Conditions".




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




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




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




***If
Enerplus expands operations beyond oil and natural gas production in western
Canada, 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 gas
production and development in the Western Canadian Sedimentary Basin, together
with its participation in the development of oil sands reserves in the Joslyn
Creek Project. In the future, Enerplus may acquire oil and natural gas
properties 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. 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 wells to a gathering
system;





- 52
-










•
    blowouts
      or other accidents;•
    adjustments
      for prior periods;•
    recovery
      by the operator of expenses incurred in the operation of the properties;
      or•
    the
      establishment by the operator of reserves for these
    expenses.





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




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




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




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




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




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




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




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




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




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




From
time to time, Enerplus conducts title reviews in accordance with industry
practice prior to purchases of resource assets. However, if conducted, these
reviews do not guarantee that an unforeseen defect in the chain of title will
not arise and defeat Enerplus' title to the purchased assets. If this type of
defect were to occur, Enerplus'







- 53
-





entitlement
to the production and reserves from the purchased assets could be jeopardized
and, as a result, distributions to unitholders may be reduced.




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




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




Income
tax laws, or other laws or government incentive programs relating to the oil and
gas industry, such as the treatment of mutual fund trusts and resource
allowance, may in the future be changed or interpreted in a manner that
adversely affects the Fund and its unitholders. For instance, certain proposed
amendments to the Tax Act announced in the Canadian federal government's 2004
budget (which are currently suspended pending further consultation) may affect
the taxation of income trusts or the permitted amount of non-Canadian resident
ownership of the Trust Units. See "General Development of Enerplus Resources
Fund - Update on Mutual Fund Trust Status and Taxation Matters".




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 New York Stock Exchange. 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
Toronto Stock Exchange and non-residents of Canada would continue to be able to
sell their Trust Units on that Exchange. There can be no assurance that such
circumstances would not detrimentally affect the market price of the Trust
Units. See "Description of the Trust Units and the Trust Indenture -
Non-Resident Ownership Provisions."




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




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




Enerplus
intends that the Fund will continue to qualify as a mutual fund trust for
purposes of the Tax Act. The Fund may not, however, always be able to satisfy
any future requirements for the maintenance of mutual fund trust status. See "--
Changes in tax and other laws may adversely affect unitholders" above and
"General Development of Enerplus Resources Fund - Update on Mutual Fund Trust
Status and Taxation Matters". 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.





- 54
-










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




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




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




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







- 55
-





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




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




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







- 56
-





were
ultimately determined to be a passive foreign investment company. United States
unitholders are strongly urged to consult their own tax advisors regarding the
United States federal income tax consequences of Enerplus' possible
classification as a passive foreign investment company and the consequences of
such classification.




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




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




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




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









- 57
-







**MARKET
FOR SECURITIES**


The
Trust Units are listed and posted for trading on the Toronto Stock Exchange (the
"TSX") and the New York Stock Exchange (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 2004.




**Month**
    
    **High**
    
    **Low**
    
    **Close**
    
    **Volume**January
    
    $
    40.00
    
    $
    35.70
    
    $
    37.72
    
    
    3,824,125February
    
    
    40.40
    
    
    34.50
    
    
    39.93
    
    
    4,146,791March
    
    
    41.48
    
    
    35.50
    
    
    38.44
    
    
    6,453,331April
    
    
    39.30
    
    
    32.73
    
    
    34.87
    
    
    5,470,719May
    
    
    36.22
    
    
    32.75
    
    
    34.64
    
    
    4,145,856June
    
    
    39.14
    
    
    34.62
    
    
    37.86
    
    
    7,688,645July
    
    
    39.65
    
    
    37.48
    
    
    39.65
    
    
    2,877,564August
    
    
    40.25
    
    
    37.34
    
    
    38.88
    
    
    2,981,325September
    
    
    42.08
    
    
    38.04
    
    
    41.19
    
    
    4,221,920October
    
    
    44.10
    
    
    38.60
    
    
    39.82
    
    
    4,066,684November
    
    
    42.17
    
    
    38.07
    
    
    41.88
    
    
    3,756,802December
    
    
    44.54
    
    
    39.05
    
    
    43.60
    
    
    3,727,625





The
following table sets forth certain trading information for the Trust Units on
the NYSE in 2004.




**Month**
    
    **High**
    
    **Low**
    
    **Close**
    
    **Volume**January
    
    US$
    31.45
    
    US$
    27.01
    
    US$
    28.40
    
    
    5,869,200February
    
    
    30.21
    
    
    25.80
    
    
    29.98
    
    
    5,197,700March
    
    
    31.02
    
    
    26.66
    
    
    29.31
    
    
    6,949,800April
    
    
    29.91
    
    
    24.25
    
    
    25.25
    
    
    8,277,100May
    
    
    26.05
    
    
    23.65
    
    
    25.43
    
    
    5,044,500June
    
    
    29.09
    
    
    25.35
    
    
    28.46
    
    
    8,404,500July
    
    
    29.79
    
    
    28.44
    
    
    29.63
    
    
    3,561,800August
    
    
    30.54
    
    
    28.58
    
    
    29.63
    
    
    4,419,200September
    
    
    33.03
    
    
    29.68
    
    
    32.52
    
    
    3,960,400October
    
    
    35.09
    
    
    30.51
    
    
    32.70
    
    
    6,285,700November
    
    
    35.49
    
    
    31.59
    
    
    35.35
    
    
    4,839,000December
    
    
    36.44
    
    
    32.75
    
    
    36.31
    
    
    4,761,300








- 58
-





**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(9)Edwin
      Dodge(3)(4)
      Calgary,
      Alberta, Canada
    
    May
      2004
    
    Corporate
      director since 2004. Prior thereto Chief Operating Officer of Canadian
      Pacific Railway Limited ("CPR") (a public Canadian national rail company)
      since 2001. Prior thereto, various senior roles with CPR and its
      predecessors.Gordon
      J. Kerr(9)
      Calgary,
      Alberta, Canada
    
    May
      2001
    
    President
      and Chief Executive Officer of Enerplus since May 2001 (and Chief
      Financial Officer of Enerplus until December 2001). Prior thereto,
      Executive Vice President and Chief Financial Officer of Enerplus since
      January 2001. Prior thereto, Senior Vice President, Financial Services of
      Enerplus since September 2000. Prior thereto, Vice President, Finance and
      Chief Financial Officer of Enerplus since 1998.Douglas
      R. Martin(1)(4)(6)
      Calgary,
      Alberta, Canada
    
    July
      2000
    
    President
      of Charles Avenue Capital Corp. (a private merchant banking company) since
      April 2000. Prior thereto, Chairman of the Board of Pursuit Resources
      Corp. (an oil and natural gas exploration and production
      company).Robert
      Normand(2)(4)(7)
      Rosemere,
      Québec, Canada
    
    June
      2001
    
    Corporate
      director.Glen
      Roane(2)(5)
      Canmore,
      Alberta, Canada
    
    June
      2004
    
    Corporate
      director.Eric
      P. Tremblay(9)(10)
      Calgary,
      Alberta, Canada
    
    January
      2001
    
    Senior
      Vice President, Capital Markets of Enerplus since September 2000. Prior
      thereto, Senior Vice President, Corporate Development of Enerplus since
      January 2000. Prior thereto, Vice President, Corporate Development of
      Enerplus since 1996.Donald
      T. West(5)
      Calgary,
      Alberta, Canada
    
    April
      2003
    
    Businessman
      since October 1999. Prior thereto, President and Chief Executive Officer
      of Rigel Energy Corporation (an oil and natural gas exploration and
      production company).Harry
      B. Wheeler(2)(5)
      Calgary,
      Alberta, Canada
    
    January
      2001
    
    President
      of Colchester Investments Ltd. (a private investment firm) since January
      2001. Prior thereto, Chairman of the Board of Cabre Exploration Ltd. (an
      oil and natural gas exploration and production
company).Robert
      L. Zorich(3)(8)
      Houston,
      Texas, USA
    
    January
      2001
    
    Managing
      Director of EnCap Investments L.P. (a private firm that provides private
      equity financing to the oil and gas
industry).





**Notes:**


(1)
    Chairman
      of the board of directors and*ex
      officio*member of all committees of the board of directors.(2)
    The
      Audit and Risk Management Committee is comprised of Robert Normand as
      Chairman, Harry B. Wheeler and Glen Roane.(3)
    The
      Corporate Governance, Nominating and Environment, Health & Safety
      Committee is comprised of Robert L. Zorich as Chairman and Edwin
      Dodge.(4)
    The
      Compensation and Human Resources Committee is comprised of Douglas R.
      Martin as Chairman, Robert Normand and Edwin Dodge.(5)
    The
      Reserves Committee is comprised of Harry B. Wheeler as Chairman, Donald T.
      West and Glen Roane.





- 59
-








(6)
    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.(7)
    Mr.
      Normand served as a director of Concert Industries Ltd. ("Concert") when
      it and its Canadian operating subsidiaries announced on August 5, 2003
      that it had filed for protection under the*Companies'
      Creditors Arrangement Act*("CCAA"). Concert was restructured and a plan of compromise and
      arrangement for its operating subsidiaries was approved in December 2004
      allowing them to emerge from the CCAA proceedings. Mr. Normand no longer
      serves as a director of Concert.(8)
    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.(9)
    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.(10)
    Mr.
      Tremblay is not standing for re-election as a director at the 2005 annual
      general and special meeting of Enerplus unitholders to be held on April
      12, 2005.






**Officers
of EnerMark**




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




**Name
      and Residence**
    
    **Office**
    
    Principal
      Occupation for Past Five Years(1)Gordon
      J. Kerr
      Calgary,
      Alberta, Canada
    
    President
      and Chief Executive Officer
    
    President
      and Chief Executive Officer of Enerplus since May 2001 (and Chief
      Financial Officer of Enerplus until December 2001). Prior thereto,
      Executive Vice President and Chief Financial Officer of Enerplus since
      January 2001. Prior thereto, Senior Vice President, Financial Services of
      Enerplus since September 2000. Prior thereto, Vice President, Finance and
      Chief Financial Officer of Enerplus since 1998.Heather
      J. Culbert
      Calgary,
      Alberta, Canada
    
    Senior
      Vice President, Corporate Services
    
    Senior
      Vice President, Corporate Services of Enerplus since March 2001. Prior
      thereto, Vice President, Management Information Systems &
      Administration of Enerplus since 1996.Ian
      C. Dundas
      Calgary,
      Alberta, Canada
    
    Senior
      Vice President, Business Development
    
    Senior
      Vice President, Business Development since July 2004. Prior thereto, Vice
      President and Director, Business Development of Enerplus since February
      2003. Prior thereto, Vice President of EGEM since August 2001. Prior
      thereto, Chief Financial Officer of Medmira Inc., (a public biotechnology
      company) since 1999.Garry
      A. Tanner
      Calgary,
      Alberta, Canada
    
    Senior
      Vice President and Chief Operating Officer
    
    Senior
      Vice President and Chief Operating Officer of Enerplus since February
      2003. Prior thereto, Senior Vice President, New Business Development of
      EGEM since August 2001 (in addition to Senior Vice President of El Paso
      Merchant Energy (a merchant trading company) since October 2000). Prior
      thereto, Senior Vice President of EnCap Investments L.L.C. (a private firm
      that provides private equity financing to the oil and gas industry) since
      1997.Eric
      P. Tremblay
      Calgary,
      Alberta, Canada
    
    Senior
      Vice President, Capital Markets
    
    Senior
      Vice President, Capital Markets of Enerplus since September 2000. Prior
      thereto, Senior Vice President, Corporate Development of Enerplus since
      January 2000. Prior thereto, Vice President, Corporate Development of
      Enerplus since 1996.





- 60
-








**Name
      and Residence**
    
    **Office**
    
    Principal
      Occupation for Past Five Years(1)Robert
      J. Waters
      Calgary,
      Alberta, Canada
    
    Senior
      Vice President and Chief Financial Officer
    
    Senior
      Vice President and Chief Financial Officer of Enerplus since December
      2001. Prior thereto, Vice President, Finance and Chief Financial Officer
      of Pengrowth Corporation (a subsidiary of an oil and gas income trust)
      since June 1998.Jo-Anne
      M. Caza
      Calgary,
      Alberta, Canada
    
    Vice
      President,
      Investor
      Relations
    
    Vice
      President of Investor Relations of Enerplus since September 2000. Prior
      thereto, Manager, Investor Relations of Enerplus since 1998.Daryl
      W. Cook
      Calgary,
      Alberta, Canada
    
    Vice
      President, Operations
    
    Vice
      President, Operations of Enerplus since 1997.Rodney
      D. Gray
      Calgary,
      Alberta, Canada
    
    Vice
      President, Finance
    
    Vice
      President, Finance of Enerplus since February 2005. Prior thereto,
      Controller, Finance of Enerplus since June 2002. Prior thereto,
      independent consultant since September 2001. Prior thereto, Controller
      (since 1999) and Manager, Financial Reporting (since 1998) with Berkley
      Petroleum Corp.David
      A. McCoy
      Calgary,
      Alberta, Canada
    
    Vice
      President, General Counsel & Corporate Secretary
    
    Vice
      President, General Counsel & Corporate Secretary of Enerplus since
      December 2002. Prior thereto, Consultant, Offshore & International
      Operations, with EnCana Corporation (an oil and gas exploration and
      production company) since 2002. Prior thereto, Vice President, General
      Counsel & Governmental Affairs with Conoco Canada Limited since 2000.
      Prior thereto, Alberta Counsel with Westcoast Energy Inc. (a regulated
      pipeline and midstream company) since 1998.Daniel
      M. Stevens
      Calgary,
      Alberta, Canada
    
    Vice
      President, Development Services
    
    Vice
      President, Development Services of Enerplus since February 2003. Prior
      thereto, Manager, Drilling and Completions of Enerplus since
      1996.Wayne
      G. Ford
      Calgary,
      Alberta, Canada
    
    Controller,
      Operations
    
    Controller,
      Operations of Enerplus since August 2001. Prior thereto, Controller of
      Argonauts Group Ltd. (an oil and gas exploration and production company)
      since January 2000. Prior thereto, Operations Accounting Consultants with
      Enerplus since September 1998.Christina
      S. Meeuwsen
      Calgary,
      Alberta, Canada
    
    Assistant
      Corporate Secretary
    
    Assistant
      Corporate Secretary of Enerplus since December 2002. Prior thereto,
      Corporate Secretary of Enerplus since 1996.





**Note:**


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





As
of March 7, 2005, the directors and officers named above beneficially own,
directly or indirectly, an aggregate of 383,394 Trust Units, representing
approximately 0.37% of the outstanding Trust Units as of that date.




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







- 61
-





**Audit
Committee Disclosure**




The
disclosure regarding Enerplus' Audit Committee required under Multilateral
Instrument 52-110 adopted by certain of the Canadian securities regulatory
authorities is contained in Appendix "D" 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, or any associate or affiliate of
the foregoing, has had any material interest, direct or indirect, in any
material transaction with Enerplus since January 1, 2002 or in any proposed
transaction that would materially affect Enerplus.




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




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




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




**INTERESTS
OF EXPERTS**




Sproule
prepared the Sproule Report in respect of the reserves attributable to Enerplus'
conventional oil and natural gas properties, a summary of which is contained in
this Annual Information Form. GLJ prepared the GLJ Report in respect of
the **** SAGD
reserves attributable to Enerplus' working interest in the Joslyn Creek Project.
The auditors of the Fund are Deloitte & Touche LLP, Chartered Accountants,
Calgary, Alberta. As of the date of the Sproule Report, the directors, officers
and associates of Sproule, as a group, beneficially owned, directly or
indirectly, less than 1% of the Fund's outstanding Trust Units. As of the date
of the GLJ Report, the directors, officers and associates of GLJ, as a group,
beneficially owned, directly or indirectly, less than 1% of the Fund's
outstanding Trust Units.




**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. Additional information, including directors'
and officers' remuneration and indebtedness, principal holders of the Fund's
securities and securities authorized for issuance under equity compensation
plans, as applicable, is contained in the Fund's information circular dated
February 21, 2005 for its 2005 annual general and special 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,
2004.












- 62
-





**APPENDIX
"A"**




**REPORT
ON RESERVES DATA BY INDEPENDENT**


**QUALIFIED
RESERVES EVALUATOR OR AUDITOR**





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




To
the board of directors of EnerMark Inc., on behalf of Enerplus Resources Fund
(the "Fund"):




1.
    We
      have evaluated and reviewed the Fund's reserves data as at December 31,
      2004. The reserves data consist of the following:(a)
    (i)
    proved
      and proved plus probable oil and gas reserves estimated as at December 31,
      2004 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, 2004 using constant
      prices and costs; and(ii)
    the
      related estimated future net revenue.




2.
    The
      reserves data are the responsibility of the Fund'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 Fund evaluated and reviewed by us as
      of December 31, 2004, and identifies the respective portions thereof that
      we have audited, evaluated and reviewed and reported on to the Fund's
      management and the board of directors of EnerMark
Inc.:




Location
      ofReservesIndependent
    
    
    Description
      and
    
    
    (Country
      orQualified
    
    
    Preparation
      Date of
    
    
    Foreign
    
    New
      Present Value of future Net RevenueReserves
      Evaluator
    
    
    Evaluation
    
    
    Geographic
    
    (10%
      discount rate)or
      Auditor
    
    
    Report
    
    
    Area)
    
    
    Audited
    
    
    Evaluated
    
    
    Reviewed
    
    
    Total(in
      $ thousands)Sproule
      Associates Limited
    
    
    Effective
      December 31, 2004; prepared September 2004 to January 2005
    
    
    Canada
    
    $
    0
    
    $
    2,645,997
    
    $
    377,274
    
    $
    3,023,271





5.
    In
      our opinion, the reserves data evaluated by us have, in all material
      respects, been determined and are in accordance with the COGE Handbook. We
      express no opinion on the reserves data that we have reviewed but did not
      audit or evaluate.





A -
1








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.Executed
      as to our report referred to above:




Sproule Associates
      Limited
    "*Hans
      J. Firla*"Calgary, Alberta,
      CanadaMarch
      14, 2005
    Hans
      J. Firla, P. Eng.
      Project
      Leader & Associate"*Michael
      W. Maughan*"Michael
      W. Maughan, C.P.G., P. Geol.
      Manager,
      Geoscience & Associate"*R.
      Keith MacLeod*"R.
      Keith MacLeod, P. Eng.
      Executive
      Vice-President





















A -
2





**APPENDIX
"B"**




**REPORT
ON RESERVES DATA BY INDEPENDENT**


**QUALIFIED
RESERVES EVALUATOR OR AUDITOR**





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




To
the board of directors of EnerMark Inc., on behalf of Enerplus Resources Fund
(the "Fund"):




1.
    We
      have evaluated and reviewed the Fund's reserves data as at December 31,
      2004. The reserves data consist of the following:(a)
    (i)
    proved
      and proved plus probable oil and gas reserves estimated as at December 31,
      2004 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, 2004 using constant
      prices and costs; and(ii)
    the
      related estimated future net revenue.




2.
    The
      reserves data are the responsibility of the Fund'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 Fund evaluated and reviewed by us as
      of December 31, 2004, and identifies the respective portions thereof that
      we have audited, evaluated and reviewed and reported on to the Fund's
      management and the board of directors of EnerMark
Inc.:




Location
      ofReservesIndependent
    
    
    Description
      and
    
    
    (Country
      orQualified
    
    
    Preparation
      Date of
    
    
    Foreign
    
    New
      Present Value of future Net RevenueReserves
      Evaluator
    
    
    Evaluation
    
    
    Geographic
    
    (10%
      discount rate)or
      Auditor
    
    
    Report
    
    
    Area)
    
    Audited
    
    Evaluated
    
    Reviewed
    
    Total(in
      $ thousands)


Gilbert
      Laustsen Jung Associates Ltd.
    
    
    Effective
      December 31, 2004;preparedJanuary
      14, 2005
    
    
    Canada
    
    $
    0
    
    $
    52,413
    
    $
    0
    
    $
    52,413


5.
    In
      our opinion, the reserves data evaluated by us have, in all material
      respects, been determined and are in accordance with the COGE Handbook. We
      express no opinion on the reserves data that we have reviewed but did not
      audit or evaluate.





B -
1








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.Executed
      as to our report referred to above:




Gilbert Laustsen Jung
      Associates Ltd.
    "*Dana
      B. Laustsen*"Calgary, Alberta,
      CanadaMarch
      14, 2005
    Dana
      B. Laustsen, P. Eng.
      Executive
      Vice-President













B -
2





**APPENDIX
"C"**




**REPORT
OF MANAGEMENT AND DIRECTORS**


**ON
RESERVES DATA AND OTHER INFORMATION**





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




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




(a)
    (i)
    proved
      and proved plus probable oil and gas reserves estimated as at December 31,
      2004 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, 2004 using constant
      prices and costs; and(ii)
    the
      related estimated future net revenue.





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




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




(a)
    reviewed
      EnerMark's procedures for providing information to the independent
      qualified reserves evaluators;(b)
    met
      with the independent qualified reserves evaluators to determine whether
      any restrictions affected the ability of the independent qualified
      reserves evaluators to report without reservation; and(c)
    reviewed
      the reserves data with management and the independent qualified reserves
      evaluators.





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




(a)
    the
      content and filing with securities regulatory authorities of the reserves
      data and other oil and gas information;(b)
    the
      filing of the reports of the independent qualified reserves evaluators on
      the reserves data; and(c)
    the
      content and filing of this report.





C -
1





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




ENERPLUS RESOURCES
      FUNDBy EnerMark
    Inc."*Gordon
      J. Kerr*"Gordon J.
KerrPresident and Chief
      Executive Officer"*Garry A.
      Tanner*"Garry A.
    TannerSenior Vice President
      andChief Operating
      Officer"*Glen D.
      Roane*"Glen D. RoaneDirector"*Donald
      T. West*"Donald T.
WestDirectorMarch
      14, 2005










C -
2





**APPENDIX
"D"**




**AUDIT
COMMITTEE DISCLOSURE**


**PURSUANT
TO MULTILATERAL INSTRUMENT 52-110**




**The
Audit Committee's Charter**




**I.**
    **AUTHORITY**





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




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





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




1.
    financial
      reporting and disclosure of the Fund;2.
    the
      Fund's compliance with regulatory requirements;3.
    external
      auditor's qualifications, appointment, fees and
    independence;4.
    evaluating
      and monitoring the performance of the Fund's external auditors;5.
    the
      preparation of the Fund's continuous disclosure documents;
    and6.
    monitor
      the manner in which the financial risks of the Fund are being
      managed.





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




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





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







D -
1










**IV.**
    **MEETING
      OF THE COMMITTEE**





The
Committee shall meet with such frequency and such intervals, as it shall
determine is necessary to carry out its duties and responsibilities. As part of
its purpose to foster open communications, the Committee shall meet at least
quarterly with management and the Fund's external auditors in separate executive
sessions to discuss any matters that the Committee or each of these groups or
persons believe 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 one's expectations are understood and addressed. The
Committee, in its discretion, may ask members of management or others to attend
its meetings (or portions thereof) and to provide pertinent information as
necessary. The Committee shall maintain minutes of its meetings and records
relating to those meetings and the Committee's activities and provide copies of
such minutes to the Board.




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





Evaluation
and Appointment of External Auditors




1.
    Make
      recommendations to the Board on the appointment of external auditors of
      the Fund and its subsidiaries;2.
    Review
      and approve the Fund's external auditors' annual engagement letter and
      audit plans, 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 auditor's performance. Approve payment of audit fees and
      pre-approve audit related and other authorized work
  fees;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 delineating all relationships between the
      external auditors and the Fund;(b)
    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;(c)
    pre-approve
      the nature of non-audit related services and the fees thereon;(d)
    conduct
      private sessions with the external auditors and favor direct
      communications between the Chairman of the Committee and the audit
      partner; and(e)
    instruct
      the Fund's external auditors that they are ultimately accountable to the
      Committee and the Board and that the Committee and the Board are
      responsible for the selection (subject to unitholder approval), evaluation
      and termination of the Fund's external
auditors.





Oversight
of Annual and Quarterly Statements and Management Discussion and
Analysis




5.
    Review
      and approve, if appropriate, the annual audit plan of the external
      auditors, including the scope of audit activities, and monitor such plan's
      progress and results during the year;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;





D -
2










7.
    Ensure
      adequacy of financial results and disclosure in the management, discussion
      and analysis through the review of:




(a)
    external
      auditors report, the annual and quarterly financial statements, the
      management's discussion and analysis, the "Memorandum Regarding Accounting
      Procedures and Internal Control", the certification process by the CEO and
      CFO, and any other pertinent reports and management's responses concerning
      the financial statements;(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 under generally
      accepted auditing standards by the external auditors;
  and(i)
    management's
      acknowledgement of its responsibility towards the financial
      statements.





Oversight
of Financial Reporting Process, Internal Controls and Certification
Process




8.
    Review
      any developments concerning the "Notification of Improprieties Policy" and
      responses on calls received;9.
    Review
      the adequacy and effectiveness of the financial reporting system and
      internal control policies and procedures with the external auditors and
      management. Ensure that EnerMark complies with all new regulations in this
      regard;10.
    Review
      with management EnerMark and the Fund's administrative, operational and
      accounting internal controls, including controls and security of the
      computerized information systems, and evaluate whether EnerMark and the
      Fund is operating in accordance with its prescribed policies, procedures
      and codes of conduct;11.
    Review
      with management and the external auditors any reportable condition and
      material weaknesses affecting internal controls;12.
    Receive
      periodic reports from the external auditors and management to assess the
      impact of significant accounting or financial reporting developments
      proposed by the CICA, the AICPA, the Financial Accounting Standards Board,
      the SEC, the relevant Canadian securities commissions, stock exchanges or
      other regulatory body, or any other significant accounting or financial
      reporting related matters that may have a bearing on EnerMark and the
      Fund;





D -
3







13.
    Establish
      and maintain free and open means of communication between the Board, the
      Committee, the external auditors and
management;





Review
of Business Risks




14.
    Review
      with management, the list of risks that they have identified and ensure
      that management has implemented appropriate systems to monitor, mitigate
      and report such business risks;15.
    Review
      adequacy of the insurance coverage;16.
    Review
      the implementation of hedging policy and its
    implementation;17.
    Review
      the disclosure of those risks in the documents sent to unitholders to
      ensure that it meets with industry standards and adequately describes them
      to unitholders;





Other
Matters




18.
    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;19.
    Discuss
      press releases regarding earnings and other financial information provided
      to analysts and rating agencies;20.
    Review
      the disclosure made in the Fund's Annual Report, Annual Information Form,
      Form 40-F and Information Circular regarding the Audit & Risk
      Management Committee; and21.
    Perform
      such additional activities, and consider such other matters, within the
      scope of its responsibilities, as the Committee or the Board deems
      necessary or appropriate.**VI.**
    **OVERSIGHT
      OF VARIOUS FINANCIAL EXTERNAL
REPORTS**





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




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





Once
a year, the Committee reviews the adequacy of its charter and brings to the
attention of the Board any 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 member's performance.




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







D -
4





**Composition
of the Audit Committee**




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




**Relevant
Education and Experience**




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





**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 2004 and 2003 were pre-approved by the
Committee. Based on the Committee's discussions with management and







D -
5





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.




**External
Auditor Service Fees**




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




**2004**
    
    **2003**(in
      $ thousands)Audit
      fees(1)
    
    $
    338.7
    
    $
    302.0Audit-related
      fees(2)
    
    
    -
    
    
    -Tax
      fees(3)
    
    
    19.9
    
    
    47.8All
      other fees(4)
    
    
    -
    
    
    -$
    358.6
    
    $
    349.8





**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. No audit-related fees were incurred
      in the Fund's last two fiscal years.(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". No such fees were incurred in the Fund's last two fiscal
      years.










D -
6






































**Enerplus
Resources Fund**


The
Dome Tower


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


Calgary,
Alberta, Canada


T2P
2Z1


Telephone:  (403)
298-2200


Fax:  (403)
298-2211


www.enerplus.com